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Thermal-Hydraulic Phenomena - September 26, 2001

 

                Official Transcript of Proceedings

                  NUCLEAR REGULATORY COMMISSION



Title:                    Advisory Committee on Reactor Safeguards
                               Thermal-Hydraulic Phenomena Subcommittee
                               Duane Arnold Energy Center Power Uprate
                               Request



Docket Number:  (not applicable)



Location:                 Rockville, Maryland



Date:                     Wednesday, September 26, 2001







Work Order No.: NRC-033                               Pages 1-177



                   NEAL R. GROSS AND CO., INC.
                 Court Reporters and Transcribers
                  1323 Rhode Island Avenue, N.W.
                     Washington, D.C.  20005
                          (202) 234-4433                         UNITED STATES OF AMERICA
                       NUCLEAR REGULATORY COMMISSION
                                 + + + + +
                 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS
             THERMAL-HYDRAULIC PHENOMENA SUBCOMMITTEE MEETING
              DUANE ARNOLD ENERGY CENTER POWER UPRATE REQUEST
                                 + + + + +
                                 WEDNESDAY
                            SEPTEMBER 26, 2001
                                 + + + + +
                            ROCKVILLE, MARYLAND
                                 + + + + +
                       The ACRS Thermal Phenomena Subcommittee
           met at the Nuclear Regulatory Commission, Two White
           Flint North, Room T2B3, 11545 Rockville Pike, at 1:00
           p.m., Dr. Graham Wallis, Chairman,
           presiding.
           COMMITTEE MEMBERS PRESENT:
                 DR. GRAHAM WALLIS, Chairman
                 DR. F. PETER FORD, Member
                 DR. THOMAS S. KRESS, Member
                 DR. DANA POWERS, Cognizant ACRS Member
                 DR. STEPHEN ROSEN, Member
                 DR. WILLIAM SHACK, Member
                 DR. VIRGIL SCHROCK, ACRS Consultant           ACRS STAFF PRESENT:
                       PAUL A. BOEHNERT, ACRS Staff Engineer
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
                                            I-N-D-E-X
                         AGENDA ITEM                       PAGE
           Introduction . . . . . . . . . . . . . . . . . . . 4
           Duane Arnold Power Uprate Presentation . . . . . . 7
           Concluding Remarks . . . . . . . . . . . . . . . 176
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
           
                                      P-R-O-C-E-E-D-I-N-G-S
                                                    (1:00 p.m.)
                       CHAIRMAN WALLIS:  The meeting will come to
           order.  This is A meeting of the ACRS Subcommittee on
           Thermal-Hydraulic Phenomena.  I am Graham Wallis,
           Chairman of the Subcommittee.
                       Dana Powers will be the ACRS Cognizant
           Member for this meeting.  Other ACRS Members in
           attendance are Peter Ford, Thomas Kress, Stephen
           Rosen, and  William Shack.  The ACRS Consultant in
           attendance is Virgil Schrock.
                       The purpose of this meeting is for the
           subcommittee to review the license amendment request
           of the Nuclear Management Company fora core power
           uprate for the Duane Arnold Energy Center.
                       The subcommittee will gather information,
           and analyze relevant issues and facts, and formulate
           the proposed positions and actions as appropriate for
           deliberation by the full committee.  Mr. Paul Boehnert
           is the Cognizant ACRS Staff Engineer for this meeting.
                       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 September 19th, 2001.
                       Portions of this meeting may be closed to
           the public as necessary to discuss information
           considered proprietary to General Electric Nuclear
           Energy.  Please let us know if and when that is the
           case.
                       The transcript of this meeting is being
           kept, and the open portions of this transcript will be
           made available as stated in the Federal Register
           notice.  It is requested that speakers first identify
           themselves, and speak with sufficient clarity and
           volume so that they can be readily heard.
                       We have received no written comments or
           requests for time to make oral statements from members
           of the public.  I have a brief opening comment.
                       The ACRS, before this meeting, received
           stacks of paper which amounted to over a foot in
           height.  We obviously don't have time to read and
           digest every word.
                       So I think that it is very important that
           the speakers focus on what issues the ACRS needs to
           consider and what information we are going to need to
           reach decisions on those issues.  And I believe that
           Dr. Ford has a statement to make.
                       DR. FORD:  Yes.  I am a GE retiree, and
           therefore I have a conflict of interest.
                       CHAIRMAN WALLIS:  Now I would like to ask
           my colleague, Dana Powers, to take over my job for a
           while and to run the meeting.
                       DR. POWERS:  Thank you Professor Wallis. 
           We are going to be looking at one of the first of the
           major power updates that we seem to have coming along
           the pike here.  This is a truism that the boiling
           water reactors in this country typically operate at
           powers that are less than what they were originally
           conceived of operating at.
                       And in part that was because of a historic
           -- a long time ago many ACRS' before this current
           version of it had particular concerns about DWR
           stability at the higher power.
                       What we are going to try to cover is a
           huge amount of material.  Professor Wallis' is over a
           foot, and he must have only gotten half of it if he
           only had a foot.
                       CHAIRMAN WALLIS:  Over a foot.  I was
           being conservative.
                       DR. POWERS:  And the plan of attack is
           that we are going to listen to the applicant this
           afternoon, and then tomorrow we are going to listen to
           the staff tell us why we should have believed
           everything that was told to us from the applicant.
                       And so I am going to turn now to Ron
           McGee, the power uprate project manager, to start the
           presentation, and you will introduce the additional
           speakers as the need arises.
                       And remain cognizant that should we have
           to deal with proprietary material, that creates a huge
           disruption.  So you have to let us know beforehand.
                       MR. MCGEE:  Good morning then.  My name is
           Ron McGee, of the Nuclear Management Company at the
           Duane Arnold Energy Center.  I would like to thank the
           committee for taking the time to review our submittal
           and for meeting with us today.
                       We recognize the importance of power
           updates as part of the solution to meeting the
           country's future energy needs, but foremost we must
           ensure that public safety is not jeopardized.
                       We believe that through our engineering
           evaluations and the staff's review process the DAEC
           application for a power uprate has shown an adequate
           amount of operational design and safety margin for the
           various facets of the project.
                       Today, we have been asked to present the
           following topics.  I will be presenting the plant
           changes and modifications, and then we will talk
           quickly about the regulatory compliance, the analysis
           performed as part of the project, and then we have
           been asked to discuss margins, which I will get to
           here in a minute.
                       Then we go through the operator training
           that we have applied.  Then we will have discussions
           on thermal hydraulic stability, the ATWS response, and
           ATWS instability fuel response, material degradation
           issues, the containment analysis, the effects of power
           uprate on the steam separator and dryer, ECCS analysis
           as part of the project.
                       And then the last presentation is the PRA
           analysis, and then we will have concluding remarks and
           a wrap up of any open issues that come up.
                       CHAIRMAN WALLIS:  Did you rehearse this so
           that it can be over in two hours?
                       MR. MCGEE:  Two hours, no.  We have --
                       CHAIRMAN WALLIS:  You are supposed to
           allow two hours for our questions.
                       MR. MCGEE:  We have accounted for four
           hours, including questions.  We believe that the
           presentation material, including questions, should be
           concluded within four hours.
                       DR. POWERS:  It is going to be so clear
           that that we will have no questions whatsoever.
                       MR. MCGEE:  The first presentation will be
           where we go over the power uprate modifications that
           we performed as part of this project.  The safety
           related modifications -- and I will point out that
           these are the only safety related modifications that
           were necessary to accommodate the power uprate.
                       These were installed in our recent outage,
           and we installed new APRM cards, installed higher
           range main steam line flow implementation, and we
           through a previous amendment, we have increased our
           required boron concentration for a standby liquid
           system.
                       The balanced plant modifications.  We
           installed higher capacity transformer; coolers --
           improved cooling capacity on our hydrogen coolers for
           our main generator.
                       A major modification was that we replaced
           the high pressure turbine, and the feed water level
           control for the feed water heater system had to be
           modified to accommodate the higher capacity.  As part
           of the ELTR, we have installed flow induced vibration
           monitoring.
                       CHAIRMAN WALLIS:  What does Phase One
           mean?
                       MR. MCGEE:  As part of our uprate, we
           intend to go up from 1658 megawatt thermals, our
           current license power level, and we intend to operate
           at 1790 megawatt thermal.  And then following a future
           outage, we plan to ascend to the rest of the license.
                       CHAIRMAN WALLIS:  So you are applying for
           the whole thing?
                       MR. MCGEE:  That's correct.  We are
           applying for the license to 1912 megawatts thermal. 
           But a balance of plant modifications will only
           accommodate operation up to 1790 for this interim
           period.
                       MR. BOEHNERT:  What are the percentages,
           Ron?  Do you know roughly?
                       MR. MCGEE:  Approximately halfway each
           time; 8-1/2 percent right now, and then another 8-1/2
           percent on top of that.  Feed and condensate pump
           breaker, protective relaying set point, condensate the
           demineralizer capacity as part of the feed water flow
           stream.
                       And the main condenser tubes because of
           the increased steam flow, and added structural
           support.
                       CHAIRMAN WALLIS:  I actually have to agree
           on the language.  I noticed in this staff review that
           they are talking about 120 percent increase?
                       MR. MCGEE:  The 120 percent that is from
           original license --
                       CHAIRMAN WALLIS:  No, no, no.
                       MR. MCGEE:  Oh, increase.
                       CHAIRMAN WALLIS:  A twenty percent
           increase.
                       MR. MCGEE:  Yes.
                       CHAIRMAN WALLIS:  The staff was talking
           about 107 percent, and it is really mind-boggling.
                       MR. MCGEE:  That would be Unit 2.
                       DR. KRESS:  You went by one of our slides
           a little too fast.  You talked about whether one of
           the mods was a MELLLA APRM card, and I know what the
           MELLLA is and all of that, but his this card an
           automatic controller to make sure that you go along
           the MELLA line?  What is the card?
                       MR. MCGEE:  The card actually monitors
           your flow by SCRAM set points, and supplies the trip
           function into your RPS system, reactor protection
           system.
                       DR. KRESS:  Okay.  That's what I thought,
           but I wanted to make sure.
                       MR. MCGEE:  That's correct.  The next
           slide.  Continuing with our balanced plant
           modification; isophase bus temperature monitoring for
           the electrical load increase; and monitor the
           temperature.
                       And the main steam line relief value
           snubber was one support that we needed to increase. 
           One of our feed water heaters was going to have a
           significant increase in its load carrying capacity,
           whereby bypassing the flow to the main condenser.
                       And control room indications and alarms
           have been modified to accommodate the previous
           modifications that you have seen here.
                       Phase Two, when we go from 1790 up to
           1912, preliminarily, we have identified feed water
           system capacity, and we will need to increase the
           system capacity from about 8.1 million pound mass to
           something just greater than 8.75 million pound mass
           per hour.
                       Feed water heaters.  Their load bearing
           capacity will need to increase, and so we are
           anticipating the need to increase various feed water
           heaters.  And then our isophase bus to carry the
           increased electrical loading.
                       MR. ROSEN:  You said the increased feed
           water, and the slide says replacement.  Are you going
           to replace the heaters?
                       MR. MCGEE:  We do plan to replace feed
           water heaters, certain ones.
                       MR. ROSEN:  But not all of them
                       MR. MCGEE:  But not all of them, that's
           correct.  Some will be at the upper -- increased at
           the EPU power level, and will be within their design
           to carry the amount of increased loading, but the
           three, four, and five heaters -- we have six heaters,
           and the 3, 4, and 5s right now looks like they will be
           marginal.  So we will be looking at a wholesale change
           outs of those.
                       MR. ROSEN:  Those are the low pressure
           heaters?
                       MR. MCGEE:  Those are high pressure
           heaters.
                       MR. ROSEN:  And the low pressures are all
           right, but the high pressure heaters need to be
           changed?
                       MR. MCGEE:  The ones and twos are the
           lowest pressure, yes, that's correct.  Those are okay.
                       MR. ROSEN:  So you are saying that you are
           looking at it.  It is curious language.  You are
           looking at replacing them.
                       MR. MCGEE:  Yes.  We are planning to
           replace all of the heaters.  We are looking at designs
           and depending on how and which ones you replace, that
           will determine the need to replace others.  Next
           slide.
                       The next topic was regulatory compliance. 
           Our application was a deterministic application, and
           it is not a risk-informed application.  It was
           performed in accordance with previously approved ELTRs
           1 and 2.
                       The process for the application and the
           studies includes a feasibility study, which was
           conducted in late 1999.  Engineering evaluations
           throughout the year 2000, et cetera.  The licensing
           reports, which you have seen most of, I believe, if
           you have gotten a foot of paper.
                       The hardware modifications that we have
           just reviewed, and then post-approval, and we have
           testing to perform, and we have performed preliminary
           testing up to our current license power uprate.
                       CHAIRMAN WALLIS:  You said this was not a
           risk-control, and yet one of the major consequences
           here is the operator reaction time during ATWS.  One
           of the major concerns in that seems to be resolved on
           a risk basis rather than some sort of compliance.
                       MR. MCGEE:  We do have a presentation that
           will include discussion of that topic if you would
           like to wait for that.
                       CHAIRMAN WALLIS:  Okay.  You will address
           that at that time?
                       MR. MCGEE:  We will.
                       MR. MCGEE:  The analysis performed.  The
           general topics were the reactor operating conditions,
           accidents and transients, the radiological
           consequences of a power uprate, component system
           capacity, including NSS and BOP; instrumentation and
           controls; the environmental impact of the power
           uprate.
                       And then a review of the station programs. 
           For instance, PSA, environment qualifications, station
           blackout, et cetera.
                       The generic topic of margins.  We were
           asked to discuss that.  And what we have done is
           included a discussion in the rest of the presentations
           today to address the impact on margins on the specific
           topics.
                       And then if the committee would like to
           follow on with questions during those times, I would
           propose that is how we address those.  And next will
           be Steve Kottenstette.
                       MR. KOTTENSTETTE:  Hi.  I am going to be
           talking about operator training.  My name is Steve
           Kottenstette, and I am an operations shift manager on
           loan to the power uprate project.
                       We started out using classroom training. 
           We took the material from the power uprate project and
           we discussed with the operators how the procedures are
           going to change, and how the tech specs will change,
           and the testing that we will do as far as the power
           uprate probe.
                       And then we moved into the simulator,
           where we took what we believed would be the best guess
           on how the plant will operate, and use a simulator,
           and through the various operational transients that we
           would see a trip over recirc pump, a trip of the feed
           pump, turbine trips, reactor SCRAMS.
                       And then we also went into some of the
           accident scenarios, where we went through an ATWS and
           showed the operators the benefits of injecting standby
           liquid control early on in the scenario, and then
           showed what would happen if we didn't inject standby
           liquid control, or had a failure to inject.
                       We did a turbine trip and SCRAM scenario,
           and then we also did an MSIV closure, and did show the
           operators how much it did change.  And for the most
           part, there was very little change as far as our
           actions and how the plant responded once a plant was
           shut down.
                       DR. SCHROCK:  Could you embellish a little
           on what you mean by your best guess as to how the
           plant is going to perform?
                       MR. KOTTENSTETTE:  We took the model or
           the design information of the plant modifications, and
           the change out of the conset pumps and the feed pumps,
           and the reactor model, and we basically gave it our
           best guess on how it should respond.
                       And then we also benchmarked it against
           the accident analysis that we got from GE, as far as
           this is how the plant should respond to a turbine
           trip, or an MSIV closure.
                       And we looked to see how the simulator
           responded, and it pretty much matched up to what we
           saw or the information that we got from the analysis.
                       CHAIRMAN WALLIS:  Do you have any sort of
           feedback for how well the operators responded to this? 
           I mean, you trained them and you would tell them these
           various things, and then it is supposed to change
           their performance in some way or their reaction at the
           time, or whatever.
                       Do you have a measure of how well they did
           after training?
                       MR. KOTTENSTETTE:  During the training, it
           was obviously observed during the training that the
           operators responded per our procedures, and as far as
           containing the scenario and responding to it, there
           was no marked decrease in operator performance.
                       CHAIRMAN WALLIS:  So you don't try to
           measure the probability of them doing the right thing? 
           This is somehow only an analytical assessment?
                       MR. KOTTENSTETTE:  As far as how the
           operators responded, or --
                       CHAIRMAN WALLIS:  There are numbers that
           are given to us in the paperwork about the probability
           of human error during an ATWS, and the numbers have
           increased.
                       And I just wondered if there was any
           measure from this training to show whether or not the
           operators were under more pressure, and made more
           mistakes or whatever with the power uprate than you
           would get from the simulator experience.
                       MR. KOTTENSTETTE:  We didn't see any
           increased errors.
                       CHAIRMAN WALLIS:  But did you look for
           any?
                       MR. MCGEE:  This is Ron McGee once again. 
           The operators during their training scenarios have
           critical tasks that they have to perform in their
           dynamic scenarios, and the operators on the power
           uprate tasks all successfully performed the critical
           tasks.
                       There were no operator failures or
           remediations necessary during the power uprate phase
           of the test of the classroom or simulator training.
                       MR. ROSEN:  I think we will hear later
           that the time for action, taking the required actions,
           is shortened by this uprate, but that what you are
           saying is that the operators were able to take the
           necessary actions in spite of the shortened times
           allowed.
                       MR. KOTTENSTETTE:  Yes, because there is
           a very simple process of actually initiating standby
           liquid control.
                       MR. ROSEN:  It is all right there in front
           of them, the keys and the mode switch?
                       MR. KOTTENSTETTE:  The keys and the mode
           switch, and take it out of the mode switch and put it
           in the switch for the controls for the pumps.
                       MR. MCGEE:  And we specifically monitored
           for that, for the operator taking those appropriate
           actions on standby liquid.  And all of the currently
           licensed crews were able to perform that action
           satisfactorily.
                       MR. ROSEN:  And I think we will hear more
           about that in the PSA discussion I assume?
                       MR. KOTTENSTETTE:  Yes, you will.
                       MR. MCGEE:  Yes, that's correct.
                       CHAIRMAN WALLIS:  I'm sorry, but you have
           your schedule.  When are we going to get into other
           questions that are not on your plans, such as the
           stresses in the components and a question that we
           might have about something that is not in your
           outline?  Do we leave that to the end?
                       MR. MCGEE:  That is an option.
                       DR. SHACK:  It seems to me that we ought
           to bring them up when they are appropriate, Graham.
                       CHAIRMAN WALLIS:  Well, if they never
           raise the issue, we are going to have to bring in up
           sometime.
                       MR. KOTTENSTETTE:  There is a section on
           material issues, and that may be the appropriate time
           to do that.
                       CHAIRMAN WALLIS:  Well, I had a very basic
           question, which is that this is going to be a constant
           pressure power uprate?
                       MR. KOTTENSTETTE:  That is correct.
                       CHAIRMAN WALLIS:  And I just wondered why
           the stresses went up in things like the main closure
           flange, the vessel and the head if there were no
           changes in pressure?  And they go up by 10 percent or
           more than 10 percent, and why is that?
                       MR. MCGEE:  Gary is looking.  We have
           several people looking.
                       CHAIRMAN WALLIS:  Well, maybe we can after
           the break come back to this question.  That is a very,
           very basic question that I had to raise at some time. 
           So, think about it.
                       DR. POWERS:  It had to be a flow.  It
           can't be anything else.
                       MR. BROWNING:  Carrying on, next we are
           going to talk about the thermal-hydraulic stability,
           and my name is Tony Browning, and I am from Duane
           Arnold.
                       We will have General Electric and Jason
           Post here to my right giving part of the presentation;
           and Mr. Kottenstette said he will get back up and talk
           about the impact on the operations of the power plant.
                       So we will kind of go through a little bit
           of quick background and the calculational methodology. 
           Then I will get back up and discuss the analytical
           results.  Then we will get into some of the issues
           that the committee has raised about the Solomon
           monitoring system.
                       And then the operational aspects as I said
           by Mr. Kottenstette, and then we will have a quick
           conclusion.  Our purpose here is to demonstrate to the
           committee that we have adequate operational and safety
           margin at the EPU conditions.  So with that, I will
           turn it over to Jason.
                       MR. POST:  Good afternoon.  My name is
           Jason Post, and I am with GE.  Stability solutions. 
           The general design criteria is that GE C12 does
           neither prevent or reliably and readily detect and
           suppress reactor instabilities.
                       Duane Arnold has stability option 1-D,
           which does both.  So they have features that both
           prevent and detect, and suppress.  Their prevention
           feature is in an exclusion zone in the power flow map.
                       It is down in the low flow and high power
           corner of the power flow map.  It is defined with the
           frequency -- the main model, and it has a very
           conservative decay ration margin, .8.
                       So, of course, we wouldn't expect an
           oscillation to grow and continue to grow until the
           decay ratio was 1.0 or higher.  But they have a .8
           decay ratio, and so there is margin built in right
           there.
                       And they have a buffer zone outside of the
           exclusion region.  Of course, as an exclusion region,
           you cannot operate in that region at all.  If you
           enter that region, you have to immediately exit.
                       The buffer zone is five percent of power
           and flow outside of that region, and so that would be
           even a more conservative, and even a more lower decay
           ratio value for that.
                       And you can go into that if you are sure
           that you have a low decay ratio, and that is from the
           SOLOMON code.  It is an on-line monitor based on the
           ODYSY code, and that is how you ensure that you
           maintain a low decay ratio in that region.
                       CHAIRMAN WALLIS:  This exclusion zone is
           based on theory isn't it at this stage?  You have not
           built these cores with flux and higher power, and so
           we don't yet know when oscillation is actually going
           to occur with these cores do we?
                       MR. POST:  Well, we have had instabilities
           in cores, and so we have a pretty good idea of where
           they occur, and the most recent one was at the
           Columbia Power Plant back in about 1995, I believe.
