United States Nuclear Regulatory Commission - Protecting People and the Environment

481st Meeting - April 5, 2001

                Official Transcript of Proceedings

                  NUCLEAR REGULATORY COMMISSION



Title:                    Advisory Committee on Reactor Safeguards
                               481st Meeting



Docket Number:  (not applicable)



Location:                 Rockville, Maryland



Date:                     Thursday, April 5, 2001







Work Order No.: NRC-147                               Pages 1-232





                   NEAL R. GROSS AND CO., INC.
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                       NUCLEAR REGULATORY COMMISSION
                                 + + + + +
                 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS
                                  (ACRS)
                               481ST MEETING
                                 + + + + +
                                 THURSDAY,
                               APRIL 5, 2001
                                 + + + + +
                            ROCKVILLE, MARYLAND
                                 + + + + +
                       The Committee met at the Nuclear
           Regulatory Commission, Two White Flint North, Room
           T2B3, 11545 Rockville Pike, at 8:30 a.m., Dr. George
           E. Apostolakis, Chairman, presiding.
           COMMITTEE MEMBERS PRESENT:
                 GEORGE E. APOSTOLAKIS          Chairman
                 MARIO V. BONACA                Vice Chairman
                 F. PETER FORD                  Member
                 THOMAS S. KRESS                Member
                 GRAHAM M. LEITCH               Member
                 DANA A. POWERS                 Member
                 WILLIAM J. SHACK               Member
                 JOHN D. SIEBER                 Member
           COMMITTEE MEMBERS PRESENT: (CONT.)
                 ROBERT E. UHRIG                Member
                 GRAHAM B. WALLIS               Member
           
           INVITED EXPERT PRESENT:
                 STEPHEN L. ROSEN
           
           ACRS STAFF PRESENT:
                 SAM DURAISWAMY
                 CAROL A. HARRIS
                 JOHN T. LARKINS
                 JAMES E. LYONS
                 ROBERT ELLIOTT
           
           ALSO PRESENT:
                 ED ANDRUZKIEWIZ
                 HANS ASHAR
                 RAJ AULUCK
                 RAY BAKER
                 WILLIAM BATEMAN
                 CHARLES BRINKMAN
                 WILLIAM L. BROWN
                 WILLIAM BURTON
                 LARRY CAMPBELL
                 C. E. CARPENTER, JR.
           
           ALSO PRESENT: (CONT.)
                 ROBERT CARUSO
                 OMESH CHOPRA
                 MANNY COMAR
                 MICHAEL CORLETTI
                 JAMES DAVIS
                 JENNIFER DAVIS
                 JERRY DOZIER
                 BARRY ELLIOT
                 ROB ELLIOT
                 J. FAIR
                 G. GALLETTI
                 BEN GITNICK
                 GEORGE GEORGIEV
                 JIM GRESHAM
                 CHRIS GRIMES
                 FRANCIS GRUBELICH
                 STEVE HOFFMAN
                 Y. GENE HSII
                 CHUCK HSU
                 B. P. JAIN
                 WALTON JENSEN
                 CAROLE JULIAN
                 PETER J. KANG
                 ANDREA KEIM
           
           ALSO PRESENT: (CONT.)
                 STEPHEN KOENICK
                 WILLIAM KOO
                 P. T. KUO
                 CAROLYN LAURON
                 SAM LEE
                 ALAN LEVIN
                 CHANG-YANG LI
                 YUEH-LI C. LI
                 W. C. LIU
                 LAMBROS LOIS
                 MICHAEL McNEIL
                 S. K. MIFON
                 MATTHEW A. MITCHELL
                 RICH MORANTE
                 CLIFF MUNSON
                 RICHARD ORR
                 KRIS PARCZEWSKI
                 ERACH PATEL
                 PAT PATNAIK
                 CHARLES PEARCE
                 ISABELLE SCHOENFELD
                 PAUL SHEMANSKI
                 UNDINE SHOOP
                 DAVID SOLORIO
           
