Plant License Renewal - February 24, 2000

                       UNITED STATES OF AMERICA
                      MTG:  PLANT LICENSE RENEWAL
                        Clemson University
                        Madren Conference Center
                        Room III & IV
                        Madren Center Drive
                        Clemson, South Carolina
                        Thursday, February 24, 2000
         The above-entitled meeting commenced, pursuant to notice, at
     8:00 a.m.
         MARIO BONACA, Chairman, ACRS
         ROBERT SEALE, Vice-Chairman, ACRS
         THOMAS KRESS, Member, ACRS
         DANA POWERS, Member, ACRS
         WILLIAM SHACK, Member, ACRS
         JACK SIEBER, Member, ACRS
         ROBERT UHRIG, Member, ACRS.                         P R O C E E D I N G S
                                                      (8:00 a.m.)
         CHAIRMAN BONACA:  This is a meeting of the ACRS Plant
     License Renewal Subcommittee.  I am Mario Bonaca, Chairman of the
     Subcommittee.  The other ACRS members in attendance are the Vice
     Chairman of the Subcommittee, Robert Seale, Thomas Kress, Dana Powers,
     William Shack, Jack Sieber, and Robert Uhrig.
         The purpose of the meeting is to meet with the
     representatives of the NRC staff and the Duke Energy Corporation to
     discuss the staff's resolution of the open and confirmatory items
     identified in the Safety Evaluation Report related to the license
     renewal of Oconee Nuclear Station, Units 1, 2 and 3, and related license
     renewal activities.  Our Subcommittee will gather information, analyze
     relevant issues and facts, and formulate proposed positions and actions
     as appropriate for deliberation by the full Committee.
         Noel Dudley is the Cognizant ACRS Staff Engineer for this
         The rules for participation in today's meeting have been
     announced as part of the notice of this meeting previously published in
     the Federal Register on January 13, 2000.
         A transcript of the meeting is being kept and will be made
     available as stated in the Federal Register Notice.  It is requested
     that the speakers first identify themselves and speak with sufficient
     clarity and volume so that they are readily heard.
         We have received no written comments or requests for time to
     make oral statements from members of the public.
         Yesterday, the Subcommittee toured Oconee Nuclear 
     Station and meet with representatives of the Duke Energy Corporation to
     review the details of how Duke conducted the license renewal scoping and
     aging management review processes.
         Before we proceed, Jack Sieber of the Committee needs to
     make a statement.
         Mr. Sieber:  Thank you, Mr. Chairman.  I would like to place
     on the record the fact that under Federal Ethics Laws I am not eligible
     to vote on matters effecting Duke Energy Corporation because I am a
     stockholder of Duke Capital Corporation, and, therefore, my non-voting
     should be construed in that light.  Thank you.
         CHAIRMAN BONACA:  Thank you.  We will proceed now with the
     meeting and
         I call upon the Duke staff to begin.  Good morning.
         MR. GILL:  Good morning.  Thank you, Dr. Bonaca.  My name is
     Bob Gill.  I am on the Oconee License Renewal Team.  I'm here to start
     our presentation.  And on behalf of Duke Energy, the Team, and, of
     course, Oconee Nuclear Station, we welcome you to the upstate South
     Carolina area.  Hope you've enjoyed your visit, your short visit
     although it may be.
         We have several presenters today to go over topics of
     interest that have been identified.  Before I do that, let me go through
     just a little bit of a background before we get into the first topics. 
     I'm going to cover briefly the project status, where we are.  This is a
     very important meeting, because it is leading up to the recommendation
     by the staff in the next couple of weeks.  There were three open items
     that the Committee decided they would like to review in depth; the
     resolution of scoping methodology, electrical insulated cables and
     connecters, aging management program, and vessel internals.  We have
     presentation prepared on each one of those.
         Briefly, on the status, the current status as we understand
     it is that the Recommendation Letter to the Commission will be sent by
     the staff by April 14.  There are a number of milestones that have to be
     completed before then, many of which have already been done.  The
     Facility Operating License, the new draft, has been provided us for
     review.  We have a meeting scheduled on March 19th with the staff to go
     over that.
         There were no technical specifications or changes
         The Final Safety Evaluation Report, which we have copies on
     the table, have been published by the staff.  We were very welcome on
     that.  A lot of good work has gone on both sides there.
         The UFSAR Supplement, a draft, was provided to the staff and
     the staff is reviewing that.  We intend to formally submit a revised
     UFSAR Supplement by the end of March so the staff can have that as part
     of the package.  We are expecting a Region II Recommendation Letter by
     the end of March.  There is a site inspection scheduled for next week,
     with a Public Exit Meeting the end of next week announced.
         Final Supplemental Environmental Impact Statement was
     received in December.  That closed out all the environmental reviews
     associated with renewal of the license for Oconee.  We are expecting
     your recommendation Letter in a couple of weeks, after the full
     committee has a chance to review all the issues.
         And for the final piece was the Indemnity Agreement, which
     was required by the regulations to be looked at.  We did not identify
     any changes.  I believe the staff has concurred in that.
         So, those eight pieces are the total package that we needed
     to renew the license.
         The purpose of this morning's discussion is for us to
     provide additional information to the members of the committee on the
     resolution of three open items, and the insights that we used to do
     that.  We will follow the handout that is in here.
         The first item that will be discussed is the Scoping
     Methodology, with Rounette Nader.
         Second, will be Paul Colaianni talking about the Electrical
     Aging Management Program on cables and connectors.
         And, finally, Jeff Gilreath from our corporate office staff. 
     And you see a couple of models here and diagrams of the vessel
     internals.  That will be our last presentation, and we will be able to
     answer any questions the staff has on that.
         Are there any questions at this point in time on what we are
     covering?  I turn it over now to Rounette Nader, who will go over the
     Scoping Methodology validation that we did late last year.
         MS. NADER:  Thank you, Bob.  I'm Rounette Nader with Duke
     Energy.  I'll be discussing the Scoping open item.  On slide number
     seven, we have the issued defined and the resolution, all here together
     at the beginning.  But the issue really evolved into from the scoping
     open item was, is the set of events that was considered by Oconee
     license renewal scoping methodology sufficient for scoping.
         The issue was resolved by case study.  Ten events 
     identified by the NRC.  Duke researched the licensing basis of the ten
     events, and the end result was that the scoping methodology had
     identified all the appropriate systems, structures and components for
     license renewal.
         On slide number eight, really the next three slides, eight,
     nine and ten, are a chronology of some of the things that occurred
     between Duke and NRC on this issue.  I'm not going to go through each of
     these.  It is really more just to show the rigor of what really went
     into this issue.  You can see that Duke submitted the license renewal
     application in July of 1998.  And in October of '98 the NRC staff,
     several members traveled to Charlotte to look at the internal
     documentation related to scoping.
         Several meetings occurred.  The request for additional
     information was issued in December.  Several meetings occurred the first
     half of '99.  On slide number nine you will see the second half of '99
     were more meetings.  The SER open item was issued.
         On slide number ten, on October 28th of 1999, which was a
     year and a day after our first meeting, Duke and NRC had a meeting to
     discuss resolution of the issue.
         Duke submitted the response in November and the SER that was
     issued just this month closed the open item.  To really understand the
     technical basis behind the issue, on slide eleven begins a presentation
     of, really of the Oconee scoping methodology for license renewal.  The
     methodology for all three disciplines combined, we have boiled down into
     seven steps.  The first four steps were the mechanical steps for
     mechanical scoping.
         So the first step was to identify functional flow paths,
     mechanical functional flow paths required to mitigate design basis
     events for Oconee.
         The second step was to add pressure boundary to these flow
     paths.  Passive pressure boundaries required before you could impact the
     flow paths.
         The third was to identify physical interference commonly
     known as two over one, any piping whose failure could interfere with a
     safety related or a central system.  On slide twelve, the fourth step,
     was to capture any other safety related or seismic equipment at the
     plant that had not already been identified.  Because of Oconee's design
     there were some incidences where there were safety related piping that
     didn't get identified in the first three steps.  They got identified in
     step number four.
         From a structural standpoint starting with item number five,
     class one structures meet the 54.4(a)(1) criteria.  Class two structures
     meet the (a)(2) criteria.  Those were scoped by looking in the UFSAR for
     those definitions.
         Step number six was electrical in nature.  You heard about
     the spaces approach.  All electrical components were initially assumed
     to be within scope, and then the screening staff screened out active
         In step seven was to meet the 54.4(a)(3) criteria, which was
     to look at the licensing basis of the five regulated events that are in
     (a)(3) and include those systems, structures and components within
         So upon completion of these seven steps, the scoping for
     license renewal was complete for mechanical, structural and electrical.
         On slide thirteen we did a graphical representation of the
     methodology and really the results.  You can see on the pie chart the
     structural pie piece, the electrical pie piece, the 54.4(a)(3), the
     regulated events pie piece.  On the top piece of the pie is the
     mechanical methodology.  It is broken into the four steps that I just
         The first step, the input into the first step, is really
     the issue of the open item.  The first step was accomplished by
     identifying the functional flow paths required for design basis events. 
     What are those events, that's how the issue got identified.  So with
     design basis events, the passive pressure boundary, the seismic two over
     one, and the other safety related in seismic.  So we felt like the focus
     of the issue was really -- is there anything, any little bump in this
     pie that should be added.  The NRC had concern that there were other
     events that Oconee should have considered when scoping for license
         So what did Duke consider as a design basis events.  Design
     basis events are as the term that is used in 54 for scoping.  Oconee's
     UFSAR, Chapter 15, is the accident analysis chapter for Oconee.  The
     first sentence, the introductory sentence for that chapter, is the
     following:  "This section details the expected response of the plant to
     which the spectrum of transients and accidents which constitute the
     design basis events."  So, historically, this is
         the -- the Chapter 15 accident analyses are the events that
     Oconee has considered the design basis events.
         Modern day regulations get written very similar to the way
     54.4 is written.  When applying these regulations to Oconee, it is
     important to recognize that Oconee's design really preceded the
     regulation that defines these on-basis events today in 50.49.  We had
     our definition that was on the previous slide, on fourteen.  We did
     institute a project in the early 90's to really confirm since all the
     regulations that were coming out really used this new type of
     methodology and new approach.  To confirm Oconee's licensing basis and
     design, and they really confirmed that the UFSAR Chapter 15 events are
     what constituted the licensing basis for Oconee as the design basis
         In addition, this project said, the end result of the
     project said, you know, really since original licensing there have been
     some other events that have come up through licensing that are really
     important.  When you are scoping these regulated programs you should
     probably consider these additional events.  A license renewal was an
     issue that did that.  We call them scoping events.  It goes beyond the
     Chapter 15 licensing basis, design basis events.
         On slide sixteen, the definition of the scoping events that
     was used by Oconee for license renewal scoping.  For the design basis
     events in Chapter 15.  Natural Phenomena Criteria, which are in Chapter
     3 of the Oconee UFSAR.  The Post-TMI Emergency Feedwater Designs, the
     scenarios associated with that.  And the Turbine Building Flood, which
     is mitigated by the Standby Shutdown Facility.  You saw that in your
     tour yesterday.
         So the Chapter 15 events, plus these other three criteria,
     were the scoping events set that was used by Oconee scoping.
         So throughout the year as Duke and NRC had our meetings and
     our correspondence on the issue, we finally came down to Resolution, the
     NRC Perspective, as you see on slide seventeen.  It is the staff believe
     that more events should be considered, and should have been reviewed in
     order the insure the functions identified in 54.4(a)(1).
         So the resolution was for Duke to conduct a case study of
     ten additional events that were identified by the staff and given to
     Duke, and to research the current licensing basis and these five
     documents:  Commission regulations, license conditions, Commission
     orders, the UFSAR, and exemptions.
         On slide eighteen, the purpose of the case study was to
     really validate the scoping methodology that had been performed by
     Oconee, the seven steps that we just spoke of.  That those seven steps
     as executed identify all the SSCs required to be within the scope of
     license renewal for 54.4.
         On slide nineteen you can see the results of the case study. 
     The assessment performed by Duke revealed that the current licensing
     basis associated with those ten events did not identify any additional
     systems, structures, or components that met the license renewal scope
     that met the criteria of 54.4.
         The final SER that was issued earlier this month agreed with
     that, the Duke assessment.  That no additional SSCs needed to added to
     the scope of license renewal.
         So slide twenty is the conclusion from the case study.  The
     Oconee License Renewal Scoping Methodology is described in the
     Application in that you saw in the seven steps that we just described,
     identified all systems, structures and components relied upon to remain
     functional, to insure the functions identified in 10 CFR 54.4.
         The case study provided the validation for Duke and the NRC,
     that the methodology that was employed by Oconee, by Duke, was indeed
     sufficient.  And the NRC could use that validation in making their
     finding that the scoping methodology was sufficient and that the results
     were sufficient.
         The final SER, as I mentioned before, did resolve the
     issue.  It closed the open item related to the scoping issue.  It does
     talk about the validation that was done, the case study that was done,
     and that the NRC gave reasonable assurance that the set of events that
     were used in the scoping methodology were sufficient to get all the
     important SSCs in the plan, and all the SSCs that met the license
     renewal scoping criteria 54.4.
         We feel good about our scoping methodology.  We've felt good
     about our scoping methodology for awhile.  Our project that was
     instituted at the beginning of the early nineties, like I mentioned
     before, did a validation of Oconee's licensing basis, and design basis. 
     We felt good because we felt like we were consistent with our current
     licensing basis.  You saw the statement of the Chapter 15 of UFSAR.  We
     felt like our scoping process was really applied in accordance with the
     rule.  We read the rule, we read the SSCs.  We felt like the methodology
     we employed was a good one.
