466th Meeting - October 1, 1999

                       UNITED STATES OF AMERICA
                           SAFEGUARDS (ACRS)
                        U.S. Nuclear Regulatory Commission
                        11545 Rockville Pike, Room T-2B3
                        White Flint Building 2
                        Rockville, Maryland
                        Friday, October 1, 1999
         The Committee met, pursuant to notice, at
     8:30 a.m.
         DANA A. POWERS, Chairman, ACRS
         GEORGE APOSTOLAKIS, Vice-Chairman, ACRS
         THOMAS S. KRESS, ACRS Member
         MARIO V. BONACA, ACRS Member
         JOHN J. BARTON, ACRS Member
         ROBERT E. UHRIG, ACRS Member
         WILLIAM J. SHACK, ACRS Member
         JOHN D. SIEBER, ACRS Member
         ROBERT L. SEALE, ACRS Member
         GRAHAM B. WALLIS, ACRS Member.                         P R O C E E D I N G S
                                                      [8:30 a.m.]
         DR. POWERS:  Let's come into order.
         This is the second day of the 466th meeting of the Advisory
     Committee on Reactor Safeguards.
         During today's meeting, the committee will consider the
     following:  proposed resolution of generic safety issue 23, reactor
     coolant pump seal failures; status of the proposed final amendment to 10
     CFR 50.55(a), codes and standards; reconciliation of ACRS comments and
     recommendations; strategy for reviewing license renewal applications;
     proposed regulatory guide on design basis information; and proposed
     resolution of generic safety issue B-55, improved reliability of target
     rock safety relief valves.
         The meeting is being conducted in accordance with the
     provisions of the Federal Advisory Committee Act.
         Dr. Richard P. Savio is the designated Federal official for
     the initial portion of the meeting.
         We have received no written comments from members of the
     public regarding today's session.
         We have received a request from the Nuclear Energy Institute
     for time to make oral statements regarding proposed final amendment to
     10 CFR 50.55(a).
         In addition, we have received a request from the
     Westinghouse Owners Group for time to make oral statements regarding the
     proposed resolution of generic safety issue 23.
         A transcript of portions of the meeting is being kept, and
     it is requested that the speakers use one of the microphones, identify
     themselves, and speak with sufficient clarity and volume so that it can
     be readily heard.
         Before we launch into the session, I will ask if any of the
     members have any opening comments they want to make.
         [No response.]
         DR. POWERS:  Seeing none, I guess we'll move to the first
     topic on the agenda, which is the proposed resolution of generic safety
     issue 23, reactor coolant pump seal failures.
         Professor Wallis, can you lead us through this issue?
         DR. WALLIS:  This issue is about 20 years old.
         It started in 1980 because there was experience with a large
     number of pump seal failures at nuclear power plants during normal
     operation, and the leak rate for a major seal failure can be several
     hundred gallons per minute, and if this occurs at one or a number of
     pumps, this constitutes a small break LOCA which has a potential to
     uncover the core in a few hours unless appropriate actions are taken.
         Now, since then, there have been improvements in several
     things.  One is in the materials of pumps seals, and one is in the
     reliability of methods for cooling them.  Very often, the seals fail
     because they are not adequately cooled.
         As a result, there have been very few experiences with major
     pump seal failures.  I think we need to get straight what that
     experience is, but I understand that, over the past 10 years, there have
     been no significant pump seal failures, and the staff has essentially
     determined that there have been so many improvements that this is no
     longer a generic safety issue, although there may be some plants that
     have perhaps not installed the materials or not made the improvements in
     their cooling system, so they might still require attention.
         So, probably on this basis, on the basis of determining --
     also on the basis of risk analysis of this issue, it is probably
     appropriate for this GSI to go away.
         Now, there are still some technical questions we may want to
     ask about, such as how many of these improvements have really been made
     and how many plants remain that require attention.