           ALSO PRESENT (CONT.)
                 BRIAN THOMAS
                 EDWARD D. THROM
                 JIT VORA
                 HAROLD WALKER
                 DOUG WALTERS
                 KEITH WICHMAN
                 JERRY WILSON
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           .                                 I N D E X
                         AGENDA ITEM                       PAGE
           1)  Opening Remarks by the ACRS Chairman . . . . . 7
           2)  Interim Review of the License Renewal. . . . .11
               Application for Edwin I. Hatch Nuclear
               Plant Units 1 and 2
           3)  Proposed Final License Renewal Guidance. . . 107
               Documents
           5)  Thermal-Hydraulic Issues Associated. . . . . 158
               with the AP1000 Passive Plant Design
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           .                           P-R-O-C-E-E-D-I-N-G-S
                                                    (8:30 a.m.)
                       CHAIRMAN APOSTOLAKIS:  The meeting will
           now come to order.  This is the first day of the 481st
           meeting of the Advisory Committee on Reactor
           Safeguards.
                       During today's meeting, the Committee will
           consider the following:  Interim review of the license
           renewal application for Edwin Hatch Nuclear Power
           Plant Units 1 and 2; proposed final license renewal
           guidance documents; safety issues associated with the
           use of mixed oxide and high burnup fuels;
           thermal-hydraulic issues associated with the AP1000
           passive plant design; and proposed acrs reports.  A
           portion of this meeting will be closed to discuss
           Westinghouse propriety information applicable to the
           AP1000 design.
                       This meeting has been conducted in
           accordance with the provisions of the Federal Advisory
           Committee Act.  Dr. John Larkins is the designated
           federal official for the initial portion of this
           meeting.
                       We have received no written comments or
           requests for time to make oral statements from members
           of the public regarding today's sessions.
                       A transcript of portions of the meeting is
           being kept.  And it is requested that the speakers use
           one of the microphones, identify themselves, and speak
           with sufficient clarity and volume so that it can be
           readily heard.
                       I will begin with some items of current
           interest or announcements.  First, Mr. John Szabo of
           the Office of General Counsel will meet with us on
           Friday -- that is tomorrow -- at 12:15 p.m. to discuss
           recent changes in ethics laws and answer any questions
           that the members may have relating to conflict of
           interest, contracting restrictions, prohibited stocks,
           et cetera.  So I suggest that we bring our lunch here
           and then listen to Mr. Szabo.
                       There will be a meeting at noon today in
           the Subcommittee Room with NRR staff to discuss
           potential synergistic effects from power upgrades,
           high burnup fuels, life extension, and accident
           precursors, and life extension, period.
                       Carol Harris will pass out financial
           disclosure forms today or tomorrow.  And the members
           are requested to fill them out and return them to
           Carol at the May meeting.  I will be meeting with
           Commissioner Merrifield today, and Dr. Larkins will be
           with me at 3:00 o'clock.  You have received copies of
           the ACRS summary matrix of 2,000 letters and outcomes
           that are in front of you.
                       MEMBER KRESS:  I didn't know we had
           written that many
                       CHAIRMAN APOSTOLAKIS:  Two thousand
           letters, yes, 2,000 letters.  At least it feels that
           way.  And it has the various criteria that we use to
           judge effectiveness and so on.  The subcommittee
           chairmen are asked to find their own letters and
           review what's in this handout and make sure it's
           correct.
                       We will do this in tomorrow's session, the
           P&P session.  So please read them before then.  We
           will discuss our meeting with the Commission next
           month.  We will discuss it today between 4:30 and 5:30
           and Friday at 3:30, between 3:30 and 4:30, and
           Saturday as necessary.
                       You have this pink cover with some
           interesting items of interest attached, several
           speeches by commissioners, an inside NRC article on
           the DPO report, and managerial assignments and changes
           within the agency.  So the members should find this
           interesting.
                       And, finally, I am pleased to announce
           that Mr. Harold Larson has been appointed as Special
           Assistant and Mr. Sam Duraiswamy as Technical
           Assistant to the Associate Director for Technical
           Support of the ACRS/ACNW.
                       And, with all of that, we are ready to
           start our session.  The first one is on interim review
           of the license renewal application for Hatch Nuclear
           Power Plant Units 1 and 2.  Dr. Bonaca, this is your
           session.
                       VICE CHAIRMAN BONACA:  Thank you, Mr.
           Chairman.
                       On March 28th, we met with the applicant
           and with the staff to review the application of Plant
           Hatch Units 1 and 2 for license renewal.  We heard
           from the applicant, and also we had a significant
           amount of information before to review from the SER.
                       On March 27, we spent about half a day
           reviewing with the staff the BWRVIP topical reports
           for the program in general.  That includes in excess
           of 20 topical reports, of which we have reviewed
           specifically 4 of them.
                       Those topical reports are important
           because they are referenced in the Hatch application. 
           They really are the foundation to the vessel and
           internal inspections and evaluations that old BWR was
           performing.  They are important to us because we will
           see them likely in every application for BWRs for
           license renewal.  Today we have the staff and the
           applicant coming in and summarizing for the full
           Committee what we heard on the 27th and 28th of March.
                       With that, I will move and ask Mr. Grimes
           to introduce speakers.
                       MR. GRIMES:  Thank you, Dr. Bonaca.
                       My name is Chris Grimes.  I'm the Chief of
           the License Renewal and Standardization Branch.  I am
           accompanied by Bill Bateman, the Chief of the
           Materials and Chemical Engineering Branch.
                       And the staff is prepared today to
           summarize the material that was presented at the
           subcommittee meetings and to highlight those specific
           areas of interest that the subcommittee pointed out.
                       Mr. William, also known as Butch, Burton
           is the project manager.  And Butch will present the
           summary of the renewal reviews.  We are leading off
           with Gene Carpenter, who is the lead engineer on the
           Boiling Water Reactor Vessel Internals Project.  And
           we have coordinated with the applicant, who is being
           represented here today by Ray Baker from Southern
           Company, in order to address the specific questions
           that came up during the subcommittee meeting.
                       And I would also like to emphasize that
           this is an interim report.  You know that there are a
           number of open items and issues under appeal, for
           which there is an ongoing dialogue with the applicant. 
           And we will do our best today to represent where we
           stand on those issues.  And we will continue to keep
           the subcommittee and the full Committee informed of
           our progress on those issues.
                       And, with that, I will turn it over to the
           staff to make the presentation.
                       VICE CHAIRMAN BONACA:  Thank you.
                       (Slide.)
                       MR. CARPENTER:  Good morning.  I'm Gene
           Carpenter with the Materials and Chemical Engineering
           Branch.  As Mr. Grimes said, I am the lead for the BWR
           Vessel Internals Project, the staff review that has
           been ongoing for that.
                       (Slide.)
                       MR. CARPENTER:  Today I am going to give
           you a very brief overview of the regulatory
           perspective on this, what has been accomplished with
           the BWRVIP Program to date and how the generic aging
           management program has been reviewed.
                       Now, last week when we briefed the
           subcommittee on this, Mr. Robin Doyle of Southern
           Nuclear gave a fairly comprehensive, if somewhat
           abbreviated, overview of it.  And that took two hours. 
           I have 30 minutes.  So my overview is going to be
           exceptionally abbreviated.
                       To start with, BWRVIP is a voluntary
           industry initiative of all the BWR owners in the U.S.
           and several foreign reactors.  It was begun in 1994 to
           address the core shroud cracking issue, which
           eventually gave rise to Draft Letter 94-03.
                       They now address all of the BWR internal
           components, the reactor vessel and an extension of
           what they had previously been chartered to do.  They
           are now looking at the Class I piping material
           conditions also.
                       The guidance that the BWRs have put out
           covers the current operating term and also the
           extended operating period.  The staff is looking at
           both of those.
                       BWRVIP has been proactively addressing
           some of the aging degradation issues that are beyond
           present regulatory requirements as well as those that
           are within regulatory requirements.
                       The BWRVIP has identified generic
           cost-effective strategies that are appropriate for
           plant-specific needs.  They are also the regulator
           interface for all BWR material issues and also the
           clearinghouse for all the information that has been
           gathered, both domestically and internationally.  So
           they are sharing quite a bit of information, not only
           with themselves but also with the staff.
                       (Slide.)
                       MR. CARPENTER:  One of the reasons that
           Mr. Doyle gave last week for all of this is that the
           BWRs were suffering through quite a bit of capacity
           loss in the early 1980s.  As this chart shows, in the
           early '80s, the plants were down up to 20 percent of
           the time.  And obviously when you have a nuclear
           reactor, you would like it to be running as much as
           possible.
                       During this time, the staff had put out
           quite a few information notices, bulletins, generic
           letters, et cetera, regarding some of the material
           degradation issues.  And BWRs had started working on
           this.  Again, in 1994, they started doing this as an
           organization, the BWRVIP organization.
                       (Slide.)
                       MR. CARPENTER:  To give you a rough idea
           of some of the components that have been looked at
           here, not only are we talking about the entire vessel
           itself, we're talking about the core shroud, core
           plate, top guide, core spray piping on the internals,
           the various support legs, basically everything inside
           that is safety-related.
                       (Slide.)
                       MR. CARPENTER:  As you may remember from
           when the core shroud issue first occurred, some of the
           components that were of high concern were these welds,
           the circumferential welds.  Later on vertical welds
           were also identified as a cracking problem.  And that
           is being addressed in one of the BWRVIP reports,
           specifically VIP-63, which the staff has reviewed. 
           They have also looked at, again, the support legs, the
           core spray piping, the top guide, more core plate, the
           jet pumps, et cetera.
                       To give you a rough idea again, all of the
           BWRs in the United States are members of the BWRVIP. 
           And they all have committed to following the BWRVIP
           guidance as it is reviewed by the staff and approved. 
           If they have any problem with following the guidance
           once it is approved, they are required to tell us
           within 45 days.
                       (Slide.)
                       VICE CHAIRMAN BONACA:  Before you leave
           the figure that shows the internals, --
                       MR. CARPENTER:  Yes, sir.
                       VICE CHAIRMAN BONACA:  -- you might want
           to point out some of the concerns there may be.  I
           mean, for example, some failure of hold-down things in
           top guide may lead to core movement --
                       MR. CARPENTER:  Yes, sir.
                       VICE CHAIRMAN BONACA:  -- and, therefore,
           their ability to insert control rods.  I mean, that's
           the kind of issues maybe the members should hear about
           briefly.
                       MR. CARPENTER:  Right.  Some of the issues
           that have arisen obviously with core shroud cracking,
           you lose two-thirds core coverage.  If the core shroud
           circumferential welds do give way and there is
           movement of the core shroud, you could preclude the
           ability to perform a safe shutdown by movement,
           damaging of the fuel, precluding the control rods from
           inserting.
                       Another problem was with the SLC, standby
           liquid control system.  If that failed, you would not
           be able to shut down under an ATWS condition.
                       The jet pumps, one of the things that was
           looked at was what would happen if you had the jet
           pumps disassemble.  Again, that would preclude
           two-thirds core height coverage.
                       If the core spray pipes had significant
           cracking in it, you would not be able to perform core
           spray cooling.  If the top guide or the lower core
           plate was cracked significantly, again, more problems
           there.  And these are all some of the issues that were
           looked at in toto as well as what would happen if you
           had cracking in the reactor vessel or in some of the
           Class I piping.
                       VICE CHAIRMAN BONACA:  Thank you.
                       (Slide.)
                       MR. CARPENTER:  Okay.  The previous slide
           was on the domestic members.  This is a listing of the
           present foreign member utilities.  As you can see, it
           includes Germans, the Japanese, Taiwanese, et cetera.
                       (Slide.)
                       MR. CARPENTER:  Some of the BWRVIP
           reports, as I said several times now, have included
           the BWR vessel, all safety-related internal
           components, and Class I piping.
                       VICE CHAIRMAN BONACA:  Just one more
           question.
                       MR. CARPENTER:  Yes, sir?
                       VICE CHAIRMAN BONACA:  Of all the foreign
           member utilities you showed, are they all G.E.
           reactors?
                       MR. CARPENTER:  I don't believe.
                       VICE CHAIRMAN BONACA:  Okay.  So there are
           some BWR reactors of other design?
                       MR. CARPENTER:  I believe so, yes.
                       VICE CHAIRMAN BONACA:  Okay.  So there is
           a sharing of information with other types of designs?
                       MR. CARPENTER:  Right.  The BWRVIP
           reports, again, they cover the core shroud, shroud
           supports, the entire list that I have here, of which
           the Hatch review did take a look at all of these. 
           Some of them are not applicable to Hatch, but we will
           talk about that in a moment.
                       The guidelines were basically broken up
           into three main sections, those of the inspection and
           flaw evaluation guidelines, which create the bases for
           the aging management program; repair design criteria,
           which would be applicable at any time in plant life,
           either during the current operating term or the
           license extension term; and also mitigation guidance,
           which would give you a way to preclude cracking,
           hydrogen water chemistry, noble metal chemistry
           addition, et cetera.  And that's also good at any time
           during plant life.
                       (Slide.)
                       MR. CARPENTER:  To give you a brief
           overview, as Dr. Bonaca said at the beginning, there
           have been quite a few of these BWR reports.  These are
           the majority of the flaws, the inspection and flaw
           evaluation guidelines.
                       Several, the BWR reactor vessel pressure
           one, BWRVIP-74, had subsumed and the guidance that was
           given in BWRVIP-05, which the ACRS reviewed several
           years ago.  BWRVIP-76, the core shroud, which started
           all of this, subsumes the guidance that was previously
           approved in BWRVIP-01, -07, and -63, -63 being the
           vertical welds, as opposed to the circumferential ones
           on the first two.
                       (Slide.)
                       MR. CARPENTER:  And, as I said a moment
           ago, they also have repair/replacement design
           criteria.  This is a listing of those for all of the
           safety-related equipment.
                       (Slide.)
                       MR. CARPENTER:  And also guidance on how
           to evaluate crack growth and mitigation.  And these
           all either have been reviewed or are under staff
           review at this time.
                       (Slide.)
                       MR. CARPENTER:  Some of the other reports
           that have been looked at were:  the BWRVIP-03
           guidance, which tells the licensees how to do a
           consistent examination; and the -06 report, which was
           a safety assessment of all the reactor internals.  And
           that gave them the bases for determining which of
           these internal components would be looked at and
           evaluated.
                       The safety assessment identified
           components that were necessary for safe operation
           shutdown.  The criteria that was used was to: 
           maintain a coolable geometry, maintain rod insertion
           times, maintain reactivity control, assure core
           cooling, and assure instrument availability, all good
           things.
                       (Slide.)
                       MR. CARPENTER:  The general format of the
           I&E guidelines, which, again, is the bases for the
           aging management program, is an overall description of
           the components, the inspection history, and the
           susceptibilities of the components; failure
           consequences; the inspection requirements, both scope
           and frequencies; flaw evaluation methodologies; and
           reporting requirements, what they are going to be
           telling the staff.
                       The program assures that the inspections
           performed correctly and on time by qualified
           personnel; and that the inspection results and flaws
           are properly evaluated and dispositioned; and that all
           repairs meet approved BWRVIP criteria or applicable
           codes, as the case may be.
                       (Slide.)
                       MR. CARPENTER:  BWRVIP conclusions were
           that the program is broad in scope; the BWRVIP
           includes appropriate inspections, evaluation
           methodologies, repair criteria and mitigation methods
           to assure BWR internals integrity; and the use of the
           program during license renewal period provides an
           adequate aging management program.  Now, that --
                       CHAIRMAN APOSTOLAKIS:  Whose conclusions
           are these?
                       MR. CARPENTER:  Again, this is the
           BWRVIP's conclusions.
                       CHAIRMAN APOSTOLAKIS:  Not yours?  Okay.
                       MR. CARPENTER:  I'm about to give you
           ours.
                       CHAIRMAN APOSTOLAKIS:  Okay.
                       MR. CARPENTER:  Okay?
                       CHAIRMAN APOSTOLAKIS:  It was too good.
                       (Slide.)
                       MR. CARPENTER:  Everyone has their own
           little advertisement that they want to put out.  This
           is the staff's.  And the staff has, again, completed
           the review of almost all the BWRVIP reports and those
           that we have reviewed and have approved.  And there
           have been one or two that we have not approved as
           either denied or not yet approved.
                       The staff has concluded that
           implementation of the guidelines as modified to
           address staff comments will provide an acceptable
           level of quality for inspections and flaw evaluations
           of the subject safety-related components.  We have
           also performed and independent research review, which
           was NUREG/CR-6677, which I provided copies to the
           Committee last week.  That found that comprehensive
           inspection programs like the BWRVIP can significantly
           reduce core damage frequencies.
                       CHAIRMAN APOSTOLAKIS:  Can or does?
                       MR. CARPENTER:  Can.
                       MEMBER WALLIS:  Well, how does an
           inspection program reduce a core damage frequency? 
           Does it lead to a reassessment of some numbers?  What
           is the mechanism for it?
                       MR. CARPENTER:  One second, sir.
                       MEMBER WALLIS:  If you found something bad
           in your inspections, it would increase the core damage
           frequency.
                       MR. CARPENTER:  What the summary for the
           NUREG-6677 says -- and this is on Page 194 of the
           report -- "With no credit for inspections, monitoring,
           or repair; i.e., no BWRVIP program, and a probability
           of significant cracks developing one, coupled with the
           initiating event frequencies and system failure
           frequencies and the PRA studied, an undesirable
           increase in the plant core damage frequency; i.e.,
           greater than 5e-6 events per year, is predicted.
                       "With the current BWRVIP inspection,
           monitoring, and repair program, there is expected to
           be no significant increase in CDF; i.e., less than
           5e-6 events per year, caused by failures of BWR vessel
           internals.  That is, IGSCC problems can be identified
           and evaluated or corrected to preclude a significant
           increase in core damage frequency."
                       So you can identify the problems before
           they occur.
                       MEMBER WALLIS:  So it's the corrective
           action that changes the CDF --
                       MR. CARPENTER:  That is my understanding,
           yes.
                       MEMBER WALLIS:  -- or is it just your
           state of knowledge, which is different, because you
           know more?
                       MR. CARPENTER:  If you can find a
           potential problem before it can become an actual
           problem, then you can reduce --
                       MEMBER WALLIS:  Presumably if you found
           problems which you didn't know about before, you could
           conceivably increase your CDF?
                       MR. CARPENTER:  If you're correcting them
           before they become a problem.
                       MEMBER WALLIS:  But if you didn't know how
           to correct them, you find something you didn't know
           was there before, it wasn't in your PRA, now it is,
           you could increase your CDF.
                       MEMBER SHACK:  Well, there's the PRA.
                       MR. CARPENTER:  That's right.
                       MEMBER WALLIS:  But the idea is it always
           increases CDF.  It may be --
                       VICE CHAIRMAN BONACA:  It seems that the
           better way to put it would be that -- I mean, it
           prevents increases in CDF that would result from the
           cracking.  I mean, that's really what it says.  With
           respect to what we have measured today, if we did not
           have these inspections and the repair, we would see an
           increase in CDF by a certain amount they seem to
           quantify.
                       MEMBER WALLIS:  What would be the
           mechanism for increasing that CDF?  It would have to
           be some cracking in the map, which increases your CDF.
                       VICE CHAIRMAN BONACA:  Sure.  You have a
           high probability of --
                       MEMBER WALLIS:  The crack growth is in
           your model, and the CDF is increasing.  But by
           inspecting, you somehow --
                       VICE CHAIRMAN BONACA:  For example, he
           would have an increase in the frequency of ATWS. 
           Okay?  And now because you have these inspections and
           repairs, your frequency of the ATWS --
                       MEMBER KRESS:  It affects two things:  the
           frequency of certain events, one of which would be
           ATWS.  It also affects the probability of events in
           the event tree of going one way or another and certain
           event trees.  It affects those probabilities.  And the
           outcome is it in reality has effects on the CDF.
                       MEMBER SHACK:  Yes.  I mean, your computed
           CDF may go.
                       MEMBER KRESS:  Sure.  Your computed might
           have gone up, but the real CDF --
                       MEMBER SHACK:  But your actual proved CDF,
           which is the one you really should worry about --
                       MEMBER WALLIS:  There's no such things as
           a true CDF.
                       CHAIRMAN APOSTOLAKIS:  There isn't such a
           thing.  Come on.
                       MEMBER WALLIS:  It's always a computed
           CDF.  There's no such thing as a measured CDF.  It's
           always computed.
                       CHAIRMAN APOSTOLAKIS:  I think Graham is
           right.
                       MEMBER KRESS:  Well, in principle, there
           is a CDF.
                       MEMBER SHACK:  You may not know what it
           is.  You may not know what it is.
                       MEMBER KRESS:  There had better be a CDF
           or we are beating our head against the wall.
                       CHAIRMAN APOSTOLAKIS:  But all you have is
           the computed CDF.  Why is it "significantly"?  I mean,
           why do you put the word "significantly" there?
                       MR. CARPENTER:  I did not do this report. 
           Is --
                       CHAIRMAN APOSTOLAKIS:  I mean, am I to
           compare this with the standard 10-6 or less vessel --
                       MR. CARPENTER:  Well, that they use to --
                       CHAIRMAN APOSTOLAKIS:  -- carrier?  So 5
           x 10-6 is significant?
                       MR. CARPENTER:  It is significant, sure.
                       CHAIRMAN APOSTOLAKIS:  Yes.  That's fine.
                       VICE CHAIRMAN BONACA:  The question I
           have:  In many of these reports on a related issue,
           there is a statement that some of the degradation
           mechanism could lead to inability of inserting control
           rods.  Okay?
                       And then there is a statement typically
           that says:  However that happens, you know, the SLC
           system is available.  And there is no discussion there
           on the fact that, you know, the core reliance on the
           SLC system is based on a very low frequency of the
           ATWS event.  I mean, that is not something that makes
           me comfortable to know that if you cannot insert the
           rods, you have the SLC system anyway.  Well, I hope
           we'll never have to use that system.
                       So I guess this is in the same contrast of
           the evaluation that NUREG provides, I imagine.  Yes. 
           Low probability and low likelihood.  Okay.
                       But, anyway, I just wanted to comment how
           there is this dependency there on the systems that in
           design basis, they are not supposed to be used either
           for the life of the plant, --
                       MEMBER FORD:  Gene, I have a question.
                       MR. CARPENTER:  Yes, sir.
                       MEMBER FORD:  -- really, following up from
           the meeting we had last week.  And it relates to the
           risk management and how quantitative we are.  It
           relates to the last line there.  In the VIP documents
           for disposition of the cracks for the austenitic
           calories, we use the upper bound of the data.  What
           would the procedure be if in the future you found
           cracks going faster than that upper bound?
                       And, as you know, we have done that.  That
           has occurred in the past for the ASME 11 code for
           corrosion fatigue.  We kept on moving the line up as
           we got more data.  Would you do the same?  Would NRR
           advocate the same, just increasing the upper bound as
           you get more data?  That is the first question.
                       The second question is both for especially
           the low alloy steel disposition curves.  It's based on
           minimal data, and it is not the upper bound.  How do
           you manage that risk or how would NRR judge the
           management to that risk?  There could well be data
           above the disposition line that has been quoted for
           low alloy steels.
                       MR. CARPENTER:  Dr. Ford, correct if I'm
           misstating what you just asked me.  The first part of
           the question was:  How would we evaluate if future
           data comes in that shows that the crack growth rate
           that we have at present is unconservative?
                       MEMBER FORD:  Correct.
                       MR. CARPENTER:  Okay.  If we find that we
           have a nonconservative crack growth rate, the staff --
           I feel very confident in stating this categorically --
           will go back.  And we will evaluate that, and we will
           perhaps tell them -- not perhaps.  We will tell the
           industry to go and reevaluate based on this additional
           data.
                       MEMBER FORD:  Okay.
                       MR. CARPENTER:  Obviously we want to be
           conservative.  We want to be safe.
                       VICE CHAIRMAN BONACA:  But I would expect
           that the BWRVIP program would have procedures of this
           type to incorporate data in the program.
                       MR. CARPENTER:  The BWRVIP is planned to
           be a living program.  And they are planning to
           evaluate as it becomes available and relook at all of
           this, yes.
                       MEMBER FORD:  And the second question,
           which I am really concerned about, the low alloy steel
           one, well, that disposition line I know because I did
           it was formulated almost out of the air.  I hesitate
           to say that.
                       MR. CARPENTER:  And I would certainly not
           correct you at all.  You are the expert there, sir. 
           But I will defer this to the staff expert on this.
                       Bill, Bill Koo, you are the one who looked
           at some of this low alloy steel stuff.  Could you
           address Dr. Ford's question, please?
                       MR. BATEMAN:  Bill's telling me he did not
           perform that review.  So I don't think we have that
           particular expertise here to support at this time.  We
           will have to get back.
                       MEMBER FORD:  I guess the answer would be
           the same as the previous one that it is a living
           document, if you like.
                       MR. CARPENTER:  Certainly.
                       MEMBER FORD:  And, therefore, you would
           just revise it.
                       MR. CARPENTER:  Certainly.
                       VICE CHAIRMAN BONACA:  Just staying  on
           the issue, however, it would be interesting to know
           more about the BWRVIP program and the commitments it
           has.  I mean, the staff cannot be ultimately
           responsible for all the elements of the program.
                       The program is really a leading program
           that is supported by the industry.  So I would expect
           it would have a number of guidelines on how new
           information is incorporated, how it is distributed
           among the participants, how commitments are revised,
           and how the --
                       CHAIRMAN APOSTOLAKIS:  Well, presumably,
           you know, the results of the inspection program are
           evaluated by somebody.
                       VICE CHAIRMAN BONACA:  Well, I mean --
                       CHAIRMAN APOSTOLAKIS:  That's what makes
           it a program.
                       VICE CHAIRMAN BONACA:  That's right, but
           I would like -- you know, what we have heard here is
           that the NRC would make certain requirements.  The
           point is that the program really should be or has been
           successful before the NRC participated in that.
                       MR. CARPENTER:  Correct.  BWRVIP, as I
           said at the beginning, is the clearinghouse for all of
           this information.  They do collect it.  They do
           provide it to all of their member utilities.  And they
           do evaluate all of the material that is looked at. 
           And they do come in and meet with the staff on a
           regular basis to discuss the materials issues that
           they have been evaluating, both domestically and the
           information that they receive from overseas.
                       To date, whenever there is a problem or
           there has been a concern raised, they have been very
           fast in responding to that problem.  For instance, a
           couple of years ago, we had an instance with cracking
           in the jet pump elbow risers.  The BWRVIP took that on
           very fast, and they did resolve it with the issuance
           of a couple of reports, including the BWRVIP-28
           report, which gave us a justification as to why the
           operating plants were safe to continue operation until
           they could perform inspections, and then later on with
           the BWRVIP-41 report, which it gave inspection
           guidance.
                       So they are looking at issues as they do
           arise.  And obviously the staff is looking at the same
           issues on a concurrent basis.
                       Yes, sir?
                       MEMBER SIEBER:  If I would go back to
           Slide 3, --
                       MR. CARPENTER:  Yes, sir.
                       MEMBER SIEBER:  -- which shows the core
           shroud, you talk about these inspections, but the
           geometries for the welds shown in that figure to me
           would be pretty complex.  And so my question is:  What
           kind of inspection do you do?  And how certain are you
           that you detect whatever indications are there in the
           geometry that is shown on this figure?
                       MR. CARPENTER:  The BWRVIP has guidance. 
           Originally the BWRVIP was seven guidance for the
           inspection of the core shroud circumferential welds. 
           That was later added to with the -63 report, which
           deals with the vertical welds.  And then it was all
           subsumed into the BWRVIP report, which is still under
           staff review.
                       They also have the BWRVIP-03 report, which
           is the guidelines on how to perform inspections,
           visual, UT, ultrasonic examinations, various other
           types of examinations that would be done of the
           vessel.  It gives you guidance on how to qualify the
           inspections and what makes a successful inspection.
                       So when they perform these inspections to
           the guidance of the staff-approved BWRVIP-07 and -63
           reports, using the -03 guidance, which has also been
           reviewed and approved by the staff and modified with
           staff comments, then we have a fairly high confidence
           level that you are going to find whatever there is to
           be found.
                       Does that answer your question, sir?
                       MEMBER SIEBER:  Yes.  Just as a little bit
           of a follow-up, though, if I look at a VT-type
           inspection, the indication has to be pretty
           substantial in order to pick that up as a VT.
                       MR. CARPENTER:  Well, bear in mind the
           VT-3 examination, which is code-required, is a very
           broad examination.
                       MEMBER SIEBER:  Right.
                       MR. CARPENTER:  The BWRVIP has taken that. 
           And they have reduced that down to an enhanced VT-1,
           which is a one-half mil examination.  So it is a much,
           much finer examination.
                       MEMBER SIEBER:  So you have gone beyond
           the code requirement?
                       MR. CARPENTER:  The BWRVIP has gone
           considerably beyond code requirements, yes.
                       MEMBER SIEBER:  Thank you very much.
                       MEMBER POWERS:  I don't really understand
           the response.  It says:  Gee, BWRVIP used a bunch of
           expert opinion to come up with an inspection
           technique.  The staff looked at that.  And based on
           their expert opinion, they approved it.
                       Does anybody at any time go back and say,
           "Okay.  Here is a system that we know has flaws in it. 
           Show that the technique, in fact, does find those
           flaws"?
                       MR. CARPENTER:  Yes, sir.  The EPRI/NDE
           Center qualifies the inspectors.
                       MEMBER POWERS:  It qualifies them for the
           techniques against some sort of sample.  But he is
           asking:  In this geometry, in this complexity, does it
           work?
                       MEMBER SIEBER:  That's different.
                       MEMBER POWERS:  That's different.
                       MR. BATEMAN:  Bill Bateman on the staff.
                       I think we would need to adequately
           address your question for you to select a particular
           weld which you thought was a complex geometry.  And
           once we understood what particular weld we were
           talking about, we would be better able to give you an
           answer.  We might even have to go back to the BWRVIP
           to help get that answer.
                       MEMBER POWERS:  I think that would be a
           useful thing for me to formulate the question that
           way.  I don't think I can.  But I think there is a
           generic issue here, one that we need to think about a
           little bit.  What can we do to validate by actual
           experience, rather than expert opinion, these
           judgments on the adequacy of the inspections?
                       Now, in some cases; for instance, in the
           flaw distributions and pressure vessels, we have been
           fortunate enough to get a couple of pressure vessels? 
           And they tear them apart at Oak Ridge or something
           like that.  And they get an actual distribution, and
           they can do a lot of things.
                       Is there anything in the offing of getting
           some actual internals someday that we can keep Oak
           Ridge busy tearing things apart looking for flaw
           distributions?
                       MEMBER SHACK:  They'll still be screaming
           hot.
                       MEMBER POWERS:  Well, these vessels aren't
           a walk through the park either.
                       MEMBER SHACK:  Compared to the core, they
           are.
                       MEMBER WALLIS:  It's very simple, then. 
           You just deny license renewal.  Then you've got a
           vessel you can take apart.
                       VICE CHAIRMAN BONACA:  Actually, we could
           ask a question of the licensee that they had
           indications on the shroud they could not tell if,
           really, there were actual cracks.  But they repair
           them anyway because of the concern they had.
                       Could you expand on how effective it was
           in the inspection, what the difficulty was in
           determining whether it was an incipient crack or --
                       MR. BAKER:  I'm looking to Charles Pearce
           in the audience.  And I am not sure that either one of
           us have the actual detailed knowledge of the repair
           that was affected today.  We can certainly follow up
           at a later date.
                       VICE CHAIRMAN BONACA:  For the
           application, it sounds like, really, you can tell if
           it was a crack or not.
                       MR. BAKER:  It was my understanding that
           we preemptively repaired it.  So whether there was a
           crack or not did not matter.