                       And so we have seen them, and we have a
           pretty good idea.  We benchmarked those cases with our
           models, and so we have a pretty good idea.
                       DR. KRESS:  But those aren't at the power
           densities that you are talking about, at the power
           levels and the flows.  They are at the original
           values, right?  The question is does that instability
           region expand or change?
                       MR. POST:  Right, and we do expand it
           based upon the same models.
                       DR. KRESS:  You use the models to expand
           it?
                       MR. POST:  Right.  The key factor is
           really the highest license rod line.  So the change to
           EPU is not as significant as the change from ELLLA to
           MELLLA.
                       In fact, we already have plants that are
           operating with MELLLA.  So, it is not a significant
           extension of the methodology.  It is consistent with
           what we have already operated plants at.
                       CHAIRMAN WALLIS:  And presumably when you
           start up this plant, you use some sort of a warning
           that the are exclusions that we have calculated, and
           if you get close to it, you had better be observant.
                       MR. POST:  Exactly, and Steve -- and later
           in here we have a start-up map to show how they go
           outside the region and discuss how the SOLOMON code is
           used as they come up outside the region.  So that is
           a specific part of this in a couple of more slides.
                       CHAIRMAN WALLIS:  So you might have to
           modify SOLOMON based on what you actually observe, or
           is that independent?
                       MR. POST:  The modification is simply in
           terms of the inputs to the code to make sure it knows
           what the operating conditions are.  The code itself
           doesn't have to be modified.
                       So that is the prevention features.  The
           detect and suppress features.  It is important that
           the oscillation for Duane Arnold is proven to be only
           a core-wide mode, and so the entire core is going up
           and down at the same time; as opposed to a harmonic,
           where you get a side to side.
                       And if you had a side by side, then the
           average power tends to be flattened out, and your
           APRM, which is your average power range monitor, gives
           a relatively flat response.
                       But if it is a core-wide mode, then the
           oscillation is easily picked up by the APRMs.  So that
           existing hardware is where we demonstrate that that
           existing hardware does provide adequate protection of
           the safety limit.
                       MR. ROSEN:  And you are sure that the
           Duane Arnold core will respond in a core-wide mode
           because of its tight neuronic coupling?
                       MR. POST:  That's correct, and that is
           part of the demonstration; that the core-wide remains
           the predominant oscillation mode.
                       MR. ROSEN:  Will you say more about why it
           is tightly neutronically coupled?
                       MR. POST:  We will say a little bit more,
           and we will make sure and see if you have any more
           questions about that.
                       MR. ROSEN:  Okay.
                       MR. POST:  Next slide.  So the prevention
           methodology is the ODYSY code.  When the stability
           solutions were initially developed, we used the FABLE
           code, which was another frequency to the main model,
           and ODYSY is just a much better code.
                       It was initially applied for another
           stability solution, the enhanced Option 1-A solution,
           which is a prevention solution.  And so we extended it
           to Option 1-D, and the SER for that was just issued in
           April.
                       So the Duane Arnold extended power uprate
           is the first application, and Duane Arnold is
           operating in Cycle 18 right now for their current
           license power, with stability regions based on the
           ODYSY code.
                       It is important to note that when we
           licensed ODYSY that we replicated the results with
           FABLE, and the way that we did that was by adding an
           additional .15 margin in the decay ratio criteria.  So
           while we say there is a .8 criteria, really .65 is
           what is being calculated by ODYSY as our limit for the
           exclusion region.
                       And then we add .15 just as an adder to
           get the .8 that we are using on the stability
           criterion now.  And as I said before, ODYSY is also
           the basis for SOLOMON.  Next slide.
                       So this is the stability criteria map, and
           in the lower right-hand side is where you have a high
           channel decay ratio, and a low core decay ratio.
                       That is the type of condition where you
           can get a channel flow instability, and the fuel is
           specifically designed to avoid or to ensure that that
           cannot happen.
                       And then in the upper left-hand side, that
           is where you have a high core decay ratio and a low
           channel decay ratio, and that is where you get a core-
           wide mode instability.
                       And then where the cupus is taken out in
           the upper right-hand corner, that's where you have
           relatively high core and channel decay ratio, and
           that's when the higher harmonics can cause a regional
           mode instability.
                       So we use the 0.56 as the stability
           criteria and as the dividing line between when a core-
           wide mode and a regional mode instability can occur. 
           And this stability criteria has been around for a long
           time.
                       It goes back to the time when the LaSalle
           instability happened or before, and it has been
           supported by various tests and events to show that
           that is the difference between when core-wide and
           channel instabilities occur.
                       So we don't do a separation type
           calculation, for example.  We don't go into all those
           other arguments.  We just use that as long as the
           channel decay ratio is below .56 when the core decay
           ration exceeds .8, that that is a basis for
           demonstrating that core-wide is the predominant mode. 
           And I will turn it back over to Tony.
                       MR. BROWNING:  And this gets into some of
           the things that we have talked about, and we will walk
           through them fairly quickly.  The development of the
           exclusion zone power to flow map was a critical piece
           of this.
                       Jason just discussed the confirmation that
           we were still having core-wide oscillations only, and
           our maximum channel decay ratio was a value of .36,
           which you can see is well below the .56 acceptance
           criteria that you just saw on the stability maps.
                       So we are still predominantly core-wide. 
           We also integrated the new flow bias trips from going
           from ELLLA to MELLLA, and you will see that has the
           biggest impact on the results.  Not so much the power
           uprate itself, but it is more driven by the change to
           MELLLA.
                       And then we go through the confirmation
           that the flow bias SCRAM at the MELLLA level will
           protect the safety limit, minimum power critical power
           ratio in the fuel, and that is a critical part of the
           analysis.
                       And then we will go through a little
           comparison of pre-EPU and EPU results so that you can
           see that change.  Okay.  Steve.  Here is the power to
           flow map that we have been talking about, and as Jason
           mentioned, the exclusion zone is the area where we are
           not allowed to operate in steady state, and it is in
           the high power low flow portion of the power flow map.
                       And one of the other things that I would
           like to point out --
                       CHAIRMAN WALLIS:  That zone has boundaries
           that go all the way around it.  It is above the red
           line?
                       MR. BROWNING:  You are not allowed to
           operate in this region.  You have to state on this
           side of the line.  The exclusion zone is inside --
                       CHAIRMAN WALLIS:  Up there?
                       MR. BROWNING:  In here.  And the other
           thing that we would like to point out is we keeping
           talking about the change from ELLLA to MELLLA.  The
           black line is the ELLLA current load line.
                       And then you see the impact of MELLLA. 
           And while it is fairly dramatic at the top end at
           rated power, down here in the stability region, you
           will notice that it is not that dramatic, and that
           really explains later why you are not seeing a huge
           change when we go from ELLLA to MELLLA, or going into
           power uprate.
                       And that's because we are talking about
           this area down here, and you can see that the impact
           is not that big.  Next slide.  And what we do is we go
           through the APR flow by flux trip, and like we said,
           going from ELLLA to MELLLA, we raise all the trip
           points up consistent with that.
                       And then the impact, of course, is that by
           doing that we have moved slightly further away for the
           SCRAM.  So when we get into the oscillation
           calculations, and look at the hot bundle oscillation
           magnitude at the H BOP, it takes just a little bit
           longer for the automatic SCRAM to terminate the
           oscillation, because we have moved that much further
           up away from that corner of the power flow map with
           the automatic trip.
                       And that is the predominant thing that we
           see.  Looking at the impact, and I know that this
           slide is a little busy, but we are trying to show that
           all the changes we made aren't that dramatic.
                       When you look at where the current power
           level rated exclusions and buffer zones are, and how
           they just shift slightly with the uprate.  You will
           notice that they are almost anchored on the natural
           circulation line, because almost nothing changes
           there, and slightly greater sub-cooling has a slight
           effect down here.
                       But the biggest impact is shifting up from
           the ELLLA to MELLLA point.  You just take it and you
           drag it over.
                       CHAIRMAN WALLIS:  Well, I think you ought
           to explain some things to me.  I mean, if I am
           starting up a plant, and I have no flow and no power. 
           I am at zero.  How do I get here?
                       MR. BROWNING:  We are going to show you
           that.
                       CHAIRMAN WALLIS:  Because it looks to me
           as if you can't get there without -- you know, I don't
           see any reason that you are allowed to operate in it.
                       MR. BROWNING:  Steve will show you that
           shortly.  We have a power flow map that actually shows
           that.
                       CHAIRMAN WALLIS:  But that lower code, the
           one you call natural circulation.
                       MR. BROWNING:  Yes.
                       CHAIRMAN WALLIS:  You have to be to the
           right of that, or the left of it, or what?
                       MR. BROWNING:  We are going to be to the
           right of it.  We are going to come up this way.
                       CHAIRMAN WALLIS:  Then you have got to be
           below that other black line haven't you?
                       MR. BROWNING:  Yes, we have to clear the
           feed water protection line here on the recirc pumps.
                       CHAIRMAN WALLIS:  And you have to be below
           that?
                       MR. BROWNING:  Yes.  We have to be above
           it.
                       MR. MCGEE:  That is at minimum.
                       MR. BROWNING:  We have to clear this line
           before we can increase recirculation flow.  So we pull
           rods and heat up the plant on minimum pump speed, and
           clear this interlock, and then we can increase in flow
           and go in this direction.
                       And then continue to pull control rods out
           and go up on this side of the exclusion zone.  And we
           will show you a power flow map where we have an
           example of that.
                       DR. KRESS:  And then when you get up on
           the MELLLA line, that is strictly a flow power.  You
           don't have to pull the rods out there anymore?
                       MR. BROWNING:  Right.  You get as high as
           you can on the load line, and then you just cruise on
           up with the recirculation flow.  That's correct.
                       Now we are going to talk about SOLOMON a
           little bit because we had some inquiry from the
           committee about the SOLOMON software, and the
           stability monitor.  As Jason has already said, it is
           the ODYSY model.
                       It has been integrated into the plant core
           physics monitoring software.  It is an integral part
           of it.  It does not run separately.  It runs with it,
           and it takes its input from it.
                       Its purpose?  It is a backup for what are
           called power shaped controls, because back in the
           original days of this stability, one of the things
           that was of a concern was that the power shapes that
           were modeled in the bundles, how did we know that we
           were going to stay in that operating environment, and
           be bounded by what was assumed in those analysis?
                       So we have what are called backup power
           shaped controls.  So other options use things like
           boiling boundary.  For the Option 1-D plants like us,
           we use the SOLOMON software and the buffer zone as our
           backup power shaped control to maintain that  margin.
                       And what it does is that it merely allows
           us to sustain operation in the buffer zone and the
           power flow operating maps.  So that little band that
           we were talking about adding on of the 5 percent, when
           SOLOMON is available, the operators are allowed to
           transgress through that area and go through it.
                       If the SOLOMON software is not available,
           it becomes an extended exclusion zone, and they are
           not allowed to operate there.
                       MR. ROSEN:  Is the ODYSY code actually
           running in the background, or is it SOLOMON looking up
           results, and pre-store the results of ODYSY?
                       MR. BROWNING:  It is actually running, but
           it is not real time.  It takes a while to do the
           calculation.  So it takes its input from the core
           physics program, and then runs its time domain
           calculation, and comes out with the decay rations.
                       MR. MCGEE:  Frequency domain.
                       MR. BROWNING:  I'm sorry, frequency domain
           calculations, and comes up with a decay ratio, and
           this displayed to the operators.
                       MR. ROSEN:  So it is possible for the
           operators, if they are moving very quickly, to outrun
           ODYSY and SOLOMON, or how do you prevent that?
                       MR. KOTTENSTETTE:  You mean as far as --
           you know, if I change the power real fast, then --
                       MR. ROSEN:  If ODYSY sees you changing
           power, it goes back and tries to calculate the new
           outputs, but you have changed again before it ever
           catches up with you.
                       MR. MCGEE:  Are you talking about a
           predictive capability?
                       MR. ROSEN:  yes.
                       MR. BROWNING:  That is one of the things
           here.  It is a predictive capability.  You can look
           ahead and the reactor operators do that on a rod
           sequence exchange, or a start up.  They will have
           planned the sequence that they are going through in
           the start up process.
                       And they will have done predictive SOLOMON
           cases ahead of time, and tried to map out exactly
           where they are in stability space as part of their
           normal package that they bring up to the control room
           for the operators to use during those operational
           scenarios.
                       And it is because of this, because it is
           not real time, and exactly what we were talking about. 
           It can't keep up.  It just can't do the calculation
           fast enough.
                       And the other thing that we need to
           understand is that it is not monitoring the in-core
           neutron detectors in a time domain.  It is not
           actually looking for an oscillation.  It is doing a
           predictive calculation in the frequency domain, using
           the inputs from the physics, just like you would run
           it to do it for a reload.
                       CHAIRMAN WALLIS:  But you need this rather
           than just having a code which is permanent because of
           changes in the burn up or something?  Why do you need
           to have any calculation at all if you have already
           calculated it once?
                       MR. POST:  Can I answer that?
                       MR. BROWNING:  Sure.
                       MR. POST:  Jason Post again.  When we
           first proposed Option 1-D to the staff, they wanted an
           extra measure of protection to make sure that you were
           maintaining your stability condition with a loaded K
           ratio and with the core-wide mode as the predominant
           mode.  So it was added as an extra feature at the
           staff's request.
                       CHAIRMAN WALLIS:  And so it follows the
           burn up changes and changes in power distribution or
           something?
                       MR. POST:  All that is built into it from
           the input.
                       DR. POWERS:  From the physics.
                       MR. ROSEN:  So the operators know how to
           start up and avoid the instability region, and they
           also have SOLOMON cases which they have run along the
           line of their intended path to full power.
                       MR. POST:  Right.
                       MR. ROSEN:  And have basically checked out
           to make sure that they are stable using SOLOMON, which
           is really running ODYSY, or taking ODYSY results.
                       MR. POST:  That is correct.  And that is
           a great lead in to Steve here, who is next.
                       CHAIRMAN WALLIS:  All right.
                       MR. KOTTENSTETTE:  I am Steve Kottenstette
           again.
                       DR. SCHROCK:  Could I ask one more
           question.  Where does the thing typically begin
           steaming in this start up period?
                       MR. KOTTENSTETTE:  Usually at one percent
           power.  Usually we get to the point of adding heat is
           usually right around 4 to 5 percent power.
                       DR. SCHROCK:  So, 4 to 5 percent.  Okay.
                       MR. KOTTENSTETTE:  Okay.  As far as the
           use of SOLOMON, again it is always running, and once
           a day we get a printout when we are up and running. 
           But since it is always looking at where we are at on
           the power to flow map, it is automatic as far as when
           it sees that the plant has gotten into either the
           exclusion or the buffer zone.
                       It automatically calculates a case for us
           and prints it out for us.  So like if we have an
           operational transient where we lost a recirc pump,
           which is the most probable cause for us to go into the
           exclusion zone, it will sit there after a time delay
           and do the calculation, and print out for us where we
           are at as far as the stability plot.
                       As far as how we would monitor for thermal
           stability, we use our APRMs as our primary means to
           either detect it and to suppress it either when we see
           it initially, or if it sees it before we can actually
           take action.
                       As far as a plant start up, you can see
           here in the pink line there that that is our typical
           plant start up, as we come up in power and maneuver
           around the exclusion and buffer zones.
                       So once we get up in power and get the
           generator on line, we are now 3-D, and can actually
           operate and provide that input to SOLOMON.  And you
           will see that we raise power and lift the control rods
           enough to get above the interlock for the recirc
           pumps, where we can increase flow now.
                       And then once we get up to a point where
           we can now pull rods again to get it close to our
           rated low line, and then after that it is just to go
           up in power with recirc flow.
                       And then as we get up close to our target
           rod pattern, there will be minor rod adjustments.  And
           that is where you see all that squiggle up here at the
           top, as we are making adjustments to account for zanon
           and other poisons that are burning then.
                       CHAIRMAN WALLIS:  And you said that
           SOLOMON is run once a day.  Is the output from SOLOMON
           simply to move around these orange lines isn't it, and
           they change a little bit from day to day; isn't that
           what it really does?
                       MR. ROSEN:  You said that you run SOLOMON
           once a day when you are at a steady state?
                       MR. KOTTENSTETTE:  Right.  Or at the other
           end of the power flow.
                       MR. ROSEN:  But when you are going up, how
           often do you run the SOLOMON when you are making this
           maneuver?
                       MR. KOTTENSTETTE:  We normally don't run
           software or ask for a SOLOMON case during a start up.
                       MR. ROSEN:  Because you have several of
           them already done ahead of time, and you have looked
           at that as part of your operating plan?
                       MR. KOTTENSTETTE:  Right.
                       MR. ROSEN:  So you know where you are
           going to be as long as you go up?
                       MR. KOTTENSTETTE:  We know that we are not
           going to be close to the buffer or the exclusion area.
                       MR. ROSEN:  You got a little close this
           time didn't you?
                       MR. BROWNING:  Well, this illustrates a
           good point.  This was an actual start up of the plant. 
           This is actual plant data from this past January.  So
           this is at the current power levels and you can see
           that we stopped it at the current power level.
                       So we were just trying to highlight here
           that it is feasible to get around the exclusion and
           buffer zones, and yes, we got close here, but
           obviously when the operators get to the uprated
           condition, they will just move a little further over
           and just shift it a little bit to the right.
                       MR. ROSEN:  What was the cause in this
           particular case of the flow dropping off from 26
           million pounds per hour to 25?
                       MR. KOTTENSTETTE:  As you go up in power,
           you get increased resistance to the core, and so flow
           is going to actually die down or reduce.
                       MR. BROWNING:  Right.  We increase the
           steaming as you are pulling rods and going up.
                       MR. ROSEN:  So with a constant recirc pump
           speed, you are getting lower -- well, we can see the
           flow dropping off about a million pounds per hour?
                       MR. KOTTENSTETTE:  Correct.
                       MR. BROWNING:  That's correct.  And so the
           main point and the emphasis was that this region down
           here, where it appears that we could be constrained,
           we were just trying to show that the operators do
           actually have operating margin room in this area to
           get around this low end.
                       Because maneuvering out here is not the
           issue.  It is clearing the interlock and then skirting
           around.  And like we said, in conclusion, we tried to
           demonstrate that the methodology that we use builds in
           margin, and that the calculational methodology of the
           ODYSY code, we have accounted for that.
                       And that the acceptance criteria that
           Jason talked about adding the extra .15 on to the
           decay ratios so that it maps back to the old FABLE
           code, and so that's how we build in the margin.
                       And then in our case, plant specifically,
           we have seen no impact on the safety margins.  We have
           got lots of margin to the decay issue.
                       CHAIRMAN WALLIS:  And how would you define
           a safety margin?
                       MR. BROWNING:  Well, the safety limit
           minimum critical power ratio, and that the fact that
           the APR and flow by scramble protect that,and protect
           the fuel, and we have demonstrated that in the
           analysis.
                       CHAIRMAN WALLIS:  So safety margin is a
           measure obtained by comparing some number with some
           other number?
                       MR. BROWNING:  Yes.
                       CHAIRMAN WALLIS:  And one is lower by some
           amount and the safety is the difference between the
           numbers or something?
                       MR. BROWNING:  Well, what we do is we look
           at several scenarios, and do the calculation to show
           the change in the critical power ratio is for those
           particular transients.
                       And then we compare that to the safety
           limit and show that we have the margin that is
           required to demonstrate the safety margin is met.
                       CHAIRMAN WALLIS:  Is there something in
           the law which says what the safety margin has to be?
                       MR. BROWNING:  It is built into the safety
           limit MCPR, and the value that we use has got margin
           built into it.
                       CHAIRMAN WALLIS:  So it is clear what is
           meant?
                       MR. BROWNING:  Right.
                       DR. SCHROCK:  What is the duration of this
           start up process typically?
                       MR. KOTTENSTETTE:  The typical start up
           process, from initial start up to 100 percent power,
           it normally takes about two days to get all the way
           there.
                       DR. SCHROCK:  So it is very slow?
                       MR. KOTTENSTETTE:  Yes, it is.
                       MR. ROSEN:  Is it very slow during the
           time that you are going through the door, through that
           window?  How long does it take to get from -- if you
           will put the slide back up with the maneuvering.
                       Let's say to go from 13 million pounds per
           hour, which is the natural circulation, to 20 million
           pounds per hour?  How long does it take you to do
           that?
                       MR. KOTTENSTETTE:  That should take
           probably about 15 minutes, because when we increase
           power with recirc, we pretty much go -- our normal
           rate is like 2 to 3 megawatts of electric.  So, with
           five percent power, that is going to take about 15 to
           20 minutes of adjusting recirc flow.
                       MR. ROSEN:  So in terms of the critical
           operational period, you are going to go through all
           those critical maneuvers and be watching the critical
           parameters.
                       And it's not like if you have to watch
           that for two days.  You are in the critical region for
           about 15 or 20 minutes, and from then on you have got
           a lot more margin.
                       MR. KOTTENSTETTE:  That's right.
                       CHAIRMAN WALLIS:  So one shift does it. 
           It's not as if you are in a critical reason for a
           shift change or anything like that.
                       MR. KOTTENSTETTE:  No.
                       MR. ROSEN:  In fact, that is a good
           question, Graham.  When you start up do you change
           shifts at any point during this period?
                       MR. KOTTENSTETTE:  It depends on where we
           start up on the shift.
                       CHAIRMAN WALLIS:  Well, if it is two days,
           you better.
                       MR. KOTTENSTETTE:  Well, yes.  But we
           pretty much hold points throughout the start up and
           get to the point where you get up to the rated
           pressure, and from there to get to the point where we
           can roll the generator.  And then from there --
                       MR. BROWNING:  And there are prerequisite
           tests that are required --
                       CHAIRMAN WALLIS:  Are you on 8 hour shifts
           or 12 hour shifts?