         There seems to be some question about what is the real flow
     rate we're dealing with.  You will see numbers of 182 and 300 gpm, but
     if you go over the Westinghouse analysis, you'll see something around
     480 gpm and so on.  So, we might want to ask a few technical questions.
         But essentially the case is there haven't been failures,
     there have been improvements, this is no longer a generic issue, and
     risk analysis shows that only very few plants require attention and,
     therefore, this should no longer be a GSI, and John Craig is going to
     get us started.
         John, are you ready?
         MR. CRAIG:  Good morning.  Yes.
         While Jerry Jackson and Art Buslik come up to the front of
     the room and get ready to make the bulk of the presentation, I'd just
     like to add a couple of comments to the remarks that you just made.
         This was an issue that was identified, in fact, some 20
     years ago, and as a result of some staff work, we developed a model that
     was based on work that Westinghouse had done, a considerable amount of
     work in testing for their reactor coolant pump seals.
         We built on that and the model that resulted, is referred to
     as the Rhodes model, which is conservative, and you'll hear how we're
     going to use that in some plant-specific analysis.
         The staff proposed a rule that the Commission, for reasons
     that Jerry and Art will go into, said that we should not move forward
     with because of plant-specific considerations, that it was not generic.
         There were other generic issues that were tied into this,
     this generic issue, one related to station blackout, one related to loss
     of cooling water systems for the reactor coolant pump seals, and you'll
     see, I think, why those issues -- or how we're addressing those largely
     as a result of plant-specific analysis.
         This is an activity that's been coordinated closely with
     NRR, and as we get to the end of the presentation, you'll hear about
     continuing reviews and some plant-specific -- more in-depth
     plant-specific analysis that will be conducted for some number of plants
     that we expect to be in the neighborhood of about 10.
         Following the results of those analyses, NRR will make
     determinations about plant-specific back-fits.
         So, with that as an introduction to -- and I agree with the
     characterization that Dr. Wallis made -- that was originally perceived
     as plant-specific, as we look at it more and more closely -- or as
     generic -- more closely, there are plant-specific questions and
     approaches, largely form the basis for the resolution of the issue.
         So, with that, I'll turn it over to Jerry Jackson.
         MR. JACKSON:  My name is Jerry Jackson.  I'm with Office of
     Research, and the other two presenters will be Mark Cunningham and Art
         I'd just like to quickly go through what our agenda will be
     this morning, what we intend to cover.
         We're going to have a short introduction and background. 
     Then we need to go into some discussion about how reactor coolant pump
     seals are cooled, and then the bulk of the presentation will be
     plant-specific analysis and risk considerations that we will get to
     then, followed by a conclusion.
         As was already mentioned, as John had already mentioned, the
     reactor coolant pump seal failures that we had a concern about were from
     the normal operation failures early on, when the issue was first
     prioritized, and since that time, as has been spoken about, these have
     improved, but even early into the issue, concerns began to develop about
     methods of loss of cooling that would affect the seal failure, and these
     were station blackout or component cooling water or service water, all
     of which you will see later support the cooling of the seals, and so,
     therefore, the bulk of the concern that the staff had has shifted to a
     loss of all seal cooling and how that can affect or cause seal failures.
         This led the staff into a number of research areas to
     determine how the seal would behave under a loss of cooling event,
     because the seal is designed to be cooled at all times.
         Our first -- the first concern that was had were for the
     soft materials, things like O-rings and so forth, that could fail under
     high temperature.  If the seal cooling were not available, then they
     would be subjected to the reactor coolant temperature, and they could
         Further -- and in this test, we identified -- at least in
     the Westinghouse seal -- that some of the earl O-rings that they used
     would, indeed, most probably fail.  Since then, they have developed new
     materials, improved materials, and tested them for those conditions.