                       VICE CHAIRMAN BONACA:  That's right.
                       MR. BAKER:  The repair was to support it
           in a different way.
                       VICE CHAIRMAN BONACA:  Wouldn't that pump
           be a comment on the difficulty of making that
           determination?
                       MR. BAKER:  Yes.  I just don't know.
                       VICE CHAIRMAN BONACA:  Yes.  Thank you.
                       MEMBER SHACK:  I think Dana's comments are
           correct.  I can't think of any situation in which one
           has qualitatively determined the probability of
           protection for an NDE technique except maybe steam
           generator tubes.  It's largely the difficulty of
           getting representative samples.
                       You know, most people aren't going to
           volunteer to take their reactor apart.  Even if you
           could afford to do it, the sampling sizes you get are
           just small.  I mean, I think it is important in this
           particular case, as Gene mentioned, that the VIP has
           committed to the enhanced VT-1 with the half mil
           resolution.
                       In this particular situation, the flaw
           tolerance is such that, by and large, these cracks
           have to be very large before they are structurally
           significant.  And so probably it is an expert judgment
           again, but I would probably be more confident that I
           could detect a crack of structural significance here
           with the enhanced VT-1 than I probably would -- you
           know, that I would be more confident in that than I
           would be most inspections, you know, my probability of
           detection of the structurally significant flaw.
                       But, again, it certainly hasn't been
           demonstrated in any rigorous fashion.
                       VICE CHAIRMAN BONACA:  We just recently
           had the experience where inspections were conducted,
           nuclear inspections, and nothing was done.  And then
           --
                       MEMBER SHACK:  Borton follow-up is a very
           effective inspection.
                       VICE CHAIRMAN BONACA:  Well, when you find
           a Borton, you find that you have a crack.  Then you
           look back at the other nozzles, and you find that you
           have indications that you hadn't seen the year before.
                       MEMBER POWERS:  It doesn't work at all for
           BWR.
                       VICE CHAIRMAN BONACA:  No.  Borton
           inspections aren't very good for BWR.
                       VICE CHAIRMAN BONACA:  No.  I understand. 
           I am only saying that I think the issue of inspections
           is a very important one.  I think the answer maybe is
           the one that Bill is offering, that before you have a
           real effect, you would have a visible indication.
                       MEMBER SHACK:  Well, I think it was
           important to go to the enhanced VT-1 because, as Jack
           mentioned, VT-3 sees when they are broken parts laying
           in the reactor.  And even VT-1 is like a 132nd
           resolution, --
                       VICE CHAIRMAN BONACA:  Right.
                       MEMBER SHACK:  -- which is like for a
           stress corrosion crack, rather difficult.  But, again,
           when you get to the enhanced VT-1 and you have a fairy
           large flaw tolerance, then you begin to I think
           develop more confidence.
                       MEMBER SIEBER:  I take it a lot of surface
           has to go on prior to the actual examination.
                       MR. CARPENTER:  That is correct, yes.  The
           BWRVIP-03 document does describe in detail how you are
           supposed to clean the lighting, et cetera.
                       MEMBER SIEBER:  Right.
                       MR. CARPENTER:  Bear in mind visual
           examinations are not the only examinations being
           performed.  They all started performing ultrasonic
           examinations.
                       MEMBER SIEBER:  Yes.  That bothers me,
           too, a little bit.  When I look at welds like H3 and
           H5, the only UT shots you can make are angle shots. 
           And you may not be able to differentiate in the area
           of the lower core plate what components are where from
           a UT readout.  It just seems complex to me.
                       MR. CARPENTER:  I understand.
                       MEMBER WALLIS:  When you look on the
           bottom of one of these vessels, what do you see?  Do
           you see junk of any sort or is it bright and clean and
           shiny or what?
                       MR. CARPENTER:  I don't know the answer to
           that, sir.  I haven't looked in the bottom.
                       MEMBER WALLIS:  I just want a feel for
           what kind of things you see in there when you look.
                       MEMBER SIEBER:  I think you see a lot of
           crud.
                       MEMBER WALLIS:  There's a lot of dirt or
           buildup?
                       MEMBER SIEBER:  Well, it's crud, which is
           --
                       MEMBER WALLIS:  Unidentified deposit?
                       MEMBER SIEBER:  Well, it's usually sort of
           a harder deposit in the core area because softer ones
           would be swept away.  You know, there is boiling and
           all kinds of turbulent flow in there.  So it would be
           an adhered hard type of crud.
                       MEMBER WALLIS:  An unidentified crud.
                       MEMBER SIEBER:  Which has to be cleaned
           off to do a VT-2 point.
                       MEMBER LEITCH:  Sometimes you see some
           pieces of debris, too.  Like down at the bottom, we
           have had problems with -- there is a suction line
           right from the bottom to -- I think it goes to reactor
           water cleanup that has been plugged or obstructed at
           several plants as a result of maintenance losing
           pieces of things down in that suction line.
                       MEMBER FORD:  Gene, could you comment on
           the question of inspection frequency?  You talk about
           it being a proactive plan, which it is.  As you go
           into a new era, like a relicensing era, you don't
           really know what you are starting with because not
           everything has been inspected, especially down in the
           bottom of the reactor.  And all of the stub tubes
           going through there, not all of them have been
           inspected.
                       Is that something that would normally be
           required by the NRR or how would you deal with that?
                       MR. CARPENTER:  Dr. Ford, you play a great
           straight man.  Specifically for the lower plenum
           internals, the staff has requested that the BWRVIP
           revise their document to go in and do a baseline
           inspection of the internals so that you do know what
           you have in there during the current operating term. 
           And that way when you go into the license renewal, you
           will have a benchmark.  So you will be able to see
           that.
                       MEMBER FORD:  The reason why I understand
           that there has been a cracking incident at Nine Mile
           Point, I'm told that that was not inspected.  And,
           yet, you had a very large crack all the way around
           this particular weld.  And it hadn't been inspected at
           all.
                       So how can we guarantee or ensure that
           there is a minimal possibility of cleaning that in the
           future?  Would this program of inspecting the reactor,
           100 percent inspection of the reactor, before
           relicensing solve that particular problem; i.e.,
           starting your clean slate, you know what your devil
           is?
                       MR. BATEMAN:  This is Bill Bateman from
           the staff.  I don't think that we can tell you with
           any 100 percent certainty if the BWRVIP does generate
           an inspection, that they will be able to identify 100
           percent of the potential defects at the bottom of the
           core stub tube welds at our CRDM housings, et cetera. 
           I don't think we're going to tell you that.
                       I think what we can say is in the case of
           the Nine Mile one, they did identify the leak.  They
           did come in for a relief request to do a roll repair. 
           And we accepted that under the proviso that they would
           subsequently develop a permanent repair.
                       So that is typically how we would handle
           items that were missed in an inspection.  You know,
           they would manifest themselves in some kind of a leak
           later on.
                       MEMBER LEITCH:  The Hatch license renewal
           application depends upon certain BWRVIP reports that
           have yet to receive staff approval.  What is the logic
           of the resolution of that?  Do we expect that those
           reports will be approved prior to the Hatch
           application being approved or is Hatch committed to
           live by those VIPs once they are approved?  How did
           that work out?
                       MR. CARPENTER:  Well, let me address first
           the BWRVIP reports that the staff is reviewing.  And
           then I'll pass on what Hatch specifically is going to
           be doing.
                       There are two inspection and flaw
           evaluation guidelines that the staff has not yet
           approved which Hatch is referencing.  And those are
           specifically BWRVIP-74, which is the reactor pressure
           vessel guidelines, and BWRVIP-76, which is the core
           shroud guidelines.
                       Now, please note -74 is a revision to the
           BWRVIP-05 document, which the staff has approved
           previously and we did talk to the ACRS about.  That
           again is available of the licensees to perform
           inspections to that guidance.
                       The VIP-76, the core shroud, subsumes
           three other documents, which the staff has already
           looked at, VIP-01, -07, and -63.  -63 still has open
           items on it, and the BWRVIP still owes a response to
           us to that, which is the reason the -76 document is
           still under staff review.
                       Once we look at all of those, it is going
           to be a fairly -- I won't say minor effort, but it
           will be a fairly quick one to complete the reviews of
           those two documents.
                       So yes, I do expect that by the time the
           final SE for Hatch is issued, we will have completed
           the reviews of these two documents.
                       VICE CHAIRMAN BONACA:  From what you have
           said, what you are telling me is that you don't see
           the issues being reviewed are major issues of
           contention or problems?
                       MR. CARPENTER:  There are some open items
           still in the Hatch review.
                       VICE CHAIRMAN BONACA:  Yes.
                       MR. CARPENTER:  But those I'm not ready to
           address at this time.
                       VICE CHAIRMAN BONACA:  I'm not talking
           about the elements of those vessel and shroud VIPs
           that have not been approved yet.
                       MR. CARPENTER:  Hatch has --
                       VICE CHAIRMAN BONACA:  Not Hatch.  I'm
           talking about the VIPs.
                       MR. CARPENTER:  Oh, okay.  If you're
           talking about just those two reports, --
                       VICE CHAIRMAN BONACA:  Yes.
                       MR. CARPENTER:  -- no, I don't see that we
           are going to have a terrible amount of contention
           between the staff and the VIP to resolve the open
           items.
                       VICE CHAIRMAN BONACA:  That's the sense we
           got during the subcommittee meeting.
                       MR. CARPENTER:  Yes, yes.
                       VICE CHAIRMAN BONACA:  Thank you.
                       MR. CARPENTER:  And if there are no other
           questions on this, I will go to my final slide.
                       (Slide.)
                       MR. CARPENTER:  The staff is completing
           the review of the license renewal appendices.  And we
           have found that by referencing the aging management
           programs and completing the action items in the
           staff's SE, that there will be a reasonable assurance
           that applicants will adequately manage aging effects
           during the extended operating period and that the
           generic AMPs usage will significantly reduce staff
           review of license renewal applications in the future.
                       MEMBER WALLIS:  This reasonable assurance
           is somebody's judgment?
                       MR. CARPENTER:  Yes, sir.
                       MEMBER WALLIS:  This is a nice sort of
           expression here, but what do you really mean by
           "reasonable assurance"?
                       MR. GRIMES:  This is Chris Grimes.  I'll
           address that question because this transcends license
           renewal.
                       Reasonable assurance is the finding that
           we have associated with our libation under the Atomic
           Energy Act because we cannot provide the public with
           certainty of safety.  We developed a finding that was
           derived from the requirements in Part 50 that say that
           our obligation is to have reasonable certainty,
           reasonable assurance, that the plant is safe.  And the
           whole construct of the regulations is built around
           that.
                       Each individual piece, whether it's the
           vessel internals program or the adequacy of aging
           management associated with water chemistry or the
           completeness of the scoping, all of those are
           predicated on individual staff judgments that are
           founded in criteria that we usually promulgate in reg
           guides and the standard review plan.
                       MEMBER WALLIS:  So these are the same
           words you use when you have a new reactor.  So one
           could conclude that the licensed reactor is as safe as
           a new one.
                       MR. GRIMES:  I wouldn't go that far.  I
           would say that there are standards that were
           established on a different basis.  We use --
                       MEMBER WALLIS:  It's less safe than a new
           one.  So how much less safe is it?
                       MR. GRIMES:  We don't make any assertion
           that it's more or less safe.  We assert there is
           reasonable assurance that aging will be adequately
           managed for the purpose of issuing a renewed license. 
           But the original license we established reasonable
           assurance that this plant will operate within its
           design envelope.
                       MEMBER WALLIS:  I'm just saying if I try
           to explain that to an undergraduate, it doesn't mean
           anything.  It just means that the staff is satisfied. 
           I like that.  That's fine.  You're doing your job.
                       But it's not English.  It's not something
           that is the understandable to the public.  If you
           could say these are as safe as they were when they
           were new or something, some sort of measure of this
           assurance, it might be more helpful.
                       MR. GRIMES:  It's a very good point.  And
           so I don't want to make light of it.  The difficulty
           that we have is trying to establish in plain language
           what constitutes -- we're satisfied it's safe enough,
           recognizing that the degree, whether it's more safe or
           less safe, is something that evolves.  And that is why
           license renewal focuses not on some established line
           in a sand of safety but more the processes that are
           used to continually challenge the judgment over time.
                       And we will continue to try and work on
           articulating some simple explanation for the purpose
           of trying to explain to the public how we reach these
           decisions.
                       MEMBER WALLIS:  One problem is, of course,
           it's not risk-informed.  As you continue to measure
           the risk, you might be able to provide assurance that
           it's no riskier than it was.
                       MR. GRIMES:  I would like to be able to
           say that.  I hesitate primarily because of the process
           aspect and the state of the knowledge.  Several
           comments before got to the complexity of the
           inspection activity relative to a finding of whether
           or not we have identified everything that possibly
           could happen.  And we don't emphasize enough the
           living program aspect that learns as it goes.  And
           reliance on the quality assurance process is to change
           behavior when knowledge teaches you something
           different.
                       I think that we might say that we believe
           that it will be as safe or more safe, but then when
           we're challenged by a quantitative measure that we
           struggled to be able to explain what we thought was
           safety when it was originally licensed versus what we
           know of safety today versus what we speculate about
           safety in the future.
                       MR. CARPENTER:  If there are no further
           questions on the BWRVIP, I will turn this over to Mr.
           Baker.
                       VICE CHAIRMAN BONACA:  Thank you.  I
           appreciate it.  Any other questions for Mr. Carpenter?
                       (No response.)
                       VICE CHAIRMAN BONACA:  If none, then we
           can move on.  I believe we have now a presentation by
           Southern Company.  Mr. Baker?
                       (Slide.)
                       MR. BAKER:  Good morning.  My name is Ray
           Baker, and I am the Hatch project manager for the
           Hatch license renewal application.  I would also like
           to say that with me today is Charles Pearce, who is my
           direct supervisor, who is the manager for the license
           renewal group at Southern Nuclear.  I appreciate the
           opportunity to speak to you today on behalf of Plant
           Hatch.
                       In the subcommittee meeting last week, we
           were asked to specifically focus on two items for your
           attention today.  So today I am pleased to speak in
           some detail about the recent Hatch operating
           experience and to discuss our programs in terms of
           existing, enhanced, and new programs.
                       (Slide.)
                       MR. BAKER:  I would like to first provide
           a summary discussion of the Plant Hatch vessel
           internals operating experience.  And following that I
           will discuss the significant aging issues that Plant
           Hatch is currently addressing; that is, those items
           that were observed during the five years preceding the
           Hatch application's submittal.
                       This discussion addresses aging issues
           only for  those systems, components, and structures
           that are subject to aging management review under the
           license renewal rule.
                       First I would like to discuss our reactor
           vessel internal experiences.  And we have actually
           talked some about that already, but let me go back a
           bit further than the shroud to the core spray
           spargers.
                       On Unit 1, IGSCC was identified in one of
           the core spray spargers early in life.  That was
           repaired by a mechanical clamp.  No additional IGSCC
           or other degradation has been detected since then.  A
           full flow injection test was formed a few refueling
           outages ago with pre and post-injection inspections. 
           And no problems were noted.
                       Another experience relates to feedwater
           nozzles.  Unit 1 experience feedwater nozzle cracking
           in the late 1970s we replaced and the old slip-fit
           sparger that was the original design with the
           triple-sleeve, double-piston sparger.  And we modified
           operation of the feedwater flow controller at that
           time.  These changes appear to have eliminated the
           causes of cracking in that component.
                       The Unit 2 sparger was replaced during
           construction with a welded sparger.  And these fixes
           that Plant Hatch and other BWRs have implemented
           appear to have resulted in elimination of feedwater
           nozzle cracking.  This was identified in a Hatch
           submittal that led to a generic submittal for the
           current inspection program.  That is a revision to the
           original NUREG-0619 program that the BWRs use for
           feedwater nozzles.  This, in turn, is referenced in
           BWRVIP-74 as a corrective approach for extended
           operation.  And this is also referenced in the GALL.
                       As we noted earlier, both core shrouds
           have been preemptively repaired.  The repair hardware
           and the vertical welds are inspected per the BWRVIP
           criteria.
                       And the final internals item I would note
           is that the access hole covers have been replaced with
           covers attached by mechanical means, as opposed to
           welded.  And the materials used in the replacement
           covers are not considered to be IGSCC-susceptible.
                       MEMBER LEITCH:  You have removed the CRD
           return line from both Hatch units, the CRD return line
           with a nozzle on the vessel that was experiencing some
           cracking?
                       MR. BAKER:  I'm not familiar with that. 
           I'm sorry.  I don't know.
                       MEMBER LEITCH:  I think most of the BWRs
           had removed that, but my question was basically
           specifically related to Hatch.  So I would like to
           know the answer to that question when we get a chance.
                       MR. BAKER:  We'll follow up with that.
                       MEMBER LEITCH:  Thank you.
                       MR. BAKER:  Next I'll turn to the current
           aging issues for the in-scope system structures and
           components; that is, those components that are of
           particular interest for license renewal.  First I'll
           mention the control rod drive cap screws.  Across the
           BWR fleet, a number of control rod drive cap screws
           have exhibited indications of localized corrosion and
           stress corrosion cracking.
                       G.E. issued a SIL, SIL Number 483, to
           address this issue.  G.E. determined that inadequate
           design in conjunction with environmental conditions
           contributed to the failures.  G.E. developed redesign
           cap screws to mitigate that degradation.  The new cap
           screw design has a larger radius at the shank-to-head
           transition region to reduce stress concentrations and
           to fabricate from a higher-strength material.  It
           includes a new washer design that features slots to
           facilitate drainage of any collected fluid.
                       These indications that were observed were
           detected during VT-1 examinations.  And no bulking
           failures occurred.  Plant Hatch is currently in the
           process of upgrading all the control rod drive cap
           screws to the new G.E. design.
                       Next I'll discuss plant service water
           piping corrosion and fouling.  Instance of fouling and
           corrosion in plant service water pipelines have
           occurred and continue to occur at Plant Hatch.
                       Areas of significant degradation or
           leakage have been limited to smaller diameter piping
           sections less than or equal to four nps.  Specific
           areas of focus are low flow areas where fouling and
           localized corrosion may occur in creviced areas and in
           heat exchangers.  In many cases, the plant service
           water and RHR service water piping inspection program
           identified the degradation prior to leakage.  In all
           cases, no loss of system-intended function occurred.
                       The plant service water and RHR service
           water piping inspection program does aggressively seek
           out those areas where degradation may be occurring
           based on past experience.  So it is experience-rated. 
           The future inspections are based on the past
           experience.
                       We continue to selectively replace
           sections of carbon steel piping in this river water
           environment with 304, 304L, or AL-6XN stainless steels
           to greatly reduce the potential for recurrence.
                       The next area of operating experience I
           would like to speak to is flow-assisted or
           flow-accelerated corrosion; in particular, in the
           high-pressure coolant injection system and the reactor
           core cooling system.
                       We had initially excluded locations in
           HPCI and RCIC from the fact program based on their low
           usage.  These systems are expected to operate less
           than two percent of the time.  However, degradation
           and minor leakage of piping downstream of the HPCI and
           RCIC steam supply drain pipes has occurred in the past
           five years.  This is piping that is downstream of the
           condensers for these turbines.
                       The identified leaks were minor in nature. 
           And no loss of intended function occurred.  These
           indications resulted in the addition of fact program
           sample points in these two systems for the Plant Hatch
           application.
                       The next area I would like to speak to is
           related to the torus shell, the corrosion of the torus
           shell.  Plant Hatch protective coating activities in
           the torus have identified limited areas on the
           interior torus shell surfaces where some breakdown of
           the inorganic zinc coatings and subsequent localized
           corrosion have occurred.
                       The protective coatings program provides
           for regular monitoring of the corrosion rates in the
           torus and for repair of degraded coatings and
           surfaces.  And no loss of intended function has ever
           occurred with regard to this.
                       Another area of interest is general
           corrosion of carbon steel in components such as piping
           and supports in areas routinely exposed to weather,
           such as intake structure pit area, service water value
           pits, and the emergency diesel generator-building
           roof.  Plant Hatch has implemented actions to address
           those areas and is in the process of implementing
           additional actions to identify and prevent future
           degradation occurrences due to weather exposure.
                       Finally, I would like to mention the fire
           water storage tank.  Damage to the original installed
           vinyl coatings and subsequent corrosion of fire water
           tanks has occurred due to various causes.  The Plant
           Hatch fire protection program identifies this
           degradation during routine inspection of the tanks and
           provides for continued monitoring of those areas of
           degradation.  No loss of intended function or leakage
           of any kind has occurred due to this degradation.
                       MEMBER SIEBER:  What kind of water
           treatment do you use for fire water?
                       MR. BAKER:  This is deep well water.  So
           there is no water treatment applied to that.
                       MEMBER SIEBER:  Treatment.
                       MR. BAKER:  That's right.  It's raw water.
                       MEMBER SIEBER:  So it's pretty high in
           dissolved solids and minerals and --
                       MR. BAKER:  It's raw water.
                       MEMBER SIEBER:  Thank you.  Filter?
                       MR. BAKER:  That's deep well.  So it's a
           clean source, yes.
                       MEMBER WALLIS:  But deep wells have lots
           of dissolved materials in them.  Water from deep wells
           has all kinds of stuff in it.
                       MR. BAKER:  Yes, sir.  There are chemistry
           samples taken.  And there are limits applied to that
           that --
                       MEMBER SIEBER:  But there is basically no
           treatment?
                       MR. BAKER:  There's no treatment.  That's
           right.
                       VICE CHAIRMAN BONACA:  You mentioned in
           the beginning that you replaced the vessel access hole
           cover plates?
                       MR. BAKER:  Yes, that's correct.
                       VICE CHAIRMAN BONACA:  Okay.
                       MR. BAKER:  They were replaced with a
           mechanical design, as opposed to a welded-in design.
                       VICE CHAIRMAN BONACA:  So they have been
           experiencing degradation?
                       MR. BAKER:  We replaced them.  And I do
           not recall if that was a preemptive repair or whether
           there was an indication it was observed.
                       MEMBER LEITCH:  There were at least
           industry indications.
                       MR. BAKER:  Yes, there were industry
           indications.  I don't recall whether there was one at
           Hatch or not.
                       MEMBER POWERS:  Can I come back to this
           fire water tank that you have?
                       MR. BAKER:  Yes.
                       MEMBER POWERS:  You say that you have a
           degradation because the liner has been damaged in the
           past.  And it is corroding.  But no loss of function
           has occurred.  How long do we have to wait before it
           does have a loss of function?
                       MR. BAKER:  The entire purpose of the
           monitoring program is to prevent that from occurring. 
           So that is is --
                       MEMBER POWERS:  I guess I am a little
           perplexed.  Corrosion is only taking place when the
           guy is inspecting it?
                       MR. BAKER:  No, that's not --
                       MEMBER POWERS:  Well, what is it about the
           inspection program that prevents the tank from failing
           at 1:00 o'clock in the morning?
                       MR. BAKER:  First, the corrosion is not
           significant corrosion.  It is a surface corrosion that
           is well-behaved.  It's not something that is a rapidly
           occurring situation.
                       The monitoring is frequent enough to
           observe any progress of it.  It is in localized areas
           where the damage to the liner had occurred.  And there
           are acceptance criteria relative to how much corrosion
           would be allowed before further action would be
           required.
                       Routine maintenance activities are
           performed in the plant.  So this is not something that
           would just be left to corrode through to failure.
                       MEMBER SIEBER:  But I think there is
           another issue, which you may be referring to, Dr.
           Powers.  If the liner comes off, it's inorganic, and
           it usually comes off.  It's flakes.  Flakes go through
           the fire water system.  And if you have all of the
           sprinklers in the plant, the sprinkler heads have
           pretty small nozzles in them.  And so they're
           susceptible to plugging from this debris caused by the
           coating.
                       If I remember your application, you
           actually have two ranks.
                       MR. BAKER:  Two tanks.  Yes, that's right.
                       MEMBER SIEBER:  And they are 300,000 a
           piece?
                       MR. BAKER:  Yes.  Large tanks, yes.
                       MEMBER SIEBER:  So one of the tanks by
           itself is adequate to satisfy the code requirement for
           a fire water system.  Does that mean that you on
           occasion drain the other tank through the inspection
           system?
                       MR. BAKER:  That's correct.
                       MEMBER SIEBER:  So the tank is fully
           drained.  And, therefore, you can work on the coding
           and restore it as necessary?
                       MR. BAKER:  That's one of the mechanisms
           where some of the damage has occurred, in fact, is
           from scaffolding up inside a tank to nick the
           coatings.
                       I would also observe that outside the
           scope of license renewal, just as part of routine
           plant activities, there is a plan to drain and recoat
           those tanks with a newer state-of-the-art.
                       This coating was the state-of-the-art 25
           years ago or so.  When it was applied today, it's no
           longer state-of-the-art.  I believe that there will be
           a recoating of that in the future.
                       But it is from our perspective here in
           managing the aging, the focus would be to make sure
           that we have it captured by identifying it and then
           managing it.
                       MEMBER SIEBER:  A secondary issue is the
           fact that you have debris now in fire water.
                       MR. BAKER:  Yes.
                       MEMBER SIEBER:  And if it goes to
           sprinklers, you may have sprinklers that don't
           operate.
                       MR. BAKER:  That's right.  Thank you.
                       MEMBER LEITCH:  What's the material of the
           recirc piping at Hatch?  Is it still 304 stainless? 
           Most of the plants of the Hatch vintage had 304 and
           were --
                       MR. BAKER:  Unit 1.  Unit 1 has the
           original recirculation piping.  So it's the original
           304 or 304L.  I do not recall which.  Unit 2, the
           recirculation system piping was replaced.  If my
           memory serves me correctly, it's 316 nuclear grade of
           the place design so that it doesn't have the dead ends
           on it.
                       MEMBER LEITCH:  Yes.  Thank you.
                       MR. PEARCE:  Ray, my name is Charles
           Pearce.  I'm with Southern Nuclear.  I stepped out for
           a second.  I can give you your answer on your CRD
           return lines.  They were cut and capped.  We do an
           inspection of that weld periodically.  The lines now
           feed into the reactor water cleanup.  So, actually,
           the CRD line was rerouted to reactor water cleanup,
           which now feeds back into the feedwater, ultimately
           back into the vessel.
                       MEMBER LEITCH:  That's both units?
                       MR. PEARCE:  Both units.
                       MEMBER LEITCH:  Yes, thank you.
                       MR. BAKER:  Thanks.  I just could not
           recall whether we had done that specifically.
                       MEMBER LEITCH:  Thank you.
                       (Slide.)
                       MR. BAKER:  Now I would like to turn to
           the Plant Hatch license renewal programs.  This first
           viewgraph lists the existing programs that we had
           credited.  We characterize a program as existing, as
           opposed to enhanced or new, if only administrative or
           minor technical changes were made.
                       Typical administrative changes include
           revisions to identify the license renewal commitments
           in the program.  For example, you see several water
           chemistry programs in the left-hand column.  And so
           for each one of those, the applicable water chemistry
           programs would note commitments to the minimum
           standards that are contained in the appropriate EPRI
           BWRVIP water chemistry guidelines.  In addition,
           technical changes of a minor nature were made to the
           two programs that I have highlighted there in the
           blue.
                       MEMBER SIEBER:  Do you use hydrogen
           injection?
                       MR. BAKER:  Yes, we do.  It is a part of
           the regime that is provided for in the EPRI water
           chemistry guidelines.
                       MEMBER SIEBER:  Right.
                       MR. BAKER:  There are two modes you can do
           it with or without.  Certainly there is no desire to
           do it any period of time without.  Our normal mode is
           with hydrogen injection.
                       MEMBER SIEBER:  Have you used hydrogen
           injection?  For how many years?  The plant is too old.
                       MR. BAKER:  We were one of the first.
                       MEMBER SIEBER:  The plant is too old to
           have always used it.
                       MR. BAKER:  No.  We were one of the first.
                       MEMBER SIEBER:  All right.
                       MR. BAKER:  So that I don't recall the
           exact year.  For a number of years now.
                       MEMBER SIEBER:  Okay.
                       MR. BAKER:  And we also have aggressively
           pursued and implemented a noble metal addition.
                       MEMBER SIEBER:  All right.  Okay.
                       (Slide.)
                       MR. BAKER:  On this next viewgraph, I list
           our enhanced programs.  As you can see on this
           viewgraph, most of the programs were enhanced by
           broadening the scope of the program.  I would note
           that the categorization here is not absolute.  All of
           these programs, perhaps with the exception of
           structural monitoring program, also include monitor
           technical additions.
                       However, for the programs, protective
           coatings program and equipment piping and insulation
           and monitoring program, the technical changes that we
           made for license renewal were more extensive.
                       MEMBER SIEBER:  In the structural area, do
           you monitor building settlement?
                       MR. BAKER:  Building settlement has been
           observed user technical specification requirements
           from the beginning of operation.  And a consolidation
           settlement occurred prior to the completion of
           construction.  And we have observed no significant
           differential structure to soil or building
           differential settlements.
                       So it's not really a part of the
           structural monitoring program.
                       MEMBER SIEBER:  Do you have a requirement
           to survey the buildings with appropriate benchmarks
           that see over the years how much one changes relative
           to the other?
                       MR. BAKER:  We continue to monitor
           building settlement by the tech specs.
                       MEMBER SIEBER:  All right.  Thank you.
                       MR. BAKER:  Yes, sir.
                       (Slide.)
                       MR. BAKER:  Finally, this viewgraph
           depicts the new programs that are being accredited for
           license renewal.  The four programs on the left are
           the four new one-time inspections.  These inspections
           are to be performed during the last five years of the
           current term and serve as confirmatory inspections. 
           Therefore, areas where we believe no significant age
           degradation is occurring beyond that which is being
           managed by other programs, these inspections will be
           used to confirm those expectations.
                       The three highlight programs contain many
           elements that were contained in existing plant
           procedures and activities.  However, a number of those
           activities were not appropriate for crediting and
           license renewal.  So we have repackaged, revised, and
           rearranged those activities into the three programs
           shown here for primarily documentation purposes.
                       So these are the 30 programs and
           activities that will function during the renewal term
           to adequately manage aging effects for the end scope
           system structures and components at Plant Hatch.
                       That concludes my presentation.  Are there
           any questions?
                       MEMBER FORD:  What spurred the galvanic
           susceptibility inspection?  Was it a problem that you
           foresaw or was there a real problem that you reacted
           to?
                       MR. BAKER:  It's potential.  We have a
           number of dissimilar connections; for example,
           in-plant service water.  And we want to observe it. 
           That will be the leading indicator for us.  We believe
           it's raw water and dissimilar metal connections.  So
           we would want to make sure.
                       MEMBER FORD:  Okay.  So it is not in the
           raptor itself?
                       MR. BAKER:  No.  No, sir.
                       MEMBER SIEBER:  Another aspect of galvanic
           corrosion is the grounding mat.  What steps do you
           take to determine that it is still intact and capable
           of performing its function?
                       MR. BAKER:  The grounding was not an end
           scope component for license renewal in our plant, but
           I would need to find out what the routine maintenance
           of those is.
                       MEMBER SIEBER:  When those mats fail, when
           a plant gets 40 or 50 years old and those mats
           deteriorate, then you can take a Simpson volt meter --
                       MR. BAKER:  Yes.