                       MR. KOTTENSTETTE:  We are on 12 hour
           shifts.
                       MR. ROSEN:  And I guess the operative
           question is that one shift actually takes you up from
           the natural circulation line up into the 30 million
           pounds per hour or something like that?
                       MR. KOTTENSTETTE:  Yes.
                       MR. BROWNING:  These guys look ahead and
           try and target those windows to make sure that they
           don't have a shift turnover right in the middle of
           some critical task in the middle here.
                       And our conclusion is that we have shown
           that the operation at the extended power uprate with
           respect to the thermo hydraulic stability has been
           acceptable.  Next slide.
                       I get to continue on, and again with
           Jason, and this time we are going to talk about
           anticipated transients without SCRAM.  We are going to
           go through and give you a little bit of background on
           how Duane Arnold complies with the ATWS rule.
                       And then Jason again is going to talk
           about methodology, and how we went through and did the
           calculations, and then I will get back up again and
           talk about the analytical results and the conclusions.
                       Again, to demonstrate that we have
           considered the operational and safety margins from the
           ATWS perspective at the EPU conditions.  First, the
           system that everybody is most familiar with when we
           talk about ATWS, and that is the standby liquid
           control system.
                       For Duane Arnold, we have gone to the two-
           pump operation, where the single switch in the control
           room starts both pumps simultaneously.  And they are
           required to pump a minimum of 26.2 gallons a minute
           each, and to get the equivalency requirement, we use
           naturally enriched boron.
                       And we use a minimum concentration of 11.8
           weight solution of sodium pentaborate.  That means the
           rule requirement for the 86 GPM equivalency that was
           spelled out in the rule.
                       And the other thing to understand is with
           our design being a BWR-4, we do inject the boron
           solution below the core through the sparger, okay.
                       We have installed the alternate rod
           insertion system, and one of the things that you will
           hear about in the conservatism and the way we do the
           calculation is that we take no credit for that in the
           analysis, which is the system that pneumatically
           bleeds off the air from the control rods, and allows
           them to go in as the back up.
                       We have the recirculation pump trip
           system, that when we detect conditions that would be
           indicative of an ATWS of a high pressure in the water
           level, the recirc pumps will trip off and run back to
           flow.
                       And that we have adopted the BWR Owner's
           Group emergency procedure guidelines for dealing with
           the ATWS, which include lowering the water level and
           taking those actions.
                       The ATWS rule established pretty much
           hardware requirements, and then behind it, we go back
           and we look at and demonstrate that we comply with the
           analytical basis that that rule was predicated on.
                       So the things that we look at are the peak
           pressure below the ASME service level of 1500 psi for
           the events.  We demonstrate that the peak cladding
           temperature remains within the 50.46 requirements of
           2200 degrees fahrenheit.
                       We look at the local oxidation fraction,
           and make sure that it stays below the 17 percent
           requirement of 50.46.  We look at the suppressible
           temperature and ensure that it remains below the plant
           design limit of 281 degrees fahrenheit.
                       And we also look at the containment
           pressure to make sure that it stays below the plant
           design limit of 62 pounds.  And then we go back and we
           benchmark to not the current power level, but the
           original license power level, which for us would be
           50.93 megawatts, to demonstrate that the impact of the
           EPU is acceptable.
                       So we go all the way back to the original
           plan and do the comparison.  And at this point, I will
           turn it over to Jason.
                       CHAIRMAN WALLIS:  How close do you get to
           these limits when you do this?  Let's say it is within
           10 CFR 50.46, are you opening up against, say, 2200
           degrees, or are you still a long way from it?
                       MR. BROWNING:  We are a fair ways away.
                       MR. POST:  We are a long way from it and
           we are going to show you those specifically as well.
                       CHAIRMAN WALLIS:  But you are closer than
           you were before?
                       MR. BROWNING:  Yes, and we will show you
           the results later.
                       MR. POST:  So this is Jason Post again. 
           I have one slide here on methodology.  We use the ODYN
           code when we did the first generic licensing topical
           report on power uprate.  That was also the same time
           that we also submitted the application to use the ODYN
           code to do the ATWS calculations.
                       And ODYN, of course, has been used for a
           number of years for transients, but we had to get the
           approval of the various models that we needed for
           ATWS, and specifically the boron mixing model.
                       And the boron mixing model is the key
           conservatism that we have in the ODYN analysis, and we
           demonstrated that it adequately bounds the best
           estimate calculation with the TRACG code.  That was
           our benchmark that we used.
                       It is important to note that we do use a
           best estimate approach for ATWS.  Some of the
           conservatisms that we have in there are on the SRV
           subpoints.  We do use conservative SRV subpoints in
           the calculation to compare to the peak reactor
           pressure criteria.
                       And we do use reasonable operator action
           times.  It is important to note that the SLCS
           initiation, which is two minutes after the ATWS
           signal, has not changed.  So someone made a comment
           earlier about how the operator response has decreased.
                       In fact, we use exactly the same operator
           action time that we used for power uprate, or that we
           would use for an ATWS analysis at current license
           power.
                       So it does -- you do have a slightly
           steeper uprate during those first two minutes, but we
           have not changed the operator action time.  We use the
           same action time.
                       We use pool cooling and service about 11
           minutes, and that is basically 10 minutes of nothing
           happening and one minute to align the system is where
           that 11 minutes comes from.
                       And as we have talked about before, this
           is supported by the emergency procedure guidelines,
           and the emergency procedure guidelines actions are
           fully adequate for EPU.  There is on change to the
           basic actions that are taken in the simulator
           training.
                       CHAIRMAN WALLIS:  Now, how is the level
           controlled during this ATWS?  Is the operator looking
           at the level in the vessel?
                       MR. POST:  Yes, he is.  We do do a water
           level reduction.
                       CHAIRMAN WALLIS:  And isn't there some
           action to control that level?
                       MR. POST:  One of the key mitigating
           features of an ATWS response is to lower water level
           below the feed water spargers so you don't have that
           low subcooling.
                       And actually you reduce clear down to the
           top of the active fuel to reduce the power level. 
           Once you reduce the power level, then you are
           mitigating the stream that is going to the suppression
           pool for the bounding ATWS event.
                       So the termination of feed water happens
           in about the same time frame as the initiation of
           SLCS.  They are both what we would call immediate
           operator actions in the power control portion of the
           guideline.
                       CHAIRMAN WALLIS:  So with the uprated
           power, there is somewhat less time to do this?
                       MR. POST:  Again, we make the same
           assumption on operator action time.  We assume the
           time is the same.  It does give you a little bit worst
           result, which you will see in a few minutes.  But we
           are using the same time to take both actions or for
           both conditions I should say.
                       DR. POWERS:  When you have analyzed these
           in the generic sense, or in the specific sense, either
           one, do you look at the pressure on the fuel rods
           during the water level drop and then the mixing?
                       MR. POST:  It is not an explicit part of
           the calculation.  Remember that during the water level
           drop, we maintain the core covered, and we do have a
           peak clad temperature calculation which shows that the
           temperature stays quite low.
                       I don't think the response to the fuel is
           any more severe than one of the transient events, the
           response for ATWS.  The real threat from ATWS is the
           containment temperature.  I mean, that is the biggest
           worry.
                       DR. POWERS:  Here is what I am interested
           in, is whether any of the fuel rods having large
           stresses put on them or strains?
                       MR. POST:  Not more severe than any other
           event in the envelope, in the design envelope.
                       MR. ROSEN:  Well, you have got me a little
           confused now frankly.  I am reading the staff's safety
           evaluation, and it is on page 75, and in that they are
           talking about the PSA and the screening that was done,
           which identified five operator actions that were
           evaluated for their impact on plant risk.
                       One of those actions is the initiation of
           SLCS for turbine trip and main steam isolation valve
           closure ATWS events.  And in that paragraph, it says
           due to the extended power outrate, the early SLCS
           initiation timing is reduced from 6 minutes to 4
           minutes; while the late SLCS initiation timing is
           reduced from 20 minutes to 14 minutes.
                       Now, just looking at the early, that says
           from 6 to 4 minutes; and yet your slide says 2
           minutes.
                       MR. POST:  Two minutes after the ATWS
           signal is what we use in the analysis, and I am not
           certain the basis for what is in the PRA.
                       MR. BROWNING:  In the PRA analysis -- this
           is Tony Browning again.  In the PRA analysis -- and we
           will speak to it later when we get to that
           presentation, those are actually acceptance criteria
           that are applied in the PSA model.
                       If the operator performs to that level by
           that time, the event tree goes in one direction.  If
           he is not successful at that juncture, it takes a
           different path and goes down through the event
           analysis in a different way.
                       And that is really all that is driving
           there.  It is driven by the map results, and the
           change in time, and the calculation of the human
           performance.  But really what it is doing is setting
           up later in those events what the successful criteria
           is, or how much suppression pool cooling is required
           to keep the containment within the design.
                       MR. ROSEN:  I understand that, and these
           results that are reported here by the staff have an
           effect on our probablistic safety analysis, and the
           impact of the change in power on the resulting core
           damage frequency.
                       MR. POST:  Correct.
                       MR. ROSEN:  And what you are saying here,
           I think, and help me to understand this, is that even
           though the PSA uses four minutes to draw some
           judgments about operator success likelihood, and that
           four minutes speaks to some analysis of the
           performance shaping factors for the PSA, in the
           thermal hydraulic analysis, you initiate SLCS in two
           minutes rather than four minutes.
                       MR. POST:  Yes, we do.  That's correct.
                       MR. ROSEN:  It's different and I don't
           understand why.
                       MR. BROWNING:  This is the basic -- if you
           will, deterministic modeling and methodology which --
           like we said in the beginning, that is the basis for
           our application.
                       The PSA look was to look for risk
           insights, and you are seeing that.  You are seeing the
           result of us looking with our PSA model for risk
           insights, and we have incorporated those.
                       That's why we went up with the simulator
           with the operator training early on and ran through
           these scenarios.  And Mr. Kottenstette said he has
           discussed that earlier, and that we really did not see
           any degradation of human performance in the simulator.
                       That was the take away from this.  We saw
           the result, and we got the lesson learned, and we went
           up to the simulator to see if in reality we were
           seeing a challenge to the operators, and if that had
           been the case -- and it wasn't, but had that been the
           case, and we had seen that, we would have had to make
           adjustments.
                       And that either at operator training or
           some other mitigative strategy, if the effect of the
           uprate had been that we needed to get standby liquid
           in much sooner, and we had seen a degradation of human
           performance in the simulator, we would have had to
           address that, but we didn't see it.
                       MR. ROSEN:  I am puzzled, and a little
           troubled about using two different numbers; one in the
           PSA analysis and one here, for when you initiate SLCS. 
           If you used the four minutes here to be consistent
           with what the PSA people do --
                       MR. POST:  Our PSA expert is going to get
           up and address that.
                       MR. BOEHNERT:  Come up to the mike and
           identify yourself.
                       MR. POST:  But that is not uncommon.  I
           mean, we have different ways that we look at things in
           deterministic space from the way that we look at
           things in probablistic space.  It is not different.
                       MR. HOPKINS:  This is Brad Hopkins from
           Duane Arnold.  I am the PRA engineer at Duane Arnold. 
           I think I can provide a little clarification.
                       In the PRA, we allow containment pressure
           and temperature to go much higher than the design
           values before we assume failure.  So in our thermal
           hydraulic analysis, we are able to live with later
           standby liquid control injection before we would
           exceed our criteria.
                       The criteria is different because in the
           PRA our containment failure occurs at much higher
           pressures than the design pressure.  That is, we would
           not expect containment failure until about 120 psi. 
           Whereas, in the licensing basis, 54 psi.  So that
           would account for some of those differences.
                       MR. POST:  So you could allow a higher or
           a longer action time and still meet your criteria?
                       MR. HOPKINS:  Yes.  We are looking at or
           trying to look at realistic evaluations and not
           putting in the conservatisms that are applied for the
           licensing based evaluation.
                       MR. ROSEN:  That clarifies it, but I would
           point out that you have the differences there.
                       MR. BROWNING:  And as we get into the
           event, specifically with the results, and we were
           asked to look at the acceptance criteria and how we
           compare those, and do a comparison of pre-EPU to EPU
           results.
                       And then a recent topical issue, we are
           going to look at our Evaluation of Information Notice
           2001-013, which was the inadequate SLCS relief value
           margin issue.  This is a comparison of Pre-EPU to EPU,
           and if you look at the --
                       MR. BOEHNERT:  Excuse me, but could you go
           back to the slide.  Can you highlight that relief
           value margin issue, please?
                       MR. BROWNING:  We will get to that.
                       MR. BOEHNERT:  Fine.
                       MR. BROWNING:  And first off we will look
           at the EPU results.  You will see that the peak
           reactor vessel pressure, the acceptance criteria is
           1500 pounds, and we are at 1343, and we are below that
           limit.
                       We are going to look at peak fuel cladding
           temperature against the 2200 limit, and as you can
           see, we are at 1380 degrees fahrenheit.  So we are
           quite low there.
                       And the peak suppression pool temperature
           limit, the design limit is 281 degrees, and we are at
           215.6 for the EPU; and the peak containment pressure,
           the design on that is 652 psi, and we are at 18.3.  So
           as you can see here, we have lots of margin.
                       And looking at the impact of the EPU,
           again, reminding everyone that this comparison goes
           all the way back to the original rated thermal power
           of 1593 psig, you are seeing the impact of not only
           the full 20 percent increase, but you also are seeing
           the impact of reactor pressure change, and a ELLLA to
           MELLLA change as well.
                       Because at our previous uprate, when we
           did this stretch of 5 percent in 1985, that was when
           it raised reactor pressure.  So you are seeing all
           those effects rolled up into this.
                       So the reactor pressure as expected goes
           up, and the suppression pool temperature and the decay
           heat goes up, and it takes the containment pressure
           with it.
                       The interesting result is the fuel
           cladding temperature.  You see a slight reduction, and
           that is because of the flattening of the radial power
           in the core, and where the peak bundle isn't working
           any harder to bring up the average.
                       So we redistribute the flow, and the net
           result of that is that the peak bundle gets a little
           bit more flow because the average bundles are getting
           a little bit less because of the increased pressure
           dropped from their steam production.
                       So the peak bundle gets a little bit more
           cooling, and so the FCT comes down.
                       CHAIRMAN WALLIS:  Do you actually have the
           acceptance criteria on this?  You told us what there
           were, but --
                       MR. BROWNING:  We have a back up slide
           with that if you would like to see it.
                       CHAIRMAN WALLIS:  But you told us what
           they were.
                       MR. BROWNING:  Here is the background on
           the information that was on the SLCS margins, and the
           concern is that in an ATWS event, and the loss of off-
           site power is the specific one that was addressed, the
           concern is that you have high reactor pressure at the
           time of standby liquid and ejection.
                       And you have reduced margins to the relief
           valve setpoint, and one of the things is that you have
           an operating margin that is required between the peak
           system pressure at the relief value next to the pump,
           and the nominal relief valve setpoint.
                       You have a required delta that you are
           required to maintain there.  So what happens is that
           you are trying to account for uncertainties, a set
           point drift in the relief valve and other things, and
           also because these are positive pressure pumps.
                       And they are very dynamic, and you get big
           pressure pulses as it ejects, and so you are trying to
           absorb all that with this margin.  And the concern is
           that if the reactor pressure is too high, it can eat
           into this margin, and you have the potential to
           interrupt the standby liquid ejection, and actually
           the circulate the boron in a loop around the pump, but
           not actually inject it into the core.
                       The results for Duane Arnold is that we
           have grater than a hundred psi operating margin to the
           nominal valve set point, and we saw no interruption in
           the SLCS ejection.
                       In conclusion, we talked about the
           methodology and how we use that to capture margin,
           which we also go back and do at the benchmark to look
           at the impact of the EPU on the plant, and to look at
           the margin that would go there.
                       And then again in the plant specific
           results, we satisfied all the acceptance criteria, and
           so we saw no impact from the safety margin.  If you
           have adequate margin for the acceptance criteria, we
           have operational margin sustained by  that.
                       And then we have an acceptable comparison
           to the benchmark case, and so we didn't see a huge
           change there.  So from that we can conclude that the
           operation of the EPU from the ATWS perspective is
           adequate.
                       DR. SCHROCK:  What was this best estimate
           of the --
                       MR. POST:  That was approved at the time
           of the ATWS rule and the first time that we started
           doing ATWS analysis.  It is because of the low
           probability, and also because it was not part of the
           original design basis.  It was an added analysis, low
           probability.
                       DR. SCHROCK:  To put it in the context of
           best estimate analysis, can you put a date on that for
           me?  Was it the early '80s?
                       MR. POST:  I don't remember when the ATWS
           rule came out, but --
                       DR. POWERS:  Around '85 or '85.
                       DR. SCHROCK:  And ODYN was its basis at
           that time?
                       MR. POST:  No, at that time we were using
           a READY code, and as I said earlier, we didn't -- ODYN
           had been used for the transient calculations, but we
           had not qualified the boron mixing model until the
           time that we did the generic submittal on power uprate
           in the mid-1990s.  That's when we started using ODYN
           for ATWS calculations.
                       DR. SCHROCK:  And in the original ATWS
           problem, you didn't present it as a best estimate
           calculations?
                       MR. POST:  Well, I am sure in the original
           analysis that was done with READY, and the ATWS rule
           compliance, I am sure that those were done as best
           estimate calculations.  Yes, I'm sure that they were.
                       DR. SCHROCK:  I don't remember it getting
           reviewed in that time frame, but it must have been.
                       MR. BOEHNERT:  I remember his argument,
           and I remember that they did a lot of that as he said. 
           I believe it was ODYN, but I don't really remember.
                       MR. POST:  There were a couple of very
           large topical reports that GE wrote on the ATWS
           response for various events, and trying to determine
           what the limiting events were and that needed to be
           analyzed, and what the assumptions for the analysis
           should be.
                       And I know that those were presented to
           the NRC, and whether they were actually presented to
           the ACRS, I am not certain.
                       DR. SCHROCK:  Well, I am just curious to
           know a little more about what is in the ODYN one.
                       MR. POST:  All right.  This is ATWS
           instability, and we talked about the instability
           prevention to ensure that you prevent an instability,
           and if it does occur, you do get an automatic SCRAM to
           show the reactor down and terminate the oscillation.
                       But one of the concerns previously was
           what happens if that SCRAM fails, and so the
           oscillation continues to grow and it is not
           terminated, and how bad does it get.
                       And so I am going to talk a little bit
           about the background, and the methodology, and what
           happens to an ATWS instability if you don't have
           mitigation, and why the application for Duane Arnold
           is acceptable.
                       And again we are trying to demonstrate
           that the existing ATWS instability analysis, which was
           done for a high power density plant with MELLLA is
           adequate for the Duane Arnold extended power uprate.
                       So there were two topical reports written
           and that were both reviewed simultaneously by the NRC,
           and one SER was written on both reports.  The first
           one is the NEDO-32047, which is the ATWS rule report.
                       And the purpose of this report was to
           determine if fuel rod failures are unlikely from a
           worst case instability event with the SCRAM failure.
                       And the result of the evaluation was that
           this had no mitigating operator actions of any kind,
           and so it maintained water level high in the reactor
           and so it maximized the power production.
                       And we found that the power spikes become
           very tall and narrow.  It is almost like a reactivity
           excursion type of event, in terms of what the fuel
           experiences.  It becomes -- so the peak energy
           deposition, and we found it is within the fuel design
           limits as you would get for reactivity excursions.
                       But the power becomes more severe as the
           core inlet subcooling decreases, and in fact you get
           to a point where as the subcooling decreases that you
           actually get a power spike that causes an extended dry
           out, and where the fuel doesn't re-wet in an
           oscillation.
                       And when you get that extended dry out of
           fuel service, then you get a very excessive clad
           temperature, to the point where a portion of the fuel
           could fail, and so we calculate that the number of
           bundles that this could happen on, and the actual
           location of the bundles.  And it is about a half-a-
           percent of the core volume.
                       DR. POWERS:  When you say that it is
           within the fuel design limits, you mean that it is
           less than --
                       MR. POST:  That's correct.
                       DR. POWERS:  And that is if it is fresh,
           but how about if it is burned up a bit?
                       MR. POST:  I think we are at around 70 or
           80 calories per gram, and --
                       DR. POWERS:  And can it tolerate that when
           you --
                       MR. POST:  I am going to call on Dr. Jens
           Anderson.  Jens, would you mind helping me with this?
                       DR. ANDERSON:  This is Jens Anderson to
           talk about that fuel.  When you get these high powered
           oscillations, you get those in the fuel bundles from
           high radial peaking.  High radial peaking will only
           occur for fuel with low exposure.
                       Once you get to the higher exposure, two
           things happen.  First of all, you don't have as much
           activity left in the fuel and so you don't get the
           higher radial peaking, and that was actually analyzed
           as part of this work that was done in the first
           report, the NEDO-332047.
                       And it shows us that as you go down in
           radial peaking, you cannot get these high powered
           oscillations.  Secondly, this is very -- the other
           things that happen is that even if you have high flux
           peaks, with lower activity in the fuel, you don't get
           the power response.
                       So I think the short answer is that you
           can get the high oscillation for fresh fuel, but for
           highly exposed fuel, you cannot have the high power
           oscillations.
                       MR. POST:  Again, this is the event and
           the results that were analyzed previously, and what we
           are demonstrating or discussing is the fact that those
           were adequately severe in the analysis that was done
           already, and did not get any worse for the MELLA EPU
           condition for Duane Arnold.
                       So we are discussing things that were
           already presented, and so it is not a new consequence.
                       CHAIRMAN WALLIS:  It has already been
           judged then as an acceptable --
                       MR. POST:  Yes, and again this is the no
           mitigation result.  I mean, that's why we had EPGs,
           and this is intended to demonstrate the worst case
           -- no mitigation, maintaining water level high,
           letting subcoolant go dry, and how bad does it get,
           and that is what that report was intended to show.