         We were also consistent with other regulations, regulations
     that used the same type of wording, such as maintenance rule, in-service
     testing, scope, motor operated valve testing scope.  Other regulative
     programs that have been instituted in the last decade or so that used
     the same kind of words, the license renewal scoping methodology was very
     consistent with those.  And traditionally when you look at the plant,
     you look at Oconee, you pull out the drawings to see what is in license
     renewal scope, we feel like we really captured all the important
     systems, structures and components.  Just a gut feel.  All the SSCs that
     we traditionally view as important to a plant, we really feel like we've
     got them.
         CHAIRMAN BONACA:  One of the main events that you reviewed
     for the items, and you yesterday described to me that was a study that
     was done -- could you tell me the dates when it was done?  At least to
     the extent that the review that that accident evolved?
         MS. NADER:  That's true.  One of the events that was
     researched in the case study was a high energy line break event that
     Oconee had done a report on in 1973.  It was based on a Jim Bouso, Mr.
     Jim Bouso letter that was issued really after Oconee Unit One was
     licensed, but before Oconee Units Two and Three were licensed.  The
     report that was conducted looked at the susceptible locations of high
     energy lines, where they might break, and what sort of safety related
     components it may impact.
         There were some resultant actions that came out of the High
     Energy Line Break Report.  There were several modifications that had to
     be done to the plant in order to insure that the plant could be safely
     shut down in the event of a high energy line break as such.
         One of the ten events was the high energy line break.  We
     did review the report.  We had Duke and the NRC, we had some guidelines
     on what sort of things should be reviewed.  The UFSAR talks about the
     high energy line breaks.  The licensing basis associated with the high
     energy line breaks were the -- there was actually a license condition on
     Unit One to get the modifications performed.  Units Two and Three, we
     did the modifications before they started up.
         So we looked at the licensing basis associated with high
     energy line break and determined that the systems, structures and
     components that were within the licensing basis for that event were in
     the scope of license renewal.
         CHAIRMAN BONACA:  I guess the question I have is from the
     perspective of ACRS and the review you performed.  There should have
     been a scope, a review of that particular event, right?  Because, I
     mean, it is part of your licensing basis and I was curious to know why
     in your going through the first six events that we went through did not
     include that one.  I'm sure that one already was reflected in your
     piping systems.  You showed us those diagrams.  I'm just trying to
     understand for future applications the fact that why you would not have
     included that specific event as one that you used originally.
         MS. NADER:  That event is discussed in the UFSAR.  It is in
         Chapter 9, I believe, of the UFSAR.  It is not one of the
     Chapter 15 accidents in the UFSAR.  It is not traditionally considered a
     design basis event for Oconee.  It was used as part of the design for
     Oconee, a design criteria to insure that you don't route high energy
     lines over safety related switch gears.  But as far as having an
     accident analysis, you know, such as a safety analysis on this event, we
     traditionally don't treat this event as a design basis event that is
     included in scoping.  Like I say, if we modified the plant correctly the
     way we were supposed to according to the license condition, and we
     perform our modifications like we should, and we don't route the high
     energy lines over safety related piping, then there is really, there is
     really ---
         CHAIRMAN BONACA:  Certainly.  But shouldn't beginning the
     scope that you cover to include more than Chapter 15 events.  In fact,
     on the list of items in which you gave us, I believe, they would be on
         MS. NADER:  That's true.
         CHAIRMAN BONACA:  I'm not questioning the scope of which you
         covered today.  I'm only asking questions about these events
     in my judgment should have been part of the original review.  And it
     would fit within the categorization that you've described here which say
     Chapter 15 events plus, TMI, and I can't find it now.
         MS. NADER:  It is on slide sixteen.  There were several
     reasons for identifying the plus; the Natural Phenomenon, the Post-TMI
     Emergency Feedwater scenarios, and the Turbine Building Flood.  Some of
     them were based on risks.  The biggest thing I think that really went
     into the plus events, if you will, is the fact that they bring in
     important parts of the plant.  If you exclude the plus, for example, you
     will not have the standby shutdown facility within scope.  You saw it
     yesterday.  It is a pretty impressive facility.  It is safety related. 
     But it would not come in the scope for a Chapter 15 event because it was
     all in post-licensing.  It was not an event that was added to Chapter
         CHAIRMAN BONACA:  And, again, on slide number sixteen you
     have expanded the basis from Chapter 15 with other things.  You showed
     us diagrams yesterday, and I'm sure that the high energy line break
     locations for physical interactions I think have been identified in some
     of the diagrams already.
         MS. NADER:  That's right.
         CHAIRMAN BONACA:  Okay.  For the purpose of to get license
     renewal in general, that to me is an understanding of where the staff
     was going and I think that it was good that this was done as part of
         MS. NADER:  And I think that's the thought process that went
     into these, the plus events, was that if you really did scope using
     Chapter 15 and these plus events, you have bound things like high energy
     line break.  That's what we found out from the validation and from the
     case study.
         Any other questions?  Comments?
         CHAIRMAN BONACA:  None, thank you.
         MS. NADER:  Okay.
         MR. GILL:  Next up we will have Paul Colaianni, who is our
     electrical lead engineer on the license renewal project.  He will
     discuss in detail the Insulated Cable Aging Management Program that
     we've added, that was not part of the original submittal.  That was
     added to the program late last year.
         MR. COLAIANNI:  Hello.
         CHAIRMAN BONACA:  Good morning.
         MR. COLAIANNI:  All right, we will start out, basically this
     open item was opened up after the original review of plants UFSAR came
     out.  It came out of the on-site inspections, and basically a review
     offered experience, showed that, indicated that something was needed. 
     The items basically fell into two categories that are generated via the
     program that came out of this.  And, basically, to resolve the item,
     basically Duke committed to initiate a cable aging management program. 
     I will go through the details here.
         We pretty much included all the verbiage in these, we tried
     to make them readable so you'd have all the details.  So, we will take
     the two separately then, thermal/radiation aging versus moisture aging.
     So, this is the thermal/radiation aging.
         Basically, what was found was insulated cables in a small
     number of localized areas in containment were identified in station
     problem reports as exhibiting accelerated aging due to their proximity
     to this high equipment.
         Corrective actions, these, of course, showed up in the
     problem investigation reports.  Corrective actions at the time tested
     the cables and they were all functional.  So that confirmed that. 
     Future surveillance was also put into corrective actions.  Modifications
     to eliminate the adverse environments were to be evaluated.  That's the
     corrective actions that came out of it.  Yes?
         DR. SEALE:  Have you got any indication based on the initial
     examinations where things were still functional, that down the road you
     might expect a deterioration in performance and that was the reason for
     the future surveillance item that is in that bullet?
         MR. COLAIANNI:
         Yeah.  There were not -- if the cables look in a condition
     that they seem to accelerate at that same rate, you might have a
         DR. SEALE:  Okay.
         MR. COLAIANNI:  Yeah, that was the reason for continuously
     monitoring of the area.  The evaluation of the modification, I mean, the
     ideal situation where you can actually eliminate it.  One case was where
     they had routed some cables over a large feedwater line.  The ideal
     would be to fix it, shield it, so that you no longer have that design
     feature in that area.  So that's the thought process behind that.
         DR. SHACK:  How were the problems identified?  That's
     basically visual inspection, saw degraded cables, or functional
         MR. COLAIANNI:  No.  Visual inspections.  Some of them were
     actual dedicated walkdowns, but these same areas were also found just by
     maintenance people walking around doing their jobs and they would notice
     something and report it back.  Then an engineer would come out and
     evaluate it.  But it turned out that many of these got identified more
     than once, so you had more than one PIP on the same area simply because
     the area kept being noticed by maintenance people.  But walkdown
     inspections, just visual indications were what was noted.
         When these are identified in the early stages of license
     renewal review, this is like 1996 time frame.  This is the walkdowns I
     told you about yesterday, that I went over.  A lot of these were
     initially noted in PIPS at that time.  The problems were judged to be
     design installation problems and not relevant to license renewal.  That
     may seem, on hindsight it kind of looks strange to say that, but at the
     time what we were thinking was, you know, we were trying to draw a
     distinct line between design problems, or maintenance problems, versus
     actual aging problems.  So that was the judgment that was reflected in
     the original application, that these were design issues that should be
     dealt with more in the modification area to alleviate the problem rather
     than an aging issue that should be part of license renewal.  So, that is
     kind of what got reflected in the original application.
         CHAIRMAN BONACA:  But you may have a design feature, not
     from a cable but from the environment that is causing the aging problem.
         MR. COLAIANNI:  Right.
         CHAIRMAN BONACA:  So the environment is part of the license
     renewal, but not from the aging then because you can just make the same
     application, eliminating that environment.
         MR. COLAIANNI:  Right.
         CHAIRMAN BONACA:  So, you are addressing that?
         MR. COLAIANNI:  Yes.  Yes.  And as you will see in the next
     slide the progression that went on, basically, in what we realize now is
     that if you have a design installation problem that you don't fix, then
     basically then you've got an aging problem that is part of license
     renewal.  But if they went ahead and fixed it so to alleviate the
     problem and it goes away, then it is not an aging problem.  So it is
     kind of a progression of thinking through the process.
         So, as I was just describing, basically in 1999 now that we
     did the on-site inspections, the problem reports were identified by the
     staff.  The problems the staff identified as indications that aging
     management was needed, which was a good call because the areas had not
     been modified to alleviate the problem.  So that is basically what this
     explains here.  So we agreed at that point since the areas had not been
     modified to alleviate the problem then aging management was needed. 
     And, basically, these sort of lessons, I call as lessons learned.  I
     tried to, you know, the incident I told you about yesterday, give them
     this type of lesson meaning, you know, if you discover in walkdown
     something that you can label as a design and replace the problem.  If
     you don't ever fix it, then you better include it in the license renewal
     program, because then it becomes an aging problem.  If you are going to
     fix it, take care of it then and you won't have to worry about it.  So,
     that is one of those lessons to learn going through this process the
     first time.  It is always a challenge to label something.
         CHAIRMAN BONACA:  Say that you didn't go through license
     renewal till you find some cable like that, what would you do?  I mean,
     you would just have the decision to either remove the cause of the
     problem by corrective action, or just simply monitor.  That depends on
     if they have built it in the system, right?
         MR. COLAIANNI:  Right.  Yeah, and it may depend on a
     particular situation.  But, the continued surveillance of that
     particular area would go on and either we'd modify it or continue to be
     surveilled down the road.  License renewal just more or less made that
     process a commitment to make sure that that actually does get done as
     part of the program.
         CHAIRMAN BONACA:  But it is not different from what you
     normally would do?
         MR. COLAIANNI:  No.
         CHAIRMAN BONACA:  This is just establishing some specific
     commitment that you would do it?
         MR. COLAIANNI:  Right.
         CHAIRMAN BONACA:  An alternative to just simply moving the
     environment that is caused by the design problem?
         MR. COLAIANNI:  Right.  Now even in this stage, even though
     those areas will be wrapped into the program, if they actually do modify
     them in the future to alleviate the situation, the adverse environment,
     then basically they can be brought back out of the program.  Then there
     would be no need to have them in there.
         CHAIRMAN BONACA:  Yesterday you showed us some very
     aggressive inspection on your part, which I think should be commended. 
     You wrote down a lot of systems, and you showed snapshots of areas where
     there were indications of challenging the equipment.  Is this just a
     one- time initiative, or is it going to be part of this aging management
     program, which you are going to have walkdowns with some frequency?
         MR. COLAIANNI:  The inspections that are envisioned, even
     though we found in specific areas, basically around the steam generators
     and pressurizers revealed some hot pipes we found specific areas.  The
     inspections themselves are going to be enlarged to basically say, you
     know, basically we are going to look around all areas that the steam
     generators where you have cables to see if you have these things.  In a
     three or four foot proximity all around the pressurizer is where you
     might have cables.  Those are the areas that are most prone to where
     these problems would pop up.  So it should make sense to just include
     the whole area around the steam generator and pressurizer in the
     inspection program.
         CHAIRMAN BONACA:  So you really haven't identified, or you
     will in
         the aging management program of cables with specification
     location which are regulated by the aging program?
         MR. COLAIANNI:  Right.  And one of the elements you will see
     in there, because those fall close to hot equipment basically, you've
     got that similar adverse environment from the cables and those
     similarities.  So that would also be included.
         CHAIRMAN BONACA:  Okay.
         MR. COLAIANNI:  I've already covered this.  Next slide.
         Mr. Sieber:  While you are doing that, there are some
     cables, power cables and control cables that you can't visually inspect. 
     Those are ones that run in duct lines or conduits.  What steps are you
     taking with those types of cables to insure that their condition is
         MR. COLAIANNI:  In our Reactor Building we have very few
     cables in conduit, basically because we have the armored construction
     cables.  So that is really not a problem.  In most places we have very
     limited use of conduit for areas that would just be subject to heat
     degradation.  Now, the moisture degradation issue is covered, and I'll
     be covering that in some later slides for medium voltage cables exposed
     to moisture.
         Mr. Sieber:  All right.
         MR. COLAIANNI:  So what we came out with, this is the part
     of the program specific to the Thermal and Aging, Radiation Aging
     Effects.  Basically, all in-scope cables installed in adverse, localized
     environments will be inspected.  And those adverse localized
     environments basically, since they sort of did it on a spacing approach,
     basically we are going to be inspecting areas looking at cables and
     areas as opposed to specific identified cables.