         Also, this led us to concerns about the hydraulics stability
     of the seals, what will be referred to later on as a popping open, the
     seal instability -- on loss of seal cooling, if you have flashing to
     occur between the seal faces that can cause the mechanical seal faces to
     actually open wide and allow a large leak rate, and after doing this
     research, we developed a seal model that will be referred to later as
     the Rhodes seal model, and it was based on -- primarily on the
     Westinghouse seal model, with modifications that the staff thought were
     necessary to the model to make it what we believe would be more
         DR. WALLIS:  I think the Rhodes seal model is essentially a
     risk model, not a hydraulic model.  It draws on some other estimates of
     thermal hydraulics.
         MR. JACKSON:  Right.
         DR. WALLIS:  The Rhodes model that plays such an important
     role in your work essentially is a risk model.
         MR. JACKSON:  That's correct.
         DR. APOSTOLAKIS:  What does that mean?
         MR. BUSLIK:  That means basically that it's a set of events
     with their probabilities -- events, timing, and probabilities.
         DR. APOSTOLAKIS:  You will talk about it today?
         MR. BUSLIK:  Yes.
         MR. JACKSON:  We'll talk about that in a quite a bit of
         This led us to propose a generic rule that would be applied
     to all the PWRs in 1994, and this rule was sent to the Commission, and
     it basically said that the licensee should take action to reduce the
     dependencies to ensure core cooling given a seal failure or demonstrate
     that the risk from seal failures were sufficiently low that no further
     reduction would be justified, and in 1995, the Commission took up this
     rule, and in their SRM of March 31, '95, they disapproved putting this
     rule out for -- to the public, and they gave as reasons, there was
     insufficient basis for gains in safety, and they also believed this was
     not a generic problem, that it was very plant-specific, and they had
     concerns about the model that the staff used in coming up with their
     risk numbers, and then they also pointed out that the industry was
     addressing many of these concerns through their IPE program.
         I'd like to put up this morning just one diagram to
     illustrate a little bit of what we consider the important aspects of
     this, not only that the seal -- the seal, as I mentioned before, needs
     to be cooled at all times, and the seal is cooled by two different
         You have seal injection flow that comes in that's provided
     by the charging pumps, which are also cooled by component cooling water
     or service water, and this comes in in the orange here.
         It's higher pressure that the reactor coolant.  This is the
     pump shaft in this area, and reactor coolant in the schematic is here.
         So, injection flow comes in at a higher pressure flowing
     down along the shaft and blocking the flow of hot reactor coolant.
         DR. WALLIS:  What is that big pipe at the bottom?
         MR. JACKSON:  This is the schematic that represents the
     second method of cooling, which is component cooling water, to a heat
     exchanger that surrounds the shaft.  This is -- in the Westinghouse
     model is referred to as the thermal barrier.
         So, you have two methods of cooling the seals -- the
     injection flow which actually cools the seals and blocks the flow of hot
     reactor coolant from coming up the shaft, and in the event that you lose
     seal injection, then you still have component cooling water through this
     thermal barrier, and when you lose seal injection, then you have hot
     reactor coolant flowing past the thermal barrier heat exchanger and
     cooled by the thermal barrier heat exchanger.
         The flow then passes through the first-stage seal.  In the
     Westinghouse design, this seal takes up almost all of the pressure drop. 
     It goes from about 2,250 pounds per square inch of cooled water,
     charging flow, and drops down to about 50 pounds pressure on the back
     side of the seal.
         So, the number two seal is just designed as a backup.  In
     the Westinghouse seal, the number one seal provides the primary sealing
         If you lose all cooling in the hot reactor, coolant flows up
     through the seal.  There's a couple of ways that failure can occur.
         There are O-rings that are critical, like this one that's
     shown here, that can blow out due to the high temperature, and the seal
     balance -- it's balanced depending on the pressure above this floating
     stationary ring, a downward force there.
         Opening force is balanced, comes from the flow and the
     pressure drop through the seal.
         If flashing occurs when the hot reactor coolant comes up
     through the seal, when you've lost cooling, then there's a possibility
     that the pressure distribution will cause this floating seal ring to
     move up and open this face very wide, and that's what leads to the large
     leak rates.