                       MEMBER SIEBER:  -- and go from one pillar
           to another and get 10 or 15 volts.  Sometimes that
           changes trip settings on equipment, causes higher
           currents during restarts.  It can make a lot of
           problems.
                       MR. BAKER: I  know that we have paid
           attention to the grounding mat for the 2 units over
           the first 20 years, but I would have to specifically
           address that later as to what we currently are doing.
                       MEMBER SIEBER:  Thank you.
                       VICE CHAIRMAN BONACA:  Just for
           clarification, a passive component inspection, that's
           why you have an inaccessible component inspections;
           right?
                       MR. BAKER:  Yes, that is correct.  Yes,
           primarily the focus of that is when something is
           excavated or exposed that is normally not accessible,
           we will take advantage of that opportunity to examine
           it.
                       VICE CHAIRMAN BONACA:  Yes.
                       MEMBER LEITCH:  I'm concerned about the
           suction to the river water pumps.  I'm not sure what
           you call them, but I assume you have river water
           cooling a heat exchanger which, in turn, cools the RHR
           system.
                       MR. BAKER:  Yes.  It's a part of RHR
           system.  It's RHR service water.
                       MEMBER LEITCH:  RHR service water.  And
           they take suction.  Those pumps take suction from the
           river?
                       MR. BAKER:  Yes, that's correct.
                       MEMBER LEITCH:  Now, I'm not familiar with
           the configuration of Hatch.  I was kind of concerned
           about this over years silting building up and then
           some unusual tide condition occurring, high winds or
           something, that might cause those pumps to lose
           suction.
                       MR. BAKER:  We have a couple of activities
           that address that.  The Altamaha River is basically a
           floodplain.  It's a meandering river historically. 
           The area immediately adjacent to the plant has been
           straight for a number of years.  It is a nice straight
           section of the river.
                       We have permits for dredging.  And we do
           dredge in front of the intake structure approximately
           every 18 months.  There is also a periodic inspection
           by divers that we send down to make sure that the
           actual intake structure pit itself as clean.  So those
           activities occur routinely.
                       MEMBER LEITCH:  Okay.  Thank you.
                       MR. BAKER:  Thank you.
                       VICE CHAIRMAN BONACA:  Any other questions
           for Mr. Baker?
                       (No response.)
                       VICE CHAIRMAN BONACA:  If not, thank you
           for your presentation.  And now we want to hear from
           the staff, somebody with the NRR.  Mr. Burton?
                       (Slide.)
                       MR. BURTON:  Good morning.  My name is
           William Burton.  I generally go by Butch.  I am the
           lead project manager for the staff review of the Hatch
           license renewal application.
                       I want to make my apologies up front.  I
           like to make my mistakes early, obviously full
           Committee, as opposed to the subcommittee meeting.
                       (Slide.)
                       MR. BURTON:  The first thing I want to do
           is give a little overview of the Hatch application
           submittal.  The application was submitted by letter
           dated February 29th of last year.  As you all know, it
           is a two-unit boiling water reactor.  It is located
           about 11 miles north of Baxley, Georgia and
           approximately 70 miles from Savannah, Georgia, west of
           Savannah.
                       Right now Unit 1, its current license is
           due to expire in August of 2014 and asking for a
           20-year extension to 2034.  Similar, Unit 2, current
           license is due to expire in June of 2018, again a
           20-year extension to 2038.
                       I did want to put up briefly -- this is
           not in your package -- just where we are in terms of
           the review.
                       (Slide.)
                       MR. BURTON:  We just completed on March
           16th the AMR inspection.  We took a team of folks from
           both Region 2 and from headquarters to go down and see
           how some of the commitments that are currently
           outlined in the aging management programs are actually
           being implemented on site.
                       And compared to some of the previous
           applications, Southern Nuclear is a lot further along
           at this point in terms of actually implementing those
           commitments from the aging management programs into
           their on-site procedures.
                       MEMBER WALLIS:  I would think this is very
           important.  I mean, I read the SCR draft.  It seems to
           be this assurance that they have these programs.  I
           don't have the same assurance that they are really
           good programs, that they are good enough programs. 
           Just the fact that they have a program doesn't mean to
           say that it is good enough.
                       MR. GRIMES:  This is Chris Grimes.  I
           would like to emphasize that the scope of these
           inspections is intended to verify that the procedures
           are in place or that the attributes of the program
           relative to scope, methods, criteria, and so forth are
           there.
                       Another aspect of the inspection includes
           the inspectors looking at the effectiveness of the
           programs relative to operating experience.  Now,
           clearly if they are new programs, you are correct. 
           There's not much we can ask the inspector to do about
           trying to assess the effectiveness of the program.
                       For some of the longstanding original
           inspection and maintenance activities, we do gather
           insights in terms of the effectiveness of the programs
           in order to try and bolster the conclusions in the
           safety evaluation about the effectiveness of the
           programs.  So it is an aspect of the reasonable
           assurance finding we try to develop.
                       VICE CHAIRMAN BONACA:  And I understand
           also that, although it is not referenced yet because
           it is not finally approved, the GALL information has
           been extensively used as a reference for evaluation.
                       MR. GRIMES:  Yes, sir, that's correct. 
           The staff had the benefit not only of contributing to
           GALL in parallel with this review but also having it
           available for the users to use as a reference
           material, even though we don't explicitly cite it in
           the safety evaluation.
                       VICE CHAIRMAN BONACA:  Thank you.
                       MEMBER POWERS:  Before we move on, could
           I ask a question about this inspection team that you
           send down there?  Did that include people who looked
           at the fire protection system?
                       MR. BURTON:  Yes.  In fact, I was the team
           member who actually did look into fire protection. 
           One of the questions that came up earlier had to do
           with the fire water tanks.  I do want to say that as
           part of that inspection, I did go down and look at
           some of the videotapes that they took at the inside of
           the tanks.  What they did was they did an inspection
           of the tanks back in '91 and observed that some of the
           coating was beginning to break down into grade and
           looked at some of the condition reports that followed
           from that.
                       And then they did it again in '99 and
           actually observed those tapes.  There was some -- you
           could see the decomposition and some of the debris in
           the bottom.  But, as Mr. Baker had said, they are
           actually in the process of -- they are going to be
           recoating the tanks in the near future.  And those
           were the original coatings.
                       MEMBER POWERS:  Did they have to re-flush? 
           Did the fire water dispersal lines
                       MR. BURTON:  I believe that was probably
           part.  I know when they emptied the tanks, I believe
           that was part of the entire thing.  Procedurally, they
           do that.
                       One of the things that the Committee is
           interested in is comparing applications.  Obviously
           because this is the first BWR, there is particular
           interest in whether there are in particular any new or
           unique aging effects that BWRs are subject to versus
           the Ps.  The staff did pay particular attention to
           that.
                       Now Southern Nuclear took a commodity
           approach in that rather than just looking system by
           system, they actually identified what materials are we
           looking at, and in what environments are those
           materials operating, commodity groups.
                       As such, what we found was that there are
           no unique materials.  The materials are not being
           operated in any kind of unique environment.  As a
           result, we did not see any new or unique aging
           effects.  In fact, in the application there is an
           Appendix C-1 that really speaks to aging effects and
           some of the consequences of that.  But we did not find
           anything new.  So in that respect, we really don't
           expect the BWRs -- we don't expect to see anything
           unusual compared to any of the PWRs.
                       MR. GRIMES:  This is Chris Grimes.  I want
           to emphasize that we did see uniqueness relative from
           application to application.  But when Butch says we
           didn't find any new aging effects, remember that
           that's drawn on the nuclear plant aging research
           program that began over a decade ago.  I would have
           hoped that we would not have found any new aging
           effects in this application.  So that was reassuring.
                       But we did learn some process lessons in
           terms of the way that the information was packaged. 
           Specifically, with respect to commodity groups.
                       MR. BURTON:  And actually to follow on on
           that, to talk about some of the other differences that
           you may see compared to some of the previous
           applications.  As Chris said, it really was the
           uniquenesses were really a matter of process and
           packaging I guess you would say.
                       As you now know, it's the first to use the
           BWRVIP reports, which we have already discussed.  It
           was the first to use a functional approach versus a
           system approach in the scoping process.
                       Now what do I mean by that?  What Southern
           Nuclear did was they looked at every single system in
           the plant, identified all of its functions, and then
           bounced the functions off of the scoping criteria.  So
           what you see is not a direct correlation between the
           system and whether it's in scope or not.  What you see
           is the identification of the in-scope function, which
           was I think a little bit different approach.
                       Then finally, Southern Nuclear as you all
           know, there are 10 program attributes that are
           assigned as criteria to evaluate the aging management
           programs.  Southern Nuclear took a unique approach in
           that they took the 10 program attributes and applied
           them to a demonstration of adequate management.
                       Probably the best way to do it is to show
           you what I mean by that.
                       CHAIRMAN APOSTOLAKIS:  This "functional
           versus system approach" what does that mean?  Even if
           you look at the system, you look at its function,
           right?
                       MR. BURTON:  Yes.
                       CHAIRMAN APOSTOLAKIS:  So what's the
           difference?
                       MR. BURTON:  The difference is that
           normally you would look at a system and you would say
           does the system directly meet what turns out to be the
           eight or nine questions that constitute the scoping
           criteria.  Probably the best way to do it is to give
           you an example.
                       Main steam.  Main steam, most of us think
           that would obviously be in scope.  But what actually
           happened was they looked at main steam and looked at
           each of its functions, and which of those functions
           would actually meet the scoping criteria.  As it
           turned out, for main steam the in-scope function was
           contained in isolation.
                       So that is actually what brought the
           system into scope, but it was actually that particular
           function.  In fact, maybe this wasn't the best
           example, because what we also found was that as they
           looked across systems, you found certain functions
           that were common across a number of systems.  What
           they chose to do was to actually pull those functions
           out and group them separately.  Containment isolation
           was one of them.  Because it cut across so many
           different systems, they have a specific category for
           the containment isolation group C61.
                       Another one was reactor coolant pressure
           boundary.  That function cut across a number of
           systems.  It was actually pulled out and categorized
           separately.  So it was really a function-based
           assessment.
                       CHAIRMAN APOSTOLAKIS:  That's not very
           clear, but at least we are making progress.
                       VICE CHAIRMAN BONACA:  We commented quite
           a bit during the subcommittee meeting that that
           created a lot of difficulty for reviewers,
           particularly when the people on the subcommittee had
           to review it because you have a system that you
           presume just because there will be scope, then you are
           looking at it, you don't find a description of the
           system up front.  Then coming through this, you just
           don't find it.  You have to search through these
           functions, for example, that it perform a containment
           isolation, then you find an element of that system. 
           So you say well wait a minute now, are the other
           pieces of that system out of scope?  A lot of the
           questions in the NRC had to do with that.  The answer
           is no, they are in scope.  They are somewhere else.
                       So it made it very confusing, I must say. 
           But I think that ultimately, you learn to do it.
                       CHAIRMAN APOSTOLAKIS:  This is a good step
           forward.  If you keep it up, eventually you will
           rediscover PRA.
                       MR. BURTON:  Okay.  Let's go on.
                       MEMBER POWERS:  We're busy trying to
           decide whether that's a good rediscovery or a bad
           rediscovery.
                       MEMBER SHACK:  If you didn't put in core
           damage frequency, George, it wouldn't exist.
                       MR. BURTON:  Oh boy.  What Dr. Bonaca just
           spoke about, we spoke about that extensively at the
           subcommittee meeting.  We reached a consensus that
           these issues are what we call navigational issues,
           being able to see your way through the application. 
           There were several challenges in that respect.
                       This is an example, this is in the
           application, in one of the appendices, called the
           Aging Management Program Assessment.  What Southern
           Nuclear did was they looked at each commodity group
           and each aging effect for that commodity group.  What
           they did was they took the ten attributes, as you see
           over here on the left, and actually showed where the
           program coverage was for that, which was actually very
           good.
                       It wasn't what we normally see in terms of
           how the 10 program attributes are applied.  I should
           say that the navigational -- the RAIs that came out
           having to do with navigational questions, and we had
           a number of RAIs because we didn't see how the ten
           attributes were being applied directly to the
           programs.  We had a number of RAIs that came out as a
           result of that.  By my estimate, probably a third of
           the RAIs fell into those groups.
                       We issued the safety evaluation report. 
           We had 18 open items.  Obviously we have had ongoing
           dialogue.  At this point, we have four that are under
           appeal.  I need to explain what that is.
                       With the license renewal process, we allow
           for situations where if we don't seem to be making
           progress at the working level, we have a series of
           appeal meetings that start at the branch chief level
           and move ahead, to try and resolve those issues.
                       Right now, of the 18 open items, we have
           four that are under appeal.  In fact, one of my
           takeaways from the subcommittee meeting was to give
           you the status because when we had the subcommittee
           meeting, the following day we were going to have the
           first of the appeal meetings.  So the next slide, I'll
           be speaking on that.
                       So we have four under appeal now.  That's
           not to say that that's the be all and end all.  As we
           continue our dialogue at the working level, if we find
           additional items that need to go into appeal, we'll
           start to do that.
                       Of the 18, five are now in a confirmatory
           status.  What that means is that the staff and
           Southern Nuclear, we have reached agreement but we
           haven't dotted all the Is, crossed all the Ts.  It's
           not official yet.  So until then, it is actually
           confirmatory.
                       CHAIRMAN APOSTOLAKIS:  Who is the ultimate
           authority regarding appeals, the one that says this is
           it?
                       MR. BURTON:  This is it?  Well, I'll let
           Chris speak to that.
                       CHAIRMAN APOSTOLAKIS:  Chris?
                       MR. GRIMES:  I don't think that highly of
           myself.  The ultimate authority would be the
           Commission.  If an individual applicant isn't
           satisfied with the staff position after it's addressed
           at the branch level, we go to the division level. 
           Then we go to the office level.  Ultimately, the issue
           could go up through the EDO to the Commission if it
           were significant enough.
                       Most of the issues of industry concern
           that got to that kind of strategic level, I think were
           revealed in the credit for existing programs issue
           that went to the Commission and instruction the
           Commission gave us in terms of how to offer the
           industry an opportunity to take credit for existing
           programs, which is the way that it was phrased.
                       So we'll discuss that a little bit further
           in the next meeting, where we talk about the improved
           renewal guidance.
                       MR. BURTON:  I did want to -- I didn't
           write down all the items that are now confirmatory,
           but I did want to give you an idea.
                       One of the open items that we had was we
           asked for a one-time inspection for the fuel oil tank
           bottoms.  That was on the table.  We since learned
           that they had actually already done such an
           inspection, and have actually given us the result.
                       They had actually dug up and inspected one
           of the four big EDG fuel oil tanks, and found that
           there was very little reduction in thickness.  That
           argument also carried over into their two smaller fuel
           oil tanks for their diesel fire pumps.
                       So we got that response fairly quickly
           because they had already done it.  So that's basically
           closed, but again, we haven't done all the official
           paperwork.
                       Another one is the complex assembly issue. 
           If you remember, that issue came up with Oconee.  That
           was actually resolved.  We developed an approach to
           resolving that.  Initially it was not clear that
           Southern Nuclear was taking the same approach.  But
           since then, we have clarified that they are going to
           be doing the assessment similar to Oconee.
                       MEMBER SIEBER:  You are talking about
           skid-mounted equipment?
                       MR. BURTON:  Yes.
                       MEMBER SIEBER:  That means you treat
           individually each component or sub-component on the
           skid?
                       MR. BURTON:  Yes.  The complex assembly
           issue, as it arose at Oconee, had to do with the
           diesel generators, which are active components.  But
           in addition to the diesel, you had skid-mounted
           auxiliaries.  Should they be considered part of the
           active assembly and therefore not subject to an AMR or
           not?
                       MEMBER SIEBER:  Right.  That was resolved,
           that they are now treated separately.  For example,
           transformers and like components, piping?
                       MR. BURTON:  That's right.  We found from
           Oconee that it was really not appropriate to lump the
           skid-mounted auxiliaries and treat them as if they
           were all active, to actually do an assessment
           separately.
                       Again, initially it was not clear to the
           staff whether Southern Nuclear at Hatch was taking the
           same approach, but we have since clarified that they
           will be taking that approach.
                       MEMBER SIEBER:  One thing that I found in
           a number of plants is that often licensees do not
           identify with mark numbers valves, heat exchangers,
           and other components in the skid package.  For
           example, the generator hydrogen seal oil system might
           have 50 valves in it.  It's mounted on a skid, on a
           bed plate.  It has one mark number.
                       Is that the condition at Hatch?  Does
           anybody know?  Or do you have individual mark numbers
           for all the components or sub-components on the skid?
                       MR. BAKER:  Certainly for the two items
           that are the subject of the open item, which are the
           diesel generator and the hydrogen recombiner, we
           specifically know all the sub-parts of those skid-
           mounted assemblies.
                       MEMBER SIEBER:  But other ones, you don't
           know?
                       MR. BAKER:  I'm not aware of anything that
           would be in the license renewal envelope that would
           meet that.  What you say is probably true for parts of 
           the plant that are not in the scope of license --
                       MEMBER SIEBER:  Seal oil, some chillers,
           for example?
                       MR. BAKER:  Yes.
                       MEMBER SIEBER:  The chillers often are
           skid-mounted thing.  A lot of times, they are safety
           related.
                       MR. BURTON:  A couple of things that I did
           want to point out.  One had to do, we touched on it
           earlier, had to do with inaccessible components,
           buried and the like.  One of the things that we
           emphasized when we went down on the AMR inspection was
           to understand exactly how these things are identified
           and taken care of procedurally.  In fact, as a result
           of the inspection, what we have is -- well, they have
           an excavation procedure.  They have in the proposed
           draft form, a mark-up of that procedure which actually
           says when you are either burying up components or if
           you are digging around a structure, they actually have
           the hooks in the procedure to actually take you to the
           appropriate aging management programs to do the
           inspection.
                       Another thing that I wanted to talk about
           scoping issue, in the past the Committee has had
           questions about design basis events, and what is the
           population of events that you are looking at to
           determine what's in scope.
                       Because of the functional approach to the
           scoping, as I mentioned before, the staff is not real
           clear on exactly how they identified the design-basis
           events.  As it turned out, at the time that they
           submitted the application, they had a draft version of
           what they called the nuclear safety operational
           analysis, which has since been incorporated into the
           FSAR.
                       This analysis was a comprehensive look at
           the design-basis events.  Even though it was in draft
           form and they didn't take specific credit for it in
           the application, it was a part of their general review
           in their scoping process.
                       Since then, the rule requires an annual
           update to the application based on any changes to the
           CLB.  So we actually caught the NSOA as part of the
           annual update.  As a result of that, they actually
           brought in -- the only thing that was brought into
           scope that wasn't there previously was the rod block
           monitor.  So that was taken care of also.
                       VICE CHAIRMAN BONACA:  But you didn't go
           through every indication that all the components for
           the scoping match the one in the design-basis, or did
           you?
                       MR. BURTON:  Well, okay.  If I speak to
           your question, maybe this will address it.  One of the
           things that is important to understand is exactly how
           the staff approaches its review.
                       The application identifies things that the
           applicant has identified as being in scope and subject
           to an AMR.  Obviously we look at that.  But a large
           part of our review is to look at the things that the
           applicant decided was not in scope and was not subject
           to an AMR to see if there's anything that was in that
           population that actually met the scoping or the
           screening criteria and to bring it in.
                       Was that getting at your question?
                       VICE CHAIRMAN BONACA:  I think so, because
           I know also that you took three systems.
                       MR. BURTON:  Yes.
                       VICE CHAIRMAN BONACA:  And for those, you
           went through what I would call a painstaking
           verification that everything which had to be in it
           would be.  So that audit I guess provides the level of
           comfort.
                       MR. BURTON:  That is correct.
                       We have had two inspections at Southern
           Nuclear so far.  The review process allows for three. 
           We have done two.  I have spoken already about the AMR
           inspection, which was the second inspection.  The
           first inspection, which we did back in September, was
           the scoping inspection.  Again, because of some of the
           navigational issues that the reviewers were having and
           again, the functional approach to the scoping, when we
           went down to the scoping inspection, we actually took
           several systems and actually walked through step by
           step from beginning to end how you identified their
           functions, how you bounced those against the scoping
           criteria, how you evaluated the evaluation boundaries,
           and how you did the screening.  So we walked through
           several systems step by step.
                       What we found was that talking with their
           engineers, we were comfortable that they were doing
           things properly, but we found procedurally it wasn't
           real clear.  It didn't take them through step by step
           exactly what to do.  They were doing it, but the
           procedure didn't really match.
                       So one of Southern Nuclear's takeaway from
           our scoping inspection was to update the procedure to
           make it less goal-oriented, which is how it was
           originally, and make it more prescriptive.  In fact,
           we went down later to confirm that they had made those
           changes.  In fact, they had.
                       MR. GRIMES:  This is Chris Grimes.  I
           would like to clarify.  There are two aspects to the
           staff's evaluation basis for scoping.  There's the
           inspection that looks at how the scope verifies that
           the scope of equipment matches our understanding, our
           safety evaluation basis.  But we separately conduct a
           methodology audit.  I think it was during the audit
           that we identified the procedural weaknesses.
                       But the audit looks at the process and
           verifies that there is a completeness aspect to the
           process that the applicant uses so that we don't have
           to rely simply on our sample of results in order to
           develop a conclusion about the completeness of the
           scope.
                       MEMBER WALLIS:  I asked you about scope by
           way of an example, take say spent fuel pumps, look at
           spent fuel pull section of the Hatch application.  You
           find a lot of stuff about boring things like anchors
           and bolts and structural steel and so on.  What about
           the function of the pool?  The pool shouldn't leak. 
           What is there that assures it shouldn't leak?  It has
           a liner, I believe.  It's not in scope.  It's not in
           scope presumably because something else takes care of
           it.  Is that what I conclude from this?
                       Only the boring things are in scope.  The
           things that really matter don't seem to be there. 
           Why?
                       MR. GRIMES:  This is Chris Grimes.  I
           would first like to start off by observing that Dr.
           Wallis is obviously not a civil engineer.
                       (Laughter.)
                       It wasn't boring to --
                       MEMBER WALLIS:  I'm one of the most civil
           members of the --
                       (Laughter.)
                       I think that is something that when you
           first look at it, strikes one.  That doesn't mean it's
           not really a question of civil versus mechanical or
           something.  The things that are picked out to be in
           scope are the things which one would sort of least
           expect to fail, so something must be happening to take
           care of all the other things.
                       What is that something?
                       MR. GRIMES:  Mr. Baker should address the
           Hatch specific.  Then I'd like to address the generic
           aspect.
                       MR. BAKER:  I think what you are seeing
           here is what Butch was referring to as one of those
           navigational things.  In reality, the spent fuel pool
           liners are in scope.
                       MEMBER WALLIS:  They are?
                       MR. BAKER:  Yes, sir.
                       MEMBER WALLIS:  They don't appear in the
           spent fuel section as being in scope.  You have to
           find them somewhere else?
                       MR. BAKER:  I'll open up the book and show
           it to you during a break.  But it is in scope, yes. 
           We consider that important as well.
                       MR. GRIMES:  And from a generic point of
           view, we learned a lesson on Calvert Cliffs and Oconee
           on articulating what is in scope for spent fuel pools. 
           You may recall that Chris Gratton spent some time
           trying to explain why the cooling function is not
           considered a design-basis function for the purpose of
           license renewal because the staff relies on the
           capability for the pool to be able to maintain its
           geometry, even with the loss of cooling.  So the
           cooling function was explored most extensively during
           the first two applications.  Then we have refined the
           guidance to look for those things that are really
           important to the boundary integrity of the pool and
           the ability to maintain the coolable geometry.
                       So I think that when we learn some more
           packaging techniques and some more plain language
           lessons, I think that you will find that all of the
           really interesting stuff is buried within those civil
           structural kinds of details.
                       VICE CHAIRMAN BONACA:  And also I would
           like to add in addition to that's true that your
           cooling system was not in scope, but your make-up --
           you had a make-up capability which was a safety grade
           and was in scope that would allow you to make up
           inventory in case you were losing the cooling
           capability.
                       So the basic functions are assured.  That
           was the whole --
                       MEMBER WALLIS:  Maybe it's a problem with
           the way the thing is organized.  The function of
           cooling is somewhere in the report.  I look up fuel
           pools in the part that was assigned to me to look at,
           it's all about acapults.  But somewhere else, someone
           else is reviewing the cooling, which makes it
           difficult to get the perspective on how you handle the
           fuel pool.
                       MR. BURTON:  Now you see some of the
           challenges the staff had.  This all falls under the
           category that I spoke about before regarding
           navigational problems.  So yes, if there is anything
           specific, we can probably get you to the right place.
                       As I mentioned, there were four items that
           are currently on the table as subject to appeal.  We
           had the subcommittee meeting on March 28th.  We had
           the appeal meeting the next day on the 29th.  So one
           of the takeaways from the subcommittee meeting was to
           report back and see exactly where we stood as a result
           of that meeting.
                       So what I have done is I have taken the
           four issues and tried to put them in a simple question
           format.  The first one was should the draw-down test
           that's required by the technical specifications be
           credited as an aging management program to confirm
           maintenance of reactor building in leakage limits.
                       One of the things that the staff was
           concerned about during the period of extended
           operation, how will Southern Nuclear continue to
           maintain their controlled in-leakage for the reactor
           building.  What was on the table was that all of the
           inputs to controlled in-leakage are going to be
           managed through inspections and corrective actions,
           the penetrations, all of the structural elements.
                       Our question was well, that is somewhat of
           an indirect measure of whether it's actually going to
           do that.  I guess one example of that, and I am going
           to go back to my ABWR days, is that one of the items
           that they looked at concerning turbine building
           flooding was they monitored pressures for service
           water, surf water, things like that, and that a drop
           in pressure would be indicative of a large leak and
           subsequently flooding in the turbine building.
                       One of the questions that came up is
           suppose you had leakage that wasn't quite enough to
           reduce the pressure to the point where you got the low
           pressure actuation.  You get all this flooding in
           there, but there's nothing instrumentally to tell you
           that.
                       So we said okay, well what's the direct
           measure of flooding, level.  Okay.  That was one of
           the things that we came up with.
                       Similarly here, you can look at all of the
           inputs to in-leakage for the reactor building, but it
           is somewhat indirect.  The way you can tell most
           directly is to measure the draw-down, for which we do
           have a tech spec.
                       Southern Nuclear was saying that is a very
           gross test.  In order for you to see anything as part
           of that drawdown test, you would have to have
           substantial degradation in the penetrations and things
           like that, which we would catch by our existing aging
           management programs far before they would degrade to
           that degree.
                       So as a result of our discussions, we felt
           like probably the best thing is to have a combination
           of the two.  To have the inspections and the ongoing
           corrective actions when you saw a problem, along with
           the drawdown is a confirmatory sort of test.
                       So that is where we are with this right
           now.  Still dialogue going on, but --
                       VICE CHAIRMAN BONACA:  Confirmatory still
           would put it into the aging management program as part
           of it?
                       MR. BURTON:  Yes.
                       VICE CHAIRMAN BONACA:  Okay.
                       MR. BURTON:  Number two --
                       MR. GRIMES:  Actually, Butch, in the
           interest of time, make sure that we get through the
           whole presentation and try and stay on schedule.  I
           think it would be fair to categorize all four of these
           things as ongoing dialogue, haven't made any
           decisions.  We need to make sure that we clearly
           understand what the true value of the drawdown test
           is.  We need to clearly understand the current
           licensing basis treatment and categorization and
           bookkeeping associated with category II piping with
           respect to the seismic II/I issue.
                       VICE CHAIRMAN BONACA:  We would like to
           hear something about that issue however, because you
           know, a face value seems as if those components should
           be in scope.  But I understand that there are issues
           to do that maybe too much of the piping was placed,
           was evaluated as a II/I and shouldn't be.  So there
           are other things we don't understand.
                       MR. GRIMES:  And that is the point that I
           want to make.  At this point, on all four of these
           issues, I know I do not have enough information to
           make a decision.  I think the applicant and the staff
           both went away with an understanding that we need to
           talk some more because we do not know the whole story. 
           On the seismic II/I, it was clear from the nature of
           over an hour's dialogue that we still do not have a
           very clear understanding of how the applicant treated
           the design capability for postulated breaks in
           category II piping.  We need to understand that before
           we can move forward on that issue.
                       VICE CHAIRMAN BONACA:  Wouldn't that be a
           significant expectation of the guidelines you have
           established if you had to say that now there are
           seismic II/I components that do not fall into -- I
           mean there is a --
                       MR. GRIMES:  Yes.  I would say there's
           fundamentally a violation of the current licensing
           basis if we don't capture the capabilities.  We have
           a semantic problem because the piping is not in scope. 
           The criterion in the license renewal rule says the
           failure of components whose -- the postulated failures
           of components whose failure could affect safety-
           related piping or safety related functions.
                       If you have included the pipe whipper
           strength in scope, do you now have to postulate that
           the piping fails in a different way?  Do you have to
           inspect the piping to make sure that the pipe whipper
           strength prevents the failure that it's going to
           impact the safety function?
                       The pipe wasn't in scope.  The restraint
           was in scope.  So this gets back to the problem that
           we have communicating with this commodities approach
           because you looked for a system.  Your paradigm was
           built on the way that we normally do system reviews. 
           But their communication package is different.  It
           looks at functions.  This gets back to Dr.
           Apostolakis' point earlier.  That is, we have backed
           into a new way of categorizing that is more in line
           with the way that PRA analysts look at things.
                       But in terms of our ability to clearly
           articulate how aging will be managed so that the