                       And there could be a larger fraction of
           the core.  The .5 percent may not be a valid number. 
           It may go up to one percent.  I'm not sure exactly b
           because of the flattening, and the radial power
           distribution, and you have more bundles that are
           closer to the limit.
                       So I would agree that the .5 percent that
           was reported in that report was based upon the core
           design at that time.  So that could get a little bit
           worse, and frankly we have not calculated that.
                       DR. SCHROCK:  And the most immediate
           consequence is that gaseous fissure products are
           released from rods that have failed.
                       MR. POST:  Yes, certainly.
                       DR. SCHROCK:  And it would seem to make
           more sense to express it as a fraction of rods failed,
           as opposed to fraction of core volume failed.
                       MR. POST:  That was the way that it was
           expressed originally.  So if I can continue with the
           next report, which is the mitigation report, 32614. 
           What this one did was recognize that that condition is
           not acceptable.
                       You certainly would not want to have your
           plan operate there, and get into that condition.  So
           they looked at what are effective mitigation
           strategies.
                       And the two that are reported are as most
           effective, one is to lower the water level to below
           the field water spargers.  Now, of course, the EPGs
           say lower it to -- there is two levels approved by the
           NRC.
                       One is to five feet above top of active
           fuel, and the other is to the minimum steam cooling
           water level, which is actually below, a collapse level
           below the top of active fuel.
                       But to mitigate the ATWS instability, you
           don't have to get it that low.  That gives you a
           bigger power reduction, but the key thing is the
           subcooling, in terms of the instability.
                       You only have to get it about one or two
           feet below the feed water spargers in order to have
           the water that is coming in spray into a steam space,
           and raise the temperature enough so that you mitigate
           the core and let sub-cooling.
                       So that can be accomplished very quickly
           with feed water run back, and that gives a real quick
           water level reduction.  And it eliminates, completely
           eliminates the large power pulses.
                       Now, you can still have a small
           oscillation that continues, but these very large
           dramatic power pulses are completely eliminated.  The
           other feature is the boron injection, which is of
           course also specified in the EPGs.
                       And boron injections is very effective for
           the long term shutdown, but it is not quick enough to
           prevent the kind of extended dry out that gives the
           fuel rod failures by itself.
                       It does eventually make the oscillations
           go away completely, but it doesn't happen -- the delay
           time from the time it was initiated, and to the delay
           time until it actually gets into the reactor core, and
           until it mixes, and until it shuts down enough to
           terminate the oscillations, it just does not happen
           fast enough.  So the water level reduction is the key.
                       And the methodology we used is TRACG, and
           which you have reviewed before.  We use multiple
           channel groups and it gives you a detailed 3-D
           kinetics in the thermal-hydraulic model of the core. 
           It is a very effective model for doing this.
                       And then the next chart there is a
           benchmark from -- it is a current calculation of the
           repeat of the case that was in NEDO-322047, and you
           can see here the type of power spikes that were
           reported in NEDO-322047 and that go up above a
           thousand percent.
                       And as subcooling continues to decrease
           then, you are kind of reaching a maximum of your
           subcooling at about 200 seconds, and that is where if
           you go to the next chart on the peak clad temperature
           --
                       CHAIRMAN WALLIS:  And that has been going
           along for quite a long time hasn't it?
                       MR. POST:  Yes.  Right.  And this is again
           where the operator isn't -- you know, this is assuming
           that whatever actions the operator has taken to try
           and insert control rods have been completely
           ineffective and the water level has not been reduced.
                       DR. POWERS:  And is this level for the
           fuel cycle?
                       MR. POST:  I don't remember exactly.  I'm
           sure that it is at the most reactive point in the
           cycle.  It is probably around the middle of the cycle
           is probably when it is done.
                       And again they are very conservatively
           bumping up the radio peaking factor to make sure that
           they get it.  So the next slide talks about the ATWS
           instability with mitigation.
                       Now, I don't have a chart to show that,
           but what happens is that at about 150 seconds, feed
           water -- the core in-let subcooling turns around, and
           the oscillations start to die back down again, and you
           don't get anymore of those huge random power peaks up
           to a thousand percent.
                       CHAIRMAN WALLIS:  Well, you have showed us
           the bad looking ones, and it would be very good if you
           showed us the good looking one as well.
                       DR. POWERS:  And even so, within the first
           150 seconds, you are putting some pretty good pops
           into that fuel.  I mean, even before the 150 seconds.
                       MR. POST:  Well, I didn't have an
           electronic version of that available, and so we will
           go to the old paper method.  But this shows how the
           core -- the base case about mitigation is that
           subcooling continues to increase and it goes up to
           about 60 degrees K, and then that is about here, and
           about 200 seconds is where they just keep going along
           and this is where the dry out occurs.
                       And with the feed water reduction, the
           water level reduction below the feed water spargers,
           you get a very effective turnaround of the subcooling,
           and you can see that we don't like these kinds of
           oscillations, but they are enough so that they stay
           within the capacity of the fuel.
                       CHAIRMAN WALLIS:  And it is counter-
           intuitive, and if you make the water colder, you think
           it would cool better.  But in fact it makes the
           oscillations worse.
                       MR. POST:  That is correct.  Warmer water
           gives you a better response from the hydraulic
           instability.
                       MR. ROSEN:  As long as you have raised the
           question of counter-intuitive.  From an operator
           perspective, Steve, a little bit counter-intuitive,
           isn't that to lower the water below the feed water
           sparges?
                       MR. POST:  As far as auxiliary power?
                       MR. ROSEN:  Are you trained to do that?
                       MR. POST:  We know that we lower power or
           reactor water power reduces with it.
                       DR. KRESS:  And it is not so counter-
           intuitive for BWRs in other words.
                       MR. MCGEE:  It is not counter-intuitive.
                       MR. POST:  In nearly every training
           scenario, they will have some sort of ATWS scenario,
           and they are trained as to that.
                       MR. ROSEN:  So you are modeling this in
           the simulator, the compliance simulator is that you
           are saying?
                       DR. KRESS:  No, this is TRACG.
                       MR. POST:  This is TRACG.
                       MR. ROSEN:  No, I am saying that you are
           modeling this event.
                       MR. POST:  If I maintain water level high,
           I will still see the high power because I am not
           getting the increase in subcooling going on.  So I
           know that it is going to be a longer scenario for me
           because power is going to be higher.
                       MR. ROSEN:  So in your simulator crews are
           trained to run feed water back and get the core level
           below the sparges.
                       MR. POST:  That's correct.  The operator
           action is to lower the water level all the way to the
           minimum steam cooling level, which is near the top of
           the active fuel, and which is well below the feed
           water sparges.
                       So they don't stop when they clear the
           feed water sparger.  They are running it all the way
           down until they get power to clear the APR and down
           scale --
                       MR. ROSEN:  Is this one of the critical
           actions in the operator training?
                       MR. KOTTENSTETTE:  It is a critical task
           for us to lower the level down to a certain point, and
           for us it is 87 inches above the top of the active
           fuel.  At that time, we have a decision to make; is
           power now less than five percent power.
                       If it is, then now I have arranged to
           maintain water level from the top of active fuel up to
           whatever that water level is that the power is less
           than five percent.
                       DR. KRESS:  Would you go back to your
           slide on the peak cladding temperature without
           mitigation that you had up there.  Yes, that one.  No,
           the next one.
                       What is happening to the center line fuel
           temperature during this process?  Do you have an
           equivalent curve for the center line fuel temperature
           in that slide?
                       MR. POST:  I do not have that available. 
           It wasn't included in that report I don't believe.
                       DR. KRESS:  But does it oscillate or does
           it have a steady rise because of the lack of good
           coupling, the thermal coupling between the clad and
           the --
                       MR. POST:  Well, I am sure that it is
           oscillating on this same kind of frequency as well. 
           So I am sure that it is not a steady temperature.  I
           mean, the surface heat transfer coefficient is varying
           as the fluid conditions changes at the surface.
                       DR. KRESS:  But your thermal conductivity
           and the fuel is not varying very much, and it is a
           pretty good heat capacity in those fuels compared to
           the clad, and I was mentally thinking that you might
           get some oscillations, but you have got a steady rise
           in that --
                       DR. POWERS:  The fuel looks like a bunch
           of stair steps.
                       DR. KRESS:  Yes, but not little or big
           stair steps.  But I was trying -- what I am thinking,
           Dana, is the total deposited energy in the fuel itself
           compared to this limit of how many calories per gram
           you get, as opposed to what you get in one
           oscillation.
                       DR. ANDERSON:  This is Jens Anderson
           again.  What you can see in this plot prior to 200
           seconds is that you have repeated boiling transitions
           and reword, and in that period the heat removal, the
           net heat removal from the surface of the fuel rod, is
           the same as the energy generation.
                       So, yes, you get some oscillation in the
           center line temperature, and the center line
           temperature is higher than the cladding temperature,
           and on average it is constant.
                       DR. KRESS:  It's not steadily climbing up
           then.
                       DR. ANDERSON:  No, it's not.  It doesn't
           start climbing up steadily until you fail to leave it,
           and then you go up to a higher clad temperature, and
           a correspondingly higher center line temperature.
                       DR. POWERS:  I cannot believe that in two
           seconds that you thermally communicate with the center
           line of a fuel rod.
                       DR. KRESS:  That was my problem.
                       DR. POWERS:  And I would find that
           remarkable, especially with a BWR rod.
                       DR. ANDERSON:  No, that's correct, and you
           are going to have a significant face shift between the
           center line temperatures and the surface, because the
           fuel is time constant.
                       Some are time constant, and the fuel is
           typically in the order of 6 seconds, while the period
           of the oscillations are more like 2 seconds.
           And which tend to give a fair amount of damping in the
           temperature response.
                       CHAIRMAN WALLIS:  Were you adding boron to
           the water at this time?
                       DR. KRESS:  No, this is no mitigation.
                       CHAIRMAN WALLIS:  No mitigation at all? 
           So what is the long term prospect?
                       MR. POST:  The long term prospect is --
                       CHAIRMAN WALLIS:  How does it eventually
           shut down?
                       DR. POWERS:  That is a special plot that
           shuts it down.
                       MR. POST:  Well, that's why we move around
           a little, but then this is the effect of boron
           mitigation.
                       CHAIRMAN WALLIS:  Eventually you want to
           raise the water level eventually.
                       MR. POST:  Well, not until you get the
           reactor shut down.
                       CHAIRMAN WALLIS:  You have to get some
           boron in there or something.
                       MR. POST:  Yes.  When you get the boron in
           the oscillations go away completely.
                       CHAIRMAN WALLIS:  That's right.
                       MR. POST:  So this particular plot has
           only the boron injections, and so if you did the water
           level reduction by here in 150 seconds, you would make
           all these power spikes go away.
                       And then as you would continue to inject
           boron, you would make them go away completely.  So it
           is a combination of the two that allow for getting rid
           of those oscillations and --
                       CHAIRMAN WALLIS:  It is this drop in the
           level that is just to shut down the neutronics, and so
           it is counter-intuitive from the point of your
           cooling, but it is what you need to do to shut down
           the nuclear reaction?
                       MR. POST:  That's right.
                       CHAIRMAN WALLIS:  Then you need to get
           some boron in for the long term.
                       MR. POST:  It mitigates the containment
           response dramatically, as well as avoiding this type
           of power spikes in the fuel.
                       DR. POWERS:  Graham, not everything is
           thermal hydraulics.
                       CHAIRMAN WALLIS:  No, it's not.  I think
           it is great.
                       DR. ANDERSON:  This is Jens Anderson
           again.  I would like to point out one thing, is that
           the curves that Jason Post has shown is what you have
           is when you have an ATWS, the high density plant at
           the middle line.  It is really not an easy EPU issue.
                       DR. POWERS:  Well, we don't have analyses
           for this plant at the high and the low power levels to
           see what they do.
                       MR. POST:  And you are right, we do not
           have that.  Because the MELLLA boundary had previously
           been analyzed and the peak bundle power for Duane
           Arnold is consistent with what the bases were that
           were performed, we have done some GE14 studies to
           confirm the GE14, which is the newest fuel design that
           they have already loaded, I believe.
                       And the response for GE14 is similar, and
           the ATWS mitigation techniques are still effective,
           and so we did not do a Duane Arnold specific TRAC
           calculation for this.
                       So the methodology, it evaluates the
           margin and it uses limiting initial conditions, and
           limiting peak bundle powers.  And there isn't really
           a safety margin associated with this.  We are past the
           safety margins for this particular evaluation.
                       There is no degradation of the fuel
           response for EPU.  We already have a pretty severe
           response, and so the margins that you had before are
           sustained.  So from this point of view, EPU is
           acceptable for Duane Arnold.
                       DR. POWERS:  Are there any questions on
           this portion of the program that we have gone through
           so far?  Seeing none, and not looking very hard for
           any of them, I am going to call for a recess until 10
           of.
                       CHAIRMAN WALLIS:  And during the recess,
           I would like to respond to the question that I raised
           about capacity, because it may be just a
           misunderstanding.
                       (Whereupon, at 2:37 p.m., the meeting was
           recessed and was resumed at 2:50 p.m.)
                       DR. POWERS:  Let's go back into session. 
           We are now going to move on to the non-controversial
           topic of the corrosion.  I know that there will be no
           questions at all, and so we will be able to whip
           through this topic with speed and direction, I'm sure.
                       MR. SEVERSON:  I am Russ Severson, and I
           am here to discuss our flow accelerated corrosion
           program at Duane Arnold, and what the impact will be
           from what I expect the impact is from the extended
           power uprate.
                       To quickly explain flow accelerated
           corrosion in five seconds, flow accelerated corrosion
           leads to wall thinning, and many perimeters, including
           water chemistry, material composition, and the
           hydrodynamics effects, affect this wear rate.
                       And, of course, carbon steel piping is a
           especially susceptible material.  Duane Arnold has had
           a long term monitoring program focusing on the
           susceptible high-energy carbon-steel piping system.
                       We include both single and two phase
           systems throughout the balance of the plant site, and
           at DAEC, we completed a tailored collaboration with
           EPRI back in the mid-1990s, which helped us base line
           and determine what our modeling was and to evaluate
           what should be modeled, and what our inspections
           should be.
                       And we have been progressing with that
           base line inspection.  All our lines are continuously
           operating lines, and are modeled in our EPRI CHECWORKS
           program.
                       The inspections are performed to verify
           their model and to monitor the wear specifically.  We
           typically do 40 to 60 inspections or actually
           locations.  We inspect locations.
                       CHAIRMAN WALLIS:  To verify a model, do
           you actually do enough readings to verify a model?
                       MR. SEVERSON:  To verify this model?  Yes.
                       CHAIRMAN WALLIS:  So you actually have a
           prediction at the rate at which --
                       MR. SEVERSON:  We have a prediction, yes.
                       CHAIRMAN WALLIS:  And it works?
                       MR. SEVERSON:  Of where it is, yes, and of
           our different rates within our continuously operating
           lines.  And in that prediction, what we had to do was
           we went back and evaluated the beginning of the
           operation, and decided what our wear rates were
           through all 18 at the time, or 15 cycles of where.
                       And to evaluate what our chemistry was
           through all those 15 cycles, and how we operated, and
           we have a heat balance, a simplified heat balance
           within the program to identify what the hydrodynamics
           are.
                       And adding all of that up, we do these
           inspections.  Now, we didn't start out doing 40 top 60
           locations.  That is now after many years of having
           this model and verifying, and ensuring that it is
           correct.
                       CHAIRMAN WALLIS:  So now you have enough
           information that you can safely scale it up to  higher
           velocities.
                       MR. SEVERSON:  Correct.  Originally, I
           think we did around like 200 inspections the first
           time we put the model together.  But since then, we
           have been having to do less.
                       DR. FORD:  Is it qualified for the higher
           flow rates?  By qualified I mean there are data for
           the higher flow rates?
                       MR. SEVERSON:  Yes, there is.  Within
           CHECWORKS, it will let you vary the feet per second
           wear rate within your systems.  Our plant has by
           design fairly low flow rates.  And so with the 20
           percent increase, you are within the boundaries.
                       DR. FORD:  And are there other data of
           what the CHECWORKS flow rate would tell you?
                       MR. SEVERSON:  Well, within their book
           that they publish with EPRI, they show graphs of up to
           40 inches per flow rates, and I don't know if some
           plants have this or not, but I do know that Duane
           Arnold is a low wear plant, and that is partly because
           we were built with larger pipe diameters than what
           they built with some of the later model plants.
                       DR. POWERS:  And one has to recognize that
           CHECWORKS has an empirical database that extends well
           beyond just the nuclear business.
                       MR. SEVERSON:  That's correct.
                       CHAIRMAN WALLIS:  Could I ask if
           Susquehanna is one of the plants with higher flow
           rates, the reason being that they have had erosion
           problems?  I understand that they are going to have a
           limited power uprate.
                       MR. SEVERSON:  It is in the model.  I have
           not had data back from Susquehanna that they wouldn't
           have had and that CHECWORKS would not have worked.
                       And I can't tell you as to what extent
           they use CHECWORKS at Susquehanna, and so I can't
           speak from that qualification of knowledge.  I do know
           that within our flow rates there are plants out there
           that model lines that will be at these newer flow
           rates, 20 percent higher, and they have not seen that
           issue.
                       And I would have to see what the
           Susquehanna issues are.  I am not sure if they are a
           reheat plant, or a second reheat plant like we are,
           which makes a huge difference into your wear rates.
                       CHAIRMAN WALLIS:  And the fuel piping, has
           that been exposed to --
                       MR. SEVERSON:  That is correct.
                       CHAIRMAN WALLIS:  And those carbon steel
           pipings have been exposed to --
                       MR. SEVERSON:  To the feeder water lines,
           yes.
                       CHAIRMAN WALLIS:  And the feeder water
           lines are checked?
                       MR. SEVERSON:  Yes, and those are the ones
           that I tried to provide data on since they are the
           ones that can show you the velocity changes since --
           and some of our other lines were going to a less -- to
           a higher quality line, and less wear from the quality
           standpoint of the steam coming in.
                       CHAIRMAN WALLIS:  And versus the
           observation?
                       MR. SEVERSON:  Yes.
                       CHAIRMAN WALLIS:  And also for the
           platinum covered carbon steel?
                       MR. SEVERSON:  I have not seen with the
           platinum covered carbon steel as to -- well, I have
           not seen where CHECWORKS significantly differs yet on
           wear rates.
                       Now, one thing about flow accelerated
           corrosion, which is that it is a very long term
           phenomenon, and I am modeling history back to '75, and
           we have had none since '96, and so far the Noble Chem
           has not shown a significant difference.
                       DR. SHACK:  But those lines at Noble Chem,
           those would be very low flow accelerated corrosion. 
           I mean, aren't they the ones that just sort of sit
           there?  The carbon steel lines that actually see Noble
           Chem.
                       MR. SEVERSON:  Not in the high flow rates. 
           Go ahead.
                       MR. KNECHT:  This is Don Knecht from GE. 
           The feed water -- the carbon steel feed water lines do
           not see the Noble Chem injections.  It is only the
           stainless steel.
                       MR. SEVERSON:  Yes, it should not have
           come back that way, because they do it with the
           recirc.
                       CHAIRMAN WALLIS:  CHECWORKS predicts a
           continuous variation of wear rate versus velocity or
           something, or is there a transition, and a critical
           velocity?  What sort of dependence is it?
                       MR. SEVERSON:  They have an empirical
           formula of -- I will throw up a slide here to give you
           a feel for what the impact of the velocity is.
                       CHAIRMAN WALLIS:  Is it velocity to some
           power or something?  So it is a continuous behavior. 
           It is not a step chain.  It is level or something?  I
           mean, downstream of a connection, it is not --
                       MR. SEVERSON:  There is another one, and
           that is true, too.  In CHECWORKS, they have a certain
           factor formula.  Let me throw that up.
                       DR. SHACK:  And that's where you would see
           dramatic changes if you suddenly went through some
           sort of a transition, but this is kind of a -- you are
           in the same flow mode.
                       CHAIRMAN WALLIS:  It is probably the
           boundary that matters, and if the high velocity gets
           right close to the boundary --
                       DR. POWERS:  You have to understand in the
           middle that they really can't calculate anything, and
           so they develop this incredible empirical library, and
           it is called CHECWORKS.
                       MR. SEVERSON:  And we are constantly doing
           testing and we use French data, and what have you. 
           Here is the formula to give you a feel.
                       CHAIRMAN WALLIS:  The geometry effect is
           this fudge factor G.
                       MR. SEVERSON:  And from their experimental
           evidence they apply this geometry effect, and what I
           just showed you was an effect that they provide.  This
           is what is in the CHECWORKS model for liquid velocity
           changes.
                       This is by keeping the other issues
           constant, and here for the BWR is the oxygen level. 
           It is a very low oxygen level for what this graph is
           showing.
                       DR. SHACK:  What is the normal oxygen
           level in your feed water?
                       MR. SEVERSON:  Right now, 30 parts per
           million.
                       DR. SHACK:  Now, when you change out your
           high pressure turbine, and is chrome moly steel, or
           are you stuck with the associated lines?
                       MR. SEVERSON:  A couple of them have
           already been changed with chrome moly steel, and a
           couple of them will remain carbon steel.  The ones
           that I have not been seeing with significant wear.
                       And a couple of them were the old alloy --
           the copper based alloy that we as a plant have not
           seen significant wear in, and there is a smattering of
           different lines throughout that we watch.
                       DR. KRESS:  Why do those curves peak at a
           given temperature?
                       MR. SEVERSON:  Why do they change in
           temperature?
                       DR. KRESS:  No, why do they peak?
                       MR. SEVERSON:  Why do they come like this
           and come back down?