         And, again, because of the way the rule is set up, these do
     not include the acute program cables.  They are already in an adequate
     program.  The staff found that to be adequate for managing the aging of
     those cables.  They've already been through a lot of pre-testing for
     their environments.  So, this program itself does not explicitly include
     EQ cables, although in the inspections you are not really determining
     whether something is in or out of EQ, but this is more of a programmatic
         Accessible cables in these areas will be visually inspected
     every ten years.  Basically what you are going to be looking for is
     cable surface anomalies to be used as an indication that something is
     going on with the cable.  You obviously can't see the actual
     installation, that installation, which is the thing that really matters. 
     But you are looking for surface indications that something is going on
     with the cable.  So, these are the types of things you would look for in
     addition to other things.  We've got a guide that I can show you that
     gives a lot of information on what kind of things to look for and where
     to look for them.
         Unacceptable indications found during the inspections will
     be investigated further by engineering.  So, basically where something
     is found either by a maintenance person, going through and identifying
     something, or an engineering problem itself, finding something, if it
     looks, and depending on how it looks, further investigation would be
     done and it could include testing and any sort of corrective actions
     that seem appropriate.
         MR. UHRIG:  In the armored cables are you looking for dents
         in the armor?  What kind are you looking for?
         MR. COLAIANNI:  Actually, in a lot of cases there are some
     cables in the Reactor Building that just have the armor on the outside. 
     But there are quite a lot of cables.  In most cases you are more
     concerned with control of the cables.  Those do have jackets that you
     can see, or they have a braided armor and you can actually see the
     jacket underneath the braided armor, or you can see deterioration of the
     braid.  But you can actually see it.  There are those pictures I showed
     you yesterday.  You can actually see there is some deterioration that is
     going on.  Although we do have armored cable, it might seem kind of
     strange to look for surface dents, but there are indications that you
     can see.  This was found in the PIPS.  Basically, a lot of things can be
     seen.  A lot of things have been seen as time goes on.
         So now we will move onto the Moisture, Medium-Voltage Cable
     Moisture Aging Effect part of the program.  The history is basically on
     the outside inspection reviews.  Areas of particular concern to
     inspectors were water collection and cable trenches and potential
     degradation of direct-buried cables.  To answer those concerns during
     the inspection, basically Oconee cables installed in trenches are
     designed for a rain and drain type exposure.  The inspection reports for
     the direct buried cable tests, as also documented in the inspection
     report, do not show, do not indicate ongoing degradation.  So, we feel
     good about at least the rate of whatever mechanism involved with those
         We did have one LER of a medium voltage cable back in 1980,
     where the cable failed.  The documented root cause of that was their
     moisture intrusion due to improper installation, due to damage of the
     jacket during installation, or improper installation where water was
     allowed to intrude into the end of the cable.  But those were the
     documented root causes in the LER itself.  But that's the only instance
     that I'm aware of of medium-voltage cable failures with the conduit at
         CHAIRMAN BONACA:  How was this failure identified?
         MR. COLAIANNI:  It was identified as part of testing of the
     motor.  It might have been a mega test, but I'm not positive, but they
     were testing the service and found an indication and narrowed it down to
     the cable itself.
         CHAIRMAN BONACA:  So there was nothing to -- it was just
     part of a test?
         MR. COLAIANNI:  Right.  So based on the site inspection, the
     staffing concluded that aging effects for medium-voltage cables exposed
     to moisture were applicable to Oconee and that aging management was
         So here we have the program elements pertaining particularly
     to this aging effect.  Basically the program includes an inaccessible
     in-scope medium-voltage cables installed in adverse localized
     environments in conduits and direct-buried.  Water collection in
     manholes will be monitored to prevent cables from being exposed to
     significant moisture as a preventive action.  Inaccessible
     medium-voltage cables exposed to significant moisture and voltage will
     be tested at least every ten years.  Now, basically when we talk about
     significant -- I use the term significant moisture and significant
     voltage.  Those are defined as part of the program.  It depends on the
     particulars of the cable itself as to what to submit.  We do have the
     framework of definition.  If you are not real sure of what your cable is
     capable of withstanding when we talk environments, we have sort of a
     threshold value in there.  But a lot of it depends on how the cable is
     designed, what environment it is designed for.  You could have a
     submarine cable which is designed for a hundred percent exposure, a
     hundred percent voltage all the time.  So that does depend on the cable
         MR. UHRIG:  What kind of testing are you talking about
     there, measuring the resistance, the pulse transmission?
         MR. COLAIANNI:  Right now, and because the first testing
     under this program will not be done for another decade, didn't specify
     what type of test.  Basically, before the test is performed, the cable
     engineer with the help of our NGO cable engineer, would determine what
     is the best type of test performed and to give him the best information
     on the individual cable.  But that really won't need to be determined,
     won't be determined till another decade before the test.  And hopefully,
     you know, mainly because there could be new test arise between now an
     then.  A lot of the test that we will replace now, that may not look
     good now, maybe customized down the road.  So we didn't want to specify
     and lock into any particular type.  But it would be something that would
     give the cable engineers a good confidence about the condition of the
         CHAIRMAN BONACA:  But you plan to do the testing?  You've
         to some testing by what?
         MR. COLAIANNI:  The first test would occur sometime before
     the end of the Unit One initial period of operation.
         CHAIRMAN BONACA:  And you would have a bona fide program at
     the time, of course problems can change as you learn more, or something
         MR. COLAIANNI:  That's correct.  The program would be fully
     in place before the first test would be performed.  So this is the
     reason we are talking prior to each test, the specific type of test
     performed along with test acceptance criteria will be determined.
         The criteria will depend on the type of test, and what are
     the particulars at the time, and the particular type of cable.  The
     cables not meeting the test acceptance criteria will be investigated
     further by engineering, be it testing, be it replacement, whatever seems
     to be corrective action.
         All right, so those are the particular aspects to each of
     those types.  Now, there are aspects of the program that deal with both
     thermal aging and moisture.  These are basically that a determination we
     made as to whether an identified unacceptable condition or situation is
     applicable to other accessible or inaccessible cables.  So in the case
     of thermal or radiation, of course you can't see cables in the middle of
     a bundle.  So if you see some indications on the surface of the ones you
     can see, you know, an evaluation would be determined whether is that a
     condition applicable to other cables that I can't see.  And the same
     thing for the moisture.  They find some cables and they do a test and
     they find an unacceptable condition, an evaluation would be done.  Is
     this occurring on other units with the same configurations, but that
     would be applied.  The initial inspections or tests would be completed
     by February 6, 2013.  That is the end of the initial four year period
     for Unit One.
         And to use as a guidance, there is a new document posed
     by EPRI now that gives good walkdown guidance.  Here are some of the
     kind things we look for, here is a good way to organize your activities
     related to these things.  And it will be used as guidance to the process
     of completing the program.
         I think that is it.  Any questions?
         With this we feel confident that we will be able to manage
     the problems that were seen by the staff in that whole process of
     license renewal.
         CHAIRMAN BONACA:  Thank you.  Any questions?  Thank you.
         MR. GILL:  Jeff Gilreath will come up now and he'll talk
     about Vessel Internals.  We have a display over to the side.
         Do we want to bring that up before here so you can use it
     here, Jeff?
         MR. GILREATH:  People can look at it there.
         MR. GILL:  Okay.  So on the break perhaps we will talk more,
     if that is all right, Dr. Bonaca.  We do have some backup slides that
     will give the details on each specific location.  Jeff has been involved
     for several years in industry efforts of vessels internals.  He is
     well-versed in the current activities.  They are ongoing, not only at
     Duke but also in Anderson.
         MR. GILREATH:  As Bob said, my name is Jeff Gilreath.  I
     work in  Materials, Mileage and Piping group for nuclear engineering
         The purpose of the presentation today is to review how Duke
     Power addressed the open items concerning reactor vessel internals. 
     Directly, there were six open items that we needed to address on certain
     reactor vessel internals.  One had to do with potential void swelling,
     potential changes.  The second had to do with potential cracking due to
     radiated assisted stress corrosion cracking, radiation embrittlement. 
     And basically the 3 and 4 materials, reactor vessel internals, the third
     had to do with cracking of the baffle former bolts.  So there has been
     some cracking identified in industry on back about baffle former bolts
     to date and the potential effect that could occur in the license renewal
     period.  The fourth had to do with the embrittlement of cast austenitic
     stainless steel.  The concern there was that we knew that there was
     thermal embrittlement, and we know that there is potential for radiation
     embrittlement.  But is there any synergistic-type effect and do we have
     the material properties to evaluate that.
         The fifth had to do with the thermal embrittlement of the
     vent value.  And that, too, is just that a vent value has a
     castaustenitic stainless steel body and it has a retained ream that is a
     martensitic stainless steel.
         And then the last had to do with the reduction of fractured
     toughness of the internals to the radiation embrittlement.  Duke
     resolved these issues in the end by committing to an inspection plan to
     inspect what are the effects of these particular mechanisms, and also to
     participate in industry and research and to report our program at it
     matures and evolves over the next few years.  On slide 34, just to point
     out different components of the internals.  In the internals, and there
     is a picture over here, and even our model, you can look at that later,
     it is really made of two sections.  It has a plenum area that is removed
     when we defuel every outage.  In the plenum area assembly there is a
     sixty-nine control rod guide tube assembly.  Within these control rod
     guide tube assemblies, there are actual spacers, ten spacers in each
     assembly as of castaustenitic stainless steel.  So, therefore, we were
     asked to address those components.
         Also, there is your core support assembly.  Your core
     support assembly is actually made up of three components that are bolted
     together.  You have your support shield.  In your support shield area
     you have some vent values.  Well, we just mentioned vent values.  And
     also the, on unit three there are outlet nozzles that are castaustenitic
     stainless steel.
         Then your core barrel assembly.  This is really where most
     of our focus is, because in the core barrel assembly there is high
     levels of radiation.  There are the baffle bolts that we've been
     addressing.  There are also the baffle plates, former plates, your core
     barrel itself.  So there is a lot of research going on right now
     evaluating those components.
         And then in your lower internals assembly there, too, in the
     encore guide tubes there is a spiral right in this area that is
     castaustenitic stainless steel and we will have to evaluate that.
         DR. SHACK:  Are your baffle bolts 3.04?
         MR. GILREATH:  Yes, sir.
         DR. SHACK:  And no coal work?
         MR. GILREATH:  No coal work.
         DR. SHACK:  So you are relatively unique that way in B&W
         MR. GILREATH:  Yes, sir.  Which may, actually, you know, we
     think we can use that to our advantage because the bolts themselves, you
     know, we obviously could remove those in an inspection and do further
     studies that would reflect how pretty much the whole internals would be
     behaving, because that would be your lead component.  And, so, we think
     that is going to really help us.
         DR. SHACK:  It could be more susceptible to swelling, too.
         MR. GILREATH:  Well, Frank Gardner has mentioned that to us
     also, and he is helping us develop a program.  He has looked at our
     internal design, and a few things about the internals are unique to B&W. 
     Let me just point those out real quick.  This is a backup slide.  When
     Frank was evaluating -- you know, this is just first shot discussing how
     our internals may perform.  He noticed that in our baffle plates we have
     some holes that are drilled throughout the plates, or bypass flood
     holes, pressure relief holes.  And also in the plates there are big
     slots.  And so the deferential pressure against the baffle plate is very
     minor, but even to a more concerned with swelling is that the cause of
     all the interchange of water and the heating effects are not going to be
     as high on these particular bolts and plates as you might see an
     internal design does not have all the flow holes.  Next slide.
         CHAIRMAN BONACA:  I have a question.  You mentioned before
     we got into different -- that is pretty unique to B&W design.  And you
     mentioned martensitic steel for that?
         MR. GILREATH:  Well, the vent valve itself, this is a
     drawing of the vent valve.  The valve body is castaustenitic stainless
     steel.  Then the retaining wedge here is a 15.4 participate hardening
     stainless steel.  Those particular items have been known to thermal
     embrittle.  And so what we want to do is make sure that with -- there is
     not much radiation in that area, but it may get to the 10.17th, neutrons
     per centimeter square range.  So, therefore, we just need to evaluate
     how that will effect the toughness of the material.
         MR. UHRIG:  Will it be a theoretical evaluation or will it
     be a measurement?
         MR. GILREATH:  Well, presently we do an active test on these
     valves every outage.  We will do an analysis.  But in that analysis what
     we hope to do is to actually take castaustenitic stainless steel from a
     plant that is shutting down that has a high level of radiation on that
     component so that we can get some real material properties.  Because
     today there are not many out there in the industry on this item.
         CHAIRMAN BONACA:  The reason why I'm asking is that just the
     hinges on there.  I mean, the valve is supposed to open freely.
         MR. GILREATH:  Yes.  Sure.
         CHAIRMAN BONACA:  So you have just hinges there.  I'm just
     not familiar with the size of them, but certainly embrittlement would be
     a concern that it could drop
         if we had a failure in there.
         MR. GILREATH:  And that will be evaluated in our program,
     and we will be inspecting it.  But we do inspect those every outage even
     today, the activation.
         CHAIRMAN BONACA:  That specifically is in your program?
         MR. GILREATH:  Yes, sir.
         CHAIRMAN BONACA:  Well, how do you inspect them now, I'm
         curious.  You do push it to see if it opens?
         MR. GILREATH:  It is a functional inspection.  No visual
     inspection of cracking or anything.
         MR. GILL:  There is a visual inspection.  They lower a tool
         valve and lift it, and they measure the force of lifting. 
     It is a strobe test, basically.  These are considered to be check valves
     for Section 11.  There are about four, I think, for each internals, for
     us eight.  But it is unique to B&W design.  It is actually a strobe test
     that they can visually look at it with a camera sticking in so they can
     see physically if there is any other abnormalities you can visually look
     at.  This is actually replaceable with the jack screws.  You can
     actually replace the valve itself.