           current licensing basis will be maintained for the
           period of extended operation, what I observed on the
           29th was two groups of people talking past each other,
           because they were talking from a different paradigm of
           how they packaged their scope.
                       VICE CHAIRMAN BONACA:  What about the
           housing?  The housing, will it be covered by your
           complex assembly definition, which has been in this
           position previously.
                       I mean all I'm trying to say is that I
           think that maybe there are ways to, for example, for
           the seismic over one, one could conclude that elements
           have to be in scope, and then accept a modified or a
           known existing accident management -- I mean aging
           management commitment because of special
           circumstances.  Are you exploring the possibility?  I
           mean that would be one way to maintain the commitment
           to II/I, but the recognizing as you always do that in
           some cases, you don't need the specific problem.
                       MR. GRIMES:  That's why I jumped in and
           tried to cut short the debate over the issues because
           I know that on all four of these things we only have
           half a story, and that we clearly need to have more
           dialogue with the applicant in order to achieve a
           shared understanding about whether or not we disagree
           about anything.
                       On the housings, I believe that we made
           our point more clearly to the applicant in terms of
           what our expectation is.  We discovered that housings
           to some are not housings to all, and that they now
           better understand that we are not violating the
           Commission's tenets of going into piece parts.  We
           need to develop some guidance beyond what we are going
           to tell you at the next presentation about improved
           renewal guidance.
                       We need to develop some improved guidance
           on making this distinction between complex assemblies
           that are on skids and separating out active and
           passive functions of components, which is a piece
           parts issue.  They sometimes get described using the
           same terminology.
                       VICE CHAIRMAN BONACA:  I asked for this
           presentation if you remember last week, because I
           thought that you expressed an interest in having our
           position on these four items.  Are you still
           interested in having our position on the fourth or
           not?
                       MR. GRIMES:  After the meeting that we had
           on Thursday, I think that I would say not, because I
           think that we owe you an explanation about what it was
           that we decided that we wanted to argue about.  We may
           be in a position soon when we come back to the
           subcommittee with the explanation of the resolutions,
           we may want you to express a view about whether or not
           the pipe-break criteria are time-limited or not,
           because of the explanation that the applicant gave us
           about how they were used as a screening tool for
           design, and that they do not actually -- they are not
           limited in some way.
                       But even on that issue, I think that we
           need some more dialogue in order to understand what
           the regulation envisioned as a time-limited aging
           analysis.  So at this point, I don't think that you
           have enough information to give us an informed opinion
           on these issues, because I know I don't.
                       VICE CHAIRMAN BONACA:  Okay.  Thank you.
                       MR. BURTON:  That's all I have.
                       MEMBER WALLIS:  I have a question for you
           now.  I thought you were going to talk about the SER. 
           So I want to ask you a big picture question.  This
           slide with the four appeal items sort of supports what
           I want to say.
                       I read the SER.  A lot of it is simply
           repeating what's in the application.  Then there's the
           staff evaluation.  The staff evaluation seems to
           consist of saying something is within scope.  The
           applicant has identified this component subject to an
           AMR.  There's some AMP here and this other thing is a
           TLAA, which is what your appeal issues are all about.
                       Okay.  There's a procedural thing, it
           seems to me.  You are now saying we are going to
           consider this, this, this, and this.
                       The big question is is the AMR good
           enough?  Are the components that are subject to review
           really going to last another 20 years?  All these
           questions don't seem to be addressed because there's
           all this stuff about procedure.  Is this in scope or
           out of scope?  Is it a TLAA?  Is this AMR?  You know,
           that's okay, that's fine.  But that seems to me is the
           preliminary to now evaluating the quality of all these
           things for the purpose of license renewal.
                       MR. BURTON:  Do you want to --
                       MR. GRIMES:  I'll take it.  It's in my job
           description.  The staff did exactly what we asked of
           them in terms of prepare a safety evaluation that
           addresses the requirements of the rule, because the
           Commissions said that the rule is the predicate upon
           which they develop a basis for granting a renewed
           license.
                       I would say that we looked very carefully
           during the concurrence review to make sure that for
           scoping, it specifically says there is reasonable
           assurance that everything that needs to be in scope is
           in scope and it's based on an explanation about what
           was looked at.
                       There are statements in the safety
           evaluation that precede the we have reasonable
           assurance that aging will be adequately managed for
           the scope that talk about we conclude that the program
           is effective or that there's experience that
           demonstrates that it works or things like that.
                       Actually as I was reflecting on the
           challenge that you offered before concerning could we
           put the reasonable assurance finding in more plain
           English.  I was thinking to myself now where in the
           NRC, where in the agency would I go to get a really
           good explanation about what the reasonable assurance
           finding means in plain language that I could use to
           convince the public.  It occurred to me that the best
           qualified group would probably be some advisory
           committee to the Commission.
                       (Laughter.)
                       As we proceed to try and develop a plain
           language version of our traditional safety evaluation
           findings that more clearly explains why the Commission
           felt that managing aging for the stuff that's in the
           CLB that is relied on to prevent or mitigate accidents
           or protect against station blackout or all the rest of
           the stuff that the Commission determined was
           important, will continue to look for ways to express
           that in language that the general public, the folks
           that attended the workshop yesterday with Mr. Cameron
           and the public participation interests, as we find
           ways to try and articulate these things so that they
           can better understand what we are really trying to
           tell them, then we'll evolve those into improvements
           in the style guide for our safety evaluations.
                       But at this point, the language construct
           was based primarily to have everything in the
           regulation covered.  We'll try to look for ways to
           improve on the clarity of that finding.
                       MR. BURTON:  And I guess I just wanted to
           add to that, because I'm not exactly sure what parts
           of the application we're looking at.  But certainly in
           section 2, the scoping and screening, the primary
           thing was to ensure that all the right things are
           being captured.
                       Section 3 is more the assessment of the
           adequacy of the aging management and things like that. 
           I don't know if you as part of your review included
           section 3.  If it did and if there's some question
           again --
                       MEMBER WALLIS:  Yes, I did, and section 4
           too.
                       MR. BURTON:  In section 4, the TLAAs.
                       MEMBER WALLIS:  So maybe what I'm asking
           questions, might have some influence on how you finish
           up writing the SERs so that it is clearer.  That you
           haven't just gone through sort of putting things in
           boxes.  You have actually done some really digging in,
           convince yourself that things are in good shape.
                       MR. BURTON:  Sure.
                       MEMBER LEITCH:  I have two quick
           questions.  I guess they are really for Mr. Baker.  A
           number of BWRs are in the pipeline going to be asking
           for power uprates.  Is that in the Hatch plans?
                       MR. BAKER:  Hatch has done the extended
           power uprate on both units.
                       MEMBER LEITCH:  Is that five percent order
           of magnitude or was it one of those larger ones?
                       MR. BAKER:  Go ahead, Chuck, if you have
           the numbers.
                       MR. PEARCE:  Charles Pearce, Southern
           Nuclear.  The first uprate we did was five percent,
           105%.  The second uprate was greater than five
           percent.  I'm not sure about this number, but I think
           it was eight percent.  So we did 105% uprate and then
           we did another, about eight percent uprate.
                       MEMBER LEITCH:  So you see, Hatch is being
           at its ultimate capacity now?
                       MR. PEARCE:  Well, I can't speak to
           whether there's going to be a further uprate plan or
           not.  I think we don't have any plans in the immediate
           future, let's put it that way.
                       MR. BAKER:  The original license was 2436
           megawatts.  We're currently talking 2736 megawatts. 
           So that is the extent of the uprate.
                       MEMBER LEITCH:  And the other question was
           do we know what the core damage frequency is for the
           Hatch units?
                       MR. BAKER:  We have that.  Chuck, if you
           can find it before I can.  I have it in my notes.
                       MR. PEARCE:  The core damage frequency,
           the total is 1.22 e to the minus fifth.
                       CHAIRMAN APOSTOLAKIS:  When you say total,
           what do you mean?
                       MR. PEARCE:  That includes the frequency
           from all the events.
                       CHAIRMAN APOSTOLAKIS:  External as well? 
           External events?
                       MR. PEARCE:  The external events, you are
           talking about the earthquake, fire?  That, I do not
           know.  I'm not a PRA expert.  I just have the total. 
           I don't believe it includes external events, but I can
           check into that in the break.
                       MEMBER LEITCH:  And that's the same for
           both units?
                       MR. PEARCE:  Yes.  It's in that ballpark
           for both units.
                       MEMBER LEITCH:  Thank you.
                       VICE CHAIRMAN BONACA:  Okay.  Any other
           questions?
                       MEMBER WALLIS:  Those where there's no,
           what will it be in 20 years?  Do you make any
           predictions like that?  There must be some effect of
           aging.
                       CHAIRMAN APOSTOLAKIS:  This is not in the
           PRA.
                       MR. GRIMES:  This is Chris Grimes.  But we
           have been periodically checking with the Office of
           Research.  I understand that they do have some model,
           aging models for PRAs that they are continuing to try
           and develop, but they are not ready to try and roll
           them out yet.  But we have continued -- we will
           continue to monitor the research programs because we
           are looking forward to an opportunity at some point in
           the future where we might be able to see a risk model
           for age, for a plant age.
                       VICE CHAIRMAN BONACA:  All right.  Are
           there any more questions for Mr. Burton or for any of
           the presenters?  There are none, so Mr. Chairman, I
           pass it onto you.
                       CHAIRMAN APOSTOLAKIS:  Thank you.  We will
           recess until 10:55, with a narrow factor of three.
                                   (Whereupon, the foregoing matter went off
                       the record at 10:40 a.m. and went back on
                       the record at 10:58 a.m.)
                       CHAIRMAN APOSTOLAKIS:  The next issue is
           proposed final licensing guidance documents.  Dr.
           Bonaca is still the leader.
                       VICE CHAIRMAN BONACA:  Thank you, Mr.
           Chairman.
                       In November of last year, we wrote a
           report with comments on the license renewal guidance
           documents.  At that time, we had reviewed in draft
           form.  Since that time, also the industry and the
           public has had an opportunity to provide a lot of
           comments to the NRC.  The staff has now updated those
           documents, essentially the SRP, the reg guide, and the
           GALL report, to address those comments.
                       They have written them now in a final new
           reg form.  I mean they have assigned new reg members
           and reg guide number to it.  They have presented it to
           the subcommittee last March 27th.  We are here to
           review them and to provide recommendation if possible
           on whether they should be finalized and other issues.
                       With that, I will begin to introduce Mr.
           Grimes.
                       MR. GRIMES:  Thank you, Dr. Bonaca.
                       Yes, by way of introduction, we drew from
           the subcommittee meeting a desire to make clear to the
           full committee that we believe that the substantial
           amount of effort has gone into improving the guidance
           for the conduct of license renewal reviews and
           understanding of the attributes of effective aging
           management programs.
                       The staff is going to describe highlights
           of those features for you.  But I want to emphasize
           that we continue to rely on the foundation of the
           renewal rule, which relies on the regulatory process
           to provide for the unforeseen.  We are certainly going
           to have new experiences in the future, and may reveal
           new aging effects or may, like the core shroud
           cracking that you just discussed, a decade from now,
           something else is going to occur.  We have a process
           to impose new generic requirements when we learn new
           lessons in the future.
                       The whole theme of this activity to
           develop generic aging lessons learned has been a focus
           on process, on providing the tools to the plant owners
           so that they will continue to find and learn and
           correct as they go, because these programs aren't
           going to start until more than a decade from now. 
           Then they go 20 years beyond that point.  So we are
           looking way out into the future in terms of the
           expected behavior changes that result from these
           regulatory requirements.
                       You also asked us to present a judgement
           on the potential erosion of the safety margin.  This
           gets back to the conversation that I struggled with
           Dr. Wallis' challenge to try and articulate a safety
           conclusion.
                       Recognizing that there's constant growth
           of knowledge, this process approach fundamentally
           relies on an ability to continue to maintain an
           adequate margin of safety.  That doesn't necessarily
           mean that the margin is larger or smaller or better
           known or less well-defined.  It really gets to the
           individual inspection and maintenance activities that
           learn and grow and adjust according to what is
           understood about the impacts on margins.
                       In some cases, we learned things that
           cause us to take margin away because we think we're
           smart enough to know how to reduce the margins.  In
           other cases, we recognized that the uncertainties are
           growing, and so we provide additional conservatism in
           the way that we manage the plant design.  So we
           increase the margins of safety where we learn that we
           do not know enough.
                       Trying to find a simple way to articulate
           that in plain language will continue to be a
           challenge.  So there are still issues that we will
           pursue for future improvements in this guidance.  But
           we believe that, and I mentioned before, more than a
           decade of nuclear plant aging research that's actually
           going on the 20th anniversary of the NPAR program,
           about a decade's worth of experience in trying to do
           license renewal reviews, we think that the guidance is
           now sufficiently mature that the Commission should
           approve it for implementation on all future renewal
           reviews with the recognition that we will continue to
           add to it as we learn new lessons in the future.
                       Our hope and expectation is that after we
           have made this presentation, that the ACRS will agree
           that it is more than adequate for this purpose, and
           should endorse it with the Commission.
                       VICE CHAIRMAN BONACA:  One last note I
           would like to make.  Before the meeting, this
           presentation is over, I would like also to hear about
           the commitment that was made in the response to our
           previous letter that the GALL report to be updated
           with some frequency I understand?  At the time, there
           was a commitment made but no procedures or specific
           processes established yet.  Maybe you could comment on
           that at the end of the meeting?
                       MR. GRIMES:  I'll do that.
                       VICE CHAIRMAN BONACA:  Thank you.
                       MR. GRIMES:  I'm sorry, and I was supposed
           to say and now I'd like Dr. Sam Lee to introduce the
           staff's presentation.
                       MR. LEE:  Good morning.  My name is Sam
           Lee.  I'm from the License Renewal and Standardization
           Branch, NRR.  This is this morning's agenda.  After my
           introduction, Jerry Dozier is going to talk about some
           examples of the public comments received.  Ed Kleeh is
           going to talk about certain NEI continued items.  Dave
           Solorio is going to discuss the one-time inspections.
                       The improved license renewal documents
           consist of the generic aging lessons learned, GALL
           report.  With that document is an evaluation of aging
           management programs -- references to GALL report to
           focus to staff review in areas where the programs are
           evaluated, and a regulatory guide that endorses NEI
           document 95-10 that provides guidance to licensing
           applicant in preparing their application.
                       This has been a significant agency effort
           involving staff from the Office of NRR, including the
           staff that are doing the license renewal application
           review.  Also, the Office of Research.  On my left,
           Jit Vora is a team leader from Research.  Contractors
           from Argonne National Lab.  On my right, Young Liu is
           the project manager from Argonne.  Also from National
           Lab, on my left Rich Morante.  He is the project
           manager from Brookhaven.
                       We are preparing a SECY paper to the
           Commission submitting this document for the approval
           by the end of the month.  During our interaction with
           NEI to discuss the public comments on the documents,
           they identified five items for further discussion with
           the staff after the issuance of these documents. 
           After we discuss these items with you later today,
           we'll continue a dialogue with NEI on these items. 
           The result of any additional guidance of clarification
           will be incorporated in a future update of the
           documents.
                       In addition, when new technical
           information and new operating experience becomes
           available, and also when the staff reviews additional
           applications, and what we learn, we will incorporate
           into future updates of these documents.
                       NEI indicated to us that the applicants
           that will be submitting the applications next year
           will be using these documents.
                       So to address how these documents ought to
           be applied, NEI is conducting a demonstration project
           in which they are preparing sample portions of an
           application and submitting them for staff review and
           comment.  They are scheduled to submit this by the end
           of the month.  We'll be working with industry through
           this demonstration project over the details for the
           implementation for procedures.
                       That concludes the opening remarks.  If
           there's any questions?  Okay.  Jerry Dozier will go
           into the public comments.
                       MR. DOZIER:  Good morning.  My name is
           Jerry Dozier.  I'm from the License Renewal and
           Standardization Branch.  With me, I have Mike McNeil
           from the Division of Research, Barry Elliot from the
           Division of Engineering, and Omesh Chopra from Argonne
           National Laboratories.
                       There were over 1,000 comments that were
           on the improved regulatory guidance.  This slide just
           represents some of the ways in which we evaluated the
           comments and tried to incorporate them into the GALL
           report, primarily chapter 4.
                       For example, in the first bullet, there
           was a lot of discussion and a lot of debate and a lot
           of comments on where is the threshold for radiation-
           assisted stress corrosion cracking, void swelling,
           where is this threshold?  Is it 10 to the 17th, 10 to
           the 21st, somewhere in between?
                       What we did though is really what the
           staff wanted, is to have an effective aging management
           program.  What we wanted to do was to find the
           components that had the most susceptible locations. 
           We wanted to monitor and inspect with an effective
           inspection technique those locations.  That was really
           the aging management program we wanted.
                       So by getting rid of the threshold, we got
           rid of a lot of the comments and a lot of the debate,
           and uncertainties.  We came out with an effective
           aging management program, which is what we really
           wanted in the first place.
                       On the second bullet, any unmade comments
           that in the GALL report, in earlier versions, if we
           could credit a program, we would credit.  For example,
           in boric acid corrosion, you could use the regular
           boric acid corrosion program and you could also credit
           ISI.  Any IS that we provide only a minimal
           acceptable, the boric acid corrosion program has been
           effective in the current term, and we expect it to be
           very effective in the extended term, so we
           accommodated that comment by only referencing the
           minimum program.
                       VICE CHAIRMAN BONACA:  But I thought the
           GALL was also a means of providing alternatives to
           minimum programs.
                       MR. DOZIER:  What the GALL report
           primarily gives you is one acceptable program.  It may
           not in all cases be the minimal program, but it is an
           acceptable program that primarily we have in the past
           through Oconee and Calvert Cliffs, if we could say it
           on a generic basis that this was an acceptable
           program, that is what you really see in the GALL
           report.
                       We don't want to limit the creativity of
           the licensee.  If they have a more effective
           methodology, of course in the application they can
           propose that on a plant-specific basis for us to
           review.  The limitation being that they couldn't
           reference back to the GALL report in that case.
                       MEMBER WALLIS:  What does "fully credited"
           mean?  I don't understand that.
                       MR. DOZIER:  As I was talking about
           earlier, for example, we would have the component,
           some carbon steel component here.  Then we'd have the
           aging effect would be boric acid corrosion.  Then we
           would credit two programs.  We would say ISI was
           effective in finding it, and also would say boric acid
           corrosion.  We would put two.  In this case, we only
           have one.
                       MEMBER WALLIS:  Credited means that the
           programs take care of your concerns with the issue? 
           Is that what you mean?
                       MR. DOZIER:  Yes.
                       MEMBER WALLIS:  It resolves the issue
           then?
                       MR. DOZIER:  It resolves the issue, yes. 
           It would be fully acceptable.  By fully credited, I
           guess I should have made to this have said fully
           acceptable to the staff.
                       MR. GRIMES:  Actually, you can drop the
           fully and it still means the same thing.
                       MR. DOZIER:  In the next bullet, the
           earlier versions, for example, the pressurized bottom
           head, we had those as plant-specific evaluations.  In
           that case, the applicant could propose a program. 
           Well, during our revisions and incorporation of the
           comments, we started really focusing on trying to give
           as much information to the applicant as we could.  In
           other words, now for the bottom head we credit the
           chemistry program and ISI and tell the applicant that
           we're only concerned with the Iconel 182 welds.  So it
           gives the applicant more direction on really what the
           staff's interest is.
                       In the GALL report, of course you'll have
           a component. You'll have many aging effects. 
           Sometimes in our public comments from the earlier
           version, there may be one of the aging effects that
           there was some controversy on whether or not that was
           really a significant aging effect or not, or really
           applicable.
                       In some cases we would remove based on the
           comment and further evaluation, we would remove some
           of the aging effects.  Does that mean the component
           went away?  No.  That meant just the aging effect.
                       In the last bullet, of course GALL is a
           useful tool for the applicant to reference during the
           license renewal application.  We based ours on the
           Oconee and Calvert Cliffs, and may not have gotten the
           full range of components that they could possibly be
           done on a generic basis.
                       So NEI provided us with some additional
           components that they would like to have in the GALL
           report and the programs.  We evaluated those and
           accommodated those types of requests.
                       Also, in the case of there was comments
           from, for example, Union of Concerned Scientists. 
           They had a few components to add.  We also
           accommodated those requests.
                       So there were many comments, and these are
           just some of the ways that we evaluated and
           accommodated the comments.  Is there any questions? 
           If not, I'd like to turn it over to David.
                       MEMBER WALLIS:  So there were no serious
           comments that really changed your mind about anything,
           were issues that couldn't be handled this way?  I get
           the feeling everything worked out fine with the public
           comments?
                       MR. DOZIER:  I may have made it sound a
           little easier than it was because there was -- we had
           several comments we went through.  We even had to go
           through the escalation process up to the branch chief. 
           So everything wasn't easy.  But we tried to address
           the best we could.
                       Barry has something to address on that.
                       MR. ELLIOT:  We have open issues.  Don't
           think we don't have open issues.  We have open issues. 
           We are still going, you know, trying to resolve those
           open issues.  This is just the issues that we were
           able to resolve here, but there are still open issues
           between the NRC and industry.
                       VICE CHAIRMAN BONACA:  I hope the GALL
           report doesn't become a minimum requirement document. 
           I mean it wasn't intended to be that way.
                       MR. ELLIOT:  We don't look at it as a
           minimum requirement document either.
                       VICE CHAIRMAN BONACA:  I'm only saying
           that there were some comments that said encouragement
           for the staff to put in only the minimum that's
           accepted for some programs.
                       MR. ELLIOT:  I can clarify, the in-service
           inspection discussion a little bit.  The reason we put
           the boric acid corrosion in is because we weren't
           satisfied with the in-service inspection program
           section 11 for corrosion, so we put in this program. 
           That's why we're taking credit for it, because we told
           them that this is what we wanted.
                       VICE CHAIRMAN BONACA:  I understand.  My
           comment only is because I view over time these would
           be probably the main document reference both by the
           applicants and the staff.  So we have seen the first
           applications involving a significant effort of the
           applicants to be creating.  I mean first BG&E had to
           do a lot by itself.  Here this is becoming more and
           more important because it is going to be the baseline
           for the applications.
                       MR. GRIMES:  Dr. Bonaca, I am compelled to
           say that by virtue of the Commission performance goals
           on effectiveness efficiency and knowing that necessary
           burden and so forth, we often describe the regulatory
           requirements as the minimum requirement.  That's just
           by virtue of the regulator is expected to only require
           what is necessary and sufficient for plant safety.
                       So it is appropriate to say these are the
           minimum requirements.  We would hope that applicants
           would establish inspection and maintenance programs
           that go well beyond in terms of the scope and the
           practices.  But that is not to say that we don't feel
           very strongly that we have put a lot of attention into
           the detail about making sure that we have what we need
           to make sure that these are effective aging management
           programs.  So to that extent, it is an important
           baseline.
                       I think it's also important to point out
           that we have tried to avoid making this a catalog of
           options because that reduces the opportunity to
           standardize and achieve efficiencies by having one way
           to do it that everyone sort of gravitates to.  So we
           did consciously try to avoid going well into what are
           all of the different ways that you can manage the
           aging effects, because that would then work against
           the efficiency aspect of the guidance.
                       We certainly expected that we are going to
           have some departures from this, but we'll try to
           discourage that.
                       VICE CHAIRMAN BONACA:  I understand.  For
           example, on the issue of scoping, that you don't have
           in the presentation here, we discussed that before,
           NEI pointed out that all you need is to have a
           methodology and then the results of the whole process,
           including screening.  When you do that, you really
           have a problem also with navigating through the
           application.
                       Now I expressed a concern we had last
           time.  I believe that the ACRS probably will encourage
           more documentation to make it possible for an
           interested individual or the public to find out what
           components are in or out.  It's not too much to ask.
                       Now I recognize in the SRP you had to
           recognize that that was the requirement of the rule,
           so you had to admit it.  But you can see how that, in
           my judgement, is a minimum requirement for
           documentation.  By meeting the minimum requirement,
           you meet the rule but maybe you don't fulfill the
           needs of the public and of the staff and the ACRS
           Subcommittee when they try to review these documents.
                       MR. GRIMES:  Point well taken.
                       VICE CHAIRMAN BONACA:  Okay.  We can move
           on.
                       MR. DOZIER:  Okay.  I would like to turn
           it over to David Solorio -- Ed Kleeh, I'm sorry.
                       MR. KLEEH:  Good morning.  My name is
           Edward Kleeh.  I am representing the License Renewal
           Branch.  With me from the Office of NRR, the Division
           of Engineering are Mr. Barry Elliot, Mr. James Davis
           is coming up, Mr. Frank Grubelich, and from the Office
           of Research is Mr. Mike McNeil.
                       I will present the five NEI continued
           dialogue items by stating both the NEI and NRC
           position.
                       Item one is individual plant examination,
           IPE, or individual plant examination for external
           events, IPEEE, has a source document to consider for
           scoping.  NEI considers it inappropriate for an
           applicant to establish a licensing renewal scoping and
           screening criteria that relies on plant-specific
           probabilistic analysis like IPE's and IPEEE's since
           they are not part of the current licensing basis.  Not
           only reflect the estimated core damage frequency for
           the plant configuration at that time.
                       NEI contends that IPE's and IPEEE's may
           contain recommendations to modify the plant, revise
           procedures, or develop training to further reduce the
           estimated core damage frequency, but only implemented
           after 10 CFR 50.59 or 10 CFR 50.90 reviews.
                       The standard review plan for license
           renewal, page 2.1-3, states that although the license
           renewal rule is deterministic, that probabilistic
           methods on a plant-specific basis may help access the
           relative importance of structures and components
           subject to an aging management review by drawing
           attention to specific vulnerabilities.
                       Reviewing an IPE or IPEEE can help a
           reviewer determine what equipment is risk significant
           and relied on for mitigation of design-basis events. 
           It provides additional understanding to permit safety
           determinations.
                       VICE CHAIRMAN BONACA:  Is this the NEI
           position still?
                       MR. KLEEH:  No.
                       VICE CHAIRMAN BONACA:  At which point did
           it become yours?
                       MR. KLEEH:  When I got to the part about
           with the standard review plan, that was the NRC
           position.
                       MEMBER WALLIS:  So the NEI position is
           that some information should be ignored?
                       MR. KLEEH:  Yes.
                       MR. GRIMES:  This is Chris Grimes.  Let me
           explain.  This set of issues are issues for which we
           have two positions that appear to conflict, but we're
           not sure.  So instead of appealing the issues, the NEI
           working group simply asked of the steering committee
           that the staff be available to continue the dialogue
           so that we can understand whether or not we have any
           disagreement.  I think that it is fair to say that on
           the IPE issue, the industry's concern is more one of
           proximity, having the IPE described in a staff review
           that is supposed to be certifying the current
           licensing basis relative to the scope of equipment in
           an aging management review.
                       Their concern is that this device might be
           used in some way to subvert the current licensing
           basis.
                       CHAIRMAN APOSTOLAKIS:  But I'm a bit
           confused though.  The current rule is deterministic. 
           It really looks at passive components.  The IPEs have
           declared the passive components as being so reliable
           that they will not put them in the accident sequences.
                       So how is it relevant?  If I look at the
           dominant sequences that an IPE gives me, that will
           have valves not closing or opening and pumps and so
           on.  How does that help me?  I mean the deterministic
           rule says that I should be looking at the passive
           components.  The others are already under the
           maintenance rule and so on, so it really doesn't help
           you very much.  So I don't even know why it's a
           dialogue item.
                       MR. KLEEH:  I have an inspection
           background.  When you use IPEs and IPEEEs, they tend
           to give you a relative importance of what systems have
           a safety significance.  You can classify and
           prioritize them.  That's mainly what the NRC is trying
           to do here.  They are trying to use all the tools
           available to be able to classify the safety
           significance of systems that they are going to
           consider to be scoped under the license renewal rule.
                       MR. GRIMES:  The guidance instructs the
           reviewer to use EOPs, the IPE, and other information
           about the plant capabilities or lack of capabilities
           in order to have them use devices that help them to
           poke at the current licensing basis to determine the
           completeness of the scope.
                       IPEs are useful primarily because for
           those that still think in a systems paradigm they know
           what are the important functions of the system from an
           IPE that they then go in and look for that intended
           function coming out of the scoping and screening.
                       So to the extent that it could be useful
           for the staff reviewers but the industry concern about
           there ought to be more guidance in how not to abuse
           it.
                       CHAIRMAN APOSTOLAKIS:  So it's the next
           step we discussed this morning, beyond what Hatch did.
                       MR. GRIMES:  Yes.
                       CHAIRMAN APOSTOLAKIS:  But you still
           wouldn't look at the active components.  Right?  You
           would look at the systems, but then you would look
           only at what's passive.  So there is progress.  I'm
           telling you, in five years, there is going to be a
           PRA.
                       MR. GRIMES:  I hope Dr. Bonaca doesn't
           expect that in our commitments for future
           improvements.
                       CHAIRMAN APOSTOLAKIS:  NEI is concerned
           that this might subvert the process?
                       MR. GRIMES:  By virtue of these being
           continued dialogue items, I think we need to offer NEI
           an opportunity to more clearly articulate what their
           real concern is.  That's why instead of taking these
           issues to appeal at the conclusion of the last
           steering committee meeting, the working group simply
           said we would like the staff to continue to talk with
           us.  So we need to better understand what it is they
           want us to do differently.
                       CHAIRMAN APOSTOLAKIS:  Now if the IPE,
           IPEEEs are used only to add things to scope, then I
           can see their concern.  But if you use a risk-informed
           approach to define SSCs that are within scope, then it
           is a different story.  They shouldn't really object to
           that.  So I guess they are afraid that the first thing
           is going to happen, like the first 25 years of PRA,
           just add to the regulations but never take anything
           out.
                       MR. KLEEH:  Item two.
                       MEMBER SHACK:  I'm glad you made that