         And the point we want to make primarily here, though, is
     that you have two methods of cooling, and even the injection flow is
     dependent on the component cooling water and the service water, as well
     as, I think, high-pressure safety injection system, too.
         With that, I think we'll go into the risk considerations,
     and I will turn it over to Mark Cunningham.
         MR. CUNNINGHAM:  As John Craig alluded to earlier, the
     original basis for the GI-23 was kind of the spontaneous failure of
     reactor coolant pump seals.
         Over time, it's evolved, and we recognize now that there's
     actually a couple of other issues that are more critical, at least from
     a risk context, about seal performance.
         In particular, they deal with the issues of station
     black-out-induced seal failures or losses of component cooling water or
     emergency service water failures.
         DR. WALLIS:  Mark, could you clarify the matter of the last
     10 years?
         My notes of our subcommittee meetings said there had been no
     seal failures in the past 10 years, but I understand it's not really no
     seal failures, there have been some, but they haven't been of any
     significance or something?  What sort of failures have occurred?
         MR. JACKSON:  We looked back through -- we looked back at
     the data, and we can find no seal failure since 1980 that would come
     anywhere near challenging the normal charging system.
         There have been no seal failures whose leak rate has been
     above 100 gallons per minute.  So the normal makeup would be able to
     take care of that.
         DR. WALLIS:  There have been failures of some sort.
         MR. JACKSON:  There have been failures.
         DR. WALLIS:  Which involve what, the O-rings or what?
         MR. JACKSON:  Not necessarily, because our concern now is
     primarily with seal cooling.  Most of the failures are failures that
     occurred just during the normal operation of the seal.
         DR. WALLIS:  Not loss of cooling water in some way?
         MR. JACKSON:  Not necessarily.  They're not necessarily
     cooling water events, loss of cooling water events.
         DR. UHRIG:  If you have that type of leak, do you consider
     operation, 100 gallons per minute?
         MR. JACKSON:  No.  The recommendations, of course, would be
     to close down.
         DR. UHRIG:  As soon as practical?
         MR. JACKSON:  They have procedures for shutting down in an
     orderly fashion.
         MR. CUNNINGHAM:  Jerry made the point earlier, these seals
     are designed to be cooled.  If you've lost the cooling to them, you
     don't want to operate the pumps, basically.
         From a risk standpoint, the spontaneous failure of reactor
     coolant pump seals, in effect, is a small LOCA, and the original concern
     was does this dramatically change our perceptions on the frequency of
     small LOCA from spontaneous failures?
         DR. UHRIG:  Remember we had a lot of problems with seals
     during startup back 20 years ago.
         MR. CUNNINGHAM:  Yes.  That's related to the genesis of this
     issue, if you will.
         DR. UHRIG:  Yeah.
         MR. CUNNINGHAM:  Again, over time, we've looked at it a
     little more differently and come up to the point now that the interest
     from a risk standpoint is a little different.
         The interest is do you have initiating events that can lead
     to seal failure and compromise the ECCS system that's used to cope with
     the small LOCA, and that's where the station blackout and the loss of
     CCW and ESW comes into play.
         In the station blackout rule and things like that, it is
     recognized that you don't have ECCS.  The difference here is, if you
     have seal failures, the rate by which you lose coolant from the system
     can go up much more than you expected.
         So, the issue then is, has the basis for the station
     blackout rule somehow been compromised by our understanding of seal
     performance, and this was recognized in the station blackout rule that
     said that we'd come back at some point once 23 started to be -- had a
     better understanding on 23 and say do we have a reason to question the
     station blackout analysis?
         So, the first thing that Art will talk about is the
     evaluation of the implications of closure of this issue on the station
     blackout rule.
         The second part, then, is related to loss of CCW and ESW. 
     Again you have a situation here that these losses of these systems can
     cause -- compromise the reactor coolant pump seals by the mechanisms
     that Jerry was talking about earlier, where you've lost the capability
     to cool the seals.