         DR. SHACK:  Now, you look at it with a camera.  Did you
     actually do a visual inspection?
         MR. GILREATH:  Yes.
         CHAIRMAN BONACA:  Now, you mention martensitic steel for
     those hinges.  Is there any specific reason why there was a different
     kind of material?
         MR. GILREATH:  Not for the hinges, but for the retainment. 
     I'm not sure what material it is for the hinge itself.
         Mr. Sieber:  Well, that would interfere, if it broke off it
     would interfere with the vessel wall so you would have damage to the
     vessel wall to some minor extent that it would not be floating around
     inside the vessel.  It would interfere with rod drops.
         CHAIRMAN BONACA:  No, it would be on the outside.
         MR. GILL:  You would probably hear it, too.
         Mr. Sieber:  Probably would.
         CHAIRMAN BONACA:  Okay, thank you.
         MR. GILREATH:  Initially, our approach to resolving these
     open issues had to do with license and a process.  In our reactor vessel
     internals aging management program we were evaluating the aging effects
     of the internals.  We were characterizing those.  We were looking to see
     if any of these particular mechanisms may effect our internals, trying
     to perform an some analysis on critical crack sizes, developing methods
     for particular inspections.  The NRC raised a concern that most of those
     studies, which there are quite a bit -- a few studies are going on, both
     at Duke and in the industry -- that most of those studies will be over
     the next five or six years.  What they were concerned with was what if a
     mechanism may not show up until late in the license renewal life, would
     you be able to detect that.  And so they said why don't you go ahead and
     commit to an inspection program that assumes all these mechanisms occur,
     and then if you can prove through your evaluations and your analysis
     that these, the effects of these mechanisms will not impact the function
     of your internals, then you can make a submittal for us to review and
     take that particular part of the inspection out of the inspection plan. 
     And, so that was acceptable to us.  So through working with NRC we did
     commit to an inspection plan, and basically took the processes that we
     were already performing and incorporating them in our inspection plan to
     help mature the elements of the plan, like the acceptance criteria, the
     method of inspection, things of that nature.  We committed to specific
     timings.  Instead of doing them early in the license renewal life, that
     we would do some early.  We would do some in the middle and some later
     in the license renewal life to assure that we've been able to monitor
     any type of aging effect.  Also, we would participate with the industry
     in doing research and trying to better characterize each aging mechanism
     and we would report that to the NRC.  And so we agreed we would commit
     to an inspection plan, but that inspection plan would mature over the
     next five years as we go through our process, and as we go through all
     our research.  And so the program itself, the elements in the program
     will be modified or maturing or evolving over the next few years.  As we
     get more industry data -- we are doing a lot or research in the industry
     -- and also as we perform some of our analysis.  If for any reason that
     we felt that we could remove any part of the inspection plan, we would
     have to make a submittal to the NRC for them to evaluate the basis for
     that removal and come to some resolution at that time.
         What we came up with in our inspection plan is actually
     three inter-related inspections.  One had to do with inspecting the
     baffle bolts.  We would propose performing a volumetric-type inspection
     of baffle bolts.  There were a lot of aging effects that the baffle bolt
     may actually see a cracking due to irradiation assisted stress corrosion
     cracking.  Reduction of fracture toughness due to irradiation
     embrittlement, and dimensional changes due to void swelling.  This is an
     inspection that we will plan to do early in the license renewal life, in
     the middle and in the end.  During that inspection as we evaluate how we
     might utilize some of those bolts, we may be removing some of those for
     further analysis.
         We committed to a, we expect our castaustenitic stainless
     steel inspection will assist with some type of visual, one type of
     visual about the enhanced DT-1 or DT-3.  What we are going to do is
     perform an analysis, and first we've got to come up with some material
     property data.  Once we do that we are going to perform an analysis,
     come up with a critical crack size, and at that time we will be able to
     determine what method we want to use for an inspection.
         With the other components in the internals there are quite a
     few; the baffle plates, the former plates, the core barrel bolts,
     different components.  We have planned to perform a visual inspection of
     all the other items, and also in this area we will be looking at
     material properties of three or four different plates, for instance. 
     That will be critical crack sizes, so that we can determine what size
     crack would effect the function of the internals and develop our
     inspection program around that.
         We will probably be using some of the baffle bolts to lead
     items on potential change and to avoid swelling, but that could change
     once we do an evaluation.  We are really where the gamma heating effect
     is.  Apparently, the gamma heating effect and irradiation are the two
     concerns that need to be addressed with swelling.
         We've got an ongoing program right now with our core barrel
     bolts and thermal shield bolts that we have done volumetric exams in the
     past.  We are doing visuals now every outage.  We've got a program in a
     BWOG that is evaluating what would be the best method of inspection in
     the future.  We are kind of waiting for the deliverable there from BWOG
     to determine exactly how we'll inspect those bolts.
         DR. SHACK:  What is your dose map look like?  How much of
     this core is really in a kind of a high EPA state, kind of a radiation
     system track point of view?
         MR. GILREATH:  Let me see if I have a backup slide for that. 
     In the area of the fuel itself the dose rates, or the accumulated
     affluence are pretty high.  They can see as high as 10 to the 23rd
     neutrons per centimeter square.  But it falls off pretty quick.  The
     core barrel itself, I think, is more like 5 times 10 to the 21st. 
     That's a ballpark number.  I'm not quite sure about that core barrel. 
     We knew that if we could get the lead component, three or four material,
     developing an inspection planned around the lead components we will be
     able to pretty much map out the effect to the whole internals.
         DR. SHACK:  Where do you say go below 10 to the 21?  How
     high up would you have to go?
         MR. GILREATH:  The map that I've seen, basically, they do
     not go   -- we do not have maps that go up into the plenum area. 
     Therefore, you know, we were wanting to be able to say, for instance,
     the spacers may be below 10 to the 20th, and wouldn't be concerned of
     radiation embrittlement, but there are some people that believe even
     though you may be below that particular threshold, is there a
     synergistic effect.  So, what if you only have 10 to the 18 neutrons per
     centimeter square, will that, coupled with thermal embrittlement, effect
     the spacers.  So we do not have maps right now that go up real high into
     the upper internal, but here it is pretty even across the core.  This
     area would be like 10 to the 21st, and come all the way down to the 10
     to the 23rd, and then come back off 10 to the 21st, 10 to the 20th, in
     that rank.  So, pretty much the length of the core you are going to have
     maximum affluence.
         As I have mentioned before, instead of committing to one
     inspection, we have committed actually a minimum of three inspections. 
     One, early in the license renewal period.  The second one would be in
     the middle.  The third would be in the third period of license renewal
     period.  However, it would be prior to our last year of operation.  We
     expect that this particular program, we'll be able to utilize it for
     other plants that have the radiations out that far.  So, you know, we
     are pretty much committed to this inspection plan.
         I just want to mention a little bit -- I don't know how much
     you know about all that industry is doing in this area, but we have
     committed to participate with the industry.  Primarily, a B&W owners
     group has a reactor vessel internals aging management program with quite
     a few elements in it looking at Oconee specific, or the B&W specific
     internals, and we are going to be utilizing a lot of the programs coming
     out of there.  To give you just an idea of that schedule, just an idea
     of some of the tasks we are doing, we are doing studies on swelling and
     gas.  Pretty much everything we've discussed today, the B&W owners group
     is addressing.  We have a five year plan to come up and to evolve or
     mature all the elements in the inspection program, utilizing industry
     data.  So at a particular time we will be submitting a program to the
     NRC for review before at least two years prior to our first inspection.
         Also, we are working with other groups.  EPRI has a large
     group, material liability program issues task group.  In that group
     we've got some of the same elements and other elements working with the
     whole industry and addressing or trying to characterize the aging
     effect.  And, two, the job program, or joint baffle bolt task team. 
     That's a program that went out and looked at the international programs,
     tried to find out where we thought the most work was being performed. 
     We found EDF with a very large program.  And so we are funding some of
     that work and we've submitted our materials also to be integrated with
     their program.  And just in the job itself there are over a hundred and
     forty deliverables that are already part of the contract.
         The reports I mentioned, our first report to the NRC was the
     topical report, BAW-2248, that addressed the effects of reactor vessel
     internals.  We just received a SER on that in December.
         Other reports that we are committed to, as our program
     evolves we are going to submit reports to the NRC every time we complete
     a significant milestone for review.  And then our first report will go
     in within one year of receiving a license.  Then our last report will be
     two years prior to our first inspection, when we will have all our
     inspection methods resolved or committed to and what the acceptance
     criteria will be, things of that nature.
         Are there any other questions?
         CHAIRMAN BONACA:  I understand you have to report to the NRC
     and the two years, it will be two years before the end of the current
         MR. GILREATH:  The first report will be within one year of
     receiving a license for licensing, for extended license.
         MR. GILL:  Sometime next year.
         MR. GILREATH:  Sometime next year.  And then our last or
     final report will be two years prior to our first inspection.  So it
     will be pretty much when license renewal begins, that period.
         CHAIRMAN BONACA:  And that report, focusing on that one,
     that one will really contain much of the detail that you are going to
     gain from all the activities you have with EPRI, and with the ---
         MR. GILREATH:  Yes.  It is really essential that we get that
     material property data, and we will be submitting that to NRC.  As a
     matter of fact, we are going to Washington in April to go over the whole
     industry program with the NRC, the EPRI program, the BWOG program, and
         CHAIRMAN BONACA:  It will be interesting because there is a
     lot of activity going on.  Okay, thank you.  We are running a few
     minutes ahead of time.  We can take a break now.
         MR. GILL:  That concludes our morning presentation.
         CHAIRMAN BONACA:  Okay.  So let's resume the meeting, and we
     have representation from the staff now regarding the SER and the closure
     of the open items.
         MR. GRIMES:  Thank you, Dr. Bonaca.  My name is Chris
     Grimes.  I'm the Chief of the License Renewal & Standardization Branch. 
     And by way of introducing Joe Sebrosky, who is the Project Manager for
     the Oconee License Renewal Application.  I would like to compliment the
     committee on holding a meeting here at Oconee, providing an opportunity
     for more access by the interested public, and also bringing the renewal
     activities to the site so that the plant people can see the licensing
     process.  I think that is a good move on the Committee's part, and we
     will plan for that for future renewals.
         With that, Joe is going to go through and present the
     staff's presentation and we are prepared to respond to any questions
     that you have about the staff's safety evaluation basis.
         MR. SEBROSKY:  Good morning, my name is Joe Sebrosky.  I'm
     the project manager for the safety review for the Oconee License Renewal
     Application.  I would just like to point out that we have several
     members of the staff in Washington that are standing by to support the
     meeting.  They have copies of the slides.  So, I am going to be calling
     out the slide numbers just so they can keep abreast of where we are at.
         As far as the presentation, I'd like to just give you a
     brief overview of where we were and where we are at right now regarding
     the safety review aspect of the license renewal application.  And then
     discuss the resolution of the open and confirmatory items, some
     discussions that were added to Oconee SER since the last version was
     published in June of '99.  And then a summary of the license renewal
     application review activities that are to be completed before Duke gets
     its renewed license.
         The last time we made a presentation to the subcommittee was
     based on a June 16th, 1999 version of the SER.  We had a meeting with
     the ACRS Subcommittee over two days on June 30th and July 1st, and we
     also interacted with the full committee on September 1st.  Since that
     time we provided the ACRS with an update to the SER on February 3rd of
     this year.
         The February 3rd version of the SER contains several updates
     to the June version of the SER.  Specifically, it closed the open and
     confirmatory items contained in the June version of the SER.  There were
     forty-three open items and six confirmatory items that were closed in
     the February 3rd version.  There were also new evaluations that were
     added due to license renewal application update or because of a Duke
     response to an SER open item.  I'll point those out towards the end of
     the meeting, specifically what added evaluations were put into the SER
     as a result of those.
         And, finally, we did make changes to the SER based on
     technical comments that we received from Duke.  Back in October when
     they provided the responses to the SER open items they also gave us
     technical comments that resulted in some changes.
         On to slide five.  I'd like to -- we are modeling this
     presentation over the presentation that we gave to the ACRS for Calvert
     Cliffs.  And, specifically what we are doing is we are breaking down the
     open items based on the division responsibilities within the Nuclear
     Regulatory Commission.
         There are four divisions that were involved in the review of
     the license renewal application.  The division that I'm in, which is
     Regulatory Improvement Programs, the Division of Inspection Program
     Management, Division of Systems, Safety Analysis, and finally, the
     Division of Engineering.
         For the Division of Engineering open items, since they
     had the majority of the review, I've actually, we've broken those items
     up into the respective branches.  And as far as going through the
     presentation for each of these divisions, what we tried to do was tell
     you what the top issues were, and then also have a discussion of all the
     other open items.  Doctor Bonaca, Noel indicated to me that you may have
     some questions that may not necessarily be in the top issues.  I'll try
     to call those out when we come to those slides.
         As far as the top issue that was resolved within my
     division, that was, we had an open item regarding the content of the
     UFSAR.  That was open item 3.0-1.  Currently right now we are in the
     process of reviewing Duke's draft UFSAR supplement that they have
     updated because of the SER and because of changes that have been made to
     the application as a result of the review.  We intend to have that
     review completed and reach an agreement on the UFSAR supplement before
     we go forward with the commission recommendation.
         So, the basis for the resolution was basically that the
     staff would review the detail content of the UFSAR supplement, and prior
     to going forth with commission recommendation agree on a resolution.