           point, George.  It's one we haven't heard before.
                       MEMBER WALLIS:  The thing that intrigued
           me was the first 25 years.  When did the first 25
           years start, George?
                       CHAIRMAN APOSTOLAKIS:  I'm sorry?
                       MEMBER WALLIS:  When did the first 25
           years start?
                       CHAIRMAN APOSTOLAKIS:  They are not
           biblical years.
                       Please go ahead.
                       MR. KLEEH:  Item two.  Operating
           experience with cracking of small board piping.  NEI's
           position is that inserts inspections ISI and chemistry
           control are adequate as aging management programs. 
           Operating experience does not justify doing more.
                       Now we get to the NRC position.  GALL
           recommends a volumetric one-time inspection for
           evidence of no cracking to verify the effectiveness of
           chemistry control.  The one-time inspection augments
           the aging management program consisting of primary
           water chemistry and in-service inspections for class
           I components.
                       The ASME Code, Chapter 11, requires
           service examinations of class I, small bore piping
           with less than a four-inch nominal diameter every ten
           years.
                       Are there any questions on that item?
                       MEMBER LEITCH:  Does this issue only
           relate to class I small-bore piping?
                       MR. KLEEH:  Yes.
                       MEMBER LEITCH:  Thank you.
                       MEMBER SIEBER:  And it doesn't relate to
           fatigue-induced cracking?
                       MR. KLEEH:  It relates to all kinds of
           cracking.
                       MEMBER SIEBER:  Not just chemistry?
                       MR. KLEEH:  The cracking is the issue, not
           the chemistry.
                       Item three is management of loss of free-
           load of reactor vessel internals bolting using the
           lose parts monitoring system.
                       NEI believes that ISI visual examinations
           are adequate for management of loss of pre-load on
           reactor vessel internals bolting.
                       The NRC position is that GALL recommends
           that loss of pre-load in reactor vessels internal
           bolting be managed by ISI in the loose parts
           monitoring system.  The NRC staff accepted 
           Westinghouse Owners Group topical report WCAP 14-5-77
           which recommends that the loose parts monitoring
           system as one of the surveillance techniques used to
           detect loss of pre-load and other aging effects on
           certain reactor vessel internals components as part of
           several aging management programs.
                       The ASME code, Section 11, category BN-3
           requires visual inspections of core support structures
           every ten years.
                       Are there any questions on this item?
                       MEMBER WALLIS:  How do you tell if the
           bolts are loose?
                       MR. KLEEH:  How do you tell if the bolts
           are loose?
                       MEMBER WALLIS:  By a visual inspection. 
           Isn't that what you mean about loss of pre-load?
                       MR. KLEEH:  That is what NEI is
           suggesting.
                       MEMBER WALLIS:  How does visual inspection
           tell you if you've lost a pre-load?
                       MR. KLEEH:  I don't think I am in a
           position to support their argument.
                       MR. GRUBELICH:  Frank Grubelich,
           Mechanical Engineering Branch.
                       We have seen in the baffle bolt cracking
           experience where industry has said that they have not
           seen this cracking of the baffle bolts that was
           experienced over in Europe.  However, we haven't seen
           it because what they were doing was a visual
           inspection.  The crack occurs between the juncture of
           the bolt shank and the head.
                       Subsequently, the log took three lead
           plants, Westinghouse lead plants, and they did UT
           examinations.  In fact, they found some cracking.
                       So our position really is to use loose
           parts monitoring.  There has been experience with
           that, and that is a program that is an ASME standard. 
           It has been published.
                       MR. GRIMES:  This is Chris Grimes.  But
           I'll point out that there is an opportunity for
           regulatory coherence here because staff just approved
           a GE topical that concluded loose parts monitoring was
           not necessary.
                       MR. ELLIOT:  Along that line, this is a
           PWR issue.  In the boiling water reactors, we credit
           ISI and water chemistry for the bolting of the
           internals.  This is only a PWR issue.
                       MR. GRUBELICH:  Part of the discussion
           with the PWR is that the point that they were making
           is that the flows in the BWRs are relatively low so
           that they can't carry the loose parts, and that they
           also have limited or restricted flow passages so that
           the larger parts will not get into the core.
                       MEMBER WALLIS:  I don't understand the
           connection.  Maybe I should be quiet.  If you have a
           loose bolt, it doesn't necessarily wander around.  It
           has to come out to wander around.
                       MR. GRUBELICH:  You can have both cases. 
           It can be loose.  It can stay in place.
                       MEMBER WALLIS:  I'd think you would be
           concerned about it being loose and staying in place.
                       MR. GRUBELICH:  Right.
                       MEMBER WALLIS:  You won't catch that by
           seeing whether it was rattling around somewhere else.
                       MR. GRUBELICH:  Correct.  But you also
           worry about the part that gets loose and gets into the
           core area.
                       MR. MCNEIL:  There's another difference
           between the Ps and the Bs.  That is, that at the
           damage levels that are common in Bs, the radiation-
           induced creep is less severe, so you would have less
           loss of pre-load simply for the creep effect than you
           would in a P.  I'm trying to explain the discrepancy
           between the position of the GE and the PWR system.
                       MEMBER SIEBER:  But the baffle bolts are
           on the outside of the core barrel, right, or the
           baffle?  So they either go to the bottom of the
           reactor vessel or into the steam generator head.
                       MR. GRUBELICH:  There are two different
           baffle bolts.  There's one on the inner surface, which
           is actually adjacent to the peripheral surface of the
           fuel -- then on the backside, there is what is called
           a core barrel former bolt.  So you have both cases.
                       MEMBER SIEBER:  Okay.
                       MR. KLEEH:  Item number four is operating
           experience with cracking bolting.  NEI's position is
           that crack initiation/growth due to stress corrosion
           cracking through carbon steel closure bolting is not
           an aging mechanism.
                       Section 2 of the ASME code specifies the
           ASA 193 grade B bolting at minimum yields 105 pounds
           per square inch, and no maximum yield strength.
                       MR. MCNEIL:  I think that figure of 105
           pounds per square inch has to be wrong.
                       MEMBER WALLIS:  105 ksi.  Must be
           thousands.
                       MR. KLEEH:  That's what I said.
                       MR. MCNEIL:  I'm sorry.  I thought you
           said 105 pounds.
                       MR. KLEEH:  If I did, it's supposed to be
           105 thousands, and no maximum yield strength.
                       The minimum yield strength should be
           sufficient for normal design loads.  The maximum yield
           strength preferred by the staff of 150 thousand pounds
           per square inch or less ensures the bolt is not too
           hard, meaning brittle, so as to be susceptible to
           stress corrosion cracking, which is more likely with
           moisture in the air and if the brittleness of the bolt
           increases.
                       GALL recommends that cracking
           issues/growth be managed by the EPRI bolting integrity
           program.
                       Are there any questions on this item?
                       MEMBER POWERS:  I guess you were just a
           little too quick for me.  The staff has come back and
           said that they don't want a high strength steel is
           because of the stress corrosion cracking limitations? 
           And NEI is saying they are perfectly willing to let
           things stress corrosion cracks?
                       MR. KLEEH:  I think what they are saying
           is they don't believe that stress corrosion cracking
           is going to occur.  James Davis can elaborate on that.
                       MR. DAVIS:  They just want to drop that
           out of GALL.  They wanted to drop that issue out of
           GALL.  We have a lot of evidence from the past
           operating experience that if your yield strength gets
           over 150 ksi, they will crack in air.  As I said to
           the subcommittee, I'm not yielding on this point.
                       MEMBER POWERS:  I guess I wouldn't either.
                       MEMBER SHACK:  No pun intended.
                       MEMBER POWERS:  You're not the only one
           that has the experience of cracking in the air on
           high-strength bolts.
                       VICE CHAIRMAN BONACA:  Good.  Fire
           protection.
                       MR. KLECH:  The final item is inspection
           of fire protection systems.  BI's position is that the
           National Fire Protection Association, NFPA, codes are
           adequate for managing aging effects in fire water
           systems.  The NFPA codes do not provide guidance for
           assessing internal corrosion of fire water systems
           which are not routinely subject to flow.
                       The NRC's position is that GALL recommends
           the single system monitoring, internal inspection and
           flow testing of fire water systems to ensure the
           corrosion including microbiologically effluence
           corrosion mix. 
                       Are there any questions on this one?
           That concludes the presentation.
                       Mr. Dave Solorio will now take over.
                       MR. GRIMES:  While Dave is moving up to
           the podium, I want to clarify.  These were the -- this
           was the subset of industry comments on the improved
           renewal guidance that ended up being quote unresolved. 
           They were originally characterized as potential appeal
           items, but when it came time for the industry to
           appeal the issues to higher management, they concluded
           that they did not want to hold up GALL to try and
           resolve these issues, rather they simply wanted the
           staff to continue a dialogue because perhaps we
           misunderstand their point or they misunderstand our
           point.
                       Barry pointed out this distinction about
           loose parts monitoring for PWRs and BWRs.  On its
           face, has to be explained in a clearer way and perhaps
           they simply don't understand the staff's position.
                       But we will continue to have a dialogue
           and we'll report on what we learn in the future.  And
           with that, David is going to address one-time
           inspections.
                       MR. SOLORIO:  Good morning.  My name is
           Dave Solorio.  I work in the Office of Nuclear Reactor
           Regulation in the License Renewal and Standardization
           Branch.
                       I'm here today to speak on the subject of
           one-time inspections for Calvert, Oconee, Arkansas,
           Hatch and GALL.
                       With me here today is Omesh Chopra from
           Argon National Laboratories.  Omesh is a Senior Member
           from the ONO team that assistant with the development
           of GALL and was the lead reviewer for many of the more
           difficult chapters in GALL.
                       I also have to my left here Robert Prato
           and to my right, Butch Burton, also from the License
           Renewal and Standardization Branch.  Bob is the ANO
           Project Manager and Butch is the Hatch Project
           Manager.
                       I asked Bob and Butch to sit up here with
           me today because they worked so hard in getting me
           information to get ready for this.  I thought that
           they should share in the glory also.
                       (Laughter.)
                       Last week, I made a presentation to the
           ACRS Subcommittee on license renewal regarding the
           one-time inspections for Calvert and Oconee and GALL. 
           The subcommittee liked it and requested that we come
           back for this full committee to expand it to also
           cover Hatch and ANO.
                       I also have another slide after this,
           Slide No. 9 that summarizes the one-time inspections
           for Hatch and ANO.  And also, I want to mention in
           case you're wondering what all the acronyms -- I
           haven't had a chance to turn to page 10.  There's a
           definition.  They have all the acronyms.  I will note
           that I left off sodium hydroxide.  I apologize for
           that.
                       I guess I want to provide some orientation
           here.  First off, for those who might not have seen
           this before, the left column here are the categories
           of the systems as they'd be represented in GALL and
           the Standard Review Plan.  I felt that a fairly
           efficient way to try to group things so that we could
           try to draw some comparisons.
                       I also want to provide a disclaimer for
           anyone attending this briefing for the first time who
           are unfamiliar with the concept of one-time
           inspections.  We're not saying these systems are only
           inspected one-time.  In fact, in the majority of cases
           there's an existing Aging Management Program already
           looking at a lot of these systems.  
                       I also wanted to mention that GALL has
           consistently applied the lessons learned of Calvert
           and Oconee regarding one-time inspections.  In fact,
           as you've heard earlier, many of these one-time
           inspections from Calvert and Oconee were incorporated
           into GALL, when appropriate, as a starting point.  In
           developing GALL, we had the experience of Argonne and
           Brookhaven National Laboratories helping us get this
           information into the GALL report and we also had staff
           members associated with the first license renewal
           reviews and the on-going reviews looking at the one-
           time inspections that were incorporated.
                       GALL also had the benefit of two public
           rounds of comments and an outcome of the public's
           participation as GALL now specifies a plant-specific
           Aging Management Program be proposed for Calvert and
           Oconee, might have proposed the one-time inspection.
                       A plant specific Aging Management Program
           could be a one-time inspection or it could be an on-
           going program, an existing program.
                       At a glance, you can see there's a few
           differences in the number of one-time inspections
           between Gall and the four plants --
                       VICE CHAIRMAN BONACA:  Before you chance
           that, on the issue of the -- it would be valuable for
           us to understand why you have one-time inspection of
           pressurizer and one steam generator for Oconee, but
           there is no inspection for Calvert.  Now I know
           Calvert has also steam generator inspections.  
                       MR. SOLORIO:  I will talk to that.
                       VICE CHAIRMAN BONACA:  Also, why does the
           GALL report -- if you could give us some indication. 
           I understand pretty much the same programs.
                       MR. SOLORIO:  I will do that in a minute. 
           All I was going to do was put this up briefly to kind
           of give everyone an orientation.  There's some
           differences there.  I'm going to go back to this and
           then I'm going to talk about what you wanted in a few
           more minutes here.
                       Actually, what I intended to do was go
           across for reactor vessel internals, all four plants,
           and kind of give you an idea of what they're doing and
           I will cover that.
                       VICE CHAIRMAN BONACA:  Okay.
                       MR. SOLORIO:  So there's some differences. 
           There's numerous reasons that explain those
           differences.  I'm going to go over a few of those
           reasons and then I'm going to talk about -- get to
           your question, sir.
                       One reason there are differences is that
           GALL provides one method for managing the aging, that
           the staff has determined is acceptable.  Applicants
           can and have proposed different Aging Management
           Programs different than GALL such as the case of ANO's
           risk-informed ISI inspection for small-bore piping or
           aging management for every piping.  The staff has
           concluded that these are acceptable alternatives.
                       Another reason for differences is that
           there are plant-specific differences or system
           nomenclature differences.  For example, Oconee has
           several features which are a little too unique, that
           we thought were a little too unique to be included in
           GALL.  That would be some of these systems down here. 
           They have a Cowamee Dam and it's our emergency power
           supply.  I know a lot of you have seen it.  I have
           heard some of you have been there.  It was a little
           too generic to be included in GALL, so you won't see
           a similar one-time inspection in GALL.
                       Also, Oconee doesn't have Oconee with one
           set of steam generators.  Isn't going to have a steam
           generator blow down system, therefore, you're not
           going to see it.  At Oconee, another example would be
           is that their fire protection system isn't labeled
           fire protection.  It's actually two other systems. 
           Low-pressure service water and 
           high-pressure service water are used to provide fire
           protection function there.  And so you look at that
           and you say where's fire protection for Oconee.  Well,
           it's there.  I could have labeled it as fire
           protection, but then I thought that perhaps someone
           would have asked me what about those systems?  So I
           left it as it was.
                       Another reason was that in many cases
           Calvert and to a lesser degree Oconee proposed 
           one-time inspections without being asked because of
           either plant-specific operating experience or because
           they wanted to ensure themselves of the effectiveness
           of their existing programs, or because they didn't
           suspect aging was occurring, but given the remote
           potential, they determined it was conservative to look
           up anyhow.
                       Another reason was that there were many
           public comments, as you've heard earlier, received by
           the staff on GALL and the staff might have concluded
           that a one-time inspection was not necessary if an on-
           going Aging Management Program was considered to be
           adequately managed on aging.
                       I think last week we talked about changes
           to the ECCS, one-time inspection for PWRs because it
           was determined that if a licensee had a chemistry
           program that matched a GALL chemistry program, the
           conditions and the contaminant control and filtering
           should be sufficient to preclude the need for a one-
           time inspection.
                       Then I'm just going to get to two more
           examples and then I'll get to the question that was
           asked.  In the case of Hatch, there's a really unique
           reason.  There could be some differences here.  It's
           because Hatch took a somewhat unique approach to how
           they scoped by function, not by system.  And as a
           result several systems were grouped together in
           unusual ways, for example, one of the in-scope
           functions for the feedwater and main steam systems was
           reactor coolant pressure boundary.  This function is
           identified under the nuclear boiler system such as
           here.  I'll just leave that up.
                       The nuclear boiler system is lifted on the
           first row here.  Therefore, main feedwater and main
           steam are actually identified as part of the RCS
           function instead of the steam and power conversion
           function, so you won't see something down here for
           main steam and feed water at Hatch.
                       In the case of ANO, another reason you can
           -- you obviously see a number of differences there,
           but some of the reasons for why there are differences
           is that ANO is frequently doing periodic inspections,
           rather than one time inspections.  Also, ANO proposed
           different types of Aging Management Programs such as
           the risk-informed ISI inspections for small-bore
           piping as I mentioned earlier.
                       VICE CHAIRMAN BONACA:  So you are saying
           that those activities are captured under programs
           which already exist and are broader, so therefore you
           don't have to have a one-time inspection for that
           specific result.  That really accounts for the big
           difference in numbers of one-time inspections you show
           there?
                       MR. SOLORIO:  Yes sir.
                       VICE CHAIRMAN BONACA:  "SH" stands for
           what?
                       MR. SOLORIO:  Pardon me?
                       VICE CHAIRMAN BONACA:  "SH" under
           Arkansas.
                       MR. SOLORIO:  Sodium hydroxide.
                       VICE CHAIRMAN BONACA:  Okay.
                       MR. SOLORIO:  It's our containment.  It's
           also my understanding that that subject of one-time
           inspections for ANO was previously brought up during
           the subcommittee meeting, so you may already have
           appreciation for some of the differences of ANO.
                       Now I'd like to go over a few examples to
           explain the transparencies in a little more detail.
                       MEMBER POWERS:  Let me ask one question. 
           If a licensee has a super water chemistry program, I
           mean it's a humdinger, it really cleans the water up
           well, does that preclude the need to do a one-time
           inspection?
                       MR. SOLORIO:  Well, if the reviewer was
           going to use GALL, GALL would tell the reviewer that
           if the chemistry program is equivalent to the GALL
           chemistry program, there may not be a need unless
           there's some specific plant operating experience which
           might suggest otherwise.
                       MEMBER POWERS:  The reason I worry about
           that is I guess there's some evidence that maybe as we
           clean water up we unleash new corrosion mechanisms
           because the impurities that are causing are not being
           tied by complexing or being captured by some of the
           impurities in the water and so 
           clean-up, good chemistry does not necessarily mean you
           don't have corrosion. 
                       MR. SOLORIO:  Yes, although in a situation
           as that, perhaps there might be operating experience
           at that plant that would suggest that their chemistry
           program, even though it sounds like a whammo-bammo one
           isn't perfect and there might be a good reason -- and
           you would expect an applicant to describe that in the
           application.
                       MEMBER POWERS:  Yes.
                       VICE CHAIRMAN BONACA:  I'd like to ask a
           question about Arkansas.  I mean the one-time
           inspections are confirmatory in nature, typically.  I
           mean you are doing it once to verify that, in fact, an
           aging effect is not taking place, okay, that's
           confirmatory.  A program is to address the possible
           aging effect that you believe is going to happen, so
           you have a programmatic inspection that you do.
                       So if I look at Arkansas, for example,
           they believe, evidently that some aging may occur of
           the components that other applications say they're not
           going to happen and so they only have one-time
           inspection and Arkansas has programs to inspect many
           times.  Have you thought about that?
                       Let's take an example of small-bore
           piping.  The other applicants are saying there's no
           aging effect coming from it, therefore, we're going to
           look at it once and then forget about it.  Arkansas
           says no, we're going to have it under a program. 
           We're inspecting  under ISI.  So they must believe
           that that's necessary. 
                       Can you comment on that?  I mean --
                       MR. ELLIOT:  Arkansas took a little bit of
           a unique approach where when they first initiated
           their Aging Management Review they identified the
           components and the environments and then they
           identified all of the maintenance activities that they
           do on all the programs that are in place.  A specific
           program addresses specific aging effect as to whether
           or not it's not likely to happen.  They still took
           credit for that program, where I think some of the
           other applicants may not have done that.  They may
           have said that this is not a practical aging effect,
           there's no need for us to commit to doing anything,
           therefore, we'll do a one-time inspection to verify
           that it is not happening.
                       VICE CHAIRMAN BONACA:  So that you don't
           want to place their commitment on the ISI for --
                       MR. ELLIOT:  Yes.  It shouldn't be taken
           as a recognition that they need to do it.  It's just
           the fact that they feel that they had a program in
           place.  There's no harm for them to take credit for it
           and instead of going through an exercise with the
           staff on arguing whether or not it's likely to happen,
           they decided that they would leave it in and commit to
           it.
                       MR. GRIMES:  Dr. Bonaca, I think it's also
           important to recognize with risk-informed 
           in-service inspection there were benefits that were
           provided by risk-informing the scope, concluded that
           there were some things they had been inspecting and do
           not now need to inspect.  And so when you say that
           Arkansas felt that they needed to do this, Arkansas
           felt that they needed to have a 
           risk-informed in-service inspection program and so it
           does have the advantage of picking up small-bore
           piping, but at the same time it was compensated for it
           by reducing inspections in other areas.
                       MR. SOLORIO:  Going to page 8, first row
           for reactor vessel internals, reactor coolant system. 
           For small-bore piping, Calvert and Oconee plan to
           conduct a one-time inspection.  GALL calls for a one-
           time inspection.  On page 9, you'll see that ANO isn't
           there, but that's because they're doing a periodic
           inspection, so they are still looking at small-bore
           piping.
                       For Hatch, small-bore piping inspections
           are the subject of an open item.  There is still
           continued dialogue on that one so I guess you can ask
           Butch in a few more months how that ended up.
                       Moving on to reactor vessel internals. 
           Calvert has a one-time inspection for CEA shroud
           bolts.  Oconee does not have a one-time inspection for
           similar functioning type of bolts at Oconee because of
           a different material.  There's not the same concern. 
           GALL calls out for a plant-specific evaluation for
           reactor vessel internal bolts of this nature.
                       ANO has committed to a one-time inspection
           of reactor vessel internals that includes bolts,
           baffle bolts.  Hatch covers aging management of
           reactor vessel internals in accordance with BWRVIP
           program.  I understand that that's been reviewed and
           if you want to ask more questions, that's part of the
           reason I've put you up here, to help with that.
           So generally, you can see how the subject of bolting
           isi being covered there.  
                       Moving on to steam generators, Calvert has
           a comprehensive program that includes inspections of
           steam generator tube supports at the U-bend area. 
           Oconee has a different design, but still has a one-
           time inspection for some supports due to gamma
           radiation concerns that they have.  GALL recalls a
           plant-specific evaluation.  ANO supports -- ANO has
           existing programs that cover and support inspections
           and of course, Hatch doesn't have steam generators, so
           it's not applicable.
                       Moving on to the pressurizer. Calvert and
           Oconee have committed to conduct a one-time inspection
           of susceptible cladding locations.  GALL requires a
           plant-specific evaluation.  ANO has committed to
           conduct periodic pressurizer examinations, polymetric
           examinations.  It's my understanding also that ANO and
           Oconee are planning to perform one-time inspection of
           their pressurizer heaters in conjunction with a BNW
           Owners Group program or initiative.  Of course, again,
           Hatch doesn't have a pressurizer.
                       Those are the examples I was going to go
           over just because of time, we're running late.  Of
           course, you can ask questions.
                       MEMBER WALLIS:  There doesn't seem to be
           much correlation between the entries from the various
           plants on the GALL Report.
                       MR. SOLORIO:  Well, I mean I really would
           have to take --
                       MEMBER WALLIS:  I don't think we could
           possibly go into them all.  There just doesn't seem to
           be that much correlation.  I wondered if there was
           some general conclusion you can draw from those.
                       MR. SOLORIO:  I was going to -- look at
           aux systems.  CC is component cooling.  That's
           actually covered by the CCCS in GALL.
                       Service water and salt water, Calvert. 
           Service water at Oconee.  That is an open cycle.
                       MEMBER WALLIS:  It's just given another
           name in GALL?
                       MR. SOLORIO:  Yes.
                       MEMBER WALLIS:  Okay.
                       MR. SOLORIO:  I'm sorry.  Fire protection
           here is equal to LPSW and HPSW there.  It's equal to
           fire protection here.
                       MEMBER WALLIS:  So it's just a translation
           problem.
                       MR. SOLORIO:  That was a big problem
           trying to correlate things between the units,
           especially with Oconee for me, anyway.
                       MEMBER WALLIS:  It looks like a real
           conspiracy against the laity.
                       (Laughter.)
                       MR. SOLORIO:  I would just like to
           conclude my remarks by saying that GALL has
           consistently applied the lessons learned of Calvert
           and Oconee and also to a large degree at ANO because
           the GALL reviewers were also working with ANO too to
           cover the one-time inspection subject.  While there
           are some differences, I hope I was successful in
           explaining that they're due to plant-specific nature,
           nomenclature, design, periodic versus one time.  So
           that's how I would conclude this part of the
           presentation.         
                       I have one more slide to discuss.
                       (Slide change.)
                       Transparency, page 11, here, provides a
           conclusion for our presentation.  We hope that we've
           impressed upon you a lot of work has been done and
           while there could be more work done to address the
           five continued dialogue issues, we believe that these
           documents should be provided as final so that future
           applicants and the staff can benefit from the
           stability and efficiency they'll provide.  Therefore,
           we request your endorsement for issuing the final
           documents to begin their implementation.
                       MEMBER LEITCH:  Would the -- on the five
           issues that we talked about earlier, would the final
           documents be issued with being silent on those areas
           or with the NRC position on those areas?  Is there yet
           hope of resolving those issues prior to the issuance
           of the final document?
                       MR. GRIMES:  We would expect to issue the
           final documents with the NRC position on those issues. 
           We've agreed that we can continue to discuss them, but
           we've taken a position that we're prepared to defend
           in terms of what's necessary and sufficient and even
           though the industry would like to continue the
           dialogue, we're only going to defend the position that
           we're putting forth in the guidance right ow.
                       MEMBER LEITCH:  And then I suppose from
           reading the preamble of the GALL that if industry, if
           on a plant-specific basis they want to take exception
           to that, they can always do that and argue that on a
           case by case basis.
                       MR. GRIMES:  That's correct.  And that's
           consistent with any regulatory guidance.  Applicants
           can always propose to depart from the guidance or
           depart from standards and justify it on a 
           plant-specific basis.
                       MEMBER SIEBER:  It sort of seems to me
           that there's a lot of flexibility in the Standard
           Review Plan and GALL and so forth and when I review
           from my location, the plant application and compare
           them with all the regulatory guidance that's out
           there, particularly in scoping where some is done by
           function, other plants do it by system, it's very
           difficult and it just seems to me that it's difficult
           to navigate through all this and fully understand what
           is going on without access to the FSAR and plant
           drawings and in some cases system descriptions, so my
           impression is that this is not all that transparent
           from the standpoint of public analysis and public
           consumption.
                       Do you agree with that, Dr. Bonaca?
                       VICE CHAIRMAN BONACA:  Yes.
                       MEMBER SIEBER:  In other words, I had
           difficulty going through all this and understanding
           what fit into what boxes and what plant called what
           system or what function by what initials and it's just
           hard to do, it really is.
                       MR. GRIMES:  And I would like to emphasize
           we've recognized that and as a matter of fact, I think
           the illustration of the language barriers that we
           continue to face, that Dave described in the one-time
           inspection area clearly indicates that there are
           things that we could do to improve the transparency of
           the process.
                       But we've been working on this explanation
           since before the draft Standard Review Plan was issued
           for trial use in 1997 and so while there are a lot of
           things that we could do to improve the clarity and
           understanding and communication between the interested
           parties, the working affected in interested parties or
           WAIPs as I like to refer to them, we think that the
           substantial -- excuse me, I think that the substance
           that we've accomplished in cataloging what's really
           important to a decision about the effectiveness of
           Aging Management Programs and guidance to the
           reviewers on how to wind their way through the various
           current licensing bases and different plant
           nomenclatures, we think that we've captured a lot of
           that and even though there is still navigational
           difficulties, that gets me to the response to Dr.
           Bonaca's original request and that is I fully expect
           to incorporate another round of lessons learned some
           time after the demonstration project.
                       I'm still not clear in my mind what that
           time frame is, probably less than a year after the
           original issuance.  So we don't have time line or
           frequency clearly established.  I think that the
           summer will give us some idea about how soon we might
           see the first update to this guidance. 
                       I also don't know at this point whether or
           not we're talking about achieving so much transparency
           with the original demonstration that we totally
           reissue the guidance in plain language, or whether or
           not we're going to continue to nibble away at it and
           simply issue supplements to the GALL, SRP and
           regulatory guide until such time as we really make
           substantial improvements and the NRC's ability to
           speak in plain language.  
                       The major lesson at this point that I
           think that we've learned since the original attempts
           to figure out how to draw a license renewal
           conclusion, almost exactly a decade ago, with the 1991
           rule and I'd say at this point that yes, there's still
           a lot more that we can do, but there's so much that
           we've accomplished that we would like the ACRS to
           endorse the promulgation of this guidance in final
           form so that we can start now working on tweaking it
           to make it better.
                       MEMBER LEITCH:  By this guidance, we mean
           not only the GALL report, the Standard Review Plan,
           but also the Reg. Guide?
                       MR. GRIMES:  And its endorsement of NEI
           Guide 95-10, Revision 3.
                       MEMBER LEITCH:  Are the differences
           between the Reg. Guide and 95-10, Rev. 3 resolved or
           is there still some --
                       MR. GRIMES:  There were no differences. 
           The Reg. Guide proposes to endorse 95-10, Revision 3
           without exception.
                       MEMBER LEITCH:  Okay.
                       MR. GRIMES:  There isi guidance in the
           Regulatory Guide that gets to some administrative
           details about electronic filing and packaging and so
           forth, but the Regulatory Guide does not take
           exception to the NEI Guide and we have verified that
           Revision 3 incorporates the substantive changes
           associated with the Standard Review Plan so that those
           two guides are not going to obviously conflict with
           each other.
                       MEMBER LEITCH:  Okay.  One other thing I'd
           like to comment on is we haven't talked to anything
           about the format of the GALL, but I think this format
           is far superior to what we saw four months ago.  I
           don't know who's responsible for revising it, but it's
           much more user friendly than -- to me at least, than
           the two-page spread out thing.  It's a lot easier to
           review.
                       VICE CHAIRMAN BONACA:  With that, are
           there any more comments or questions for the
           presenters?  For Mr. Grimes?  If none, I'll give it
           back to you, Mr. Chairman.
                       CHAIRMAN APOSTOLAKIS:  Thank you, Dr.
           Bonaca.  Thank you, gentlemen.
                       We have the first session of the
           afternoon, Safety Issues Associated with the Use of
           Mixed Oxide and High Burnup Fuels.  There will not be
           a presentation by the staff.  The subcommittee
           chairman will brief us for about 20 to 30 minutes.  So
           what I propose we should do is start our discussions
           after the briefing of the Commission meeting in May,
           okay?  We will not need a transcription.  Would you
           please come back at 2:50 because we still have a
           session that needs to be transcribed.
                       And with that, we'll reconvene at 1:10.
                       (Whereupon, at 12:10 p.m., the meeting was
           recessed, to reconvene at 2:50 p.m., Thursday, April
           5, 2001.)
           