                       DR. KRESS:  Yes.  Why do they come back
           down?
                       MR. SEVERSON:  Because flow accelerated
           corrosion is a temperature dependent phenomena.
                       DR. KRESS:  I know, but I thought it would
           have just kept going up.
                       CHAIRMAN WALLIS:  There is no why about
           any of this.  It is empirical.
                       MR. SEVERSON:  Well, around 300 degrees is
           your highest wear rate for flow accelerated corrosion
           with everything else said.
                       DR. KRESS:  But my question is why is
           this?
                       DR. POWERS:  It is the solubility data
           from Oak Ridge.
                       MR. SEVERSON:  He's exactly right.
                       DR. SHACK:  It is solubility.
                       DR. KRESS:  It is dissolving the oxide off
           of it.
                       MR. SEVERSON:  Yes.
                       DR. POWERS:  It is solubility for EPRI
           304, and goes through a maximum, and that is what
           underlies those curves.  That was figured out by the
           chemists.
                       Now, the metallurgists came along and they
           said that in order to do anything they had to put
           fudge factors in because they can't calculate
           anything.
                       CHAIRMAN WALLIS:  So it is washing away
           the rust.
                       DR. POWERS:  Yes, washing away the rust.
                       CHAIRMAN WALLIS:  Now I understand.
                       MR. SEVERSON:  Now, we already went
           through this, and let's go on to the next slide.
                       CHAIRMAN WALLIS:  Well, you have predicted
           what the change will be and it is going to be very
           small presumably.  Is it?
                       MR. SEVERSON:  Yes.
                       CHAIRMAN WALLIS:  What sort of change do
           you predict?
                       MR. SEVERSON:  Down here at the end, we
           will show you.  It is about half to 1-1/2 mills,
           depending on where you are within the system because
           of temperature, and flow rate because of the size of
           the geometry.
                       So what I did was that I took the highest
           flow area in the feed water, and I took the worst
           temperature case in the feed water, and did a
           parametric study and showed what the differences were.
                       And this is about a half to one-and-a-
           half, where we are seeing about four mill now, and so
           we should be seeing about 5-1/2 mill, which with the
           piping, we will have about 150 mill margin to code
           allowances.
                       CHAIRMAN WALLIS:  In a hundred years?
                       MR. SEVERSON:  No, at 25, I think, or 30. 
           Let's go to the next slide.  So as I would conclude
           that we will monitor what the water rate changes are
           with the power uprate, and with the increased
           velocity.
                       CHAIRMAN WALLIS:  Where does all the water
           waste go?  Does it actually stays in the solution, and
           just deposits somewhere else?
                       MR. SEVERSON:  It ends up in the
           condensate polishers.
                       CHAIRMAN WALLIS:  Does it build up in
           other parts of the system?
                       MR. SEVERSON:  Yes, you will see it
           throughout.  And we found direct actual evidence with
           our chemistry numbers with iron, and we found actually
           a pretty good correlation as to what our wear rates
           are compared to the iron is at the end of the feed
           water.
                       DR. POWERS:  You don't have any regions
           where you have corrosion product build up that is
           going to strip off, mechanically strip off?
                       CHAIRMAN WALLIS:  A piece of scale that
           will then wrap around?
                       MR. SEVERSON:  I don't believe that we
           will have any impingement problems.  Is that your
           issue?
                       DR. POWERS:  I was just thinking of the
           Surry incident, where they stripped some oxide off
           mechanically because they jacked the flow rates up.
                       MR. SEVERSON:  I don't see that.  We are
           not in those flow rate ranges, and I think that's
           where these max numbers are.  But we are like going
           from 16 to 18 feet per second generally.
                       DR. POWERS:  So you are really quite low.
                       MR. SEVERSON:  Yes.
                       CHAIRMAN WALLIS:  Are we talking about
           flow reduced vibration in your analyses, too?  I would
           think that reduced vibration would affect where, too,
           because of the boundary areas change when you
           oscillate the things.
                       MR. SEVERSON:  Well, I don't think that
           this --
                       CHAIRMAN WALLIS:  And then the reduced
           vibration would affect that.
                       MR. SEVERSON:  I don't know if we have
           seen that, but I don't know if that phenomena really
           exists.
                       MR. ROSEN:  When you estimated 25 years of
           margin, that was for beyond the 40 year?  In other
           words, a total of 65 years?
                       MR. SEVERSON:  That is from now.  That is
           about from now with -- well, the differences that I am
           seeing in wear rate, I probably would not change my
           designs from when I think we should change by about,
           and depending if we went another 60 years, or another
           10 years, I would probably have about the same
           numbers, whether we had a power uprate or not.
                       Because the wear rate right now until when
           we do a piping change, or decide to do a piping
           change, is not that much of an added effect, compared
           to what we have had since the beginning.
                       In actual fact, I think our chemistry
           probably in the early days wore us more than what we
           are going to wear now with a power uprate.
                       MR. ROSEN:  You are saying, I think, that
           if Duane Arnold were to get or to come in for a
           license renewal that it would do it at the higher
           power level which it is now asking for, and not have
           to plan a piping replacement.  Am I correct?
                       MR. SEVERSON:  Not in this area.  I don't
           believe so in feed water, and in some other areas, we
           are probably going to be doing pipe replacements
           anyway.
                       But some of the other areas that we were
           looking at, like some of the extraction steam lines
           are actually going to be improved under a power
           uprate, but change them anyway just because of where
           we are at.
                       But overall the majority of the piping
           will not be affected by a power uprate, and what we
           are going to decide to do, and what we are going to
           decide to change out, won't be affected.
                       I can't answer your question directly
           partially this is a continuously monitoring program,
           and we have done some pipe replacements, and we will
           probably do some more because of varying different
           reasons.  And some of the reasons that we do pipe
           replacements is because we don't want to inspect it
           anymore.
                       We know that if we put in a better piece
           of pipe that I can reduce my inspections, and I can
           save money that way.  But I don't consider that the
           EPU will have much effect on the decisions that we
           make.
                       MR. PARK:  Good afternoon.  My name is
           Gary Park, and I am the ISI Program Engineer for the
           Duane Arnold Energy Center.  I administer all the
           inspections that we do on the reactor vessel, and on
           our ASME Section 11 components.
                       The first slide that I would like to talk
           a little bit about is about the program that we have
           at Duane Arnold.  I think we have a pretty aggressive
           ISI, IVII, program, and IVII being internal vessel and
           internal inspections.
                       If you will notice for the Class One
           components -- and I have only counted back to 1985,
           but by the year 2005, we would have done 1,875
           inspections just on the Class One systems.
                       And so the power uprate as far as the
           effect on the structural integrity of these
           components, we have already got a pretty good base
           line inspections for those.
                       The thing that I need to bring out about
           the inspection program is the fact that we find
           problems before they actually exist to a failure.  We
           also utilize in our inspection program the recommended
           inspections of the boiling water reactor vessel
           internals project.
                       And I hope that everybody on the panel or
           on the committee is familiar with that, because I am
           sure that you have been addressing different safety
           evaluations from that particular group of utilities
           and their recommended inspections.
                       I think one of the materials that we
           should address in this presentation is the stainless
           steel materials that we have inside the reactor
           vessel.
                       Again, we perform the recommended
           inspections of the BWRVIP, and we follow all of their
           documents, and we have a pretty aggressive program in
           doing so.
                       For example, the course route, we have
           inspected all the H-1 through H-7 wells twice since
           1985, and we have not found any IGSCC, intergranular
           stress corrosion cracking, in any of those welds.
                       So that shows that we have a good base
           line prior to power uprate in a particular important
           component that the industries have been finding
           problems with.
                       DR. FORD:  And on that particular item, it
           is true isn't it that most of the VIP disposition
           curves, et cetera, have not been obtained, or are not
           based on data rather at relevant flow rates?
                       MR. PARK:  The recommendations made from
           the VIP is in fact on safety and not based on any
           pressures or temperatures.  It is just based on if
           that component fails, where are the areas that we
           should inspect.
                       DR. FORD:  But are the frequency of your
           inspections based on disposition curves?
                       MR. PARK:  I am not quite sure I
           understand what you mean.
                       DR. FORD:  Well, what are the inspections
           based on?
                       MR. PARK:  It is based on material and
           your --
                       DR. FORD:  And if you find a crack?
                       MR. PARK:  Then you increase your
           frequency, yes.
                       DR. FORD:  And the frequency is dependent
           on the degradation rate?
                       DR. FORD:  Sure.  Sure.  And crack growth
           rate would be one of them, yes.
                       DR. FORD:  My point is that most of the
           crack growth rates which go into deriving what those
           disposition curves are, are being based on data not at
           high -- well, do you understand what I am saying?
                       MR. PARK:  Well, I understand what you are
           saying.  I don't know that I know the answer to that.
                       DR. FORD:  I guess going back to the very
           first slide, "Inspection Programs finds problems prior
           to failure."
                       MR. PARK:  Right.
                       DR. FORD:  And which assumes that you are
           inspecting --
                       MR. PARK:  At a frequency, that is
           correct.  That is correct.
                       DR. FORD:  And that is the origin of my
           words.  And it goes on to the next question, and
           talking about DAEC performing examination of vessel
           internals, and we are particularly interested in
           IASCC/IAGSC.
                       It was mentioned earlier that the profile
           has changed.
                       MR. PARK:  Well, I will defer to Tony on
           that, but it is more flattened out, but it has changed
           some.
                       DR. FORD:  And therefore the pressure at
           the core shroud has increased?
                       MR. PARK:  Yes.
                       CHAIRMAN WALLIS:  Do we know how that will
           affect cracking at the core shrouds, and at that prior
           flux, and therefore fluence, especially if you are
           going to extend -- the fluences are all going to
           increase at a higher rate?
                       MR. PARK:  Yes, and there is some
           threshold and that's when IASCC starts, and I am not
           sure where we are at as far as Duane Arnold.  I think
           we are approaching that.
                       MR. BROWNING:  This is Tony Browning
           again.  We have already exceeded the VIP threshold for
           IASCC in like the top guide area in the upper shroud
           area.  The other thing you mentioned was the increase
           in fluence.
                       One of the things that we noted when we
           did the fluence calculation was that the increase to
           the shroud area wasn't as dramatic as you were
           expecting, and that was because of the partial rods
           from the GE-14 design that we were going to.  There is
           just less neutrons there.  It is not as dramatic as
           the uprate itself.
                       MR. PARK:  And then I think the other
           important thing to note is that we have done probably
           the highest percentage of any inspection that is done
           on these particular welds, and we have not found any
           cracking at all.
                       So we have a real good history of water
           chemistry, and then as I will address in a later
           slide, we have done the mitigation measures to help
           support and continue operation of that.
                       In fact, that is a good lead into the next
           slide.  Duane Arnold has implemented hydrogen water
           chemistry which protects our recirc piping, which is
           stainless steel, and we were the lead plant in the
           industry in getting a relief from inspection
           frequencies based on the results of our hydrogen water
           chemistry.
                       And as we have continued to do
           inspections, we continue not to find anything, and so
           we believe that HWC is effective in mitigation of
           IGSCC in our stainless steel piping, particularly our
           recirc piping.
                       And then in 1996, which has already been
           mentioned here on the committee, we were the pilot
           plant for the Noble Chem, and we have since injected
           Noble Chem another time.  So we have injected twice,
           which does enhance the effectiveness of HWC in
           protecting the reactor internals.
                       DR. FORD:  Which is of importance in
           monitoring, and not just crack monitoring, but
           environmental monitoring.  Remind me, but at Duane
           Arnold do you have corrosion potential monitors in the
           core?
                       MR. PARK:  We have installed those, and we
           do have a caste system that is external that has
           reactor fluid in it, reactor water that runs through
           it.
                       DR. FORD:  The reason for my question is
           not quite the answer to the question that I asked.  My
           concern is that, yes, you have Noble Chem, and yes, it
           will stop cracking in the core, but the question now
           is that if you increase the flow rate in the core is
           there going to be any additional danger by that one
           action of increasing the flow with Noble Chem?
                       And that to a certain extent is only going
           to be answered if you have corrosion potential
           monitors in the core.
                       CHAIRMAN WALLIS:  Well, that hasn't
           changed, the core flow hasn't changed in the power
           uprate.  That is only the feed water and the steam
           flow that have changed.  The core flow stays the same
           doesn't it?
                       MR. BROWNING:  But back to your earlier
           question, and this is Tony Browning again.  We do have
           in core monitoring.  We replaced one of the LPRMs
           streams with the ECP monitors at the time.
                       MR. PARK:  We have done that in the past,
           yes.  They don't last very long as everybody knows.
                       MR. BROWNING:  Right.
                       MR. PARK:  But we have done it in the
           past.
                       MR. BROWNING:  Yes, to demonstrate the
           effectiveness of the Noble Chem injection.
                       MR. PARK:  Right.
                       MR. BROWNING:  And as Gary pointed out, we
           have the external cracks verification system, the
           outer clave with the pre-crack specimens in it to
           monitor the effectiveness of water chemistry.
                       MR. PARK:  Before I got to my conclusions,
           I think I will turn some time over to Mr. Al Roderick
           to answer the stress question that was brought up
           earlier if I may, and we have an overhead of that.
                       MR. RODERICK:  I am Al Roderick with Duane
           Arnold.  The question that was raised earlier was
           based on a review of a response to a staff's REI in
           the area of stress analysis.
                       In looking at the main closure flange from
           current to EPU, I believe if you do the math of that,
           I think it is about a 12-1/2 percent increase that has
           been evaluated.  What that is a result of is from GE's
           methodology in looking at EPUs, is to not redo a
           complete code stress analysis for the vessel.
                       They have in their methodology is the
           determination of scaling factors based on changes in
           perimeters from the code of record, or the calc of
           record, to the EPU conditions.  It could be in the
           area of pressure, temperature, flow rates,
           particularly with flow rates with impact nozzles.
                       And they determined the stress of the
           scaling factors that would be applied.  And they don't
           do it on an individual component basis.  When looking
           at the reactor vessel, it is split up into zones if
           you go back and look at the original diagrams for
           defining operating conditions.
                       And so wheat they did was to
           conservatively apply the maximum scaling factor that
           came out of a particular region in the vessel, and as
           I pointed out earlier, as you are going back to the
           calc of record where the stresses are coming from, and
           in radioing up the EPU conditions.
                       So I don't have the specifics of what all
           fed into the 12-1/2 percent, but it is based on a
           conservative screening methodology for a good
           description, because it is a first cut, and it is
           applied to the entire stress intensity.
                       It is not usually split out in terms of
           pressure thermal mechanical loads, et cetera.  The
           highest ones apply to the total stress intensity to
           get a conservative extrapolation or prediction of the
           stress, that is then compared to the code allowables.
                       And because all the code allowables were
           met, nothing more detailed or refined was done.
                       CHAIRMAN WALLIS:  Are you saying that the
           reason that there is a 12-1/2 percent difference from
           current to power uprate is because a different method
           is being used?
                       MR. RODERICK:  We are not using a detailed
           computer or code calculation.  We are using a scaling
           --
                       CHAIRMAN WALLIS:  So then the 12-1/2
           percent is somewhat illusionary?
                       MR. RODERICK:  It is based on changes in
           parameters, and I don't have all the details.
                       CHAIRMAN WALLIS:  I would think the main
           closure flange is mostly influenced simply by the
           pressure in the vessel isn't it?
                       MR. RODERICK:  Well, as I said earlier, it
           is not done on a component specific basis.  It is done
           for the whole region in the vessel.  So a scaling
           factor of 12-1/2 percent increase may have come from
           a different component in that Region A of the vessel,
           and is conservatively being applied to the flange to
           evaluate those.
                       CHAIRMAN WALLIS:  Well, it still doesn't
           explain why the numbers come up by 12-1/2 percent when
           the pressure has hardly changed at all.  There is
           still some mystery, which maybe you can clear up with
           the staff or something.
                       MR. PARK:  Let me try something now. 
           Instead of doing a full-blown code stress analysis for
           a power uprate, GE took the conservative approach to
           make sure that all these regions in the vessel would
           still meet the code allowable.
                       CHAIRMAN WALLIS:  That's okay.  So if you
           simply look at the EPU versus code allowable, that is
           what you are saying.
                       MR. PARK:  Right.
                       CHAIRMAN WALLIS:  But the problem that I
           have is that when I look at the difference between
           current and EPU, which should tell me by how much are
           you changing things, then that 12-1/2 percent is not
           something that I should take seriously?
                       MR. PARK:  And you brought up the point
           that the pressure is not changing, and so why do we
           see a change there, and all it is there is a
           conservative --
                       CHAIRMAN WALLIS:  It is a different method
           of calculation.
                       MR. PARK:  It is just a conservative
           number being added to see if we still meet code
           allowable, as opposed to doing the number crunching on
           a full-blown code stress for the component.
                       CHAIRMAN WALLIS:  So the comparison
           between current and EPU is different because different
           methods are being used.  They weren't so conservative
           before?  Is that what I am gathering?
                       MR. PARK:  Well, I am sure that the
           original design was very conservative.
                       MR. MCGEE:  This method was adequate to
           demonstrate the margin --
                       CHAIRMAN WALLIS:  You are getting close in
           terms of the 80,000 and the 77,364.  Presumably the
           staff asked this question for some reason, and this
           was supposed to answer some question was it?  The
           question was whether or not the stresses were code
           allowable was it?
                       MR. PARK:  It is just to demonstrate that
           we are still meeting code allowable designs.
                       MR. MCGEE:  We did have discussions with
           the staff and with the particular reviewer on the
           method that was utilized.
                       CHAIRMAN WALLIS:  Well, maybe when you
           come to the full committee that you can have a better
           explanation of why the numbers differ by so much from
           current to EPU, because it still seems to me that we
           are just saying that if somebody used a different
           method -- if you use a different method, then why show
           the comparison, and it is a little foggy what the
           comparison is really showing us.
                       MR. RODERICK:  The request from the staff
           was what did we use to access the acceptability of
           stresses in these components, and in the work that had
           been done was a conservative scaling up of the current
           calculated stresses based on a maximum scaling factor
           in the region, and probably in this case came from a
           different component.
                       And then compared to the allowable or the
           acceptance criteria.  So this was the basis for
           demonstrating margin and acceptability at EPU
           conditions for these components.  And the two pieces
           that I was able to look at for the closure flange
           itself is in the original analysis, and the original
           drawings for the pressure term was using a thousand
           PSIG.
                       And in doing consideration of this area of
           the vessel, we are now looking at a 1,025.  So just
           looking at that ratio itself would be at 2-1/2 percent
           increase.  So that obviously is not it.
                       The temperature change is 3 degrees, and
           that is just based on a saturation temperature.  So
           with those two pieces of information, I am very
           comfortable that this 12-1/2 percent scaling factor is
           from another component that is still part of this
           region of the vessel.
                       CHAIRMAN WALLIS:  Well, I don't want to
           pursue it anymore.  I think when you come back, if you
           could identify what that component is, and give us a
           clearer explanation of why the numbers are so
           different, and the full committee will be satisfied.
                       DR. POWERS:  I don't know whether you are
           the correct speaker or not, but who should I ask about
           the fatigue usage factors?
                       MR. PARK:  Fatigue usage factors?
                       DR. POWERS:  Right.
                       MR. PARK:  Do you have a question?
                       DR. POWERS:  Well, in looking at your SAR,
           I noticed that your fatigue usage factors usually went
           down, and it was kind of surprising.  And when I read
           the text, it said that they had used a less
           conservative method of analysis when they calculated
           the fatigue usage factor.
                       And in some cases they produced some
           remarkable reductions in the usage factors.  For
           instance, the hydraulic system return nozzle went from
           about .85 down to .57.  There is another case where it
           went from .97 to .2.
                       And I just wondered what the less
           conservative analysis method was.  I mean, what was
           entailed.  But then I went on and I noticed that your
           feed water nozzles were -- that the usage factors
           actually went up pretty dramatically.
                       They went from about .85 -- and this is
           end of license times, and so .85 up to .968, and it
           doesn't surprise me that the usage factor would go up
           on the feed water nozzles.
                       But it seems like a big jump, even if you
           were using a less conservative analysis method.
                       MR. PARK:  So you want us to just address
           what that analysis was?
                       DR. POWERS:  I just would like to know
           what the differences were in the method of analysis.
                       MR. PARK:  I was not prepared to do that,
           but we certainly can write something up.  Do you want
           us to bring that back before the full committee?
                       DR. POWERS:  You can just tell me one way
           or the other, formally or informally.
                       MR. PARK:  Okay.  As far as my
           conclusions, I think we have pretty much addressed
           those during our discussion.  We follow the
           recommendations of the VIP, which I think is an
           industry standard that is going to be developed, and
           I believe that the VIP has also come out with a
           recommendation for going out and doing self-
           assessments to make sure that we are implementing
           those products.
                       We used Noble Chem and HWC, which has been
           shown to be an effective mitigation, and that those
           effects are going to help in the power uprate.  And
           then also our vessel internals have been evaluated,
           and it is important to note that they still meet the
           design criteria with some margin.
                       CHAIRMAN WALLIS:  Now, how did you decide
           what is sufficient margin?  They meet the criteria,
           but --
                       MR. PARK:  Right.
                       CHAIRMAN WALLIS:  And you start getting
           into one margin that is sufficient, and that gets
           again fuzzy doesn't it?
                       MR. PARK:  Well, they meet the criteria. 
           They are still under what the design margins are, or
           the design is.
                       CHAIRMAN WALLIS:  But you were very
           uncertain about your predictions.  You presumed that
           they have a bigger margin.
                       MR. PARK:  Excuse me?
                       CHAIRMAN WALLIS:  If you meet the
           criteria, but you are close, and then you say that we
           are uncertain in our predictions, and we had better
           back off, then that would be increasing the margin
           because of uncertainty wouldn't it?