         MR. GRIMES:  I would like to add to that.  Since we issued
     the draft revised UFSAR supplement to the staff, along with guidance
     explaining what the content changes are, pursuant to 57.1E, and the
     guidance that has been developed and relative to changes in 50.59, so
     that the staff would be able to view the contents of the UFSAR in the
     context of the regulatory process that is going to maintain the
     licensing basis in the future.  And any issues that stem from the
     staff's review of the UFSAR supplement, we would intend on identifying
     and tracking in the same way that we identified and tracked resolution
     of open items in the UFSAR itself.
         MR. SEBROSKY:  The next division was the division of
     inspection program management.  The branch within that division that was
     involved with the review was the quality assurance branch.  They were
     the lead on the scoping issue that was discussed this morning with Duke,
     and also on several other items.
         This slide, just on a high level, provides an overview on
     the basis for the resolution of the open item, and it reiterates what
     Duke presented this morning, the fact that we asked them to look at ten
     additional events, and based on them not identifying any additional
     systems, structures or components, we felt comfortable and it gave us a
     reasonable assurance that the scoping was done properly.
         CHAIRMAN BONACA:  On a genetic basis, but we are talking
     about the SOP, etc.  It is better for the older plants in need of being
     more specific than just -- I'm not sure that 50.54 specifically felt
     this is all Chapter 15.
         MR. SEBROSKY:  We don't, we didn't agree with the view that
     design basis events.  It says narrow as the way that Duke explained that
     they maintained the licensing basis.  But we do agree that the end
     result, by virtue of the overlapping scoping techniques, captured all of
     the necessary systems, structures and components that are relied upon to
     prevent or mitigate events that are described in the licensing basis. 
     That is how we selected the ten additional events to evaluate.  And I
     would expect that we would take that experience and feed it back into
     improved guidance for the standard review plan, and possibly even we can
     work something out with the industry group, guidance for the industry
     guide 95.10 that would explain how to review plant capabilities in a
     broader way.
         I'd also mention that after the generic aging lessons
     learned, an SRP update, we have a commitment to the Commission to the
     consider rule-making, and I would expect that if there is an opportunity
     for us to clarify the language in part 54 that describes scoping, to
     make it more consistent with the evolving design basis description under
     50.2., and the other language that describes design basis events.  And
     50.49, for environmental qualification.  And the maintenance rule. 
     There's a maintenance rule workshop that was just held two days ago.  As
     all that experience comes together it is conceivable that we can clarify
     that the expectations for future renewal applicants.
         CHAIRMAN BONACA:  Good.
         DR. SHACK:  Does the latest revision of 95.10 incorporating
     this?  I mean, would you expect to see the future applications
         MR. SEBROSKY:  95.10 addresses scoping and addresses
     methodology, but to the extent that it doesn't get into this what is a
     design basis event, and how is the definition of current licensing basis
     in part 54 intended to be applied to a current licensing basis, that is
     still an area where these other activities going on in 50.2 with the
     industry.  There is guidance there.  There is guidance for 50.59.  There
     is guidance for the maintenance rule.  All of those things sort of
     surround this thing.  If we could bring some more focus to it, I think
     that would make the process more efficient and predictable in the
         Go on to other issues that were resolved for the quality
     assurance branch under slide number eight.  We did have an open item
     relative to the corrective action for non-safety related systems.  The
     resolution for that is basically the UFSAR supplement.  Duke is
     identifying under one of their attributes corrective actions,
     specifically what process will apply to both safety related and
     non-safety related systems.
         I'd like to move on to DSSA, which is slide nine. 
     Basically, as far as the top issues go within this division, they are
     the division that did the scoping.  The systems groups looked at the
     scoping to make sure that the boundaries were appropriate, and also
     challenging in some cases whether or not systems should be within scope.
         The top issues that I identified for the division were
     the ones that added additional system structures of components.  We had
     three open items that did that.  There was the -- we challenged the
     chill water system, which is the heat sync for the control.  As a result
     of that Duke scoped that in and we reviewed that, performed an Aging
     Management Review.  So you will see added discussions both within
     Chapter 2 of the SER, and also within Chapter 3 where we asked the
     Division of Engineering to look at the Aging Management Review  for
         Also, the other two open items were associated with the
     ventilation sealant material, and one was with the passive long-lived
     equipment excluded from AMR.  If you go back to the tour that the ACRS
     took yesterday of the standby-shut down facility, this one issue dealt
     with skid-mounted equipment, which the diesel was considered to be
     skid-mounted equipment.  The question that the staff had was were the
     boundaries that Duke originally drew appropriate.  When they drew those
     boundaries, skid-mounted equipment, like some of the heat exchanges that
     were on the skid were excluded from an aging management review.  We
     didn't agree with that.  We challenged that.  Duke subsequent to the
     initial application provided aging management review from its
         And lastly, under one of the top issues that was resolved
     for DSSA, there was an issue that came up late in the Calvert Cliffs
     review regarding ECCS piping insulation and whether or not that should
     be within scope.  The staff asked a question about that and Duke gave us
     justification for their design as to why the piping insulation, they did
     not need that to meet any of the criteria in 54.4A1, A2 or A3.  We
     agreed with that, but there was an additional evaluation and exchange of
     information that was done.  You also see that in the SER.
         MR. GRIMES:    I would like to clarify.  That was
     insulation on 4A water system piping and whether or not the insulation
     was necessary in order to insure that the sufficient statement and
     solution.  So it wasn't insulation in a broader context, it was for that
     specific functional capability.
         MR. SEBROSKY:  The next slide is other issues that we
     resolved within DSSA.  I didn't plan on talking about each one, but
     there was one, Dr. Bonaca, that you had indicated some interest in, and
     that was on the recirculated cooling water system, which is the heat
     sync for the spent fuel pool.  We have the staff available if you have
     any questions about that.
         CHAIRMAN BONACA:  No.  I think with the review of yesterday
     in the afternoon, I think that we recognized that what you did, which
     really is not part of the licensing basis, the current licensing basis
     for the plant.  We still have questions regarding the loss of spent fuel
     cooling event as a basis for the pool.  Clearly it is not the basis for
     cooling.  We heard that the makeup water system is circulated.  It can
     be used to make up water in case the cooling system is lost.  That was
     the basis for your cooling, I believe.  I believe that the membership
     accepted that yesterday as recognizing that as a means of cooling the
     pool and making up the water.
         DR. POWERS:  I guess I would characterize the members have
     heard that.  I would characterize it as saying the members heard that.
         CHAIRMAN BONACA:  Yeah.
         DR. POWERS:  I wouldn't say that there was any endorsement.
         CHAIRMAN BONACA:  True.  True.
         MR. SEBROSKY:  But I would also like to add that was one of
     the areas that we explored very carefully in making sure that we
     understood what the licensing basis was.  And we did consider it very
     carefully, and DSSA affirmed that was the way that a number of plants
     are currently designed and licensed.  We considered whether or not there
     were any risk insights that warranted pursuing that separate from
     licensing.  Mr. Gratton explained in the conference call that we had
     that their understanding of the licensing basis were prepared to pursue
     that separately with the ACRS if you like.
         CHAIRMAN BONACA:  Before you move that, I had a question
     regarding the open item regarding active equipment in storage,
     if I remember.  I understand that you agreed not to include that
     equipment in scope.  I personally agreed with that.  The only question I
     have is that because Duke said that they are routinely inspecting and
     testing their equipment, so therefore it is maintained in a way that --
     but it seems to me that in any event the equipment is being inspected,
     tested, installed and then tested when it is installed anyway.  Why
     would you consider possibly in scope?  I'm trying to understand, you
     know, for example, how will you address this issue?  Do you still have a
     requirement that this be ---
         MR. SEBROSKY:  The way that the issue came up was that there
     was equipment that is warehoused that has passive elements, and whether
     or not the passive features of that equipment need to be managed while
     over time because the aging effects are the same whether or not the
     equipment is being used or in storage.  It is more the process by which
     the equipment that is taken out of storage and then put into service is
     verified as suitable for service that provides us with a process
     assurance that if there are any applicable aging effects, if they are
     not managed or at least checked before the equipment is put in and then
     subjected to the routine inspection program.  So, that's the way the
     issue started to evolve.  It was, well, do we need to have an aging
     management program for this equipment while it is in storage.  And we
     concluded that by virtue of the process that certifies spare parts for
     use, that provided sufficient assurance that if there were any aging
     effects they would be identified and then checked before the equipment
     is actually put into service.
         CHAIRMAN BONACA:  Yeah, that point I made, I totally agreed
     with that, with the conclusions that you made regarding that.  I just
     believed that those conclusions are pretty genetic because the process
     is by which the utilities install the spare parts.  It is very similar. 
     You have to set the specific requirements and go through, which would
     include the inspection and the testing, and then selection testing.
         MR. SEBROSKY:  The reason that the issue came up for Oconee
     is if you look at the scoping criteria one of the criteria is regulated
     events, 54.4A3.  There is an appendix R.  As you noted yesterday on the
     tour, Oconee has some unique features.  For example, the turbine
     building, that's where the emergency feed water pumps are located.  They
     are not located in the ox building, so there is a vulnerability to a
     fire in the turbine building.  That's why they added, one of the reasons
     they added the standby shut down facility.  So, when you go their
     Appendix R requirements, they rely on a lot of cabling that is in
     storage.  Also pumps and breakers that are in storage to help recover
     from a fire in the turbine building.  The staff looked at that and they
     noted that Duke had looked at the passive components, the cables, and
     did an aging management review and determined that the cables were in a
     benign environment.  But we asked about the active components, and
     that was the reason for that open item.
         So, it is somewhat related to the unique nature of Oconee's
     licensing basis.  That is why the question was asked.
         MR. GRIMES:  I'm sorry, I didn't respond to your specific
     question.  Yes, I would expect to add guidance in the standard review
     plan that explains why we do not need to be concerned about aging
     management programs for equipment that's in storage.
         CHAIRMAN BONACA:  Okay.  Good.
         MR. SEBROSKY:  I guess as far as the top issues, I'd like to
     move to the Division of Engineering.  We've broken it down by branch
     here.  For the materials in the Chemical Engineering branch, the top
     issues that we identified for this branch, if you go to slide 11, are
     those associated with the reactor vessel internals.  And if you go back
     to Duke's slides this morning, this slide is consistent with that as far
     as the open items that were associated with the internals.
         Are there any questions that the ACRS members have of the
         CHAIRMAN BONACA:  I think that we saw a very comprehensive
     program that addresses a lot of the issues from the swelling to others.
         MR. SEBROSKY:  The first issue on the next slide, slide
     twelve, really involves a reactor vessel internals component.  Again,
     that was talked about this morning.  That's the vent valve bodies,
     internal reactor vessel.
         The next set of open items dealt with CASS components. 
     Finally, there was a new issue, this 3.4, 3.3-9 that was added after the
     SER was written in June, and that had to deal with reactor vessel
     monitoring line.  The staff questioned whether or not that needed an
     aging management review.  Are there any questions on that?
         As far as other issues that were in this branch, they had
     the majority of the open items.  There are several items on this slide,
     Dr. Bonaca, that Noel has indicated to me that you might have questions
     about specifically on the pressurizer heater sheath-to-sleeve plate,
     open item  The buried piping, the standby shut down facility
     HVAC coolers, and the standby shut down facility heat exchanges.
         CHAIRMAN BONACA:  Yes.  I had some questions on the
     pressurizer heater, we discussed it yesterday with the applicant.  I
     understood, the question was more relating to the nature of the one time
     inspection where you would not have an inspection unless you have a
     failure to the heater, so I thought that we had characterized one time
     inspections somewhat differently.  Essentially, the inspection that you
     performed to get a confirmation that in effect is not occurring.  Or if
     it is occurring it is a benign factor.  And, so, you know, that was more
     of a clarification than anything else that we got from the applicant. 
     Everything was fine with that.
         On buried piping, the questions I have was in several
     instances, two instances on this.  All the inspections for the buried
     piping of the Kewanee facilities are not really done there.  I mean,
     they are referring to the inspections at Oconee as being indicators of
     the aging management at the Keowee facility.  The reason is that the
     materials used supposedly are the same between Keowee facility and
     Oconee facility.  I had some questions about two things.  One, the
     environment.  It is, in any case did you look at the differences in
     environment and possible aging effects resulting from it.  And second,
     the Keowee facility was not really under Appendix B program until now. 
     And so, therefore, there maybe -- do you have enough records to say
     that, yes, you have the same material, the same conditions, and
     therefore the inspections that would be for Oconee are also indicative
     of the conditions you would find at Keowee?
         MR. SEBROSKY:  I guess our lead reviewer, and I'm hoping he
     is on the phone, was Jim Davis.  Are you there?
         Mr. Davis (via telephone.):  Yeah, I'm here.
         MR. SEBROSKY:  Jim, I was hoping that you could respond to
     Dr. Bonaca's questions.
         Mr. Davis:  Well, basically, what they are concerned with is
     the soil corrosion of a pipe, and with carbon alloy steel you don't see
     much difference in corrosion rate.  Basically what they are doing is
     they are doing an internal inspection, eleven foot diameter pipes, which
     counts for about eighty percent of the piping that they have.  That's
     not the recommended way to do things, but we found it acceptable.  If
     there was an oil or gas line, it would be totally unacceptable.
         The downside is it is going to cost them a lot of money when
     they see a leak because they are going to have to replace all that
     piping, probably.  But that is their decision to make.  They are
     inspecting eighty percent of the pipe.  I see no difference in the, or
     significant difference in the corrosion rate from soil anywhere that you
     have buried pipe.
         MR. GRIMES:  And, Jim, correct me if I misstate this, but I
     think that the way that you described that we would say they were not
     relying so much on the identical nature of the piping, but more that the
     inspections that they have provide a bounding circumstance by which any
     indication would cause them to go look at the effected piping and, as
     Jim points out, if they find a problem then they are going to do a lot
     more digging than if they had a more focused inspection activity because
     of the benign, relatively benign nature and the expectation that they
     are not going to see a problem, this constitutes sort of a bounding
     approach to be issued.