           
           
           
           
           
           .                     A-F-T-E-R-N-O-O-N  S-E-S-S-I-O-N
                                                    (2:50 p.m.)
                       VICE CHAIRMAN BONACA:  We lost our
           chairman, therefore we --
                       MEMBER SHACK:  That's why we have a vice
           chairman.
                       VICE CHAIRMAN BONACA:  That's correct.  So
           I am starting the meeting again and next presentation
           that we have right now is the Thermal Hydraulic Issue
           Associated With the AP1000 Passive Plant Design and I
           believe that Dr. Wallis is leading this discussion.  
                       Dr. Wallis?
                       MEMBER WALLIS:  Thank you very much.
                       MEMBER POWERS:  Will it touch on the
           momentum equation?
                       MEMBER WALLIS:  I guess we can ask
           questions about anything we choose to ask about. 
                       The subcommittee met with Westinghouse and
           spent about three times as long as we're going to
           spend today, but the purpose was really a preliminary
           presentation by Westinghouse to let us know what
           AP1000 is, how they approached its design and how
           they're approaching their application for licensing. 
           They view this as an informational meeting and they do
           not expect us to write a letter at this time.
                       I would point out that the staff has yet
           to begin their review of AP1000.  So it's a big
           premature for us to reach some conclusions without
           some input from the staff.
                       Without more delay, I'd like to invite
           Westinghouse to proceed.
                       MR. WILSON:  Good afternoon.  I'm Jerry
           Wilson.  I'll begin the meeting.  I'm with the NRC's
           Future Licensing Organization and I thought I'd start
           out with a little bit of overview on the AP1000
           review.
                       Last year, Westinghouse approached us and
           said they were thinking about seeking design
           certification for their AP1000 design, but before
           doing that they wanted to determine what the scope and
           cost of that effort would be and more specifically, to
           get agreement on --
                       MEMBER WALLIS:  Someone has changed the --
           I'm sorry, Jerry.  Someone has changed -- I introduced
           you falsely.  Someone changed the agenda on me.  I'm
           sorry.
                       MR. WILSON:  That's all right, Dr. Wallis.
                       MEMBER WALLIS:  Maybe you should correct
           the record.
                       MR. WILSON:  No one would accuse me of
           being a representative of Westinghouse.
                       MEMBER WALLIS:  Maybe you should tell the
           record who you really are.
                       MR. WILSON:  As I said, I'm Jerry Wilson
           and I'm with the NRC staff in the Future Licensing
           Organization.
                       Westinghouse had specific issues that they
           wanted agreement on to determine -- that would affect
           the scope and duration of a review for design
           certification and so we set up a three-phased approach
           to do this.  The first phase was to determine the
           issues we should look at for the 
           pre-application review and estimate the effort to do
           that.  We completed Phase 1 last July.  Met with the
           ACRS in August.  Got a letter from the ACRS.  And also
           in August of last year, Westinghouse decided to
           proceed with Phase 2.
                       Now in Phase 2, Westinghouse requested
           that we evaluate these four issues.  Is the test
           program that was performed for AP600 sufficient to
           support the AP1000 application?  They've submitted two
           reports as you see here on the overhead.  We're in the
           process of getting ready to start that review.  NRR is
           going to be the lead in this review and we're seeking
           assistance from Office of Research.
                       The next issue is applicability of the
           AP600 analysis codes to the AP1000 design review. 
           Westinghouse has yet to submit the code applicability
           report to us.  We see this as a key part of our review
           and that's the part that will make our assessment when
           we officially start the review and so we're waiting to
           get that information.
                       They also are seeking additional use of
           design acceptance criteria beyond what was done in
           AP600.  They made a submittal on that area and the
           staff has begun its review in that regard.
                       Finally, we have to look at the exemptions
           that were granted on AP600 to see if they would still
           be granted on an AP1000 review.
                       Now we've estimated that it's going to
           take approximately 9 months to do this review.
           Although we haven't officially started the review, I
           would for planning purposes tell the committee that I
           anticipate in approximately 6 months we'll be back
           with our recommendations on the Phase 2 results.  We'd
           like a letter from the committee at that time.  We'll
           also be preparing a letter, a SECY paper to the
           Commission, advising them of our recommendations on
           Phase 2 and once we hear from the Commission on that,
           then we plan to send a letter to Westinghouse, giving
           them NRC positions.
                       And Mr. Chairman, that's all I had for
           this overview.  If there's any questions I can take
           them now.
                       If not, then I'll turn the meeting over to
           Mr. Corletti of Westinghouse.
                       MEMBER WALLIS:  Thank you very much.
                       MR. CORLETTI:  Thank you.  Good afternoon. 
           My name is Mike Corletti.  I'm with Westinghouse
           Electric Company.  Thank you for having us today.  
                       (Slide change.)
                       MR. CORLETTI:  Our agenda, we're going to
           be speaking, you see here, I'm going to be talking
           about really our purpose for this 
           pre-certification review and give you an integral NSSS
           overview, overview of the NSSS.  Then Terry Schulz
           will be talking about our passive safety systems
           design and analysis.  He'll be focusing on the plant
           description and analysis report that we submitted in
           December, that included a description of the AP1000
           and preliminary safety analyses that were performed,
           using the codes that were developed and approved for
           AP600.  
                       Bill Brown will then be discussing our
           PIRT and Scaling Report that we submitted last month. 
           We really see that as the first key deliverable for
           the codes and testing issue because before we can get
           to the detailed review of the code, we really have to
           come to agreement that the tests that were used to
           validate the codes for AP600 are also applicable to
           the AP1000.  And that report provides scaling to --
           our scaling approach is outlined in that report.  I
           believe you've all received that.
                       Finally, Mr. Gresham will get up and speak
           with regards to our planned approach for codes.  Our
           plan is to the use the codes that were approved for
           AP600 and we owe a code applicability report that is
           due out mid-month and Mr. Gresham will speak to that.
                       Finally, the other issue is that of design
           acceptance criteria and Richard Orr will speak about
           our approach for design acceptance criteria and also
           talk a little bit about some seismic analysis that had
           been completed already for AP1000.
                       (Slide change.)
                       MR. CORLETTI:  As Dr. Wallis said, this
           meeting is basically an informational meeting.  It was
           not our intent to ask for a letter at this time and
           really to introduce ACRS to AP1000 design, how we've
           gone about designing the plant based on AP600.  The
           objectives of the pre-cert review, I believe Jerry's
           covered those already and then our proposed approach
           resolving these issues.
                       (Slide change.)
                       MR. CORLETTI:  We came to the staff last
           year about around this time talking about the AP1000. 
           We had worked on it for some time since we had
           completed AP600.  When we completed AP600 in the
           commercialization of that, the market has changed
           significantly from the time that AP600 was initiated
           and this is what is driving towards developing the
           AP1000.  Basically with the approach of using the
           AP600 as a basis, we can use the design, the detail
           design that we developed on AP600 and really, we're
           developing the AP1000 within what we're calling the
           space constraints of the AP600.
                       (Slide change.)
                       MR. CORLETTI:  You'll see here -- no you
           won't.  When we say the space constraints of the
           AP600, you see here's the AP600 and AP1000 side by
           side.  So if you look at a plan view, the plants are
           essentially the same, the same structurals generally. 
           The steam generators are somewhat larger to account
           for the higher core power.  But really, from this view
           it looks, it basically is the same view.
                       (Slide change.)
                       MR. CORLETTI:  When you look at the
           section view, the containment has grown to accommodate
           both steam generator removal and the larger mass
           energy releases associated with the larger core power.
                       (Slide change.)
                       MR. CORLETTI:  On the AP600 or AP1000,
           basically we're also trying to use the same components
           as much as possible, use proven components that have
           been used at Westinghouse plants and others.  By using
           this approach, we retain the basis for the cost
           estimate, the number of components are the same, the
           same configuration essentially.  Some of the
           capacities are increased, but the number of components
           and the way they're all put together are essentially
           the same.
                       With our approach we're also -- the key to
           this is for AP1000, is to meet the regulatory
           requirements that we encounter for the passive plant,
           so really, we're adopting all the passive plant issues
           and also part of that is preserving the large safety
           margins that the passive plant had with AP600 and in
           our reports that we've sent in today, or up to this
           date, have tried to demonstrate that with a
           preliminary safety analysis that we've shown to
           illustrate the large safety margins that we're
           preserving with AP1000.
                       MEMBER WALLIS:  So 1000 was just chosen as
           a nice round number, rather than some optimum and why
           isn't it 1200 or 1500?
                       (Slide change.)
                       MR. CORLETTI:  Well, basically, the next
           slide here, next two slides, we wanted to stick with
           a proven core design and so we went to -- for AP1000
           we went to a 14-foot core, longer fuel assemblies.  We
           have 14-foot cores in our South Texas designs and also
           in Doel and Tihange, two plants that are in Belgium. 
           And those plants, actually have 157 fuel assemblies
           which are the same as AP1000 so the core design is
           essentially the same.  Now those plants, the Belgium
           plants are at 3000 megawatts thermal.  AP1000 has
           been, the core power has been increased to the same
           level from a power density as our operating three loop
           plants.  
                       So that was what basically sized -- we
           didn't want to make the vessel bigger in diameter.  We
           made the vessel longer to accommodate the longer fuel
           assemblies, but we didn't want to make it, to grow in
           diameter, because that would have affected the
           structures.
                       MEMBER WALLIS:  Not longer than South
           Texas?
                       MR. CORLETTI:  Not longer than South
           Texas.  We wanted to keep within an experienced basis
           that we had with South Texas.
                       (Slide change.)
                       MR. CORLETTI:  You see some of the key 
           comparisons of the 600 and 1000.  As I said, the
           reactor power is increased from 933 megawatts up to
           3400 megawatts thermal.  The hot leg temperature has
           been increased from 600 to 615, but that again is
           within our operating experience.
                       The number of fuel assemblies is
           increased.  Also the number of control rods is
           increased from 45 to 53.  The reactor vessel ID is the
           same.  It's the same ID, again, it's grown in length.
                       The steam generator, the steam generator
           surface area has been increased to 125,000 square
           feet.  It just so happens that as we begin the AP1000,
           our steam generator design group had just completed
           design and actually has set the steam generators to
           the Arkansas units which were a generator of about
           1500 megawatts per generator, about this size.  We
           based the design largely on that design.  Since then,
           we've merged with Combustion Engineering which has
           more experience with designing steam generators at
           this power level.  The team has been working together
           to finalize the design of the AP1000 steam generator.
                       Essentially, we'll have the same
           performance requirements with the low moisture
           carryover of the delta 75 that we had on the AP600,
           Iconel 690 thermally-treated tubes.
                       MEMBER LEITCH:  Are there any AP600s
           actually under construction now?
                       MR. CORLETTI:  No sir.
                       MEMBER LEITCH:  So your plans for the
           AP1000 don't depend upon building any AP600s,
           necessarily?
                       MR. CORLETTI:  That's right.  We're still
           basing it on proven components.  We're not relying on
           this to be a follow-on to AP600.  It would be
           available, essentially if a customer wanted to
           purchase a plant, we believe we can the schedule that
           we could do almost either one within the same time
           frame.
                       MEMBER LEITCH:  Okay, thanks.
                       MEMBER POWERS:  Why the 690 alloy for the
           steam generator?
                       MR. CORLETTI:  That is what we've been
           using on their most recent steam generators.
                       MEMBER POWERS:  That does not speak highly
           for it.  I mean it's not immune to stress corrosion
           cracking.
                       Why not go with the 800 alloy?
                       MR. CORLETTI:  I believe that the
           operating experience with the 600 has been very good,
           690.  And they basically have not seen the need to
           change.  They've had very low incidents of any tube
           plugging with this material.  It has excellent
           operating experience.
                       MEMBER SIEBER:  Do you have any Iconel 600
           anywhere in the reactor coolant system pressure
           boundary?
                       For example, it's extensively used in
           current PWRs on the head, some weld filler materials,
           etcetera, pressurizer.
                       MR. CORLETTI:  No.  I cant speak to -- I
           can't speak to that.  We've been using the approved
           materials that we used on the AP600 which more the
           Iconel 690 and I know the materials that they selected
           were basically in accordance with the latest EPRI
           guidelines on materials selection.
                       MEMBER SIEBER:  On the other hand, your
           Tihange temperatures went up by 15 degrees which puts
           it into the sensitivity zone, so the operating
           conditions are different than the AP600.  I'm just
           wondering if you made a change to materials in any way
           to account for that?
                       MR. CORLETTI:  No.  It will be the same as
           AP600.
                       MEMBER SIEBER:  Okay.  You also state that
           the reactor vessel diameter is the same?
                       MR. CORLETTI:  Yes sir.
                       MEMBER SIEBER:  But there is 12 extra fuel
           assemblies in there?  How do you accomplish that?
                       MR. CORLETTI:  I don't have that, but
           basically on the outer periphery, at the north,
           southeast and west of the core, there was room for
           three additional assemblies.  It's essentially the
           same as our three loop plants now that have 157
           assemblies.  They were eliminated on AP600.
                       MEMBER SIEBER:  Okay.  So that should
           improve the neutronics efficiency a little bit as
           opposed to making a 14-foot core reduces your
           neutronics efficiency?  Does that come out as a sort
           of a fuel cost balance or do you know?
                       MR. CORLETTI:  I don't know.
                       MEMBER SIEBER:  Thanks.
                       MEMBER WALLIS:  Well, the power rating per
           area of fuel is higher?
                       MR. CORLETTI:  Yes, it is.  AP600 had a
           very lower power density core.  You see it's 4.1
           kilowatts per foot.  We've increased it up to the
           level that we have in our operating three loop plants.
                       MEMBER WALLIS:  That's the main way in
           which you get the extra power?
                       MR. CORLETTI:  Yes sir.  And increasing
           the length.  One of the consequences to go to the
           higher power, we had to increase the capacity of the
           reactor coolant pump.  The reactor coolant pump is
           increased from 51,000 gpm to 75,000 gpm flow rate and
           the head is increased from 240 feet to 350 feet of
           head.
                       In order to minimize the impact to the
           motor, we've gone to a variable speed controller. 
           That's only used during shutdown.  When you start the
           pumps up in cold water, that is the largest draw on
           the motor and that's typically what the reactor
           coolant pumps, Westinghouse's reactor coolant pumps
           are sized for.  With the variable speed controller it
           allows you to start the pumps at low speed in the cold
           conditions.  When the fluid is heated up to operating
           conditions, then that is disengaged.
                       MEMBER SIEBER:  Is that an electronic
           controller?
                       MR. CORLETTI:  Yes.
                       MEMBER LEITCH:  Mike, you said used during
           shut down.  Do you mean start up?
                       MR. CORLETTI:  Right.  That's right.  Shut
           down operations is anything called low temperature.
                       And then again, the pressurizer has been
           increased with respect to the AP600.
                       MEMBER SIEBER:  Do you expect that the
           higher flow rates you have at the additional steam
           generator tube vibration or fuel vibration?
                       MR. CORLETTI:  The fuel vibration you have
           to look at the upper guide supports.
                       MEMBER SIEBER:  Right.
                       MR. CORLETTI:  Because the one that's
           right in front of the hot leg is the most and we have
           looked at that and we've looked at where we were on
           AP600 and we do have sufficient margin, but that is
           the most susceptible.
                       On the steam generator tubes, we've
           increased the number of tubes, so that the velocities
           through the tubes is not appreciably larger.
                       MEMBER SIEBER:  Thank you.
                       MEMBER LEITCH:  Mike, to go back to the
           question of hot leg temperature.  I noticed that South
           Texas has a hot leg operating temperature of 624 with
           Iconel 690.  That's apparently a fairly new steam
           generator, is that --
                       MR. CORLETTI:  Yes.  We just replaced that
           steam generator.
                       MEMBER LEITCH:  I was wondering, is that 
           design temperature or --
                       MR. CORLETTI:  That's the operating
           temperature.  And the units at Doel and Tihange are at
           very high hot leg temperatures also.  There's many
           units, I think you see in the table there that have
           operating temperatures.
                       DR. ROSEN:  The South Texas Unit 1 steam
           generators have been replaced.  The Unit 2s have not
           yet been replaced.  They'll be replaced in 2002.
                       MEMBER WALLIS:  Any other questions for Mr
           Corletti?
                       MR. CORLETTI:  Thank you.  The next
           presentation is on the passive safety systems and
           Terry Schulz is going to present that and basically
           our design approach to designing the AP1000.
                       Thank you.
                       MR. SCHULZ:  Good afternoon.  My name is
           Terry Schulz and I will be talking about the passive
           safety systems and our design approach to those
           systems and try to give you some insights into how we
           have come to the sizes and capacities that we've
           selected.
                       (Slide change.)
                       MR. SCHULZ:  First of all, the approach is
           to use the same configuration, as Mike pointed out, as
           AP600, same arrangement.  However, in the passive
           systems we know we have to increase the capacities in
           some areas and we've selectively looked at where we
           think we need to do that to maintain adequate safety
           margins.
                       We've considered both deterministic and
           PRA conditions and we've also given consideration for
           applying margin, as we did in AP600 to where there was
           test or computer code uncertainties.
                       The process we used is an iterative
           process and we've actually done this a couple of times
           already, where we looked at basically a hand
           calculation type, sizing, estimating of the
           performance using first principle type hand
           calculations which are largely independent of test and
           analysis.
                       These calculations are typically not a
           transient, but a point in time that we select based on
           our experience and understanding of the plant.  Then
           we kind of check that and verify it using the computer
           codes, again, at this point in time AP600 computer
           codes, the same ones we used in the SSAR analysis. 
           These are not intended or portrayed to be Chapter 15
           final analysis.  They're kind of check calculations. 
           They're obviously able to look at the transients, the
           integrated effects of the plant response.  We've not
           done all the events  we would eventually do in a SSAR,
           but we've looked at what we consider limiting events.
                       And another factor that does affect our,
           in some cases what we chose to do, was constraints in
           the plant.  As Mike pointed out, physical constraints
           in the plant can affect the design, the design
           approach that we have.
                       MEMBER WALLIS:  Did your thermal draw 
           code analysis lead to significant changes in the
           design or did the eventual thing look just like what
           you had in your hand calculations?
                       MR. SCHULZ:  Well, for example, in the
           passive RHR, our initial idea was to increase the pipe
           size and not to change the heat exchanger because that
           was minimizing the change to the plant and we thought
           we had -- and that would give us maybe a 25 percent
           increase in capacity, heat removal capacity which is
           not nearly as much as the power increase, but we
           thought we could compensate for that by having much
           more mass in the steam generator.  And for some
           events, in fact, that was adequate.
                       However, for other events like a steam
           generator tube rupture, it didn't work as well as we
           wanted it to, so we introduced another change, was to
           increase the capacity of the heat exchanger.  So in
           fact, there are cases where -- when we went through
           the computer analysis, we learned things that we
           didn't have in hand calculations and in some cases it
           was just other events that we hadn't considered when
           we did the hand calculations.  In other cases, the
           hand calculations are, of course, very simple,
           relative to the computer and not as accurate.
                       MEMBER WALLIS:  Well, yes, okay.
                       (Slide change.)
                       MR. SCHULZ:  The first feature I would
           like to talk about is the passive RHR and the
           configuration of this heat exchanger and system is
           exactly the same as AP600 in terms of valves, the
           arrangement of the pipe of the heat exchanger, the
           elevations, in fact, are the same.  We did increase
           the pipe size from 10 inch to 14 inch and we increased
           the surface area by adding longer horizontal tubes and
           a few more tubes.  I think the heat exchanger surface
           area increased about 22 percent.
                       (Slide change.)
                       MR. SCHULZ:  We did some hand calculations
           on both the AP600 and AP1000 which -- and this hand
           calculation is actually fairly sophisticated in this
           case and using the same correlations we use in our
           computer codes.  It's to calculate the heat transfer
           in the AP1000.  It is almost as much as the power
           increase with the changes of both the pipe size and
           the surface area.  Not quite, and you see the time to
           match decay heat is a little bit longer.  If you also
           consider what's going on in the secondary side of the
           plant, Mike Corletti pointed out we have these larger
           steam generators.
                       We've also applied more water mass on the
           secondary side per megawatt than AP600.  So at the
           beginning of a transient, we've got like 36 percent
           more water per megawatt.  At the end of the transient
           when we've boiled off some of that water, we have
           almost twice as much water.  So even though our heat
           exchanger is a little bit smaller, the net effect of
           having more mass in the steam generator means that
           we've got even more margin relative to heat removal
           capabilities.
                       So from this point of view in terms of say
           a hand calculation, we expect the plant to have
           increased margins.  
                       (Slide change.)
                       MR. SCHULZ:  In addition, we have done a
           number of transient analyses.  I'll show you the feed
           line rupture.  We also looked at loss of feedwater in
           steam generator tube rupture.  It's a little hard to
           tell which plant is which here, but you can see this
           is plotting the saturation pressure versus the -- on
           the high side there and the hot leg and cold leg
           temperatures down below.  And the general trends are
           similar.  The AP1000 temperatures are a little bit
           higher, so the subcooling margin is slightly less, but
           it is still very significant, 140 degrees at least in
           AP1000.  
                       Current operating plants, this temperature
           tends to go back up and come within a few degrees of
           saturation, not that that is an unacceptable
           situation, but it's a measure of safety that we use in
           this type of a transient.  So our conclusion here is
           that AP1000 behaves very much like AP600 in terms of
           a transient response.
                       (Slide change.)
                       MR. SCHULZ:  The next thing I'd like to
           move on to is to talk about the passive safety
           injection features.  And this includes the
           accumulators, the core makeup tanks, the ACS system
           and the IRWST and recirculation.
                       Again, the configuration, if you look at
           this same sketch for AP600, they look exactly the
           same.  A number of valves, the way the valves are
           connected is exactly the same.  The elevations are
           almost the same except for the pressurizer is a little
           taller, so some of those valves are up a little
           higher.
                       The core make up tank has been increased
           in size about 25 percent and the flow capability has
           been adjusted by adjusting a flow tuning orifice so
           that the flow is also 25 percent more.  So we're
           getting a bit more core makeup tank flow.  Accumulator
           capability has not been changed and I'll speak to that
           in just a minute.  Fueling water storage tank, the
           injection lines, the containment recirculation lines
           and the ADS stage 4 pipes have all been made bigger to
           make, to increase the capability of IRWST injection
           and recirculation.  I'll talk about each of these in
           turn.  
                       (Slide change.)
                       MR. SCHULZ:  At the time I have this up I
           want to also have this slide up here so I can -- so I
           have on the left slide here, a margins assessment,
           again a hand calculation type thing, for each of the
           key features, the accumulator, for example, core make
           up tank and so on, where we've tried to get a measure
           of how AP600 and AP1000 compare.  
                       For the accumulator, we did a kind of
           ratio on power density and time to refill the core and
           ratio to peak clad temperature.  So this is not a
           sophisticated, large LOCA analysis.  It's a simple
           ratio of the fact that AP1000 has the higher power
           density.  We expect the core to heat up faster in the
           reflood stage.  And so we think that the peak clad
           temperature might be something around 1940 degrees as
           opposed to 1640 for -- and these are basically -- the
           AP600 number is the best estimate LOCA with
           uncertainty as quantified in the SSAR for AP600.
                       And as I mentioned the flow capability of
           the accumulator was not changed.  And the tank itself
           is constrained by concrete walls on the sides and the
           floor.  It's already a spherical shape so it would
           have been pretty challenging to make that tank bigger.
                       The other factor is that there are a
           number of operating plants that have large LOCA peak
           clad temperatures that are as high and higher than the
           1900 and of course, the licensing limit is 2200.  So
           we feel comfortable with that result.  
                       The core makeup tank, I mentioned we
           increased it by 25 percent both in flow and volume. 
           What you see here is a comparison of the flow
           capability of the core makeup tank as opposed to a
           calculated requirement at the point in time when the
           accumulator would empty in a direct vessel injection
           line break.
                       This is, in our experience, the most
           limiting condition for core makeup tank because in a
           direct vessel injection line break, one of the tanks
           spills, the other one injects and so it has to perform
           the whole duty.  And you see here the margin of the
           design versus this requirement is a little bit less on
           AP1000, but it still looks comfortable in this
           situation.
                       ADS stages 1, 2 and 3 we have not changed
           for the AP1000.  It's exactly the same, pipe sizes and
           valve sizes.  And we think that that is adequate for
           AP1000 because at the higher pressures that this
           system is important at in terms of the initial
           depressurization, we can get adequate flow.  So even
           though the AP1000 has more power and a bigger reactor
           coolant system volume, that this system will perform
           adequately and in our computer analysis shows that.
                       On the other hand at ADS stage 4, we've
           significantly increased the capacity.  I mentioned the
           pipe sizes go up from 10 inches to 14 inch for each of
           the ADS stage 4 lines and there's four of those.  And
           if you look at with the same delta P across the
           system, the flow would go up about 89 percent versus
           AP600.  That's, of course, not saying it's enough, but
           it's giving you a feeling for how much flow capability
           we've added to the system.
                       Now the ADS stage 4 works very closely
           with IRWST injection and later on, containment
           recirculation.  Both of those, we've also increased
           substantially by making the pipe sizes bigger and in
           the case of containment recirculation, we've done one
           other thing which is to change the alignment of the
           normal RHR system.
                       The normal RHR system is not a safety
           system.  It doesn't have to work, but it is suggested
           in our emergency procedures that the operator should
           turn it on because it adds a level of defense.  It
           also, in the case of a direct vessel injection line
           break, would tend to increase the rate at which the
           IRWST drains down because it's going to spill more
           flow if it's running than if it's not running.
                       This is all accounted for in AP600, but in
           AP1000 we changed the normal water supply from the
           IRWST which is inside containment, to another supply
           outside containment.  So if the pump works, it will
           actually make things better instead of making things
           a little worse.  And that gave us a somewhat less
           severe condition for AP1000.  So it's another change
           we made to improve the situation for that design.
                       (Slide change.)
                       MR. SCHULZ:  If you look at -- and again,
           we've done the analysis of several small LOCAs for
           AP1000.  This is a direct vessel injection line break. 
           And it's showing you the upper plenum mixture levels. 
           It's kind of a little hard to show this.  This spike
           early on is actually AP600.  AP1000 doesn't behave
           quite the same way and it doesn't mainly because
           AP1000 is a little bigger plant and it's the same
           break size, so you don't get quite as much rapid blow
           down early on.
                       Later on, the response is actually fairly
           similar, not exactly the same.  AP600 has a little dip
           in here when fourth stage is trying to get the
           pressure down for IRWST injection.  AP1000 actually
           has IRWST injection starting a little bit earlier, but
           it's not continuous.  That's why you're getting some
           of these spikes.
                       MEMBER WALLIS:  Those periodic spikes,
           what are they for?  What are they due to?
                       MR. SCHULZ:  You're getting intermittent
           IRWST injection and when you get the --
                       MEMBER WALLIS:  Then it gets starved and
           then you --
                       MR. SCHULZ:  So when you get injection,
           the level goes up, but --
                       MEMBER WALLIS:  But it seems to go down --
                       MR. SCHULZ:  You can't quite keep the
           pressure down, so the injection slows down and the
           water level comes back down again.  We saw things like
           that at OSU and it's something that the plant, AP600
           is doing some of it also, not as pronounced.
                       MEMBER WALLIS:  You see spikes like that,
           though you wonder about the peer program because the
           turn around, it's like the stock market.  It's headed
           for disaster there and then somehow it turns around,
           but the accuracy with your computer program has
           something to do with the depth of the spike there.
                       MR. SCHULZ:  Yes, yes.
                       MEMBER WALLIS:  That makes one a little
           bit concerned.  Things happen so quickly in the spike.
                       MR. SCHULZ:  We've got several feet here
           and this time scale, of course, is a very long time
           scale.  
                       But that's something that certainly,
           should be looked at in more detail when we get into
           real safety analysis.
                       DR. ROSEN:  What does ADS stand for?
                       MR. SCHULZ:  Automatic depressurization
           system.  I moved my slide.  But there are valves
           connected to the pressurizer which are stages 1, 2 and
           3.  These are all sequenced to give you a staged
           depressurization.  Stage 4 is actually connected on
           the hot legs and goes directly to containment.  Stage
           1, 2 and 3 go from the pressurizer into a sparger in
           the IRWST.  And those valves are all staged so that
           the transient on the reactor coolant system is less
           severe.
                       MEMBER WALLIS:  Going back to the spikes,
           this is sort of the place where you'd like to do some
           sensitivity studies to see if you have a sort of
           somewhat different disengagement model for the vapor,
           whatever the model is.  I was sensitive of these
           things to those features in the code and you want to
           know there are some assumptions you make which would
           make those more exaggerated.
                       (Slide change.)
                       MR. SCHULZ:  Yes.  In summary, in terms of
           safety margins, I haven't talked about the loss of
           flow, but that's when the reactor coolant pump inertia
           is important.  And you can see AP1000 may be a little
           bit less margin than AP600, but both will be
           comfortably more than the typical operating plant.
                       Same with the feedline break subcooling
           margin which I talked about.  Steam generator tube
           rupture analysis, AP600 displayed a significantly
           enhanced behavior relative to operating plants which
           did not require any operator action to mitigate a
           steam generator tube rupture.  We've done some
           preliminary analysis on AP1000 and had the same
           result.  We don't need operator reactions to mitigate
           a steam generator tube rupture.
                       Small LOCA, we've done several.  Not the
           full spectrum, but several breaks for AP1000 and we're
           getting no core uncovery for these smaller breaks like
           AP600.  I've already talked about large break LOCA. 
           That's the same result you saw before.
                       MEMBER LEITCH:  Isn't that 300 degree
           increase and decladding temperature surprising?  I
           mean when I look at the data I was surprised by that
           much of an increase.
                       MR. SCHULZ:  Realize where this is coming
           from.  This is basically taking AP600 very carefully
           detailed calculated re-flood temperature rise and
           rationing that temperature rise based on the higher
           power density of AP1000 and that's where that number
           is coming from.
                       MEMBER WALLIS:  It's not a thermal
           hydraulic code calculation?
                       MR. SCHULZ:  It's not a thermal hydraulic
           code calculation, but we would expect it to go up. 
           Now whether that's where we end up, we won't know
           until we actually do the detailed large break LOCA
           analysis.  But this kind of a manipulation is we've
           done it before on new plant designs and it's something
           you can get a reasonable handle.
                       MEMBER LEITCH:  Yes, I see.  Thank you.
                       MEMBER WALLIS:  If it wasn't the criteria,
           do you think you might tweak your design to get the
           desired PCT rather than finding what PCT you just
           happened to get?
                       MR. SCHULZ:  Well, we actually considered
           running the accumulators faster.  We can do that. 
           However, they also empty quicker and there's other
           transients, especially in PRA space where the
           accumulator is say the only means of defense at high
           pressure because we've had common mode failure of the
           core makeup tanks which is not a design basis
           consideration, but it is something we consider in the
           PRA.
                       And running the accumulator faster there
           is not good in terms of the balance of safety here
           between large break LOCA and small break LOCA.  So
           after considering that the PRA sequences, we felt that
           it was better to run the accumulator the same speed
           and take a little less margin in large break LOCA and
           again, it says good or better than a lot of operating
           plants.  So we don't feel uncomfortable with the large
           break LOCA.
                       MEMBER WALLIS:  But generally speaking,
           you are asking for somewhat less margin in all of
           these areas than you have with AP600?
                       MR. SCHULZ:  No.  I don't think that's
           true.
                       MEMBER WALLIS:  Aren't all the numbers --
                       MR. SCHULZ:  Well, small break LOCA, we're
           basically saying they're the same.  If you look at the
           capability at stage 4 at IRWST injection and
           recirculation, we think we've actually added more
           margin into the design and so we'd expect that
           performance to be probably a little better.
                       Some of the other cases, yes.  Feedline
           break is a little bit less, but again, it's much
           better than operating plants.
                       I need to wrap up pretty quickly here.
                       (Slide change.)
                       MR. SCHULZ:  The containment comparison,
           as Mike showed, we've made the containment higher. 
           It's about 22 percent bigger in free volume.  We've
           also increase the design pressure from 45 psig to 59
           psig.  It's a steel shell containment so we're getting
           that pressure increased by increasing the thickness a
           little bit, changing the material and we've also
           increased the amount of water that's on top of the
           containment so that we can account for the increase in
           decay heat.
                       MEMBER POWERS:  Did you change your
           configuration around there, the hatchway?
                       MR. SCHULZ:  You're talking about the
           containment hatch?
                       MEMBER POWERS:  Right.
                       MR. SCHULZ:  We actually ended up making
           the hatch smaller.
                       MEMBER POWERS:  It looks like it.
                       MR. SCHULZ:  Yes.  This hatch is sized to
           remove a steam generator.  Because our steam
           generators got so big that we've decided that's not
           practical to remove the steam generators out the side
           and we would have to cut a hole in the top of the
           containment and remove it through the containment
           shell.
                       MEMBER POWERS:  So your vulnerable
           location around the hatchway is not so bad now?
                       MR. SCHULZ:  That's right.
                       MEMBER SIEBER:  The containment itself has
           no sizeable concrete structure on the outside, I take
           it?
                       MR. SCHULZ:  It's a steel pressure vessel
           that's 1-3/4th inch thick.  There is a separate shield
           building, a concrete shield building that's offset
           from that and that actually in our case provides the
           air inlet which comes down outside of a baffle that's
           in between, turns and goes up closer, with closer
           spacing relative to the containment and that's part of
           our passive containment heat removal.
                       MEMBER SIEBER:  How thick is the concrete
           in the wall there?
                       MR. SCHULZ:  It's about 3 feet.
                       MEMBER SIEBER:  So it has the equivalent
           shielding capability for severe accident capability?
                       MR. SCHULZ:  Oh yes, for severe accident,
           missile shields, radiation shielding, yes.
                       MEMBER SIEBER:  Thank you.
                       DR. ROSEN:  Have you actually done a steam
           generator removal study for the AP1000?
                       MR. SCHULZ:  I think so, yes.  Yes, we
           have.  Yes.  
                       (Slide change.)
                       MR. SCHULZ:  And the final slide I have
           here speaks to the containment performance.  We looked
           at both large LOCA and large steam line break.  The
           large LOCA has a very similar response to AP600 where
           the first peak is significantly below the design
           pressure.  The second peak is also well below design
           pressure, assuming more realistic steam generator
           energy input.  This was an issue discussed a lot on
           AP600.  Our SSAR results show a much higher second
           peak, but it has a very overly conservative sort of
           unmechanistic transfer of heat from the steam
           generator into the reactor coolant system.
                       The steamline break is limiting in this
           plant.  However, it's a much simpler analysis in that
           it happens early and the passive containment cooling
           is not really much of a factor in this peak.  So how
           well the passive system performs is it's just more
           simple volume and some passive heat sinks involved.
                       Are there any questions?
                       MEMBER SIEBER:  Do you use sprays to
           control the containment pressure?
                       MR. SCHULZ:  No.  There are no sprays in
           the plant from a design basis point of view.  So all
           the heat removal is through the passive containment
           cooling system and the passive heat sinks in the
           plant.  There is a connection to the fire system, but
           it's a sort of PRA-type severe accident capability
           that takes manual alignment and it's a long-term type
           operation.  It would not be effective in a short-term
           peak pressure situation.
                       MEMBER WALLIS:  Okay, shall we move on?
                       MR. SCHULZ:  Yes.
                       MEMBER WALLIS:  Thank you very much.
                       MR. SCHULZ:  You're welcome.
                       (Slide change.)
                       MR. BROWN:  Okay, we'll move on to --
                       MEMBER WALLIS:  This is an open session,
           is it?
                       MR. BROWN:  Yes, there is nothing
           proprietary here.
                       I am Bill Brown from Westinghouse and I'll
           be going over the AP1000 PIRT and scaling assessment
           that was done.
                       (Slide change.)
                       MR. BROWN:  We had already submitted our
           report and last month here we met with the Thermal
           Hydraulic Subcommittee and I made a rather lengthy
           presentation on that of which I will try to go through
           quickly.
                       The main goals here was to try to
           determine the extent to which AP600 could be used for
           AP1000 and our main goal was to be able to use this
           database for code validation in accordance with 10 CFR
           Part 52.  
                       The basic steps we used was first, take
           the PIRTs which identify all the phenomena, have them
           reviewed again by several experts for application to
           AP1000 and then take the results of these and look at
           the high ranked, important phenomena and then assess
           that relative to AP1000.  
                       (Slide change.)
                       MR. BROWN:  This gives you a quick idea of
           some of the experts that we talked to, Dr. Bajorek,
           Dr. Bankoff, Dr. Hochreiter from Penn State, Dr.
           Peterson from UC and Dr. Larson and Mr. Wilson from
           INEEL.  The main result of this was that we really
           found that there was very, very few changes
           whatsoever.  Large break LOCA indicated that core
           entrainment was a little bit higher and in the small
           break LOCA we found that entrainment again in the ADS-
           4 two-phase pressure drop was increased and we had no
           changes whatsoever for the containment and/or for the
           non-LOCA transients.  So essentially, we're looking at
           really virtually no change for the AP1000.
                       (Slide change.)
                       MR. BROWN:  We addressed quite a
           significant amount of phenomena here and this gives
           you kind of a flavor for the types of things that we
           looked at:  reactor vessel inventory, core exit
           quality, ADS floor, injection through the sump and the
           CMT, containment pressure, the heat and mass transfer
           to sinks on containment.  We looked at these more from
           what I would call a system level top down and then
           sort of bottom up we looked at some more detail or
           local phenomenon such as entrainment, surge line
           pressure drop, phase separation and so on.
                       (Slide change.)
                       MR. BROWN:  The basic approach in the
           scaling that we used for assessment was we focused in
           on the high-ranked phenomena especially for the areas
           in AP600 where certainly major interest would seem to
           be the small break LOCAs since we were interested in
           the core cooling and the vessel inventory, and then of
           course, containment pressure and steam line break.
                       Areas in which we already have data that
           are found in convention PRW data bases such as large
           break LOCA phenomena, blowdown and steam generator
           recirculation, things like these, we didn't really
           look at these.  We looked at the things which were
           unique to the passive plants and which we were
           interested in making sure that we could use the data