                       MR. PARK:  Well, there was some
           conservatism in developing that criteria, and in
           developing what it was.
                       CHAIRMAN WALLIS:  So, criteria with
           conservatism.
                       MR. PARK:  Well, yes, that might be a
           better way to put it, yes.  Is there any other
           questions?  Thank you.
                       MR. BROWNING:  Quickly.  Dr. Powers, we
           have the calculation for the hydraulic system return
           line, but it is proprietary material.  We can show it
           to you over the break if you would like to see it.
                       DR. POWERS:  That would be fine.
                       MR. BROWNING:  Great.
                       MR. HUEBSCH:  My name is Steve Huebsch and
           I with the Duane Arnold Energy Center, and I am going
           to present some information pertaining to the
           containment pressure temperature response from the
           EPU.
                       Specifically the areas of interest that
           were looked as parameters as part of the analysis were
           the drywall pressures, the drywall gas temperatures,
           the drywall shell metal temperatures, the wet well
           pressures, the suppression pool water temperatures,
           and the containment loads.
                       These parameters were looked at both in
           the short term and in the long term.  The analysis
           looked for both peaks, as well as the specific results
           and comparison between the two.
                       DR. SCHROCK:  This containment, it is
           BWR4, is the toros containment?
                       MR. HUEBSCH:  Yes, it is.  It is the Mark-
           1.
                       DR. SCHROCK:  Thank you.
                       MR. HUEBSCH:  One thing that I want to
           address and that is probably the most important thing
           as far as evaluating the containment structures is
           when you look at the analysis and the way the analysis
           is done for both the peak drywall pressures and the
           temperatures, as well as the
           Mark-1 containment analysis for the load stuff, they
           start basically with a thermal hydraulic analysis to
           develop the loads based on the Mark-1 program, and
           testing that was done in accordance with those days.
                       Once those loads are developed, those
           loads are put into the structural calculations, and
           those structural calculations then are required to
           meet the ASME code requirements for a containment
           vessel.
                       And in all of the cases that we looked at,
           we were able to maintain the ASME code allowables as
           defined by the original design requirements.  The
           methodologies that were used for the analysis
                       CHAIRMAN WALLIS:  Are you going to talk
           about this 5 percent hydrogen limit?  Is that part of
           your discussion or somebody else's?
                       DR. POWERS:  I don't know what limit you
           are talking about?
                       CHAIRMAN WALLIS:  Well, I was trying to
           understand the SAR, the draft SAR, and there is a lot
           of stuff about combustible gas control and 5 percent
           hydrogen, and it seems to be pretty obscure.
                       MR. HUEBSCH:  That is not directly
           associated with this presentation, but we can discuss
           it.  I guess
                       DR. KRESS:  That is a corrosion production
           of hydrogen at 5 percent.  It generally is not
           important generally.
                       CHAIRMAN WALLIS:  It is not important?
                       MR. HUEBSCH:  It is dealing with post-
           accident flammability issues with hydrogen-oxygen
           generation, post-LOCA.
                       DR. KRESS:  Their past system was supposed
           to be designed to deal with that kind of levels.
                       CHAIRMAN WALLIS:  That's right, and
           monitoring --
                       DR. KRESS:  Yes.
                       MR. HUEBSCH:  Monitoring, and then dealing
           with it such that we don't end up with a flammability
           situation post-accident.
                       CHAIRMAN WALLIS:  Well, maybe we can just
           ask the staff to explain that one then if you don't
           want to.
                       DR. POWERS:  We will meet with the staff
           tomorrow on that.  You are not responsible for the
           SAR.
                       MR. MCGEE:  We can discuss that, but --
                       DR. POWERS:  Well, we can have the staff
           do that tomorrow.
                       MR. MCGEE:  Well, I would be more than
           happy and if you want to wait until this is done, then
           I can answer any direct questions.
                       MR. HUEBSCH:  The analysis methods that
           were used to do the containment analysis, in the short
           term cases, to come up with the peak drywall
           pressures, and to determine a short term temperature
           in both gas, as well as suppressible temperatures, was
           the M3CPT model that GE has.
                       This is the model that was used in the
           Mark-1 containment analysis.  It was approved for use
           at that point for the short term analyses.  In the
           long term event, which is looking at heat up based on
           decay heat changes and things of that nature after 8
           hours, 10 hours, out.
                       CHAIRMAN WALLIS:  Why would you expect a
           difference with the power uprate?  Is it because of
           the heat stored in the metal and the fuel?
                       MR. HUEBSCH:  For which case, the short
           term?
                       CHAIRMAN WALLIS:  Is it a difference heat
           source; is that what it is?  Why is there a difference
           in the power uprate?
                       MR. HUEBSCH:  In the short term, you see
           certain things, and in the case of the Duane Arnold,
           we see a little more sub-cooling.  So when you have
           the break, you have more mass transferred to the
           containment structure.
                       You see some changes in the pressure and
           in the longer term, you have a higher decay heat, and
           you transfer that heat.  So you will see some changes
           in this analysis, and the changes were in accordance
           with what was expected because of those specific
           attributes to the power uprate.
                       The long term model that was used in
           accordance with the ELTR is called SHEX, and that was
           done to do not only the DBA-LOCA cases, but the other
           longer term analysis -- station blackout, the MPSH
           analysis for ECCS, and other methods.
                       And the SHEX model has been approved only
           a case by case basis.  It i not generically approved
           like the M3CPT model was, but it is in accordance with
           the ELTR.
                       The loads, the specific loads on the
           containment structure, the Mark-1 containment loads
           were done in accordance with the Mark-1 program.  The
           new loads as developed by, or as looked at, were
           compared back to the original test data, and the
           original program to determine whether or not it was
           previously bounded by the cases that were analyzed for
           the initial program.
                       The methodologies used were bounding
           correlations, and the models are conservative by
           nature, and they are benchmarked back to the original
           analyses, and they are qualified against the test data
           that was done for the Mark-1 stuff.
                       One specific issue that is important is
           the increase in the containment peak pressure, and
           this inputs into our local leak rate testing and
           various other things that we do to maintain
           containment integrity.
                       DR. SCHROCK:  This is on a scaled test
           data and is the range of the parameters that are
           changed by the power uprate, and is that covered by
           that testing range that exists?
                       MR. HUEBSCH:  Yes.  The way the original
           testing was set up, it was based on things like pool
           swell and various things, and loads from the SRVs, and
           the blow down model through the vents.
                       These were analyzed numbers, and then they
           were -- and then the specifics of Duane Arnold were
           compared to those values that were tested in the low
           definition report developed by GE, and then other
           analysis.
                       And, Dan, I don't know if you wanted to
           add anything to that or not.
                       MR. PAPPONE:  This is Dan Pappone with GE. 
           There are two basic test approaches.  One was a
           generic bounding test configuration that was developed
           to bound all Mark-1 containments.
                       So they ran the one test for all
           containments, and what we are doing in the individual
           plant applications is that we are comparing either the
           original analysis or in this case the power uprate
           analysis, to confirm that we are still within that
           original test basis.
                       There are some tests that are done on m
           more of a plant unique basis, where the test facility
           itself may be -- you know, the geometry there is
           fairly fixed, but some of the parameters, the initial
           parameters, were set up to bound a specific plant.
                       And there again we are looking at the
           power uprate conditions to confirm that we are still
           within or bounded by the actual test.
                       DR. SCHROCK:  And I guess that was the way
           that I was thinking of it.  Ordinarily, you would want
           your tests to cover the range of parameters to which
           it is going to be applied.
                       And here you are extending that range of
           parameters in a power uprate program.
                       MR. PAPPONE:  Right, but we are going back
           and confirming that once we have extended the plant
           specific values to the power uprate conditions, we are
           still within the original bounds of the test, those
           parameters.
                       DR. SCHROCK:  Okay.  Thank you.
                       MR. HUEBSCH:  In this case, it shows that
           basically the peak containment pressure analyzed has
           gone up 3 pounds.
                       DR. KRESS:  Do you have to do that also
           for ATWS events?
                       MR. PAPPONE:  Did we run these cases for
           the ATWS events?
                       DR. KRESS:  Yes.
                       MR. PAPPONE:  There was a pressure
           temperature analysis that was done.
                       DR. KRESS:  Was it less than this?
                       MR. PAPPONE:  Yes.  The 45.7 psi occurs
           very quickly in the DBA LOCA event, and it is the peak
           pressure that is identified as analyzed per the whole
           series of accidents.
                       DR. KRESS:  For the whole series of
           accidents.  Okay.
                       MR. HUEBSCH:  One of the issues that the
           long term SHEX model gets involved in is the use of
           containment pressure for an ECCS pump performance.  At
           the Duane Arnold Energy Center, the plant was
           originally licensed with the use of containment
           overpressure for the core base systems specifically.
                       And in the original RHR core spray pump
           specifications, and in the containment specifications,
           there is actually criteria for how to analyze for the
           containment pressure models.
                       We have stayed within the original license
           bases, and the design bases for the containment
           analysis that we did today as part of the EPU.
                       The specific analysis, because when we got
           involved with the ECCS strainer issues, there were
           some aspects of the PRA that looked at what happens if
           you lose your injection capability, as well as lose
           your containment.
                       So those aspects have been looked at for
           insights, as far as the use of containment pressure,
           and what would happen if you lost it.  The other thing
           is that when we ran the containment overpressure
           analysis that we were consistent with both the branch
           technical position that was written for this is how
           you should analyze to mitigate -- to minimize your
           pressure and maximize your pool temperatures.
                       As well as the original specifications for
           the plant.  So we applied those aspects when we ran
           the cases, and the analysis also includes things like
           containment leakage, and it factors those in so that
           you are decaying off your containment pressure as the
           event goes on.
                       What you see here is the results of the
           analysis and where after the MPSH calculations were
           calculated what are the reliance on containment
           pressure is.
                       And there were two specific issues or
           points that were significant.  One was at the 10
           minute mark, because prior to 10 minutes the pumps
           were at run out conditions.
                       And at the 10 minute mark the operators
           restrict the pumps to rated conditions.  Although
           there is pressure available in accordance with the
           analysis, we have no reliance on containment pressure
           in the first 10 minutes of the event.
                       But what we have found at Duane Arnold is
           that the reliance on pressure -- and this is in
           accordance with the original license -- occurs at peak
           pool temperatures.
                       And the black is the available, and the
           others required for original license, we require 3.1
           psi for over pressure.  And we will be looking at 5.3
           psi and EPU conditions --
                       CHAIRMAN WALLIS:  That's because the water
           is hotter in the pool?
                       MR. HUEBSCH:  Correct.  The water
           temperature has gone up, and I believe where we were
           analyzed after completion of the ECCS strainer
           installations was roughly 202 or 203 degrees
           fahrenheit peak pool temperatures, and we are looking
           at 209.2 degrees now.
                       And so a seven degree increase because of
           EPU for this specific analysis.  One thing at Duane
           Arnold specifically is that the pressure is used for
           core spray, and you run into a temperature issue.
                       Core spray requires over pressure roughly
           at 180 degrees.  So anytime the pool temperature
           reaches 180 degrees or above there is some reliance on
           over pressure with the current analyses assumptions,
           which are very conservative.
                       For the RHR system, the way we are
           configured is that after the events of the LOCA and
           divisional failure, you are down to one RHR pump.  We
           don't require containment over pressure for that one
           RHR pump.
                       If you had two RHR pumps running, there is
           a requirement, but that's not our design basis, but we
           have analyzed all those cases.  In the continual load
           section, Dan talked about that a little bit.
                       The specific loads that were evaluated for
           EPU were in line with the original Mark-1 pool swell,
           vent thrust, condensation oscillation, considerations
           of chugging, and SRV discharge, both the first pop, as
           well as the second pop, and the impacts of low, low
           set.
                       And whether there were any changes between
           our current configuration and EPU.  The only one of
           these that had any impacts on the original loads that
           were analyzed were the vent thrust section, because we
           are seeing a higher dry wall pressurization rate.
                       And so you have a larger load on the vent
           system as the blow down model comes through the vents. 
           The loads were increased roughly by five percent.  It
           was a scaling or a linear evaluation rather than a
           detailed evaluation as was done in the Mark-1.
                       CHAIRMAN WALLIS:  This is just a momentum
           of the fluid coming out of the pipe; is that what it
           is?
                       MR. HUEBSCH:  I believe so.  Dan, is that
           correct?
                       MR. PAPPONE:  This is Dan Pappone.  The
           basic vent thrust loads are from the momentum of the
           flow through there, with the power uprate looking at
           a little bit higher -- well, it is a trade off between
           a little higher initial break flow due to the
           subcooling, and a little bit lower energy coming out
           of the flow.
                       So every pound coming out is a little bit
           lower because of the higher subcooling, but we are
           getting -- the flow is coming out a little faster. 
           The next effect of that is a little higher
           pressurization rate in the dry well, and that shows up
           in the flow through the vents and the thrust loads.
                       And we run that through the Mark-1
           calculational methods to come up with that 5 percent
           increase in the load definition.
                       MR. HUEBSCH:  And those values were then
           compared to the structural allowables, and we are
           still within the allowables for the program.  So it
           still meets the requirements of the ASME code, and all
           the margins are maintained.
                       Let's go to the conclusions then.  One
           other area where one of the limits were challenged is
           in the station blackout event, at about roughly 3.7
           hours into it the temperatures exceed the 281 degree
           containment design temperature.
                       And what was done in that case was the
           pressure and temperature requirements were looked at
           in comparison to the design requirements.  Our
           containment design is 56 pounds at 281 degrees
           fahrenheit.
                       In the case of the station blackout event,
           it reached 283 -- well, just short of 284 degrees at
           the four hour point basically, 3.7 hours out, with 8.7
           psi.
                       So because you are at such a low pressure
           and the temperature is only there for a short period
           of time before the four hour coping period is over, it
           was analyzed as being acceptable.
                       As we said earlier, the vent thrust loads,
           and the dry wall temperature as I just said, and the
           station blackout, were the only two events that
           challenged the thermal hydraulic analysis that had
           previously been done for the plant.  So everything
           else was bounded.
                       And the structural analysis of all the
           events, including those two, after the loads were
           changed or evaluated for the higher considerations,
           were still within ASME code.  So there were no
           challenges to the DAEC containment.
                       MR. KNECHT:  I am Don Knecht from GE, and
           I am here to talk about the separators and dryers, and
           really a specific aspect of it.  As you see here on
           the outline, the basic things that we are going to be
           focusing here on are the loads, and the separators,
           and the dryers, and some of the dryer experience that
           we have been having.
                       There was an RAI asked by the NRC dealing
           with the flow induced vibrations, and that's really
           the emphasis here.  There are some other aspects, but
           I am not going to address those now.
                       First off, a little bit on the impact of

           EPU.  Obviously there is a steam flow increase, and
           both the steam flow increase coming out of the core
           affects the separators and turns the excitation forces
           which are transmitted to the shroud.
                       The dryer sees the increase flow pretty
           with regards to the power increase, and along with
           this is an increased pressure drop across the dryer. 
           The other issues that I am not going to deal with here
           are the moisture content issues and the effect of the
           carry under change that goes on with the dryer
           performance, to just to try to contain the discussion
           a little bit.
                       Now, on the separator, the excitation
           forces that are going on are primarily from the flow
           increase, and also the swirling action in the
           separator as it is going out.
                       Those are increased, but Duane Arnold, not
           coincidentally, but Duane Arnold was the prototype
           unit for the BWR4 in terms of the stresses on the
           separator, and were instrumented at the time of start
           up.
                       And they found that the stresses at that
           time were only about 15 percent of the allowables. 
           With the EPU scaling it up for the increased flow and
           what not, it shouldn't be more than about 20 percent
           of allowables.
                       So as far as the separator is concerned,
           there really is no concern, and there is quite a bit
           of margin preserved for that.  So I don't really see
           any issues with the separators themselves.
                       Now, on the dryers, the dryers are
           designed -- first off, they are a non-safety related
           component.  It's main function is to keep the moisture
           content of the steam below a certain goal.
                       From a safety standpoint, we don't want
           any failure that a dryer such that there would be a
           lose part that could go and impact, let's say, an MSID
           closure or some other consequence.
                       So the dryer is designed for the main
           steam line break event and it has sufficient margin as
           it was originally designed to show that a main steam
           line break would not result in any adverse
           consequence.
                       Now, with the EPU, that event does not
           change because we are at constant pressure, and the
           main steam line break is a choke flow type of
           consequence.  So there really is no impact on the
           loads on the dryer due to that.
                       So the structural integrity of it should
           be maintained.  Now, the question in the RAI dealt
           with flow induced vibration, and because it is a non-
           safety component, it is not something that is analyzed
           with codes and what not.
                       Instead, it is more of a qualitative
           evaluation that is done, and because of the flow
           increases the load should increase by about 31 percent
           was the estimate.
                       CHAIRMAN WALLIS:  This is based on a --
                       MR. KNECHT:  Yes.
                       CHAIRMAN WALLIS:  Now, is that really the
           whole story?  I mean, don't you get vibration due to
           resonances and things which are not just proportional
           to momentum?
                       MR. KNECHT:  This is really dealing with
           the amplitude of the flow induced vibrations.  The
           frequency stays the same, because they are based on
           the natural frequency.
                       CHAIRMAN WALLIS:  Unless you have some
           sort of resonance between some wall shedding or
           something and the mechanical behavior.  You are way
           away from that and maybe you are right.
                       MR. KNECHT:  That is not the concern. 
           What we have done traditionally on the dryer
           performance, or not so much the performance, but the
           flow induced vibrations, is that we have looked at
           this on a fleet wide basis.
                       As it turns out, Duane Arnold has not had
           any particular problems with their dryers, in terms of
           this, but there have been cracks that have gone on in
           the dryer drains and some other components.
                       And so it has been looked at for several
           years, and we have a database going back into the mid-
           1980s tracking various dryer cracks that have been
           found.
                       So those have been used in a way that
           tries to identify areas that we think should be looked
           at.  The VIP program talks about since the dryer is
           going to be removed during outages anyway that a
           visual inspection should be done on the dryers, and
           that is what has been done in pretty much all plants,
           but at Duane Arnold at any rate.
                       We use the fleet experience to try to
           guide those inspections as to what ought to be
           inspected, but the cracks that have been seen have
           been pretty odd, and they have not been so much of a
           problem.
                       So the areas where we have seen some of
           the more dramatic cracks have been in the drain
           channels, where we have seen some fairly significant
           cracks.  But none of these cracks have led to any
           concern with the integrity of the components.
                       And so we use this program as sort of an
           operational way of evaluating the integrity of the
           components.
                       The other main point here is -- and
           getting on to the next slide, is that once these
           cracks are identified, they are readily repairable
           because the dryer is available in the pool, and they
           are generally repaired, unless they are so small that
           another cycle or so would not lead to any real
           concern.
                       The experience that we have had so far is
           that there have been two types of cracking.  The IGSCC
           cracking has been a little bit more than half the
           cracks that have been observed.  But those are not
           really impacted by EPU.
                       The chemical environment in the steam has
           not really been changed by EPU, per se.  It is mostly
           just a steam environment.  So we don't see any impact
           of EPU on IGSCC.
                       Now, the high cycle fatigue is the other
           area, and clearly there is an impact there.  But again
           we have seen no cracking at Duane Arnold, and many
           plants have seen cracking, and they have been all
           repaired.
                       MR. ROSEN:  Do you have a visual of this
           dryer where you can show us where the cracking has
           been observed?
                       MR. KNECHT:  Over there I do.
                       (Brief Pause.)
                       MR. KNECHT:  This is the general area. 
           This is a brief diagram here of the dryer, and this is
           the top of the separators here coming up, and there is
           just a little bit of a gap here between the top of the
           separators, and these are the typical dryer drains
           where the steam will come up through these channels
           here, and through the dryer assembly, and then out.
                       Now, the moisture that comes off of the
           dryer collects down here in these troth areas here,
           and that leads into -- well, these are the bottom
           drains that lead into a troth, and then these are the
           drains that go down here and into the separator area,
           and combine with the separated moisture that is
           removed and then back.
                       But what doesn't really show on this
           diagram is that the cracks that have been seen are in
           some of the drain channels that lead from here out and
           down.
                       And subject to the vibrations that get
           generated here in the dryer drains, and so it is
           transmitted back down through that structure.
                       MR. ROSEN:  You called them channels.  But
           are they open at the top or are they pipes that are
           closed?
                       MR. KNECHT:  The troth is open down in
           this general area, and then those troths drain into
           some pipes.
                       CHAIRMAN WALLIS:  Well, the things that
           shake are the louvers aren't they?  Whatever they are,
           the things that have the initial impact on --
                       MR. KNECHT:  The drains here?
                       CHAIRMAN WALLIS:  Yes.  And those are the
           things that shake?
                       MR. KNECHT:  Yes.
                       MR. ROSEN:  So I am still trying to figure
           out what cracks.
                       MR. KNECHT:  The drain channels -- and
           unfortunately they don't show this, but if you go in
           3-dimensionally, there is some --
                       CHAIRMAN WALLIS:  Well, it is a funny
           place to crack if the drains are shaking.
                       MR. KNECHT:  That is the forcing drain.
                       CHAIRMAN WALLIS:  It is transmitted down?
                       DR. FORD:  Are those welded to conform
           down there?
                       MR. KNECHT:  There are some welds, yes.
                       DR. FORD:  And the cracking, presumably
           the stress is associated with those probably?
                       MR. KNECHT:  It could be contributing.
                       CHAIRMAN WALLIS:  And so because the pipe
           is further, it is the rigidity of the whole structure? 
           The pipe is helping to retain --
                       MR. KNECHT:  There are probably some
           stresses there.  Because they are easily repaired, I
           don't think we go into a lot of analysis as to --
                       MR. ROSEN:  Well, you are worrying about
           the wrong end of the problem.  I mean, I grant that
           they are easy to repair, but what I am concerned about
           is one of those parts carrying away during operation,
           and what would happen then.