         DR. POWERS:  It would be interesting to see the data that
     suggests that the carbon steel piping corrosion is fairly independent to
     details of soil conditions.
         Mr. Davis:  Typically, you know the NBS in the old days and
     this now did a very detailed study of corrosion in soils of steel or
     alloy steel.  They found that the average life is twenty-eight years. 
     This pipe is coated, but it is not cathodically protected, which
     normally would make it worse.  If you are not going to cathodically
     protect it, you should leave it bare, and then after thirty years
     replace it all.  If you cathodically protect it is good forever.  So,
     I'm not quite sure what there logic is of not cathodically protecting
     it.  But basically, once they see problems they are going to have
     problems everywhere.  They are just going to have to go in and deal with
         DR. POWERS:  I guess we would be interested not just in the
     average life time, but the variable around that average.
         Mr. Davis:  It all depends.  It depends on a lot of things. 
     If you find a section of pipe that corrodes through, and you replace
     that section of pipe, the new pipe will last about six months, because
     it acts as an anode and cathodically protects the rest of the pipe.  So,
     you get into a real serious problem if you don't use good engineering
     practice, which a lot of the nuclear industry doesn't, and that piping
     is not under, there are no rules or regulations to control it.  But if
     they see problems they are going to have to go in and look at all their
         DR. POWERS:  I guess I'm more interested in the data that
     led to your conclusion, that there was a fair insensitivity to this type
         Mr. Davis:  It is kind of hard to predict.  The variance
     probably plus or minus ten years, their soil is pretty benign.  They
     could do a soil conductivity measurement, and that would give them a
     good indication of how corrosive it is.  Usually if it is a high
     resistivity, five thousand centimeters, then the soil is not considered
     to be very corrosive.  But if it is a lower resistance then it is
     considered to be very corrosive.  The program that they propose to go in
     and inspect periodically, they are going to find leaks if they have any,
     or depending on the inspection time it takes.
         MR. GRIMES:  Jim, did you mention where those studies are
         Mr. Davis:  Yeah.  They are NBS and the National Institute
     Science and Technology did the big studies.
         MR. GRIMES:  The National Institute of Standards and
         Mr. Davis:  Yeah.  It used to be the NBS when they did
         the -- but, you know, and the type of soil they've got
     there, I would expect it to be close to a thirty year life.
         CHAIRMAN BONACA:  You also made a statement before that I
     don't understand the answer.  You said that you would be concerned if in
     fact the environment was not water, but oil or gas.
         Mr. Davis:  If you have oil and gas pipelines, that falls
     under Title 49 of the Code of Federal Regulations, and it says, "If you
     bury a pipe and you've got oil or gas in it, you must coat it and you
     must cathodically protect it, and then you must monitor it using pipe to
     soil potential measurements like Calvert Cliffs does.
         Oconee has chosen not to do that.
         DR. SHACK:  But then Oconee is not transporting oil or gas
     interstate through cities and ---
         Mr. Davis:  Yeah.  And they are not required by law to do
     it.  If they want to replace their pipe every thirty years they have the
     right to do that.
         CHAIRMAN BONACA:  I understand.  Okay.  Thank you.
         DR. SHACK:  I guess the other argument is you don't really
     expect the soil to be terribly different at Oconee and Keowee, so
     whether it is average soil or not, there doesn't seem to be a reason to
     believe it is terribly different.
         Mr. Davis:  That's right.  You normally expect the higher
     corrosion rates if you have brackish water or something like that.  That
     is not the case for Oconee, so you wouldn't expect to have a very
     corrosive soil there.
         DR. POWERS:  I'm going to have to comment on the technical
     basis for the staff's decision, and I just don't understand the
     technical basis for this.  I guess I understand the technical rationale,
     I just don't see the data.  As far as the variability of soils I think I
     can see places where soils vary dramatically over the course of a few
     feet.  I don't know whether that's the case here.  I don't have enough
     information on the site to ---
         Mr. Davis:  Normally you would expect to see large
     variations.  What we are relying on here is that they are inspecting
     eighty percent of a total surface area of the pipe on a regular basis. 
     If they have a problem, they will detect it.
         MR. GRIMES:  And take appropriate corrective action.
         Mr. Davis:  Right.
         MR. GRIMES:  But we can provide the, we can provide the NIST
     reference, the N-I-S-T references, in terms of the data that lists the
     variability of corrosion for buried pipe.  But otherwise our technical
     basis is based on inspection and corrective action, not necessarily
     managing the aging effects that are applicable to the buried surfaces of
     the piping.
         DR. POWERS:  I think this gives us an opportunity to
     highlight before the Commission the approach that is adopted here.
         I think it is an opportunity for us to point out to the
     Commission that the approach is here.  Okay, they've taken the strategy,
     the strategy will work, because if they find a problem they will have to
     dig and replace things.  You've got some confidence that there is
     detection because they are doing eighty percent of the tech things, and
     the other twenty percent we think is much like the remaining eighty
     percent.  But I think we have to have an understanding of the technical
     rationale for that.  We have to see the technical rationale.  If it is
     an engineering guess, that's an engineering guess.  If it is based on a
     careful analysis, it is based on a careful analysis.  It is just a
     matter for us to point it out to the Commission.
         CHAIRMAN BONACA:  Well, actually we are hearing that they
     are going to inspect and if there are problems they are going to fix
     them.  That's pretty much what I hear.  The other issue, you know, it is
     more regarding the bounding of all systems of the Keowee from Oconee
         And that ---
         DR. POWERS:  But it is not a random eighty percent they are
         CHAIRMAN BONACA:  That's right.  It's ---
         DR. POWERS:  It is a distinctly unrandomed eighty percent.
         CHAIRMAN BONACA:  Right.  So that would be right.
         MR. SEBROSKY:  Well, I'd just point out on this slide,
     before we leave this slide, there were two other items, 3.2.12-1 and
         CHAIRMAN BONACA:  I had a couple questions of this.  One was
     for the SSF HVAC coolers.  You had a question regarding the need for
     providing both floor measurements and measurement to assess if there was
     any measure of loss of material, for example, that would effect the
     changes.  I believe the resolution was that the frequency of testing is
     such that the flow measurement can be relied upon to detect if there is
     any change.  I didn't understand.  There was no specific explanation in
     the SER why lack of identity allows you to get that assessment and the
     field loss.
         MR. SEBROSKY:  Our reviewer for that is Stephanie Coffin. 
     Stephanie, are you there?
         Ms. Coffin (via telephone.):  Yes, I'm here.
         MR. SEBROSKY:  And did you hear Dr. Bonaca's question?
         Ms. Coffin:  Yes, I did.  The answer is they do measure
     across those heat exchanges.  Not as part of their, in response to open
     item what they propose with the new preventive maintenance activity that
     we reference in closing out this open item.  And in that PM activity
     they do measure it across the heat exchangers.
         CHAIRMAN BONACA:  Okay.  That is not what is documented in
     the SER, but that is fine.  So I'll take it as the answer to this
     question.  And I had one more question regarding the 3.2.13-2.  That's
     where carbon steel inspection indicate, a user indicator of conditions
     of known carbon steel components.  And the specific question was that
     the carbon steel inspections are used as lead indicator of conditions
     such as, for example, a MIC attack.  Or other that it may cause pitting. 
     And the position was that this type of corrosion does not effect the
     destruction of any of the components.  Okay, if you have a MIC attack
     you typically have a pin hole leak and therefore you can't identify it
     ahead of time.  I wanted to hear more about that, because for my limited
     experience with MIC attack, I've seen pipes literally devoured inside by
     MIC attack.  There was a pin hole leak, but the pipe was ready to go. 
     And maybe even in a more -- so I would like to hear the technical phases
     for concluded that this is a --
         MR. SEBROSKY:  And Stephanie before you give the answer I
     guess I just wanted to make sure I -- that, if I understand correctly,
     it is actually on slide fourteen, and the question that you have is on
     3.2.13-2, correct?
         CHAIRMAN BONACA:  Yes.
         MR. SEBROSKY:  I think I had the wrong slide up.  Stephanie,
     did you understand the question?
         Ms. Coffin:  Yes, I did.  The basis for closing out this
     open item was Oconee's operating experience with their service water
     system.  They have been doing these inspections for close on twenty
     years now, and they have not found any, not had to replace any kind of
     piping due to corrosion concerns.  They haven't documented any
     indications of problems with MIC, or very localized degradation with
     problems that they've seen in their service water piping is general
     corrosion for the techniques they are applying are acceptable.  That
     doesn't mean that this isn't a concern to the staff, and what the
     licensee, and the licensee recognized that and they committed to
     following more closely the results of those service water inspections as
     well as other, say, specific materials to document any times that they
     have a degradation due to a localized corrosion phenomena and consider
     its relevance to the service water, service water piping inspection and
     factor that into how they are approaching maintaining the integrity of
     their service water piping.
         MR. GRIMES:  Another way I would put that is, the general,
     the inspection activities associated with general corrosion and plant
     conditions will identify if MIC becomes a concern in the future, or any
     other aging effect for which there hasn't been any present evidence
     warranting a specific aging management program.  So it goes beyond just
     a particular concern about microbiologically induced corrosion.  I
     thought I'd say what MIC is, because you have to say it so slowly.  So
     in that sense this conclusion is very general for us.  If there hasn't
     been any evidence of a particular aging effect, we still rely on the
     general programs to reveal and deal with any evidence if it occurs in
     the future.
         MR. SEBROSKY:  We've actually moved onto slide fourteen. 
     There weren't any other questions that I noted on slide thirteen.  But
     since we've moved onto a new slide, Dr. Bonaca, Noel indicated to me
     that there was also a question that you had regarding 3.2.13-3 on the
     relationship of the program to Keowee, and also on 3.2.13-4 on the UT
     inspection capability, located degradation.
         CHAIRMAN BONACA:  Yes.  The first one we already discussed. 
     That was related to the same question that we had before, relationship
     between inspection for Oconee and Keowee.  And the other one ---
         MR. SEBROSKY:  I guess the question that I had from Noel was
     regarding 3.2.13-4 is, "What is the staff's basis for finding the
     applicant's justification acceptable?" Some localized degradation
     mechanisms may not be bounded by inspection for general corrosion and
     may result in pipe failure.
         CHAIRMAN BONACA:  Yes.  That was UT test, which are not very
     effective to identify.  That was the point I had.  There are none, as
     far as I understand it, where you are effectively localizing,
     identifying localized pitting, and microbiologically induced corrosion. 
     And so I would like to hear more about that.
         MR. SEBROSKY:  Again, the reviewer for this open item is
     Stephanie Coffin.  So, Stephanie, if you could respond to that.
         Ms. Coffin:  The reason why open item 3.2.13-4 is related to
     closing out 3.2.13-2 and because the staff accepted that general
     corrosion with the limiting degradation note for this service water
     piping, UT is an acceptable technique to use.  If they have to change
     their program in response to finding the localized pitting or mix, they
     have committed to changing their techniques to use one that is qualified
     for the application, which means it won't be UT, it will probably be a
     visual inspection.  I can't think of what much else you could use.  I
     don't know if you heard, did you hear what Jim Davis ---
         MR. SEBROSKY:  No, we did not hear what Jim said.
         Ms. Coffin:  Jim also pointed out that they also have their
         heat exchanger performance testing, which would also tell
     you that you may have a MIC problem because you would getting fouling. 
     So that is sort of a secondary measure in place to let you know that may
     be of a concern in your plan.
         MR. SEBROSKY:  The rest, if that answers your question, the
     rest of these open items on this slide dealt with TLAA's and some --
     TLAA's being Time Limited Aging Analysis -- and also some confirmatory
     items.  Were there any questions on those?  I didn't note any.  On the
     ones that are left on the slide, Dr. Bonaca, I didn't note any that Noel
     indicated.  As a matter of fact, I believe that of all the questions
     that Noel forwarded to me that we addressed all the items.
         CHAIRMAN BONACA:  But I have more.
         MR. SEBROSKY:  I understand.  I understand.  I guess, moving
     on, the next group is the mechanical engineering branch within the
     Division of Engineering on slide fifteen.  Our reviewer for this was
     John Fair, and I'll just give a high level overview and then ask John to
     address the specifics.  John, are you there?
         Mr. Fair (via telephone.):  Yes, I'm here.
         MR. SEBROSKY:  And basically, I guess, what I wanted to say
     as a high level overview is we presented three options to Duke, and they
     chose an option that is a plant specific option, similar to what Calvert
     Cliffs chose.  So the resolution for Calvert Cliffs and Oconee for this
     issue are the same.  And, John, is there anything that you wanted to
         MR. FAIR:  The only thing I wanted to add is that the
     resolution for both Calvert Cliffs and for Oconee is consistent with the
     recommendation that came in on GSI-190, which was to do something to
     monitor the effects of fatigue cracking due to environmental concerns. 
     So it is consistent with the GSI-190 resolution.
         CHAIRMAN BONACA:  Did Duke use the same locations for
     monitoring that the GA used?  I know they identified them from the regs
     60-260 or so.  That's fine by me.
         MR. SEBROSKY:  John, did you hear the question?
         MR. FAIR:  Yes, I did.  They are essentially the same as
     were used by Calvert Cliffs, and the ones from Duke are out as new regs
     60-260.  Several of the new regs 60-260 locations were addressed in the
     topical report on the vessel.  And the remaining ones that weren't
     addressed by the topical report on the vessel, Duke is going to evaluate
     the GSI-190.