         In some plants, in some designs, CCW and ESW are also used
     to cool the charging pump bearings or a variety of things like that so
     that you can -- a loss of CCW can, again, also cause failure of ECCS.
         So, it's, in a sense, a common-cause failure that's much
     more significant than the spontaneous losses of seal cooling.
         So, the second part of Art's presentation is going to be
     discussion of the loss of CCW and ESW systems.  He's gone through some
     review of different plant designs to see what the implications of this
     might be, and what you'll see is there's a fairly broad -- the issue
     becomes very plant-specific on the issue, based on the design of the
     pump seals, on the design of the CCW systems and that sort of thing, and
     Art will go through that now.
         MR. SIEBER:  I have a question.  I have heard folks talk
     about disaster bushings.  Is there such a thing, and what is it and
     where is it?
         MR. CUNNINGHAM:  I'm sorry?
         MR. SIEBER:  Disaster bushings, which is intended to close
     the clearance in the seal package.  Have you heard about that?
         MR. JACKSON:  There's flow limitations that are built into
     the seal.  They're called -- maybe the Westinghouse person in the
     audience might address those.  The name escapes me now, but yes, I've
     heard of those.
         DR. KRESS:  Are you talking about the labyrinth seals?
         MR. JACKSON:  Labyrinth seals.  Yes, the labyrinth seals
     limit the flow somewhat through the seals.
         MR. SIEBER:  But not all plants have that, right?
         MR. JACKSON:  All plants, I think, have a labyrinth seal.
         MR. TIMMONS:  My name is Tom Timmons from Westinghouse.
         The concept of a disaster bushing is something that has been
     looked at but has not been installed on any Westinghouse plants.
         What Jerry was referring to is a labyrinth seal, which is
     tortuous path between the shaft and a clearance on the casing, which
     limits the flow up through the thermal barrier heat exchanger into the
     seals in normal operation or on loss of all seal cooling.
         MR. SIEBER:  Thank you.
         DR. WALLIS:  I have a question I'll raise at this time.
         Mark, you mentioned common-cause failures, and you spoke
     about component cooling water loss.
         Now, I read all the stuff that came to me, and nowhere could
     I find how many of these seals -- you talk about the seals or seal are
     mentioned, but there's never anything in the literature about how many
     pumps are affected, and you've got -- this flow rate is quoted, but
     presumably it's a flow rate per pump.
         Is there some common-cause failure where you lose cooling
     water, you lose it to all the pumps?
         MR. CUNNINGHAM:  That's correct, and that's built into the
     Rhodes model.
         DR. WALLIS:  Then you have to multiply the 500 gpm by four.
         MR. CUNNINGHAM:  That's correct.
         DR. WALLIS:  You will address that?
         MR. CUNNINGHAM:  We will talk about that.
         DR. WALLIS:  I didn't find that in any of the literature.
         MR. CUNNINGHAM:  But you're absolutely right, most of the
     design that Jerry was showing -- there's an individual pump.
         DR. WALLIS:  So you lose all the seals.
         MR. CUNNINGHAM:  You have the potential for losing all of
     the seals and having, instead of the leak rates we're talking about,
     three or four times that, depending on the number of pumps, that's
         I guess Art is going to start out talking a little bit about
     the Rhodes model that we foresee.
         MR. BUSLIK:  The Rhodes model is common.  You need to
     understand that to understand how the seal behaves with a lack of seal
     cooling, and so, before discussing two particular ways of losing seal
     cooling and the ability to mitigate it, namely station blackout and loss
     of component cooling water or ESW, I'll define what the Rhodes model
         Now, the Rhodes model came from Appendix A to NUREG/CR-5167,
     which was a cost-benefit analysis for this issue, and basically, the
     only paths which have any significant probabilities are, one, the
     reactor coolant pump seals half open, and this, as Jerry said, refers to
     hydraulic instability of the seals, when two-phase flow goes between the
     seal faces, and the seal faces that pop open -- there are three stages
     in a Westinghouse pump.