                       But I can't get a good feel for what would
           carry away since I don't have a picture of it.  Can
           you help me with that question?  What if the crack
           proceeded to where it severed the component?
                       CHAIRMAN WALLIS:  It would just leak
           wouldn't it?  I mean, it's whole --
                       MR. ROSEN:  I don't care about leakage.
                       MR. KNECHT:  If a part is completely
           carried away -- well, first off, we have never seen an
           experience where we saw that it was completely covered
           away.
                       If it did, it would become some kind of a
           lost part, but I don't think it would go -- this is
           down below the dryer assembly, and it would probably
           find its way into this area someplace.
                       Now, there would be an increase in
           moisture coming out of the dryer, because you would be
           bypassing things and we are not concerned about that. 
           So it has not really been a concern.
                       MR. ROSEN:  Where would a plate of steel
           or an elbow of pipe that came lose there go?  Where
           could it go?
                       MR. KNECHT:  I suppose that it could find
           its way up here, and block part of the drain here.
                       MR. ROSEN:  There is no way that it could
           get down below the separators?
                       MR. KNECHT:  No, because steam is going
           up.
                       MR. ROSEN:  Yes, but not all the time. 
           When you shut down --
                       MR. KNECHT:  It could go back through.
                       MR. ROSEN:  Go with me for a minute on
           this.  You have got a crack, and the crack proceeds to
           where the part fails.  It is a piece of steel now,
           regular shaped.
                       Now for some reason in their wisdom, the
           operators decide to shut the plant down, and now there
           is very little steam.  Where does the part go?
           You said don't worry about it, there is lots of steam. 
           Well, not all the time.
                       MR. KNECHT:  Wouldn't it just lay down on
           top of --
                       CHAIRMAN WALLIS:  The pipe is held at the
           other end if it cracks off at the place you indicated,
           and it is just held at the other end, and the forcing
           function has gone away because it is broken off.
                       MR. KNECHT:  Well, it might come down
           between the separators.
                       CHAIRMAN WALLIS:  What if it doesn't come
           down at all?
                       MR. ROSEN:  Well, it has broken loose.
                       CHAIRMAN WALLIS:  No, it is only broken on
           one end.
                       MR. KNECHT:  Well, it would wind up
           somewhere in that region, and probably lay on top of
           the separators.
                       DR. KRESS:  I don't think I would put this
           one in my PRA.
                       DR. FORD:  I think the argument is going
           to as far as that particular mode of degradation is
           concerned, it is not going to change.
                       MR. ROSEN:  It is not an EPU specific
           problem.  All I am trying to get someone to say is
           that it won't get down and damage the fuel, and hit
           the fuel or the controller out drive, or something
           like that.
                       Can you say that, that it can't get below
           the separators and get down to the fuel?  Can you say
           that?
                       DR. KRESS:  If you have ever seen those
           separators, it would have to be a mighty small piece
           to get down there.
                       MR. KOTTENSTETTE:  How big a part are you
           saying has broken off?  Is it something that size or
           a piece of something this long?
                       DR. SCHROCK:  Well, your experience with
           the crack should tell you something about what a
           potential piece may be, and what it's size and origin
           might be.
                       MR. MCGEE:  But if it resulted in a piece
           being broken off on one end and taking away the
           stress.
                       MR. ROSEN:  You have a lot of experience
           with cracking of these things to know that they don't
           result in pieces, but I don't have that similar
           experience.  And cracking can be a funny thing, and
           you could end up with a crack that proceeds in a way
           that a piece comes loose in my world.
                       Now, I am only asking whether that piece
           could go down and cause some real damage in the fuel
           or in the control rod drives.
                       DR. KRESS:  It is about the size of a
           quarter.  It wouldn't hurt the control rod drive.
                       MR. PAPPONE:  This is Dan Pappone.  The
           region that we are talking about is outside of the
           shroud, and the fuel in the control rods are inside
           the shrouds.  So we have got an area there --
                       DR. KRESS:  Yes, it would never bother the
           control rods.
                       MR. KNECHT:  If it went outside the shroud
           region, it would drop to the bottom, and where the
           recirc pump suction is.  So unless it is just the
           right size part, and just with the right dimensions
           and weight, and all these improbabilities, it is not
           going to cause any problem.
                       I mean, the one thing about the drain
           channel cracks is that those have been several inches
           long.  They are not little flakes of something.
                       So if something were to break loose, and
           it is hard to imagine that when all that stress is
           relieved, it is going to be a large part.  There has
           been no evidence that any part has ever come loose.
                       CHAIRMAN WALLIS:  And all of this is
           because of the drains are shaking up above?
                       MR. KNECHT:  Well, that and probably --
                       DR. KRESS:  It is probably residual
           stresses like he said.
                       CHAIRMAN WALLIS:  Well, the velocity
           through the drains is pretty low isn't it?
                       MR. KNECHT:  I'm sorry?
                       CHAIRMAN WALLIS:  Gravity drain or
           something?
                       DR. KRESS:  Oh, yes.  There is hardly any
           velocity at all.
                       CHAIRMAN WALLIS:  And so there is nothing
           there that is going to happen.  It is the drains that
           are shaking.
                       MR. KNECHT:  And that is creating the high
           cycle --
                       CHAIRMAN WALLIS:  And are these drains
           being tested?  Have they been tested at higher
           velocities in a testing facility?  Is there a separate
           effects test?  You take each separator and test it?
                       MR. KNECHT:  Not so much from a flow
           induced vibration standpoint, but from a performance
           standpoint, we have done extensive testing on the
           dryers and separators.
                       CHAIRMAN WALLIS:  So if there were any
           kind of residences or anything --
                       MR. KNECHT:  Well, we are well within the
           range of experience.
                       CHAIRMAN WALLIS:  And you have run them in
           a separate effects test at these flow rates?
                       MR. KNECHT:  Yes, with the uprated flow
           rates, we have data that supports that.
                       CHAIRMAN WALLIS:  Yes, you have.
                       MR. KNECHT:  Now, I guess one other point
           to make here is that we have had at least three plants
           that have operated at an extended power uprate for
           several years now, and at least two of them.
                       And we have had some KKM that have
           operated up to not quite the 120 level, but they have
           been operating much higher than their original design. 
           And they have shown virtually no evidence that there
           is increased cracking because of the uprate.
                       DR. KRESS:  Is their power level
           comparable to --
                       MR. KNECHT:  It is slightly higher than
           Duane Arnold.  Duane Arnold is one of the smaller
           units.
                       CHAIRMAN WALLIS:  And do they use the same
           kind of separators?
                       MR. KNECHT:  No.  Hatch and KKM are very
           similar, and KKL is slightly different.  And by way of
           conclusion, and I think we have gone through most of
           this already --
                       CHAIRMAN WALLIS:  The percentage figures
           that you are giving there on the Hatch, and KKL, and
           KKM, what are those again?
                       MR. KNECHT:  Those are power updates above
           the original power level.
                       CHAIRMAN WALLIS:  So they are the new
           power updates compared to the old power?
                       MR. KNECHT:  The current uprating power
           versus the original power.
                       DR. SCHROCK:  I guess you said these three
           are not the same as each other, but it wasn't clear
           that you meant the comparison to Duane Arnold.
                       MR. KNECHT:  Well, Hatch and KKM are both
           BWR4 units, and have pretty much the same dryer.
                       DR. SCHROCK:  The same dryer?  Okay.
                       MR. KNECHT:  KKLs and BWR6s have slightly
           different dryers.
                       DR. SCHROCK:  I thought because they were
           foreign that they might have a difference other than
           that.
                       MR. KNECHT:  No, other foreign plants have
           different dryers, but these are similar to Duane
           Arnold.  Again, the dryer really has an operational
           function, and for testing it and repairing the cracks,
           and that sort of thing, is really an investment
           protection issue.
                       There is no loss of margin with the
           structural integrity basis of the dryer, because the
           main steam line break does not change.  And we think
           we know where to look for flow induced vibration
           cracks based on the experience.
                       Again, Duane Arnold has not seen any, but
           we know pretty much where to look.  They are visually
           inspected at every outage, and so there is kind of a
           confirmation there that can be managed.  And they are
           also repairable.
                       So we don't see a safety concern with
           these dryers, and the integrity of them and the
           performance of them is managed by the utilities.
                       CHAIRMAN WALLIS:  And the visual
           inspection, this is with some sort of video device?
                       MR. KNECHT:  It can be.  Once it is in the
           dryer pool, there is usually a camera that is used to
           inspect them.  But there is no hard requirement on how
           that is done.  I think that is up to the utilities. 
           Any more questions?
                       DR. POWERS:  I noticed in your SAR that
           you discuss increases in the vibration levels for your
           recirc drives, and that you looked at those by
           extrapolating some results from start up testing.  Can
           you explain more about that to get to the kinds of
           recirc close that you are going to have at the power
           uprate for that test data that are applicable?
                       MR. KNECHT:  Well, the flow rate in the
           recirc system increases just slightly to overcome the
           pressure drop.
                       DR. POWERS:  I see.
                       MR. KNECHT:  It is not a very large
           increase.
                       DR. POWERS:  Okay.  I was thinking it was
           proportional.
                       MR. KNECHT:  It is about a one percent
           change.
                       DR. POWERS:  That explains it.
                       MR. BROWNING:  This is Tony Browning again
           from Duane Arnold, and the next presentation that I am
           going to co-give with Dan Pappone from GE is on the
           ECCS analysis that was done for the extended power
           uprate.
                       Dan is going to get up and talk about the
           methodology side of how the analysis was performed,
           and then I will get up and talk about the plant
           specific results, and the conclusions.
                       Again, we are trying to demonstrate that
           we have got adequate operational and safety margins
           from the LOCA perspective at the extended power uprate
           conditions.
                       MR. PAPPONE:  Okay.  The methodology that
           we are using is the SAFER/GESTR methodology, and it is
           kind of an intermediate methodology, where we are
           taking advantage of the technology development, and
           basing the primary analysis on realistic, a fairly
           realistic basis, using nominal models and inputs.
                       But at the time that the methodology was
           approved, we still had to live within the original
           50.46 in Appendix K requirements.  So we do calculate
           a licensing basis PCT that uses the required Appendix
           K models, and that is the PCT that is used to compare
           against the 2200 degree acceptance criteria in 50.46.
                       We also, because we are doing a nominal
           realistic analysis, we also do an upper bound PCT
           calculation to demonstrate that this licensing basis
           PCT that we calculate is sufficient --
                       DR. KRESS:  What do you mean by upper
           bounds?
                       MR. PAPPONE:  Well, we essentially work
           through to what we expect would be a true plant PCT
           given the modeling uncertainties, and the
           conservatisms that are in the SAFER code would account
           for those.
                       We account for the test uncertainties, and
           then there is a set of significant input parameters
           that would vary at a two sigma level to come up with
           an upper bound level, and so we are doing an
           uncertainty analysis.
                       DR. KRESS:  So a two sigma level rather
           than an upper bound?  It is a continuous distribution. 
           You are picking out the two key parameters that
           determine it and see what you get.
                       MR. PAPPONE:  Right.
                       CHAIRMAN WALLIS:  How much does a two
           sigma above mean?
                       MR. PAPPONE:  By the time that we factor
           in all of the uncertainties and the two sigma part, we
           are usually looking at something like 300 to 400
           degrees above the normal temperature.
                       And then also we do have a restriction
           that was placed on the methodology itself in the SAR
           that approved the methodology, and we have a
           restriction on that upper bound PCT.  We are not
           allowed to let that go higher than 1600 degrees.
                       DR. KRESS:  Well, that is actually built
           into your --
                       MR. PAPPONE:  That was a condition on the
           SAR that approved the methodology.
                       DR. KRESS:  How did they arrived at that
           limit?
                       MR. PAPPONE:  Two pieces; one is the test
           data that was submitted at the time, the actual bundle
           heat up test data.  Those tests only went up to 1600
           degrees because they stopped the test at that point to
           protect the test bundle.
                       And the other part is that the upper bound
           PCT evaluations that are in the generic LTR, licensing
           topical report, were in the 1600 to 1700 degree range.
                       CHAIRMAN WALLIS:  So you might argue that
           on the 600 degree margin to maybe 200?
                       MR. PAPPONE:  Well, I don't want to push
           that.  That is a nice thing to have, but we are also
           looking at relaxing this and bringing it before the
           staff.
                       DR. SCHROCK:  I have a question concerning
           the decay heat evaluation in this method.  My
           recollection of the SAFER/GESTR methodology was that
           you had used the 1979 ANS standard, with a lot of
           evaluations for different fuel conditions, different
           points in life and so forth.
                       But you say then that in the end that you
           were required to do an Appendix K evaluation, and so
           that would mean that you would have to use the decay
           power specification there, which was the older draft
           ANS standard, 1971-1973.
                       MR. PAPPONE:  That's right.
                       DR. SCHROCK:  In the SAR, it takes about
           the may-witt (phonetic) approach, and that is
           confusing to me.  I mean, what I just described is
           either a best estimate approach, which is the '79
           standard, or the conservative approach which is in
           Appendix K, which is the '73 standard, draft standard. 
           So how does may-witt (phonetic) get into this at all?
                       MR. PAPPONE:  May-witt is used in the
           containment LOCA analyses, and was originally used in
           the containment LOCA analysis.  It was never used in
           the ECCS performance for the clad heat up.
                       DR. SCHROCK:  Yes, you're right.  That's
           where it is here.  So you are using a different --
                       MR. PAPPONE:  What we were using was --
           well, the nominal calculation and the upper bound
           calculation is the '79 ANS 5.1 standard with that
           uncertainty.
                       And then the licensing calculation, that's
           where we pick up the '71-'73 ANS 5.1 standard.
                       DR. SCHROCK:  And this May-witt is not in
           LOCA?
                       MR. PAPPONE:  That is not in the ECCS
           LOCA.
                       DR. SCHROCK:  In the ECCS considerations?
                       MR. PAPPONE:  Right.  That was in the
           containment LOCA.
                       DR. SCHROCK:  And it is just a sort of
           fact of history that you -- that you had May-witt
           plugged in there, and nobody ever changed it.  Do you
           think it is better for containment analysis?
                       How can one be better for LOCA and the
           other one be better for --
                       MR. PAPPONE:  I don't know the basis for
           using May-witt in the original containment analysis,
           but the current power uprate containment analyses we
           were using in the '79 ANS 5.1 standard with the two
           sigma uncertainty on that.
                       CHAIRMAN WALLIS:  And so May-witt has gone
           away completely?
                       MR. PAPPONE:  May-witt has gone away
           completely.  The only time that we would see that is
           if we are comparing back to the original calculations. 
           Say if we are doing a benchmark calculation.  I am not
           familiar with the statements in the SAR.
                       DR. SCHROCK:  Well, the statement in the
           SAR is that the May-witt decay heat model used in the
           current licensing basis.
                       MR. PAPPONE:  Now, is that in the
           containment section of the SAR?
                       DR. SCHROCK:  Right.
                       MR. PAPPONE:  Yes.  Well, Steve or Tony
           may know.  But I think that is a case where you redid
           the containment analysis a couple of years ago, that
           is when we would have moved off of May-witt.
                       MR. BROWNING:  Right.  Now, the FSA cases
           of record are the original containment evaluations
           that were done, and they were done with May-witt.  So
           we were highlighting to the staff that we had
           undergone a change in methodology as we went through
           EPU.
                       CHAIRMAN WALLIS:  Well, the staff accepts
           the new methodology.
                       MR. BROWNING:  Correct.
                       CHAIRMAN WALLIS:  Well, is there a problem
           with this?
                       MR. PAPPONE:  Or is it just a historical
           notation in the SAR.
                       DR. SCHROCK:  Well, I was trying to
           understand why there would be any use made of May-witt
           at this point in time.
                       CHAIRMAN WALLIS:  Well, there isn't.  It's
           gone.
                       MR. PAPPONE:  It's gone.
                       CHAIRMAN WALLIS:  And so we can forget it.
                       DR. SCHROCK:  It says in the SAR that it
           is the current licensing basis.
                       MR. PAPPONE:  And so continuing.  It's
           Tony's turn.
                       MR. BROWNING:  And on to the plant
           specific analysis and results.  The analysis was done
           for the Duane Arnold specific ECCS configuration, and
           what was unique for BWR4 was the fact that we had LPCI
           logic, and so we have to look at that in a single
           failure evaluation space because we have a
           vulnerability there that some of the other designs
           don't have.
                       And which is the failure of the LPCI
           inject value to open, which completely starves the
           vessel for LPCI flow.  So that factors into the single
           failure evaluation that is unique to us.
                       And then we do the full break spectrum
           evaluation to confirm that the design basis accident
           is the double-ended guillotine break of the suction
           line is the worst case, and that we validate that the
           large breaks do dominate over the small breaks.
           So we look at the small break spectrum as well.
                       And for the plant specific results, the
           licensing basis PCT that we talked about and that we
           do the conformance to 50.46, we came up with a
           calculation of a bounding value of 1510.  So we have
           a great deal of margin with the regulatory limit.
                       CHAIRMAN WALLIS:  LB means licensing
           basis?
                       MR. BROWNING:  Yes, PCT, and then the
           upper-bound PCT.
                       CHAIRMAN WALLIS:  So which is lower bound
           and upper bound, and its licensing phase is an upper
           bound?
                       MR. BROWNING:  Yes. The jargon.  So the
           upper-bound PCT is only 1350, which is well below the
           1600 limit, and we also see that the upper bound is
           below the licensing basis.  So we meet both
           requirements.
                       CHAIRMAN WALLIS:  This is much like what
           you have pre-EPU is it?
                       MR. PAPPONE:  There was only about a 10
           degree change in the licensing PCT DBA.
                       MR. BROWNING:  Right.  So as you see here,
           there is an across the break spectrum of break sizes,
           from the small break, all the way up to the DBA case.
                       You can see the change due to the EPUs,
           and the little squares are the pre-EPU cases, and then
           the triangles are the EPU cases.  So you see the trend
           follows, and then when you get to the DBA case, they
           are very close.  They are within 10 degrees of each
           other.
                       And then you can see where the upper bound
           at the DBA case shows up.
                       DR. POWERS:  In fact, doesn't your EPU
           temperature, peak clad temperature, go down?
                       MR. BROWNING:  Yes, slightly.
                       DR. POWERS:  And that is because of the
           flattening out of the core --
                       MR. BROWNING:  Yes, the same phenomena
           that we saw earlier.  The peak bundle has a little
           more flow because we --
                       DR. POWERS:  I looked at that, and I said
           to myself that this has got to be red.  I have got to
           see this.
                       MR. BROWNING:  I think you will see the
           words in the staff safety action are counter-
           intuitive.
                       CHAIRMAN WALLIS:  The limit on the right
           hand, the three square feet -- what is the limit?
                       MR. BROWNING:  It is 2-1/2 square feet,
           yes.
                       CHAIRMAN WALLIS:  And which pipe is it?
                       MR. BROWNING:  That is the recirc suction
           line.  That is the largest pipe that we have on the
           vessel.  So, you can see -- well, the trend stays the
           same, and the results go up a little bit.
                       MR. ROSEN:  And the solid lines are done
           with the Appendix K models.  I just noticed that in
           the cartoon that you showed before.
                       MR. BROWNING:  Yes.
                       MR. ROSEN:  And that shows that that
           number was about 2000 degrees.
                       MR. BROWNING:  Oh, that was just a
           representative cartoon.  Those were not the plant
           specific results.  That was just to get across the
           jargon.
                       MR. PAPPONE:  That was to show which limit
           went with -- or which temperature calculation went
           with what limit, and the relative relationships.
                       MR. BROWNING:  Right.
                       MR. ROSEN:  The one on the left looks okay
           relative to the numbers on the right.
                       MR. PAPPONE:  Well, the one on the right
           is okay, too, because it is the one that is compared
           to the 2200.
                       MR. BROWNING:  But it is not the Duane
           Arnold result.
                       MR. ROSEN:  So it is not the number, your
           number?
                       MR. BROWNING:  It is not our number, no. 
           And as Dan has explained, the methodologies is where
           we try to build in the margin, especially using the
           upper bound technique that account for all the
           uncertainties, and the licensing basis PCT still has
           to apply the conservative Appendix K models for the
           regulatory conformance.
                       And then the acceptance criteria are
           conservative as well.  So for the plant specific
           results, we saw obviously no impact on safety margin
           because we had a great deal of margin to 2200.
                       And then the operating margin is obviously
           maintained by that same operating condition.
                       DR. KRESS:  What would you do if those
           numbers went all the way up to the 2200 on your
           Appendix K?
                       MR. PAPPONE:  On the licensing PCT?
                       DR. KRESS:  Yes.
                       MR. PAPPONE:  That's fine.  We have got
           plans that are licensed near 2200, and we have --
                       DR. POWERS:  And there is definitely one
           at 2183.
                       DR. KRESS:  Yes, that's what I thought.
                       MR. PAPPONE:  We do have a couple of the
           early plants that are PCT restricted after 2200.
                       DR. KRESS:  Well, this is in terms of
           margin.  If you are at 2200, you still have sufficient
           margin.
                       MR. ROSEN:  This goes to the question of
           whose margin is it.
                       MR. BROWNING:  The 2200 up to the field
           cladding failure point, that is the licensing margin
           and that is the sacred turf.  What we are talking
           about down here is the margin to 2200 and this is the
           operating latitude.  And as long as we maneuver within
           here --
                       MR. ROSEN:  I would propose the standard
           that if you would license up to the 2200, then the
           margin is the licensee and the vendors.  And the
           answer to the question is whose margin is it.  It has
           been licensed up to nearly the 2200.  So I think that
           is QED.
                       MR. BROWNING:  Right.  And now we are on
           to your favorite topic.