           from AP600.  And we did not go in and assess things
           that were of low importance.  We focused on the high
           level.
                       (Slide change.)
                       MR. BROWN:  So we started from using our
           AP600 scaling analysis as our basis.  We tried, of
           course, to learn from what we had discovered from
           AP600 and tried to look at the major features which
           were different such as the things you've heard before
           earlier discussed about core power, volume, the
           automatic depressurization system area and how these
           things would compare.
                       And what we essentially found for the
           separate effects type test we really look at the
           operating conditions and the geometric similarities
           with those.  When we got into things such as the
           integral effects tests, we really had to do some
           supplemental scaling analysis.
                       (Slide change.)
                       MR. BROWN:  To give you an idea, a flavor
           of the type of -- again, the number of tests that we
           looked at in AP600 which was something in the
           neighborhood of a $40 million program, quite
           extensive, we had a couple of integral effects tests,
           SPES, OSU, ROSA-AP600 which was NRC funded.
                       We had a large scale test facility for
           containment and we had a whole host of separate
           effects tests for the automatic pressurization system,
           the core makeup tanks, the passive RHR heat exchanger
           and numerous containment tests for the heat and mass
           transfer for the plates that we had and their vertical
           surfaces in containment, the water distribution and so
           on.  And for all of these, we provided an assessment
           and for several of these we actually did a new scaling
           analysis for.
                       MEMBER KRESS:  I don't recall the
           University of Wisconsin Condensation Test.
                       MR. BROWN:  Yes, that was the condensation
           tests that were done at -- with the Coradini people up
           there.
                       MEMBER KRESS:  The effects of non --
                       DR. ROSEN:  That was the flat-plate tests.
                       MR. BROWN:  Yes, that was the flat-plate
           tests, yes, right.
                       MEMBER WALLIS:  I was thinking about the
           scaling analysis.  You showed us a lot of comparisons
           with just sort of this effect versus that effect and
           their imbalance about the same in the experiment is in
           the real thing and there was a number that should be
           1 and it's 1.1 or something you showed us.  But those
           were sort of pair by pair and something like OSU, OSU
           actually tries to model the whole thing and you've got
           many things that interact during the whole transient. 
           I think your scaling analysis was more pair by pair,
           so you wouldn't be able to -- OSU was design to model
           AP600 everywhere.
                       MR. BROWN:  It's an integral effects test.
                       MEMBER WALLIS:  OA models AP1000 every --
           it may have -- this pair of effects may be in balance,
           but when you put the whole thing together, it's not
           going to be quite a model of AP1000, is it?
                       MR. BROWN:  There will be as any of the
           integral effects test facility, there are things of
           lower importance of which are not in exact balance and
           part of the premise of this was that we had
           established by going through AP600 very painfully that
           there was a number of things in there which don't
           become important and some of them simply because
           they're not active.
                       For example, once the automatic
           depressurization system goes off, the passive RHR, the
           core makeup tanks, for example, can essentially be
           drained and it was found both numerically doing the
           analysis as well as though the tests that the energy
           removal of these components is very small.  You can go
           ahead and scale them, but they're not very
           significant.
                       MEMBER WALLIS:  That was not very clear. 
           You looked to scaling as CNTs and injection from the
           IRWST, all of these.  If you scaled each one of those
           phenomena, but in the whole transient, they're all
           interdependent.  At the starting point for one phase
           is where you've finished at the previous phase, the
           effects go through the transient.  Really, you have to
           run the code or something to get the whole system
           effect.
                       MR. BROWN:  We do break the scaling up
           into phases, yes.  We do not have, if you're looking
           for an analysis which would start from time zero and
           look at the whole snapshot, yes, we do, we do break
           them up.
                       MEMBER WALLIS:  OSU is sort of trying to
           scale everything after a certain time.
                       MR. BROWN:  We find OSU is particularly
           good once the system is low pressure.  It's a low
           pressure facility and not surprisingly you find that
           it's very well scaled once the system is depressurized
           to low pressure.
                       MEMBER WALLIS:  The thing I'm getting at
           is that the interactions between the systems, other
           than in pairs really has to be modeled by something
           like a thermal hydraulic code for scaling analysis
           balances.
                       MR. BROWN:  Yes, you get to the point with
           scaling where you very quickly and I think Dr. Zuber
           found this out in AP600, although he had the vision of
           this, you pretty quickly get to the point that in
           order to be able to work with the set of equations
           that very quickly you put the complexity in where you
           now need a code to solve them and you no longer have
           a scaling analysis.
                       But one of the things that I think we've
           gone to be able to help that out is one knowing, for
           example, that no all, even though we have all of these
           passive components, potentially available, not all of
           them are operating at each phase during a small or
           LOCA transient.  Not all of them are always
           significant.  And you can also determine that by
           scaling and the testing to bear that out.  I mean, for
           example, we have a small break LOCA, that's a one inch
           or a two inch break.
                       It's very important during the blow down
           phase and during natural circulation, once you open up
           this huge hole, we call on automatic depressurization
           system there.  Suddenly, the mass and energy out of
           this break becomes nothing, so I could continue to
           scale this for you, but we find it's not significant
           and that's why I didn't bother focusing that in this
           report.  We focused on the things that were important
           when they were important.
                       And we have reams and reams of notebooks
           in AP600 that were submitted and we went through that
           process significantly.  I attempted to do that and put
           all the components in each particular phase that were
           all active.  In many cases, I painfully found out that
           many of them were just simply not important.
                       There was questions like, for example,
           momentum distribution effects once the ADS system went
           off and we pretty much found that maybe other than the
           surge line which leads up to the ADS 1, 2, 3, it's
           pretty much their pressure distribution around the
           system.  It's not very significant while the system is
           in critical flow.
                       Okay?
                       MEMBER LEITCH:  There's a statement in the
           executive summary of the blue book here that puzzles
           me a little bit.  Basically it says that starting with
           the AP600 and then demonstrating through scaling that
           the -- I'm sorry, starting with the AP1000 and then
           demonstrating through scaling that the AP600 program
           applies to the AP1000 and therefore that the AP600
           analysis codes are applicable to the AP1000. 
                       It seems to me that you're saying through
           scaling the test programs are comparable or can be
           scaled?
                       MR. BROWN:  Yes.
                       MEMBER LEITCH:  And then you say and
           therefore the analysis codes can be scaled.  That's
           not intuitive obvious to me.
                       MR. BROWN:  I guess we need to restate to
           what was probably intended is that if we have a set of
           scaled facilities and through scaling we determine
           that they cover the most important phenomena that we
           expect to see in the full-scale test and we have
           demonstrated though scaling that these test facilities
           are applicable to the 
           full-scale plant and therefore we say now if the codes
           which in AP600 they were, the codes were then
           validated to that database, and if the scaling still
           exists between the test facilities to AP1000
           therefore, we should be able to use those same
           validated codes because now we're validating to the
           same data base and we're saying as long as it's still
           applicable and that's the key, if through scaling it's
           still applicable, therefore the codes are also now
           validated for an AP1000.
                       So you're basically saying if my codes can
           predict the test facility and the test facility is
           sufficiently scaled to the plant, I can use them to
           predict the plant performance.  That's the philosophy. 
           That's what was done in AP600 and we're taking the
           same philosophy here.
                       MEMBER LEITCH:  Okay.
                       (Slide change.)
                       MR. BROWN:  So the major results that came
           up here, similar to AP600, we were able to find at
           least one integral effects test facility for each
           phase of a small break LOCA transient which was able
           to address the important phenomena to AP600 to that it
           was suitable for code validation and we found
           specifically that, for example, the SPES facility was
           acceptable through the high pressure phase of a
           transient, but it became distorted after the ADS 4
           which is our biggest flow path would open up and goes
           to subsonic. 
                       But on the other hand, we were able to
           cover that because we've got OSU which is good at the
           low pressure phases.
                       MEMBER KRESS:  When you say distorted, the
           time rate of change of things are different.
                       MR. BROWN:  Yes, like for example, you do
           get a -- because of the vent area relative to the
           volume, for example, you can get a distortion with
           that.
                       MEMBER KRESS:  But you go through the same
           set of phenomena.
                       MR. BROWN:  Yes, you do.
                       MEMBER KRESS:  So you don't distort the
           phenomena.
                       MR. BROWN:  Yes.
                       MEMBER KRESS:  You just distort the --
                       MR. BROWN:  The timing.
                       MEMBER KRESS:  The way timing goes.
                       MR. BROWN:  Yes.  And I think that's
           sometimes a bit of an issue with the consultants at
           times with the scaling and I would say that really if
           you want to go back and take out time in here, we're
           very well scaled.  I mean even better.  But when you
           actually factor in the timing in here which I've done
           as well, you can find that maybe some of the
           facilities are better scaled with actually preserving
           the time in which you would --
                       MEMBER WALLIS:  This would really muddle
           the phenomenon, the timing wouldn't be important.
                       MEMBER KRESS:  That's right.  That's what
           you're saying.  You know the timing is going to be
           different anyway for the scaled test.  
                       MR. BROWN:  It's hard to preserve.
                       MEMBER KRESS:  You can't preserve the
           whole thing.
                       MR. BROWN:  Right.  It certainly helps if
           you can get the timing as well.  That's certainly a
           bonus if you can do that, yes.
                       That's really the only difference.  I
           think that's the best way to think about this plant
           really.  You're really boiling down to things like
           volume and area and power and you're talking about
           timing.  I mean really we're not talking about any
           different phenomenon.  That's why our position on the
           codes are, we have the same phenomena.  Our experts
           tell us we have the same phenomena.  We have it
           covered in the tests and we're really talking about
           the rate at which it happens.  That's it.
                       And if we can't model volumes and areas
           and powers, I think we probably better quick.  It
           should be --
                       MEMBER KRESS:  You have to get to the
           momentum equation.
                       (Laughter.)
                       (Slide change.)
                       MR. BROWN:  We found also over our
           Separate Effects Test also again covered our ranges
           and we've got the same phenomena, so we think that
           those are applicable.  
                       With regard to some pass of the
           containment cooling system, with regard to this
           pressure transient issue which you just mentioned, Dr.
           Kress, we still found we have our large scale test
           facility for containment is very good for evaluating
           heat and mass transfer correlations, but because of
           the power to volume distortion, if you will, the
           timing of the pressure transient is not perfectly
           preserved to an AP600, so it's not a good
           representation of a pressure transient, but it
           certainly has the appropriate phenomenon to use for
           heat and mass transfer correlations.
                       MEMBER KRESS:  When you get a condensation
           on the walls of something like that, actually the rate
           of condensation gets to be important in terms of the
           effect of noncondensibles.  I was -- my question on
           that is were your separate effects test able to cover
           the same rate of condensation that you expect to get
           here, rate per unit area isi what I am interested in.
                       MR. BROWN:  Yes.  We have the -- if you
           want to look at heat flux, we looked at things like
           the Reynolds number of the film, that type of thing. 
           Yes, we're still -- in the AP600, we did a very good
           job, I think, of being able to cover the range because
           were trying to anticipate a very wide variation in
           these things.  So there is a very significant range
           that's covered in those tests.  Very large range.  And
           it's in some of the tables in that report if you look
           back in the containment section you'll see the large
           range that was in there.  I didn't think we had enough
           time to go through that here.
                       We also had done some CFD analysis which
           was very simple.  It was a 2-D slab.  We weren't
           trying to claim that this was -- you're shaking your
           head already.
                       MEMBER WALLIS:  Unacceptable.
                       MR. BROWN:  What we were trying to address
           here was the height to diameter effect.  I mean
           because one of the questions I think that we asked
           ourselves right away was well, mixing and
           stratification was of interest in AP600.  This is a
           very big plant.  And we were increasing it by 25  more
           feet and we wanted to ask ourselves well, given
           whatever AP600 is, how do we compare to this?  So we
           used this as a tool. 
                       When we presented this to the Thermal
           Hydraulic Subcommittee, Dr. Wallis asked us if we
           could just simply rotate this in 3-D and see whether
           or not we could look at the three dimensional effects
           as well.  I see he's still shaking his head.
                       MEMBER WALLIS:  It's a different problem. 
           I mean drawing of a plank is different from drawing a
           log.  Cylindrical geometry is not a plane.  It's
           different.
                       MR. BROWN:  I agree.  The attempt was to
           try to look at what the --
                       MEMBER WALLIS:  I think the attempt was
           good.  Now you have to -- right.
                       MR. BROWN:  That's a start.
                       MEMBER KRESS:  If you're just validating
           that your containment is well mixed, I think the
           ability to well mix 2-D is harder than to well mix the
           3-D and if you can do it with the 2-D, you ought to be
           able to do it with the 3-D.  
                       What do you think, Graham?
                       MEMBER WALLIS:  I don't know.  Maybe
           you're more easily convinced than I am.
                       MEMBER KRESS:  I say that because --
                       MEMBER SHACK:  It's only a 2-D problem. 
           It's just an axis symmetric 2-D problem not a plane 2-
           D problem.
                       MEMBER WALLIS:  So just use
           polycoordinates and solve the equations.  It's simple.
                       MR. BROWN:  All right.  We can scale it.
                       MEMBER WALLIS:  I don't know, what fluent
           does is simply says are you using polycoordinates or
           Cartesian.  You say one or the other and it solves it. 
           You just have to make that decision, that's all.
                       MR. BROWN:  There's a lot of mesh
           generation, a lot of babysitting.
                       MEMBER WALLIS:  Well, most CFD codes just
           generate the mesh for you.  You should do it.
                       MEMBER KRESS:  You should do it just to
           satisfy the naysayers.  It's good for your soul.
                       MR. BROWN:  Okay.  Comment received.
                       MEMBER WALLIS:  Hit me with the bottom
           line.  Is it well mixed or just stratified?
                       (Laughter.)
                       MR. BROWN:  Well, what we found, what we
           saw in the 2-D was we really saw virtually no
           difference.  It was very well mixed.  In fact, it was
           probably better mixed.  It was almost -- when you got
           to the near last several inches of the boundary there,
           you couldn't see any gradient whatsoever.  It was very
           well mixed.
                       MEMBER KRESS:  As I casually mentioned in
           the subcommittee meeting, you're better off if it's
           not --
                       MR. BROWN:  Say it a little louder. 
           Right, that was good.
                       (Laughter.)
                       We're really trying to say is if we allow
           the steam to even allow it to stratify, it's even
           better because we have this nice Raley-Bernard
           convection problem with this very cold surface on top
           of a hot surface, which you would expect would mix
           pretty well.
                       (Slide change.)
                       MR. BROWN:  In conclusion then, we found
           that -- we think that the phenomena looks similar to
           AP1000.  We think we have the test, both separate
           effects and we can find at least one integral effects
           test to cover each phase of the AP1000 small break
           LOCA transient and therefore our analysis codes can be
           validated here and therefore are applicable to AP1000
           and so therefore we should have a sufficient database
           for code validation in accordance with the
           requirements of 10 CFR Part 52.
                       MEMBER WALLIS:  Now that may be a
           reasonable conclusion. It doesn't mean to say that
           you'll reach the same conclusions about AP1000 that
           you did about AP600 when you actually run the codes
           because it may turn out that these small changes in
           geometry and the mass, be more mass here than there
           and so on, actually have fairly significant effect on
           something that matters when you go from 600 to 1000.
                       MR. BROWN:  I agree with you.  And all
           we're saying is we can use the same tool to predict
           that, that's all we're trying to get across here.  We
           agree that the answers could look a bit different and
           I would be a little worried if they didn't probably if
           they looked exactly -- we really expect that we're
           saying is we have the same similar phenomenon so
           therefore we can use the same tool.
                       MEMBER WALLIS:  When we look at those
           answers and we look at sensitivities, it may be that
           you have to get something righter than 1000, let's say
           like entrainment from the vessel or something.  You
           have to model something better with 1000 or maybe
           less, less well.
                       MR. BROWN:  We need the approved Dr.
           Graham Wallis correlation first to do that because
           what else is out there isn't --
                       MEMBER WALLIS:  I haven't had correlations
           for some time.  
                       MR. BROWN:  We need another one.
                       (Laughter.)
                       MR. BROWN:  What's out there right now.
                       Any other questions?
                       DR. ROSEN:  The stage 4 operation of the
           ADS, how does one test that during normal operation of
           the plant?  
                       MR. BROWN:  Terry could probably address
           that, Terry Schulz.
                       MR. SCHULZ:  This is Terry Schulz from
           Westinghouse.  The stage 4 valves are squib valves. 
           So they're not cycled in the plant.  The ASME code
           addresses squib valves in terms of in-service testing
           and what they allow you to do is to remove
           periodically and this is on like a 5 to 8 year basis
           the propellant that would actually operate the valve
           and that's the main question about the operability of
           the valve because everything else is pretty passive
           and simple in terms of the operation.
                       And you remove that after it's been in
           service and you go into a test fixture and actually
           fire it in a test fixture and determine if it would
           have operated.  And by doing this you can then and
           also in terms of the quality and QHX on the
           propellants that you trace through the life from when
           you first made the propellants until you've checked
           it, that's what you would do.  
                       You would also do some inspections to make
           sure the pipes are not plugged up or something like
           that, but the geometry is very simple in the stage
           four.  It's not very complicated at all, very short
           pipes, big pipes.  The main thing is whether the valve
           would operate or not and that's addressed in ASME
           code.
                       DR. ROSEN:  What size valves are those?
                       MR. SCHULZ:  In AP600, they're 10-inch. 
           On the AP1000, they're 14-inch.
                       DR. UHRIG:  Terry, on the squib valves, do
           you do continuity testing on the circuitry from time
           to time?
                       MR. SCHULZ:  I know we discussed that on
           AP600 and I'm trying to remember what we concluded. 
           I think we concluded that we would at least
           periodically do that, like when we change the
           propellant.  We would not do it continuously.  I don't
           know if there's anything else we committed to do.
                       DR. UHRIG:  I'm just wondering because you
           say 5 to 8 years.  I'm wondering just like every year
           or something, you might test the conduit of the
           circuit to make sure that's --
                       MR. SCHULZ:  I'm not 100 percent sure of
           what we committed to there.
                       DR. UHRIG:  Thank you.
                       MR. BROWN:  Any other questions?  Okay. 
           Thank you.
                       (Slide change.)
                       MR. GRESHAM:  Good afternoon.  My name is
           Jim Gresham.  I'm with Westinghouse and I have just a
           few slides here to give you an overview of the
           approach on codes and analysis for AP1000.
                       (Slide change.)
                       MR. GRESHAM:  As has been mentioned at
           least twice already today, probably more, we're
           starting with the computer codes that were used for
           AP600 and approved for that application and just
           assessing the differences in the plant and design test
           and so forth.  So from that starting point we're
           confirming the adequacy of these codes for the AP1000
           design and I have another slide that talks about the
           steps in that.
                       Any potential concerns that there are in
           that review we'll have to address and as well as that
           in the AP600 review and in the AP600 FSER, there were
           some concerns with the codes mentioned.  We are
           addressing all of those.
                       MEMBER WALLIS:  I wonder how you can do
           this ahead of time.  It seems to me that you have to
           actually exercise the code for AP1000 and see what
           kind of things you're getting from it and if you find
           something which concerns you, which didn't concern you
           with AP600 then you're going to have to say it's not
           quite the same.  I don't think you have a carte
           blanche that says because it worked for 600, it must
           work for every aspect of 1000.
                       MR. GRESHAM:  I would agree with that. 
           Some of the items that were mentioned on AP600 I think
           we have to deal with up front.  But you're right in
           that as you look at the analysis results you'll see
           things and you need to understand why.
                       MEMBER WALLIS:  So I don't know that we
           can -- you can reach consensus on this as a starting
           point.  I don't think we can reach consensus early on
           about acceptability until we see how it works.
                       MR. GRESHAM:  Yes, I agree with that
           statement.
                       MEMBER WALLIS:  Thank you.
                       (Slide change.)
                       MR. GRESHAM:  The steps that we used or
           are using to confirm the adequacy of the codes is
           first to look at the important phenomenon that exists
           in the plant and this has been done through the PIRT
           in the scaling report which Bill already discussed
           with you.
                       We need to identify the correlations and
           the models that are used in each of the codes to
           analyze the important phenomena in the design and
           since we're starting with the AP600 approved codes and
           have confirmed the phenomena are the same, that's
           already been done in the AP600 design certification
           process.  We're relying a lot on that information.  
                       Then demonstrate that the test data are
           adequate and for validation of the codes and that has
           been demonstrated in the scaling in the PIRT work and
           then as I mentioned we have to demonstrate that the
           limitations that have already been identified are
           being adequately addressed.
                       MEMBER WALLIS:  And to reiterate, there
           may be some other limitations that emerge when you
           start working on AP1000.  We don't know if there will
           be, but there might be.
                       MR. GRESHAM:  Yes, there might be and --
                       MEMBER WALLIS:  Just the fact that you
           have addressed the AP600 ones doesn't mean that you've
           found all the ones that might apply to 1000.
                       MR. GRESHAM:  Yes.  We have some
           confidence as we proceed through here because nothing
           is identified in the PIRT or the scaling work, but
           certainly all the way through here, we need to be on
           the look out for that.
                       (Slide change.)
                       MR. GRESHAM:  There are several ways that
           we may choose to address these limitations.  And these
           include, there may be one or more of any of these, but
           it's possible to change the design.  Terry talked
           about some of the changes in the design that has led
           to actually more margin in some cases. 
                       We may find the phenomena that we feel
           like we need to do some additional validation to test
           to understand the effects better and then complete the
           story relative to the codes.
                       Just by evaluating that there's a lot of
           margin in some area may be, may go toward addressing
           limitation in the code.
                       We will do in some cases additional
           analyses such as the CFD calculations that we already
           discussed to address a limitation for a code or in
           some portion of the code, either a portion of the
           transient where different phenomena are occurring or
           a particular model that the code has to be able to
           show that we have some concerns about.  And use this
           analysis not as the safety analysis in the SSAR, but
           as additional information to show the effects that
           will occur in the plant that are predicted to occur in
           the plant.  And there may be some cases, we have not
           found any yet, but there may be some cases where we
           believe that we need to make changes to the codes.
                       MEMBER WALLIS:  Well, there's carryover
           into the AS fall line, carryover -- do you have a
           bigger radius for it, do you  have higher velocities,
           maybe?  I don't know what you have.
                       MR. GRESHAM:  It isi larger.  The ADS is
           10 to 14 inch.
                       MEMBER WALLIS:  How well do you model that
           actual entrainment to the Aegis fall out?
                       MR. GRESHAM:  Yes.  I'm not sure about the
           velocities.
                       MEMBER KRESS:  I was about to say it's
           still sonic velocity.
                       MEMBER WALLIS:  No, no, it's actually at
           the hot leg.
                       MEMBER KRESS:  It's about the same
           temperature. 
                       MEMBER WALLIS:  It's about the same?
                       MR. SCHULZ:  This is Terry Schulz from
           Westinghouse.  The connection to the hot leg is
           actually an increase from like 12 inches to 18 inches,
           so it's gone up more than the power has gone up.
                       MEMBER WALLIS:  So you've got more than
           the hot leg.
                       MEMBER KRESS:  You get more flow.
                       MR. SCHULZ:  No, the hot leg is 31 inches
           in diameter.
                       MEMBER WALLIS:  It's a different diameter
           ratio of hot leg to ADS fall line?
                       MR. SCHULZ:  Yes.
                       MEMBER WALLIS:  So you might have to do
           something about modeling that.  It is different
           geometry than the fall.
                       MR. SCHULZ:  Yes.
                       (Slide change.)
                       MR. GRESHAM:  We are working on a report
           to give to the staff, the Code Applicability Report
           where we will discuss the important phenomena,
           referencing back to the work that was done on the PIRT
           in the scaling, to provide a description of the codes
           that we're using to analyze the different accidents
           for AP1000 and look at the code applicability of the
           AP600 codes for application to AP1000 and much of the
           information is in the FSER and some of the documents
           that we provided in support of that and the
           limitations that were identified are also discussed in
           the FSER and we will go through each of these and
           describe how we believe that we're addressing those.
                       MEMBER WALLIS:  Now you said you'd supply
           a code description.  The staff has been actually
           asking for the code itself from other applicants and
           has been getting it and that's something that this
           committee is much in favor of, actually having the
           code itself examined and run by the staff.  That gives
           assurance that it's user independent.  You get the
           same answer and you can investigate things. 
           Everything is in the open.  It would be very desirable
           if that could happen here.
                       MR. GRESHAM:  Well, we're asking the staff
           to look at the code applicability report when they get
           it and discuss --
                       MEMBER WALLIS:  It's all based on
           submissions by Westinghouse.
                       MR. GRESHAM:  Sure.
                       MEMBER SIEBER:  When you're all through
           with the phenomenon logical modeling that you're doing
           here, you have the capability to determine the
           uncertainty in these phenomenon logical codes?
                       MR. GRESHAM:  Not entirely, no.  In the --
           we're using the best estimate, large break LOCA
           methodology using the COBRA track code for the large
           break and the quantification in the convolution of
           uncertainties is certainly involved in that.
                       In most of the other safety analyses,
           we're using a bounding approach where we're
           demonstrating that we have a conservative calculation
           of the consequences of the different accidents and so
           we're covering the uncertainties in that regard, but
           in terms of quantifying the uncertainties, we won't
           have that.
                       MEMBER SIEBER:  So you really won't know
           how much margin you have either.
                       MR. GRESHAM:  Just lots.  
                       MEMBER SIEBER:  I'm not sure that makes --
           lots and great are about the same kind of term.
                       (Laughter.)
                       MR. GRESHAM:  Yes.
                       MEMBER SIEBER:  So the answer is probably
           won't have very much way to quantify margin and
           uncertainty when you're --
                       MR. GRESHAM:  That's right.  We won't have
           a quantification.
                       MEMBER WALLIS:  So on the issue of
           supplying the code to the staff, is that something
           which is still under negotiation?
                       MR. GRESHAM:  Yes, it is.
                       MEMBER WALLIS:  Have you folks seen the
           light yet?
                       MR. GRESHAM:  It's still under
           negotiation.
                       Any other questions?
                       DR. ROSEN:  The ADS, as I understood it,
           the stage 4 is different in AP1000?
                       MR. GRESHAM:  Yes, it is.
                       DR. ROSEN:  It's not in AP600?
                       MR. GRESHAM:  No, it is in AP600, but it's
           larger in the -- I'm sorry, larger in the AP1000. 
           Stages 1, 2 and 3 are the same size, but stage 4 is
           larger in AP1000.
                       DR. ROSEN:  Does the AP1000 have a
           different estimated core damage frequency than the
           AP600?
                       MR. GRESHAM:  I don't believe we've
           calculated that yet.  We have not done the PRA.
                       MR. SCHULZ:  This is Terry Schulz from
           Westinghouse.  Jim is right.  We have not calculated
           that number, but the design approach that we are
           taking relative to PRA is to size the components and
           arrange the systems in terms of the same arrangements,
           same number of valves, same type of valves, so that
           the reliability of the system would be expected to be
           the same.
                       We're trying to from a preliminary design
           point of view, have the same success criterion in
           terms of the number of ADS valves, number of
           components required, so we've actually done some
           preliminary T & H analysis with multiple failures to
           try to check our success criteria.  And that's not
           been done formally and that's not going to be part of
           this Phase 2 staff review of AP1000, but our design
           approach is to try to end up with the same core melt
           frequency by using the same configuration, same type
           of components and same success criteria.
                       DR. ROSEN:  Of course, the ADS valves are
           larger for AP1000 than they are for AP600 so their
           reliability might be different.
                       MR. SCHULZ:  That's usually not a strong
           factor in the quantified reliabilities of components
           within some limitations, of course.
                       MEMBER WALLIS:  Can we move on?
                       MR. GRESHAM:  Okay.  
                       MEMBER WALLIS:  We're a little bit behind,
           Mr. Chairman, but I think we have a little elasticity
           in the schedule that's coming up.
                       VICE CHAIRMAN BONACA:  Yes, we do.
                       (Slide change.)
                       MR. ORR:  My name is Richard Orr and at
           Westinghouse I'm responsible for the design of the
           structures and the seismic analyses and I'll cover
           very briefly some of the evaluation of the structural
           changes and then get into the discussion of the
           approach to design certification.
                       (Slide change.)
                       MR. ORR:  As Mike and Terry have
           described, we have attempted to keep the configuration
           as close as possible for AP1000 to AP600.  The
           configuration was described in a report submitted to
           NRC at the end of last year.  From a structural point
           of view, the main differences are the height of
           containment and associated with that, the height of
           the shield building, so going from AP600 to AP1000,
           everything above this elevation moves up 25 feet.  
                       In plan view, everything looks the same so
           the major change, as I say, is just this increase in
           elevation.
                       We have evaluated these differences and
           concluded that we can accommodate them in the
           structural design.
                       MEMBER POWERS:  Not everything is the
           same, down below there, though, is it?  Aren't the
           steam generators --
                       MR. ORR:  As far as structure is
           concerned, it is identical.  The steam generators are
           bigger.
                       MEMBER POWERS:  But that's not identical.
                       MR. ORR:  Let me get directly to my next
           slide.
                       (Slide change.)
                       MR. ORR:  In our evaluation of the
           changes, we have conducted a seismic analysis of the
           nuclear island and used methodology identical to
           AP600, adjusted the models for the changes for AP1000
           and this includes raising the shield building 25 feet,
           increasing the shield building roof, the PCS tank from
           540,000 to 800,000 gallons.  We include in the
           analysis the containment vessel which is a little bit
           taller and an increased thickness.  We include the
           structures inside containment.
                       The only changes in the structures there
           are the shield walls around the steam generator and
           pressurizer have been extended upwards a little bit
           for shielding.  And we include in the analysis the
           reactor coolant loop which has been modified to
           include the bigger steam generators and the bigger
           pumps.
                       All of these items are included in this
           single model and I'm showing here some typical
           results.  There's a lot more results.  All I want to
           do is highlight three of them here that I've marked.
                       MEMBER WALLIS:  Excuse me.  North,
           southeast, west has something to do with steam
           generators.
                       MR. ORR:  No.  North, southeast, west is
           strictly an orientation we've established for the plan
           view of the AP600.  North is towards the turbine
           building.
                       MEMBER WALLIS:  So the difference is that
           the steam generators are on one side or something? 
           What's different about it?
                       MR. ORR:  About?
                       MEMBER WALLIS:  The two axes, what's -- it
           looks sort of -- it's a symmetrical building, isn't
           it?
                       MR. ORR:  No, the footprint, the shield
           building and the containment sit on a base mat and are
           integral with the auxiliary building.
                       MEMBER WALLIS:  Okay, that's what makes
           the difference.
                       MR. ORR:  The long access is the 
           north-south axis.  The short access is the east-west
           axis.
                       If we look first of all at the seismic
           response at the highest elevation at the top of the
           shield building, the acceleration and this is for a
           three-tenths g input on a hard rock site, the
           acceleration response increases from 1.47g to 1.54, an
           increase of about 5 percent.  And this is really the
           one that controls the design of the shield building
           roof and the 800,000 gallons of water.  We have,
           indeed, done preliminary design of the shield building
           roof and demonstrated that yeah, we can add some
           sufficient reinforcement.  There's no problem.
                       Next one I want to show is what we term
           base shear.  This is sort of the shear force at grade
           elevation that is very significant in the design of
           the shear walls, the shield building and the walls in
           the auxiliary building.  Here, the shear in the north-
           south direction which is the one that increases the
           most, increases from 37.5 to 46.8 which I think is 20
           percent if I recall, 25 percent, sorry.
                       And the other one I want to point out is
           the overturning moment, again, at grade elevation and
           for about the north-south axis which is the shorter of
           the axes, it increases from 4100 to 5500 which is a 33
           percent increase.  
                       We have looked at the effect of this on
           design of the structure.  We find no problems in sort
           of the design of AP1000.
                       I should just point out one of these
           numbers is higher.  About the east-west axis, I
           haven't identified that as a problem.  This is the
           long axis of the building and it's much easier to
           accommodate in the design.
                       MEMBER SIEBER:  None of this includes the
           effect of soil liquification?
                       MR. ORR:  These are all for hard rock.
                       MEMBER SIEBER:  Hard rock.
                       MR. ORR:  We have a site interface
           established that says there shall be no soil
           liquefaction.  That is something the combined license
           has to demonstrate for his site.
                       MEMBER SIEBER:  So that means if you build
           a plant like this, you put it on franky piles or
           something like that to get the hard rock support?
                       MR. ORR:  Not necessarily.
                       MEMBER SIEBER:  That would be a way.
                       MR. ORR:  A hard rock site is acceptable. 
           Something like 50 percent of the existing nuclear
           plants are on rock.
                       MEMBER SIEBER:  Yeah.
                       MR. ORR:  A good soil site, there would be
           no problem.  There are one or two soil sites that
           would sort of require fairly extensive foundation
           work, but then they did for the existing units that
           are there already.
                       MEMBER SIEBER:  I was thinking that a lot
           of the sites may be half or built on river banks which
           is usually silt.
                       MR. ORR:  Yes.
                       MEMBER SIEBER:  Which is pretty liquid.
                       MR. ORR:  The interface we established on
           AP600 and would be applicable here as well, is a shear
           way velocity for the soil greater than the thousand
           feet per second.
                       That excludes one or two of those real
           soft sites.  It basically means you've got to dig it
           all out and replace it by competent material.  Certain
           existing sites have had to do that.
                       MEMBER SIEBER:  Right.  Is there a
           difference between East Coast and West Coast where a
           plant like this might be precluded --
                       MR. ORR:  We have established the seismic
           input design level at three-tenths g which does
           exclude California for the standard design.
                       MEMBER SIEBER:  Okay, thank you.
                       MEMBER KRESS:  What moment can the
           containment stand before it buckles?  Have you
           determined that?
                       MR. ORR:  The critical condition for the
           containment is not internal pressure.  It's the
           combination of external pressure and safe shutdown
           earthquake.  External pressure is a situation where
           you basically trip the reactor on an extremely cold
           day and pull the temperature of containment down
           fairly rapidly and for AP600 that is something like
           negative pressure of 2.5 psi.
                       We designed for an external pressure of 3
           psi and then we combined that with the safe shutdown
           earthquake and we were able to demonstrate for AP600
           adequate margin.  The critical location is at the base
           of containment.  I think, if anything, we'll have a
           slightly greater margin because we've increased the
           shell thickness two inch and three quarter versus inch
           and five-eighths.  So it's an evaluation that still
           needs to be done and it will be included in the Phase
           3 part of NRC's review, but I don't expect it to be an
           issue.
                       DR. ROSEN:  What is the diameter of this
           containment at the operating floor elevation?
                       MR. ORR:  It's 130 feet.  I did check the
           configuration.  It's very, very similar to the
           dimensions of Comanche Peak.  Comanche Peak is 135
           foot ID.  This is 130 and then the shield building is
           further out and the total height is almost identical.
                       MEMBER SIEBER:  What's the space between
           the containment liner and the inner surface of the
           concrete?
                       MR. ORR:  From the inside surface of the
           containment vessel to the inside surface of the shield
           building is a nominal 4 feet 6 inches.  So it's got to
           4 feet 4 and a quarter.
                       MEMBER SIEBER:  All right, thank you. 
           Which is enough for a stairwell, right?
                       MR. ORR:  Oh yes, you can get in there. 
           In fact, we have designed the air baffle to be removal
           for inspection and maintenance purposes.  
                       For AP600, we did extensive seismic
           analysis and structural design.  Clearly, sort of for
           AP1000 we do have some limited resources and there's
           some, much higher priority safety analysis being
           performed.  So we have suggested, proposed to NRC that
           we would use design acceptance criteria for the
           detailed structural design and seismic analyses at
           soil sites.  This approach has been used on other
           certified designs, not quite to the same extent.
                       We would be using the same criteria and
           methodology and these will be documented in the AP1000
           design certification document and we will be
           identifying certain other key information,
           constructural configuration which we've described
           here.  We will present results of the seismic analysis
           for hard rock and present a design of the containment
           vessel in the design certification document.
                       This approach was described in a report we
           submitted to NRC earlier this year.  We have had one
           meeting with them to discuss it.  The detailed design
           analysis would be performed by the combined license
           applicant, would be presented to the staff at the time
           of the combined license application, so it would be
           reviewed and accepted by NRC prior to start of
           construction.
                       Once the combined license is issued, then
           there would still be on-going construction and there
           would still be the same inspection and acceptance
           criteria as we have used for AP600.
                       Thank you.  Any questions?
                       MEMBER WALLIS:  Any questions?  Any final
           words from anyone?
                       MR. CORLETTI:  We have no more words, so
           if you have any more questions.
                       MEMBER WALLIS:  I thought you were going
           to give us some final words.
                       MR. CORLETTI:  No, not really.
                       MEMBER WALLIS:  A finale.  Well, thank
           you, Westinghouse very much.  
                       If the committee has no more questions,
           I'll hand this back to the chairman.
                       CHAIRMAN APOSTOLAKIS:  Thank you, Graham. 
           Thank you, gentlemen.
                       Now we're scheduled to break and work on
           preparing draft reports.  I'm willing to break, but
           I'm not sure we need to prepare any reports.  Is
           anybody working on a report?  I would rather come back
           here and read the first draft of what we have and give
           some advice to the authors and then move on and
           revisit maybe the Commission meeting or do other
           things.  So why don't we break until 4:50 and then
           we'll come back and read this.
                       (Whereupon, the proceeding went off the
           record at 4:35 p.m.)
           
	 
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