         The first stage has a relatively low probability of popping
     open and is actually neglected in what I'm doing.  The second stage has
     a -- is assigned a probability of 20 percent by Dave Rhodes of popping
     open, and given that the second stage pops open, the probability that
     the third stage will pop open is one.
         Now, the pop-up that occurs when the hot fluid reaches the
     seal faces, the inlet to the seal face, seal stage, once -- when there's
     sufficiently low sub-cooling of the fluid at the inlet to the seal
     faces, then flashing will occur during the seal phase.
         DR. APOSTOLAKIS:  Can you explain these three stages using
     the diagram that Jerry showed earlier?
         MR. BUSLIK:  He would probably be able to do it better.
         DR. APOSTOLAKIS:  Just to help me follow you.
         MR. BUSLIK:  Basically the fluid seems to go through it in
         DR. APOSTOLAKIS:  So, explain, please, the three stages?
         MR. JACKSON:  There are three stages in the Westinghouse
         You see where seal runner number one is, is attached to the
         DR. POWERS:  Okay.  Yeah.
         MR. JACKSON:  And there is -- the first seal stage is the
     mating part between -- this is the floating seal ring, and the first
     stage seal is the mating part between this floating seal ring and the
     runner which is attached to the shaft.
         So, that limits the flow, and in the Westinghouse seal, this
     takes the primary pressure drop, it's the primary limiting mechanism for
     flow there.
         Then, it's further reduced through the second stage seal,
     which is this runner attached to the shaft, and the mating part is to a
     floating seal part here.
         So, the mechanical face is here.  That's the second stage
         And then the third stage seal is just -- it's similar with a
     third stage runner and a part here.  That's simply a low-pressure
     atmospheric-type seal.
         So, in the Westinghouse seal, the primary method of sealing
     is all in the first stage, and in the event that it fails, then it
     shifts to the second stage, but the third stage is not really designed
     for the high pressure.  That's why it has a probably -- a given of one
     of failure if you have the other failure.
         DR. WALLIS:  Your analysis of loss of cooling water is
     occurring somewhere else.  Typically, if you broke something like the
     first number one seal bypass, then the flow would go squirting out
     there, would never go to the seal at all.
         MR. BUSLIK:  If you broke this, for example -- if something
     happens and the flow here is stopped, your seal injection is stopped. 
     If both of those happen, you would lose cooling.
         DR. WALLIS:  If the mechanism for that had been the breaking
     of, say, the number one seal bypass, your water would not have to go
     through all these paths.
         MR. BUSLIK:  The concern is that can lead to a small LOCA. 
     What it doesn't do is -- because it doesn't lead to this situation where
     you've lost the coolant and lost the ECCS.
         If you have a small break LOCA and you're able to mitigate
     it, then it's not as serious, and if it happened at a sufficiently large
     frequency that it would increase the frequency of small break LOCAs --
     but that was back to what we were considering originally.
         DR. WALLIS:  On that slide, you have the probability of
     pop-open mode is 20 percent epistemic uncertainty as a statement?
         MR. BUSLIK:  Yeah.
         DR. WALLIS:  Is that an assumption, or is there some
     evidence for that?  Where does that come from?
         MR. BUSLIK:  That's basically expert judgement.  If you look
     at the NUREG-1150 expert judgement studies that were done, one expert
     from Westinghouse gave a relatively low probability of it.  Dave Rhodes
     was another of the experts.  He gave, I think, 20 percent, and later, we
     attained that.  And then there was a third expert who gave it 25 percent
         It's state-of-knowledge uncertainty.  Westinghouse has a
     calculation which indicates that actually you don't worry about
     two-phase flow going through the seal, but the seal, because of thermal
     heating up, will pinch closed, and you won't get any flow through it, or
     very little flow, but there are large uncertainties in that calculation,
     according to various experts.
         Jerry may be able to answer that one better.