                       DR. POWERS:  We are about to move on to a
           topic that I know will go quickly because PRA invokes
           a little interest in this committee.  I wondered if
           the members wanted to take a 10 minute break in order
           to build up their strength to get through this.
                       DR. KRESS:  No, let's go on.
                       DR. POWERS:  Apparently they want to
           charge ahead.  Any acquisitions that I am a slave
           driver will not be tolerated.  Okay.  So, Brad is
           going to come up here, and he looks like a brave,
           strong young man.  He has taken a few slings and
           arrows in a checkered career here, huh?
                       MR. HOPKINS:  My name is Brad Hopkins, and
           I am a PRA engineer at Duane Arnold.  The purpose of
           the PRA evaluation for a power uprate was to identify
           possible vulnerabilities resulting from power updates.
                       These may come from potential sources,
           such as changes in system criteria possibly, or maybe
           from changes in human error probability.  I would like
           to note at this time that a power uprate is not a risk
           informed application.
                       But nonetheless we are interested in the
           question of risk.  That is, does power uprate
           constitute undo risk in some way or form.
                       DR. KRESS:  How do you identify
           vulnerability?
                       MR. HOPKINS:  Well, we will look at, or
           what do we use as a criteria for vulnerability, go to
           the next slide.
                       DR. KRESS:  I didn't want to say that word
           because I get criticized every time I use it.
                       DR. POWERS:  As well you should.
                       MR. HOPKINS:  We will answer that
           question.  My second bullet here is we have a
           guideline that tells us how much of an increase in
           core damage frequency or large/early release frequency
           constitutes a significant increase.
                       We used or we compared our results to the
           EPRI PRA applications guide.  We also -- and I think
           the NRC has been using Reg Guide 1.174, and we
           compared to that also to make sure that we meet that.
                       Now, the areas that we looked at are
           equipment, reliability, and we look at initiating
           event frequencies, and we looked at system success
           criteria, such as how many pumps do we need to operate
           to have adequate core coverage, or how many SRVs do we
           need to open to adequately depressurize.
                       And finally we looked at human error
           probabilities.  Now, we didn't have anything too
           interesting in the first three bullets.
                       DR. KRESS:  How do you actually look at
           the effect of power updates on equipment reliability?
                       MR. HOPKINS:  How do we look at the
           effects on equipment reliability?
                       DR. KRESS:  Yes.
                       MR. HOPKINS:  There is -- well, I guess
           there is not a hard and fast methodology that we could
           find if you take a good look at it, but we tried to
           assess what equipment might be seeing higher duty,
           such as the feed water pumps.
                       And we recognize that some equipment does
           have higher duty, and failure rates may be higher. 
           But I think with the maintenance rule in effect now,
           we have good programs for monitoring the effectiveness
           of our safety related equipment.  So we don't really
           anticipate --
                       DR. KRESS:  So in your PRA, you just used
           the same failure rates for the equipment?
                       MR. HOPKINS:  For this assessment, we
           wound up inserting the same failure rates for the
           equipment.
                       DR. KRESS:  But you did review because you
           went back to see if you thought there was any reason
           to change those?
                       MR. HOPKINS:  Yes.
                       MR. ROSEN:  You are talking just about
           reliability, and are you also talking about
           unavailability as well?
                       MR. HOPKINS:  Well, unavailability as
           well.
                       MR. ROSEN:  The slide just says
           reliability.
                       MR. HOPKINS:  We identified all basic
           events that had a raw value of a certain value, and we
           focused in on those pieces of equipment, the equipment
           that we felt was significant.
                       And we asked ourselves is there any reason
           that we should increase the failure rate of this
           equipment, and I think in all cases that we said no.
                       So I am going to focus later on in the
           presentation on focusing more on the human error
           probabilities, since those are the ones that have the
           most impact.
                       Here is a summary of our results, and I
           have a column for the base value, or our present PRA
           numbers, and a value for extended power uprate, and in
           the right-hand column --
                       CHAIRMAN WALLIS:  The PRA predictions are
           valid to three significant --
                       DR. POWERS:  At least.  That's always.
                       MR. HOPKINS:  We will take a quick look at
           the question of uncertainty on the last slide here. 
           But, no, I don't have uncertainty drawn up here.
                       But the computer calculates it out, of
           course, to --
                       CHAIRMAN WALLIS:  And you are arguing is
           the change is what you are looking at, and not
           something that you have a better handle on than the
           absolute value?
                       MR. HOPKINS:  Right.  Here it is the
           change that we are interested in.
                       DR. KRESS:  If I look at your base case
           CDF and LERF, I get an early conditional failure
           probability of .05 and thereabouts just in my head. 
           For Mark-1s, I am used to .5s and .4s for that.  Do
           you guys have that good of a containment?  It's a
           Mark-1 isn't it?
                       MR. HOPKINS:  So you are comparing the
           level one to the level two?
                       DR. KRESS:  Yes, as .05 is a pretty good
           number, and for Mark-1s, I am used to an order of a
           magnitude higher than that in PRAs.
                       MR. HOPKINS:  Yes, and so the level two is
           lower than we might expect.
                       DR. KRESS:  Yes.
                       MR. HOPKINS:  I guess I don't have a real
           good answer for that.
                       DR. KRESS:  I guess the question would be
           why is your particular plant looking so much better
           than other Mark-1s?
                       DR. POWERS:  I will make a guess.
                       DR. KRESS:  Okay.
                       DR. POWERS:  A drywall spray.
                       DR. KRESS:  They have a drywall spray.
                       DR. POWERS:  They have it and they are
           using it.
                       DR. KRESS:  That certainly could make a
           difference.
                       DR. POWERS:  Because the reason that you
           get the high failures on the Mark-1s is either a melt
           flow across the floor without water, or an overheat at
           the seals up at the top.  And the spray takes care of
           both of those.
                       DR. KRESS:  That is probably a good
           explanation, Dana.
                       DR. POWERS:  That's my guess.
                       MR. HOPKINS:  That sounds very good to me. 
           In the future, I think utilities are seeing some value
           in providing PRA results to the public, and making it
           publicly available.  I think we will see that trend in
           the future.
                       And on the human error probabilities, we
           reviewed all human error probabilities with a raw
           value of 1.06 or greater, and then we employed a map,
           a thermal hydraulic code, to determine whether the --
                       MR. ROSEN:  How did you select 1.06?  It
           seems so timid.
                       MR. HOPKINS:  Okay.  Well, 1.06 --
                       MR. ROSEN:  I would have thought that you
           would pick a number like two at least.
                       MR. HOPKINS:  Well, 1.06 corresponds to an
           increase in core damage frequency of 1 times 10 to the
           minus 6.  So any increase at this event, if an event
           would cause the core damage frequency to increase by
           1 times 10 to the minus 6 or more, then we would
           evaluate it.  And there were about 20 or
           so --
                       DR. POWERS:  I can't help but point out to
           the members that this is what we have been asking the
           staff to do for the human performance program plan for
           a long time.
                       So these particular evaluations ought to
           be very interesting to us; and the question you ask is
           are these humans doing as well as we would like them
           to do here, and here you have a basis for looking at
           this.
                       DR. KRESS:  Why do you call it a MAAP
           thermal-hydraulic code?  I wouldn't have characterized
           it that way.
                       MR. HOPKINS:  As opposed to a probablistic
           --
                       DR. KRESS:  I would have characterized it
           as a severe accident code, but a relatively poor
           thermal hydraulic code.
                       DR. POWERS:  That is not how you
           characterize it in private.
                       MR. HOPKINS:  Well, we could call it a
           transport code.  We will call it a transport code, a
           radio nuclide transport code.
                       CHAIRMAN WALLIS:  He is calling it thermal
           hydraulic to try to give it respectability.
                       MR. HOPKINS:  We recognize that it has
           limitations.  Next slide, please.
                       DR. POWERS:  But in fairness wouldn't it
           be pretty adequate for this?
                       DR. KRESS:  Yes, I think that would be
           perfectly adequate for this.  For a BWR, it is
           actually pretty good for this sort of stuff.
                       DR. POWERS:  And all it is worried about
           is heat and mass here.
                       DR. KRESS:  Yes, this should do fine for
           that.  I didn't mean to put it down.
                       DR. POWERS:  What do you mean you didn't
           mean to put it down.
                       CHAIRMAN WALLIS:  That is a good first
           approximation to thermal hydraulics.  There is no
           energy.  It is MAAP.
                       MR. HOPKINS:  I think we maintain a
           questioning attitude when we use MAAP, and we try to
           compare it with more detailed codes when we can, or
           when that is possible.
                       Now, I would like to go through the five
           most important operator actions that we found, and it
           is not my point to dwell in great detail on each of
           these.
                       But more to give you a sense of what is
           causing the most increase in the core damage
           frequency.  Most of the increase came from ATWS
           events.  So four of these operator events apply to
           various ATWS scenarios.
                       So the first one is failure to initiate
           standby liquid control.  So this is applicable to ATWS
           events where the main condenser is not available. 
           Therefore, all of the energy is going down into the
           suppression pool.
                       DR. KRESS:  The spray is not available to
           them either?  Is the suppression pool spray not
           available?
                       MR. HOPKINS:  Well, in many cases, yes, I
           think the sprays are available.
                       DR. KRESS:  Yes, there is too much heat
           going in there.
                       DR. POWERS:  There is too much heat going
           into the containment.
                       MR. HOPKINS:  Now, we look at two
           different time frames for injecting standby liquid
           control.  If we are able to inject early, then later
           on in the event we only need one RHR service water
           train, and one RHR train to remove the decay heat from
           the water.
                       If we are not able to inject early, we
           still have an opportunity to inject standby liquid
           control a little bit later.  But if we inject later,
           then we need to use both trains of RHR service water
           and RHR for adequate core cooling.
                       CHAIRMAN WALLIS:  What is the formula that
           relates to that?  Is there a magic correlation that
           says that when you go from 6 to 4 that --
                       DR. KRESS:  It is an EPRI correlation.
                       CHAIRMAN WALLIS:  All right.  So that is
           based on experience?
                       MR. HOPKINS:  It is an expert opinion is
           what it is.
                       CHAIRMAN WALLIS:  Oh, so it is based on
           data.
                       MR. HOPKINS:  We used a variety of
           methods.  That is not my area of expertise.  So I am
           not able to address it in really good detail.
                       MR. ROSEN:  But fundamentally those
           techniques take into account the fact that operating
           under stress when you have less time, you have a
           higher likelihood of failure?
                       MR. HOPKINS:  That's right.  That's right. 
           But in this case, like Steve was saying earlier, our
           operators are well practiced in injecting standby
           liquid control.  We cover it often in the training.
                       MR. ROSEN:  Would you go back to the prior
           slide for a minute.  Now, you see, that is the point
           that I made earlier, that for early initiation, with
           the time reduced from 6 to 4 minutes, but the
           deterministic analysis assumes 2 minutes.
                       MR. HOPKINS:  It seems like we are overly
           favorable on the deterministic analysis.
                       MR. ROSEN:  Well, you are overly
           pessimistic here.  But they are not the same, and I
           think I understand why.  One is a best estimate, which
           is this one; and the other one is a conservative, or
           is an analysis for deterministic purposes.
                       MR. HOPKINS:  Right.
                       MR. ROSEN:  I wish they were the same
           somehow, but I am having trouble reconciling two
           different estimates.
                       MR. HOPKINS:  I think we are looking at
           two different outcomes possibly.
                       MR. ROSEN:  But we also know in this case
           -- and Steve -- I am having trouble with your last
           name.
                       MR. KOTTENSTETTE:  Kottenstette.
                       MR. ROSEN:  Kottenstette.  He told us that
           the four minutes and the two minutes are both
           achievable times because everything the operator needs
           to do is in front of him in the control room;
           information and the mode switch and key.
                       So it is irrelevant whether it is four or
           two minutes.  The point is that the operators can take
           those actions, and it is in their training program,
           and it is in the simulator.
                       It is a critical task, the training
           program, and they can take it in either case within
           the four or two minutes.  All right.  Go on.
                       MR. HOPKINS:  All right.  This one is
           failure to inhibit ADS.  Now, for an ATWS, for most
           ATWS scenarios, we want to prevent automatic
           depressurization from occurring.
                       The reason for this is that if you
           depressurize, then the low pressure emergency core
           cooling systems initiate automatically, and they dump
           a lot of water into the vessel.
                       And we have a concern of a reactivity
           excursion when that happens.  So we really need to
           inhibit ADS.
                       CHAIRMAN WALLIS:  So your ECCS system is
           not borated?
                       MR. HOPKINS:  That's correct.
                       MR. ROSEN:  Well, it is starting to borate
           it, but very slowly.
                       MR. HOPKINS:  Correct.  So here the
           available time is reduced from 16 to 10 minutes, and
           we have a corresponding increase in the failure
           probability for that event.
                       And failure to reduce power via the
           lowering of reactor vessel water level.  Another means
           of getting our power level down is to lower the water
           level down to below the level of the feed water
           injection spargers.
                       By doing this we avoid the need to
           depressurize the vessel by keeping the suppression
           pool temperature below its heat capacity temperature
           limit.  The available time is reduced from 15 minutes
           to 12 minutes, and we have a corresponding increase in
           the failure probability.
                       DR. KRESS:  In your failure to initiate
           standby liquid control, you have 14 minutes for late
           initiation, the failure probability was about .09, and
           on this one you have got 10 minutes for the ADS, and
           it is .03 apparently.
                       How come the failure probability is lower
           for a 10 minute than it is for a 14 minute action? 
           Has it got something to do with the type of complexity
           of the action or something?
                       MR. HOPKINS:  Right.  We would be
           factoring in the complexity of the action.
                       DR. KRESS:  And that is built into the
           model somehow?
                       MR. HOPKINS:  Yes.  And here we are really
           combining two of the previous operator actions for a
           little different scenario here.  This one is an ATWS,
           where the turbine bypass valves are available.
                       Now, the turbine bypass valves can pass
           about 24 percent of reactor power.  However, the power
           is about 45 to 48 percent.  Therefore, we still have
           a significant amount of energy going down into the
           torus water level.
                       In this scenario the operator is not able
           to get the power level down, either by lowering the
           water level, or by injecting standby liquid control.
                       So we increased the failure rates for both
           of these by the same amount as what we saw previously.
                       DR. KRESS:  You uncover the core when you
           lower that water level?
                       MR. HOPKINS:  Do we uncover the core? 
           Yes, I believe the EOPs have us go down to minus --
           about minus 30 inches.
                       MR. POST:  This is Jason Post.  That is
           the collapsed level.  There is still a two phase level
           swell that is well above the top of the active fuel.
                       MR. HOPKINS:  Thank you, Jason.  The last
           one -- okay.  Now we have looked at all of the ATWS
           events.  This one is applicable -- this one is a
           failure to depressurize the reactor vessel, and it
           applies to transients, small LOCAs, and medium LOCA
           events.
                       So if your high pressure systems are not
           able to inject, it is very important for the operator
           to manually depressurize the vessel so that the low
           pressure systems can turn on.  So this is a fairly
           significant operator action in our PRA.
                       So I guess for transients and small LOCAs
           the available time is reduced from 65 minutes to 55
           minutes, and so these probabilities are pretty low
           compared to the other ones.
                       I hope that the operator recognizes that
           he is not -- that he doesn't have any water going in
           the vessel.  I think it is something that is pretty
           easy to see, and the action is easy.  He should be
           able to do it in an hour.
                       We looked at external events, and here we
           are looking at things like high winds, floods,
           tornadoes, transportation, chemical hazards, and we
           didn't see any effect of power uprate on those events.
                       However, for fire and seismic, those were
           the only external events in which we felt that there
           was a measurable effect.  Now, for here, we carried
           the operator actions through our fault trees for fire
           and seismic PRA.
                       And we found less than a one percent
           increase here, and so we didn't find anything too
           interesting in external events.  No additional unique
           hazards were identified.
                       For shutdown risk, here power uprate is
           judged to have a negligible effect on our overall
           ability to adequately manage shutdown risk.  And since
           about 1992, we have employed EPRI's Sentinel model for
           monitoring risk during refuel outages.
                       So here we look at both the defense and
           depth in meeting various safety functions, and we are
           calculating probability of boiling in the core region.
                       So we think that we have had a very good
           handle on shut down risk.  We are experienced with it
           by this time, and we think that with a power uprate
           that experience will continue.
                       DR. POWERS:  I guess I don't understand
           why when you think about it that if you have a power
           uprate of 20 percent that you must have roughly a 20
           percent increase in decay heat load.
                       And so your time to boiling must be
           roughly 20 percent shorter than it was before.  So the
           time that you have available to recover from some loss
           of cooling capacity must be about 20 percent shorter.
                       MR. HOPKINS:  Yes.
                       DR. POWERS:  So shouldn't that mean that
           you have roughly a 20 percent increase in risk being
           shut down?
                       MR. HOPKINS:  That's correct.
                       DR. POWERS:  And a window of shutdown, and
           I don't mean all of it.  But in a window of shutdown
           where boiling risk is reasonably high.
                       MR. HOPKINS:  You are correct.  The decay
           heat values are higher.  And we track very carefully
           the number of systems that we have available for
           removing decay heat, and at any given time during the
           outage we would know exactly how many systems we have
           to have operating to meet that load.
                       But in general there is only a few periods
           of the outage where the times are very short.  That
           would be the transition periods when you are cooling
           down the vessel, and when the water level in the
           vessel is at its normal level.
                       But for most of the outage the reactor
           cavity is flooded all the way to the top to allow for
           fuel moving.  And therefore the times -- we have on
           the order of hours, and sometimes 24 hours for later
           periods in the outage for responding to events,
           whether it is loss of decay heat removal, or
           inadvertent drain down events.
                       DR. KRESS:  Has your PRA been subjected to
           the industry peer review process?
                       MR. HOPKINS:  Our PRA went through the
           industry certification process four years ago.
                       MR. ROSEN:  It was one of the first, I
           think.
                       MR. HOPKINS:  We were one of the first. 
           We had a very favorable certification, and I think one
           of our real strengths is our documentation out there. 
           We have a living PRA program that was developed within
           a qualitative framework.
                       MR. ROSEN:  Now, I thought you were going
           to say in response to Dana's question is that you do
           get more decay heat as he points out, but
           that you end up not getting to shut down temperatures
           as quickly as you would now.
                       So that ultimately the way that you
           control shutdown risk is to basically wait a little
           longer before you could initiate shutdown operations.
                       MR. HOPKINS:  Right.
                       MR. MCGEE:  But it ends up being an
           operational impact where we need to keep the shutdown
           for a longer period of time before going into other
           phases of an outage.
                       DR. POWERS:  It seems to me that becomes
           a time period that bean counters will attack, and the
           pressure to shorten that.
                       MR. HOPKINS:  Well, there will be pressure
           to shorten that, but the bean counters are already in
           this case very happy, because they have been running
           at 20 percent.
                       DR. POWERS:  They are only happy quarter
           by quarter, and the next quarter, they are going to
           want another 20 percent.
                       MR. ROSEN:  But the plant staff should
           point out to them that while it is true that it is
           going to take a few more hours to get into shutdown
           operations, they should be thinking about all the
           money they have made while the plant ran at the
           extended power uprate.
                       MR. HOPKINS:  Well, that vessel is still
           pretty hot when the mechanics are unbolting the head
           bolts.  They will be doing a dance.  Now, uncertainly. 
           In our original IPE submittal, we addressed
           uncertainty with a sensitivity analysis.  That is to
           say that we don't have a formal rigid uncertainty
           analysis for our PRA.
                       For the present study, we selected
           operator actions that were sensitive in the first
           place.  That is, the first step of this study was to
           look at those parameters that are sensitive.
                       One other thing we did was we looked at
           all of the low worth operator actions, and we doubled
           their failure rates all at once.  We ran a single case
           with all of those values doubled.
                       DR. KRESS:  This South Texas guy here is
           going to ask you why you didn't increase those by a
           factor of 10.  That's what they did for their effect
           of QA on the reliability of low worth components that
           are not safety significant.
                       MR. HOPKINS:  But not for a power uprate. 
           We would be talking about an exemption request.
                       DR. KRESS:  Yes, you see, an exemption
           request.
                       DR. POWERS:  As long as you are harassing
           the South Texas guy, I will harass him some more. 
           Wait as long as you want to.  The decay heat load that
           you have to deal with is still higher by 20 percent,
           and it still shortens down all the times that you have
           to boiling by 20 percent.
                       DR. KRESS:  So that doubling didn't have
           any significant effect.
                       MR. HOPKINS:  The doubling did not.
                       CHAIRMAN WALLIS:  Are we back to the
           beginning?
                       MR. HOPKINS:  We are not, and that is the
           last slide.
                       DR. POWERS:  Are there other questions
           that people would like to ask about the PRA?  Not
           seeing any and not looking very hard for any, Ron, did
           you have any closing comments that you needed to make?
                       MR. MCGEE:  I just wanted to thank the
           committee today for allowing us this time to present,
           and by my count we have three things that we need to
           follow up on.
                       And they are Mr. Wallis' question
           concerning the stress analysis, and Mr. Powers' had a
           question and I believe we will be able to follow up
           with something on that.
                       But then also we have the post-LOCA H202
           monitoring question that I think we will be able to
           address tomorrow during the staff's presentations. 
           Other than that, are there any other questions for me
           at this time?  If not, thank you.
                       DR. POWERS:  If there are no further
           questions, I will turn the meeting back over to the
           Thermal Hydraulics Subcommittee Chairman.
                       CHAIRMAN WALLIS:  Dr. Powers has done his
           usual and hasn't kept us late.  So I am very happy to
           recess exactly on time at five o'clock, and we will
           reconvene at 8:30 tomorrow morning.  Thank you very
           much.
                       (Whereupon, the opening meeting was
           adjourned at 5:00 p.m, to convene at 8:30 a.m. on
           Wednesday, September 27, 2001.)
 
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