         CHAIRMAN BONACA:  Okay, and that is responsive to the
     recommendation that you are giving on the closure?
         MR. FAIR:  That's correct.
         MR. SEBROSKY:  Were there any other questions on that?
         CHAIRMAN BONACA:  No questions.
         MR. SEBROSKY:  As far as the rest of the issues that were in
     this branch, there weren't any that were identified to me before hand. 
     The issues that we had open items on were:  containment tendon
     anchorages; letdown cooler thermal fatigue; aging effects of HVAC
     sub-components; the reactor coolant pump oil tank inspection plan; spent
     fuel pool temperature.  And then we also had several related to
     structures and the secondary shield wall.  Were there any questions
     about how those were dispositioned?
         CHAIRMAN BONACA:  No.  We discussed the secondary shield
     wall yesterday, the pre-stressing tendons, that the aging issues that
     are different than the ones for the containment.
         MR. SEBROSKY:  That's correct.
         CHAIRMAN BONACA:  And it was explained to us that the
     program that is being utilized to manage the tendons in containment is
     different from the one for the shield wall.  But it seems to be like a
     comprehensive problem, also the one for the secondary shield wall.
         MR. SEBROSKY:  And, finally, slide seventeen finishes up the
     issues that are within this branch.  These relate, again, to time
     limited aging analysis, and also some confirmatory items that we had. 
     Were there any questions on that?
         CHAIRMAN BONACA:  Yeah.  There was a time-limited aging
     analysis to do with the tendons, right?  But they have chosen not to
     just before the inspection, so that is why they are gone?  And that
     closes the whole issue?
         MR. SEBROSKY:  Hans -- yeah -- our reviewer on that is Hans
     Ashar.  Hans, are you there?
         Mr. Ashar (via telephone.):  Yes, I am here.
         MR. SEBROSKY:  Did you have any comments on Dr. Bonaca's
         Mr. Ashar:  No, I think his observation is correct.  We had
     hoped to have enough data that can provide a tendon drain line based on
     the previous data, and the drain line so that the forces are good enough
     for sixty years.  But in the case of Oconee, that was not possible
     because they did not have random sampling data earlier.  So they chose a
     management program.  They are going to comply with the regulations
     regarding the drain line and not meeting the second requirement in the
     drain line requirement.
         CHAIRMAN BONACA:  I understand now they've gone from
     sampling the same nine tendons to sampling random samples?
         Mr. Ashar:  That is correct.  Yeah.  That is correct and
     they are going to implement a subsection item for section 11, a project
     tendon inspections.
         MR. SEBROSKY:  If there aren't any more questions on slide
     seventeen I'll go ahead and move to slide eighteen.  This is in our
     Electrical and INC branch within the Division of Engineering.  Paul
     Colaianni gave a discussion on it this morning.  The issue was actually
     added as a result of an inspection.  Caudle Julian and Vic McCree from
     region two are here.  And as a result of the second inspection, they
     identified that there were aging effects with the cabling.  As a result
     of that we added an open item.  Duke gave us an aging management program
     that we reviewed and found acceptable.
         Our lead reviewer on that is Paul Shemanski.
         Paul, are you there?
         Mr. Shemanski (via telephone.):  Yes, I'm here, Joe.
         MR. SEBROSKY:  Was there anything that you wanted to add to
     that discussion?
         Mr. Shemanski:  No, not really.  I thought Paul Colaianni
     gave a
         pretty good description of the overall program.  I guess the
     only thing I would like to point out though is that this is a new
     program for Duke.  When the application came in they identified
     basically three potential aging effects; radiation, thermal and
     moisture.  In the application they concluded that none of these were
     basically applicable aging effects.  And as a result of our inspection
     we found some evidence that the staff felt, you know, we recommended or
     felt we needed an aging management program for cables.  Subsequently,
     Duke came in and we worked very closely with them on the attributes of
     the program.  Since, again, this was a new program, so I think we are
     satisfied generally that the proposed program would be acceptable.  It
     is based primarily on inspection.  That is basically what I have to say.
         MR. SEBROSKY:  Were there any questions on this item?
         I guess that ends the discussion about the open items and
     the confirmatory items.  What I'd like to move on to is just to point
     out to the ACRS members the added discussions that were put into the SER
     from the June version.  I have several slides on this.
         The first slide just identifies responses to open items that
     resulted in SER sections.  The majority of these were identified in the
     June version, but as we said you will notice that there is one on
     insulated cables and one on reactor vessel monitoring pipe that were
     added after the June version.
         Regardless, as a result of the open items that are on this
     slide, scoping was done by DSSA, Division of Systems Safety Analysis. 
     An Aging Management Review was done by the Division of Engineering.  And
     sections were changed in both Chapter 2 and Chapter 3 for the Oconee SER
     for these as a result of the NRC open items.
         The next slide, slide 20, and I apologize on missing a nine
     here, but on the September 30th, on September 30, 1999, Duke gave us a
     license renewal application update that is required by 10CFR 54.  They
     identified several new system structures or components that were added
     as a result of changes to the current licensing basis.  This slide just
     details those things such as the essential siphon vacuum system,
     portions of the component cooling water system being expanded and
     portions of the low pressure service water system being expanded.  The
     staff did a review and again made changes to the SER based on this.
         The next slide just provides details of what Duke's
     technical comments were.  If you go back to the October 15th letter that
     Duke gave us, in that letter they provided us all the written responses
     for the open and confirmatory items, and they also gave us this list of
     ten items to look at.  In some cases we identified that there were no
     changes necessary to the SER and we discussed that with Duke.  But in
     other cases, for example, we added the discussion about the leak before
     break, that was about a page long.  And we've clarified some other
     things as a result of Duke's comments.  Are there any questions on that?
         Then I guess the final slide is basically a schedule of
     where we go from here.  This just identifies the end gain, including the
     sub-committee and the full-committee meetings, and also the ACRS letter. 
     But we have several actions that we have to complete, including issuing
     the new regs in SER.  Caudle and Vic have to do ---
         MR. GRIMES:  Issuing the SER as a new reg.
         MR. SEBROSKY:  I'm sorry, issuing the new reg as an SER. 
     Sorry.  Anyway, Caudle and Vic have to do the final inspection and get
     the Region 2 administrator letter.  The schedule was to forward the
     Commission paper with the staff recommendation by April 14th, then it is
     in the Commission's hands.   
         MR. GILL:  The engage schedules are presumptive.  We presume
     that the ACRS will write a favorable letter.  We presume that the
     follow-up inspection won't identify any issues that can't be readily
     resolved.  And we presume that we will work out the details of a renewed
     license to present to the Commission in order to meet those milestones. 
     But, we've been able to fulfill that kind of schedule on Calvert Cliffs,
     and I have a recommendation pending before the Commission that they are
     going to discuss on March the 3rd.  That's why we asked you to move the
     full committee discussion of Oconee to March the 2nd.  So, we are
     playing both end games in parallel and we'd expect to follow this same
     pattern for Oconee.
         That ends my presentation, unless there are any questions.
         DR. POWERS:  I'm wondering how comfortable we are with all
     of this, this rush to completion.
         CHAIRMAN BONACA:  I'm sorry?
         DR. POWERS:  How comfortable are we going to be, how
     comfortable is the full committee going to be with this rush to
         CHAIRMAN BONACA:  Well, I mean, I think we would like to
     have a discussion now of the sub-committee and talk about also that
     issue there.  And then my sense is that at the end of the discussion we
     will then define for the staff and for Duke what we would like to hear
     next week.  So, why don't we just start and go around the table and see
     what general perspective there are, and comments regarding what we heard
     in the past couple of days and the closure of open items in the SER, and
     where we are right now as far as having our meeting next week and where
     we think we are going to be with the committee.
         Why don't we go around the table and see if there are any
     specific comments.  We'll start with you, Bill.
         DR. SHACK:  No, I don't have any particular problems.  The
     big open issue that we sort of had was the reactor vessel internals.  It
     seems to me they've addressed that with a fairly comprehensive program. 
     You don't have all the answers, but, obviously, if you are inspecting
     you will identify problems and can address those.  And if you can make
     some of those go away by analysis after further research, that's fine. 
     So, updating that.
         The questions on scoping I thought were reasonably well
     addressed by the discussions we had yesterday and today.  So, I don't
     see any real show-stoppers here from my point of view.
         CHAIRMAN BONACA:  Tom, your feelings?
         DR. KRESS:  I agree with Bill.  I don't see any real
     show-stoppers either.  I think they did an excellent job of addressing
     the scoping question.  I just wonder how that will play out on the next
     review.  I think we need to look into how we are going to review the
     scoping issue for the other plants.
         But the items I had on my list to review for open items, I
     think the resolution and the closure was very appropriate and
         CHAIRMAN BONACA:  Bob?
         DR. SEALE:  I was certainly impressed with the thoroughness,
     and really the enthusiasm with which the applicant has plowed new ground
     here.  I guess the old story is that only the lead dog gets to see the
     change in scenery.  And, certainly, you are seeing a lot of change in
     scenery as you go through and do this analysis.
         I have one concern that just struck me that as you went
     through you in some cases referred to some rather vintage analysis, even
     things that were done before TMI.  And I wonder if those vintages are
     perhaps all they are cracked up to be.  Are there things that have been
     learned since then.  Clearly there has been a very extensive amount of
     engineering work addressing some of the issues in the TMI realm that
     might cause one to ask whether or not those conclusions were completely
     true.  And I guess, Chris, I guess that is something your guys want to
     take a look at.
         MR. GRIMES:  Actually, I'll address that by saying that as
     we present the results of these license renewal findings, we emphasis
     that the underlying principals for license renewal; the first of which
     is reliance and the regulatory process to maintain plant safety. 
     Wherever there were lessons learned over time regarding whether the
     Three Mile Island lessons learned, or other specific events, the
     regulatory process has identified bulletins, generic letters, and other
     actions by which vintage analysis, or vintage designs are back fit to
     more modern standards.  We may have learned some lessons that we
     conclude did not warrant backfitting, but that does not necessarily mean
     that the utility has not taken that experience and reflected that in
     their vintage analysis.  We rely on them to do, to reflect on those
     things and go above and beyond with the backfitting requirements.  So
     that reliance and the process gives us the confidence that whatever
     vintage features needed to be upgraded, have been upgraded.
         CHAIRMAN BONACA:  Mr. Uhrig?
         MR. UHRIG:  I, too, am impressed with what I've seen the
     last day and a half.  My major concern had to do with the cable aging,
     and I think that was very appropriately addressed yesterday, and
     summarized here again this morning.  I don't have any reservations on
         The one surprise that came out this morning is the lack of
     cathodic protection.  But, again, it is not an issue as far as license
     renewal is concerned.  I'm just surprised.  I had understood this was
     always pretty much standard procedure, but it is not an issue as far as
     the relicensing is concerned.  Thank you.
         CHAIRMAN BONACA:  Dr. Powers?
         DR. POWERS:  I'd like to first just comment on absence of
     cathodic protection.  I think there are probably more instances in this
     world over cathodic protection than cathodic trouble, whereas it is
     protected, there are some serious problems with ground loops and things
     like that.  But it can occur on a complicated site.  So, the fact that
     there is no cathodic protection doesn't bother me very much.  I work
     with some sites where it is just a nightmare trying to cathodically
     protect things.
              I think it is important that we be able to write a
     letter that is fairly parallel to the one that we wrote on Calvert
     Cliffs.  So it is important to make sure we have the information that
     can do that.  Now, clearly, there are sites specific, but we    ought
     to have a certain parallelism to the extent if we can.  On the other
     hand, we do have to recognize that we are talking about methodology and
     setting a pattern that is going to be adopted in the future.
         So, I don't think we should hesitate to comment on
     methodological issues in the sense that they've been proven out here at
         DR. KRESS:  Do you see the scoping methodology they use as
     being generally applicable to other plants?  That was the concern I had.
         DR. POWERS:  I think that I would take from their scoping
     methodology, if I were a different plant, to be, the lesson learned
     there is to be imaginative in your approach on scope rather than trying
     to follow somebody else's line of script.  That's the take home lesson I
     would get from that.
         There is a question in my mind on how much we want to speak
     to the technical issues of information to the Commission, and particular
     on the, what I would say betting on the aspects of this, since we've
         gotten explicit questions from the Commission on the issue
     of one-time inspections.  I'm wondering if in our presentation for the
     full Committee it might not be valuable to have a little more discussion
     of philosophy on that one-time inspection.  Why do they think that this
     is a good way to look at something.  How can you set the time frame for
     when it would be useful to do and when it is not useful to do.
         CHAIRMAN BONACA:  Yeah.  And it is not set by the program.
         DR. POWERS:  Just because it is clear that is a question
     that is on the mind of the Commission.  Enough for them to write us and
     ask us a question about it.
         DR. KRESS:  Well, their basis that they used was, I thought
     it was strictly pragmatic; how can we fit it into the remaining
     shutdowns we are going to have between now and the end of the original
         DR. POWERS:  I think there is nothing wrong with that, and
     I'm not objecting to it.  I'm trying to understand why ---
         DR. KRESS:  Understand why that's good enough?
         DR. POWERS:  Why that is good enough, yeah.
         DR. SEALE:  And what the circumstances might be under which
     one inspection wouldn't be adequate.
         DR. POWERS:  That's right, because there is, one of the
     things that is going to happen is you are going to set a precedent here,
     and you may well have to find, come up on occasion where you have to
     undue that precedent.  And so you want to make sure that precedent is
     cast in the right light, so that somebody can't come back and say, "hey,
     you let these guys do this and I want to do the same thing," or it is
     almost the same thing, and now you are not letting me do this.