         MR. JACKSON:  As Art said, the second stage -- on failure at
     the first stage, the Westinghouse analysis and other analyses show that,
     if everything goes as planned, the second stage rotates in a manner that
     closes off or pinches off the flow, and it's held together thermally and
     doesn't allow a flow to go through there, it becomes a limiter, but
     there are things that could happen that would cause that to not occur,
     and that would be too much -- it requires a small amount of leakage
     through this second-stage seal, but that's pinched closed but just
     enough to supply a boundary -- a boiling water boundary condition on the
     back side.
         So, this is -- we feel is open to some question if it will
     really occur, and that's really the basis for the probability of 20
         DR. APOSTOLAKIS:  So, this is acting as an initiator?  This
     is the first failure, or this is in the context of something else that
     this happens?
         MR. JACKSON:  This is given losses of seal injection and
     component cooling water.
         DR. POWERS:  Okay.
         MR. JACKSON:  There's a 20-percent probability -- this
     conditional probability of 20 percent of having this failure mode of the
         DR. APOSTOLAKIS:  Now, why did you choose to go with
     epistemic here?  I mean if you have 1,000 of those initiators, you would
     expect exactly 20 percent?
         MR. BUSLIK:  No.
         DR. APOSTOLAKIS:  That's what this means.
         MR. BUSLIK:  If you 1,000 -- if it were epistemic, my
     understanding would be it would be like a coin which is two-headed or
     tail tails and you don't know which.
         DR. APOSTOLAKIS:  Right.
         MR. BUSLIK:  So, here, if you had 1,000, then nearly all of
     them would pop open or nearly none of them.
         DR. APOSTOLAKIS:  That's what I'm saying.
         MR. BUSLIK:  That's the approximation.
         DR. APOSTOLAKIS:  Now, is that a reasonable approximation? 
     I mean why don't you have aleatory uncertainty?
         MR. BUSLIK:  There is some.
         DR. APOSTOLAKIS:  Some of them will fail, some may not.  I
     mean that's too drastic, is it not?
         MR. BUSLIK:  There may be some.  For example, one of the
     mechanisms which may make it pop open is there may be scratches or wear
     on the seal faces, but I'm not sure how much of that is really required
     there, and if there were wear, practically, as far as a point estimate
     is concerned, it's a question of whether they all fail or only one of
     the four fail, and if there were wear, you would expect that the pump
     seal faces would be worn pretty much the same, I believe, for all of the
         DR. WALLIS:  What did the experts say about this
     probability?  If you have four pumps, they said that, if one fails, they
     all fail?
         MR. BUSLIK:  Dave Rhodes did.
         Now, I believe there was a -- and I think probably Jerry
     Jackson thought so.  I believe that the Westinghouse expert did not
     believe that was the case.  It really depends, to a certain extent, on
     whether -- on how important you think that -- how bad you think the wear
     has to be, and they also gave a lower probability.  I think that's part
     of it.
         MR. SIEBER:  But the wear reveals itself as a change in seal
     leak-off, right?
         MR. BUSLIK:  No, I don't think you have to have that much
     wear for it to occur.
         DR. APOSTOLAKIS:  So, you had three experts, you say, and
     they gave 20 percent, 25 percent?
         MR. BUSLIK:  You always have to worry whether experts are
     independent.  One expert gave 20, one gave 25 percent, and the other
     gave a low probability.  I don't remember what it was, but it was
     perhaps 1 percent, 2 percent.
         MR. CUNNINGHAM:  Just to be clear, the three experts were
     assembled.  That was in work being done for NUREG-1150.  So, that's been
     a number of years ago.
         DR. APOSTOLAKIS:  They went through the training and
         MR. CUNNINGHAM:  Yes, that's right, all the expert
     elicitation process that was used.
         One of the issues in 1150 was reactor coolant pump seal
         DR. APOSTOLAKIS:  This was one of the few level one issues.
         MR. CUNNINGHAM:  Yes, that's exactly right.
         DR. APOSTOLAKIS:  Probably the only one.  I don't remember
     another one.  Was there another one?