         CHAIRMAN BONACA:  And the other thing is that clearly we
     understood the philosophy of the NRC in accepting one-time inspection as
     a confirmatory inspection that in effect is not occurring.  That in of
     itself has a logic behind it that says you should wait and allow for
     time to give yourself time to make sure that you give it time to this
     improbably effect to manifest itself.
         And so, then we had some communication that says, well, you
     know, there should be no restriction when you do it.  Well, you have
     twenty years behind you.  It doesn't make all sense.  I think it would
     be good to have that discussion with the staff planned for next week.
         DR. KRESS:  Well, my concern with that, Mario, is that I'm
     afraid it is an unanswerable question.
         DR. POWERS:  And I think that is an acceptable response from
     the staff.
         CHAIRMAN BONACA:  That's fine.  Sure.  Okay.
         DR. POWERS:  I think you, if the staff came in and said,
     "Look, here is what we are trying to accomplish."  You are trying to
     respond to a negative hypothesis.  You are doomed to failure here.
         DR. KRESS:  Yeah.  You are doomed to failure, yeah.
         DR. POWERS:  So you are looking for plausibility, and that's
         all we've sought is plausibility here, and a program that
     has these characteristics to us is plausible and the ones that have
     these characteristics is implausible to us, I think that is an
     acceptable answer, because that is pretty much the answer we've given
     the Commission on that, this plausibility document.
         CHAIRMAN BONACA:  We never gave a communication we expect to
     establish a criteria, but we said that this seems appropriate to the
     extent possible that you would delay as much as you can.  They go in
     cycle.  And that's why, I mean, I think it is important we understand
     why not, or there is a different criteria.  One is, you know, can you
     perform a one-time inspection when your license the new plant.  He says
     that he can do that.  So, that's an issue we should hear about.
         DR. POWERS:  I think it's that I personally would like to
     see, understand a little better, the technical underpinning for the
     decisions on the sampling of piping for the ground corrosion.
         CHAIRMAN BONACA:  Yes.
         DR. POWERS:  I don't know that it is wrong.
         CHAIRMAN BONACA:  No.  But to hear the criteria ---
         DR. POWERS:  In other words, a little more details on this
     so that I would be in a position to defend it, as well as the staff.
         CHAIRMAN BONACA:  Okay, Mr. Sieber?
         Mr. Sieber:  As you know, I'm recused from voting on the
     application with Duke Energy.  On the other hand, I'm not recused from
     assisting the committee in making its investigation, reviewing the items
     that were assigned to me, and commenting on those.  I have done all of
     those.  Along with Dr. Uhrig, I was assigned to look at the electrical
     issues here.  But there are other items that I was particularly
     interested in.  As a general conclusion I believe that there is nothing
     that bothers me to any significant extent that would prevent the
     issuance of an extended license.  I would point out that in my
     discussions with individual Duke employees, they were very forthright
     and honest, and very willing to tell me everything that I asked them, or
     volunteer information straight from the shoulder, and I think that
     that's a prime and essential ingredient to being able to maintain a safe
     plant.  But I got that impression while I was here and I would encourage
     them to foster that amongst all the people that are involved with
         CHAIRMAN BONACA:  Thank you.  In my impressions -- first of
     all, I would like to just make some comments regarding the interim SER
     as we received it, and the final SER.  There are some big differences in
     my mind, and that's mostly for the issues we sought.  Scoping.  I think
     that the extended review by the staff was important in my mind because
     it gave us further assurance that in a pretty cloudy definition, as we
     have for an older plant like Oconee, they have gone the extra mile to
     verify that there are components out of scope.  I think that by looking
     at a number of additional, particularly the high energy line break,
     which really spans the whole gamut of the plant.  When you cover that
     and you find no additional components, that gives a good feeling that
     really you have covered the scope issue reasonably well, or well.
         The reason the reactor, RVI-AMP, which is Reactor Vessel
     Internal Aging Management Program, I think is a significant commitment. 
     And I think that -- you know, so many of the issues we had regarding
     fatigue, regarding swelling, is really captured by that program.  I
     really like to see that program is so tied in with the initiatives of
     the industry to aggressively go after these issues because the industry
     has not addressed those issues.  So that is really their -- it has to be
     that leadership.
         Also, I was satisfied about the closure on the issue of
     attendance, because that is a program where inspections, you know, you
     are not relying any more on those that, you know, we had other questions
     on when we met for the interim review.
         Also, the cables.  What I appreciated the most was the
     initiative of the plant to go out and look at locations and take
     pictures and be candidate with us, and that we could see and then to
     respond.  It means that they intend to take care of it.
         I was impressed by the physical conditions of the plant. 
     Most of all, by the fact that I didn't see a difference between the
     components which are going to be aging and those which are not, which it
     is telling me that there is a tendency to look at all components and
     take care of that.
         One statement though, I'd like to make, has to do with
     more an impression, the reliance on established CLB.  That is part of
     the rule.  But my feeling is always that there is a rule and then there
     is we want to run a safe plant anyway.  And so I, and I'm not saying
     that Oconee would not in fact look outside of the rule, but you --
     particularly when the CLB is very old, you have to be alert to all
     components that you know by other means or any means that are important
     to safety.  There will be some that you didn't capture in that CLB, and
     some that you captured, for example.  And, so, I know that we have
     discussed this with the staff, these questions that got raised, and I
     believe again that the scope is adequate, but I think it is important
     that we all always recognize that, you know, we know as much as we, you
     know, our tools give us to know.
         DR. KRESS:  Mario, do you think the addition of the
     additional events to look at following this Chapter 15 is almost like
     doing a PRA?  If you add enough of the events in ---
         CHAIRMAN BONACA:  Let me give you a feeling for what -- let
     me just give you -- I mean, this is a high energy line break analysis
     done most likely in the early 70's.  I heard 1973.  You know, there were
     computer codes used at that time.  You don't even recognize it was for
     heat, but you blow super heat inside certain rooms at times and you get
     significant effects.  And, so, you know, as in a PRA, what you know is
     as good as the methods you use.  And, so, and there is nothing wrong
     with the licensing base of older plants, but the fact is, you know, they
     are more limited and we have to recognize that.  Now, that is really
     what I meant.
         DR. KRESS:  All right.  I was encouraged that the staff was
         able to add additional, what I would call design basis
     events, into this.
         CHAIRMAN BONACA:  Yes.
         DR. KRESS:  Because I think that sets a bit of a precedence
     that even though we can't see how to work the PRA, and that precedence
     to me does give a way to make sure the scope does cover all safety
     significant to the components of the system.  That was encouraging to
         CHAIRMAN BONACA:  Yeah.  And to me, too.  It was
     significant, you know, cross verification of scope.  And I agree with
     Dr. Powers that we should hear something about one-time inspection, the
     initiative as being somewhat belabored.  Again, the perspective of the
     committee is not one that we should impose any requirement as being done
     the last day, but one that says it is prudent to do it.  Later and
     earlier because you want to keep a chance for this effectively.
         DR. KRESS:  I realize there is pragmatic and practical
         consideration there.  It takes so long to do an inspection. 
     You can't do it all at once, even though it is a one-time inspection,
     and it ought to be spread out over time.  My thought there is that I
     think there is a need to prioritize.  Which ones do you do first and
     which ones do you do last, and not worry too much about the timing, but
     the order in which you do it.  I haven't seen much discussion on that.
         DR. POWERS:  I think what you are looking for is some
     language, some thought on a question of detectibility and sizing. 
     Clearly, you want to inspect for those things that are most easily
     manifested and most easily detected, most easily sized earliest.  And
     the most difficult latest.  And in that, that maybe all the guidance you
     can offer.
         DR. KRESS:  I haven't seen any guidance.
         DR. SEALE:  Well, in this case, in this case, too, there is
         going to be the additional attraction, if you will, and
     advantage perhaps of having an extended outage or two having to do with
     steam generator replacement that is going to sort of open the plant up
     for perhaps more detailed examination of some things than others.  It
     would be a shame to not be sure that the tough ones that needed time to
     do, or to gain access to, were ignored when that opportunity arose.  But
     you can't count on that every time.  Not everybody is going to do that,
     but serendipity does come up and bite you every once in awhile.
         CHAIRMAN BONACA:  My thoughts on what to put in the letter. 
     I agree with some of the comments that Dr. Powers made in the beginning,
     but as we, I would like to use the same format we used for Calvert
     Cliffs.  I would like to highlight in that letter some of the problems
     which have been instituted in this list of open items, which I mentioned
     before.  We were very significant, I mean, the reactor vessel programs,
     the containment commitments, and the cable problems.  I would like to
     address the closure of GSI-190.  I think that is important because this
     comes right after we close another genetic basis and we have a licensee
     who has responded and has essentially committed to certain specific
     inspections to deal with additional concerns that really, they could
     take our position on that and say, "Well, we are not going to do it
     because GSI-190 is closed."  So I think that was something I wanted to
     identify in the letter.  I would like to put something regarding
     one-time inspection just to clarify the committee perspective on that. 
     We may have been misunderstood in the past, or they may have believed
     that we were trying to impose some kind of specific requirements, which
     we never intended to.
         Dana, you mentioned before the importance of communicating
     some of the methodology that the staff is using to accept closure of
     open items, and said to me the one of corrosion of carbon steel pipes. 
     It is a good example.  And, so, we will ask the staff to give us, you
     know, a very brief summary of the logic as they go through that we heard
     today verbally, and I would like to further summarize that just for
     information for the Commissioners.  That was pretty much, I mean, there
     may be additional items that seem to be important enough for them to put
     in the letter for comment anyway, for your review.  But that would be
     the bulk of where I would like to go.  And I will hopefully have a firm
     draft for you before we travel to Washington so that you can take a look
     at it, because we have a very short time table.
         DR. KRESS:  Well, once again, I was impressed with the depth
     and comprehension of the staff's review.  That gives you a lot of
     comfort to know they do a really good job on this.
         CHAIRMAN BONACA:  Yeah, likewise.  I was very impressed with
     their work.  I was very impressed with Oconee.  Unfortunately, and I say
     unfortunately, it gives us a benchmark as we did for Calvert Cliffs, and
     sets up expectations at least on our part for the next applications, and
     we hear about people coming in groves and groups and lumping together. 
     We will have to really be watchful of the process that Oconee is going
     through to identify components of established programs.  We will be with
     them for a long time, because they are taking the time to look at it,
     inspect it, and hopefully as well will happen on the next applications.
         We have identified a couple of things I would like to hear
     for a full committee meeting, and it seems to me that from Oconee, from
     Duke, we would like to hear about the three items represented today,
     which is scoping, cables and the Reactor Vessel Internal Aging
     Management Program.  Any other items you would like to hear from Duke?
         DR. KRESS:  Well, their plans for the one-time inspection.
         DR. SEALE:  Yeah.
         CHAIRMAN BONACA:  Okay.  Plans for the one-time inspection,
     and maybe just some basic information regarding their embedded pipes
     corrosion inspection so we can understand that philosophy.
         And on the part of the staff, we need to hear pretty much
     the summary of closure of open items with -- I will expect special focus
     on the three areas that are being presenting by Oconee, which is
     scoping, cables and reactor vessel internal.  Also, explaining their
     philosophy and accepting some of, you know, the approach for example on
     the corrosion of embedded piping.
         And they heard us today talking about one-time inspections,
     so if there is any additional information that, or other perspectives
     that you are to give us, that would be the place for us to receive them
     so we can possibly address them in the letter.
         MR. GRIMES:  Dr. Bonaca?
         CHAIRMAN BONACA:  Yes.
         MR. GRIMES:  Just so that I make sure we are clear, Duke is
     going to make a presentation of the full committee that is going to
     describe scoping, cables, reactor vessel internals, their one-time
     inspections, and the buried piping?
         CHAIRMAN BONACA:  Yes.
         MR. GRIMES:  And the NRC staff is going to provide a summary
     of the closure of open items, and will specifically emphasize -- I'm
     going to start first with the reliance on the CLB and the regulatory
     process in terms of what the scope or renewal is.  One-time inspections,
     both philosophically and in terms of what our expectations are, and then
     how we do them in the change to the licensing basis.  And then the
     buried   piping issue, in terms of the illustration of the
         staff's approach to evaluating aging management programs. 
     Is that correct?
         CHAIRMAN BONACA:  Correct.
         MR. GRIMES:    Thank you.
         CHAIRMAN BONACA:  Okay.  Do we have any other comments?  Any
     comments from the public?
         MR. TUCKER:  My name is Mike Tucker.  I'm Executive
     Vice-President for Duke.  I rarely miss the opportunity to get up in
     front of a microphone.  I would just like to thank the staff very much
     for the work that you have done in reviewing the Oconee application.  I
     think you are correct, the NRC staff has done a very rigorous review of
     this topic, and our staff has certainly put a lot of effort into it. 
     Doctor Seale, we very much appreciate your view that the view is only
     different as a lead.  This team has done a good job and we look very
     much forward to the review next Thursday, I guess, with the full
     Committee moving on this project, so we have an opportunity to bring
     some more to you in the future.
         CHAIRMAN BONACA:  Thank you.  If there are no other
     comments, we will ---
         DR. SEALE:  We do need to get to visit plants a little more
         CHAIRMAN BONACA:  I agree.
         DR. SEALE:  I think you learn a lot.
         DR. POWERS:  We've got one coming in June.
         DR. SEALE:  I know.
         DR. POWERS:  I would personally like to thank the Oconee
     staff for the hospitality and the fine tour we had.
         CHAIRMAN BONACA:  And for the lunch that was delicious, I
     must say, and plentiful, too.  Okay, so with that I think we can adjourn
     the meeting.  The meeting is adjourned.
         [Whereupon, at 11:15 a.m the meeting was concluded.]


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