         MR. CUNNINGHAM:  I think there were a couple of others, but
     you're right, the vast majority of them were level two.
         DR. BONACA:  Do all pump designs use the same materials for
     the seals, and what are these materials, and what are the failure modes?
         MR. JACKSON:  No, they're different.  Our early concern was
     primarily just with the Westinghouse seal, and most of the work was done
     with that seal, and that's what the model has been developed for.  We
     had to use this tool as a -- what we feel is a bounding case to apply to
     the other seals.
         Now, Westinghouse accounts for like 54 of the plants when
     the other two seals involved are, I think, 10 Byron Jackson and nine
     Bingham that are involved.
         DR. WALLIS:  We can read this slide.  I'm puzzled by what I
     see.  I see this 182 gpm, and then your upper bound is 300.  I read a
     Westinghouse report where they predict 490 and an E-Tech report where
     they say 440, and there's an H.B. Robinson experience where it was 500.
         MR. BUSLIK:  Let me explain.
         When I say 182 gallons per million, that's a given for a
     certain set of failures, that the second stage and third stage fail, so
     to speak, pop open, so that basically they don't limit flow.  Whatever
     flow resistances there are are from the number one seal and the
     labyrinth seal.
         The 480 gallons per minute corresponds to essentially
     removing the whole seal package and having left only that tortuous path,
     basically, to limit things, the labyrinth seal, and then you would get
     estimates on 480 gallons per minute.
         That has a low probability of occurring.  Compared to this
     20 percent, it has, I think, according to Dave Rhodes, something like
     five times 10 to the minus three probability, and it turns out it won't
         DR. WALLIS:  Well, I guess it depends on the consequences. 
     If you have a leak of 2,000 gpm, four pumps, rather than a leak of, say,
     1,000, that makes quite a difference.
         MR. BUSLIK:  Well, it depends upon when you're trying to
         DR. WALLIS:  It makes a difference to your LOCA, that's
     right, and you're talking about four hours, but you don't get four hours
     with the 2,000.
         MR. BUSLIK:  Don't get four hours, that's true.  If 480
     gallons per minute had an appreciable probability and if there were --
     if the curve for recovery of off-site power, let's say, of station
     blackout went down very rapidly, conceivably it might make a difference,
     but it doesn't.
         DR. WALLIS:  It seems to me you have to still assess it. 
     You can't just dismiss it.  You have to look at the probability and the
         MR. BUSLIK:  It was assessed, I believe, by Dave Rhodes.
         DR. WALLIS:  And your final evaluation of probability
     appears, then?
         MR. BUSLIK:  I didn't actually include it.  I neglected it
     in what I did, but I could make a bounding estimate,
         DR. WALLIS:  The H.B. Robinson was an experience where they
     started up a pump after -- they did get like 500 gpm.
         MR. BUSLIK:  That's correct, but what happened there, my
     understanding, is that -- well, actually, Jerry can explain it.
         MR. JACKSON:  I think they had a problem with the pump that
     failed, where the first-stage seal -- there was a sale failure, and they
     shut down in the normal manner, and while they were shut down, there was
     an occurrence that somehow blocked -- they got crud into the other seal
     on the other pumps, into the seals, and they couldn't start up the pumps
     because they couldn't get the minimum flow through the first-stage seal,
     and they tried to restart the failed seal, and when they did that they
     had a mechanical failure.
         The parts of the first-stage seal were thrown into the parts
     of the second-stage seal and into the parts of the third-stage seal.
         So, mechanically -- they mechanically failed the seal by
     trying to restart it when it already had a failure that resulted in a
     high leak rate.  It was a procedural error.
         DR. WALLIS:  They got 500 gpm.  The only evidence we have --
     these are estimates, these numbers here, is that 500 gpm is possible,
     and these numbers here are based on theory.
         MR. BUSLIK:  These numbers are based on theory, that's
         Now, you may also --
         DR. WALLIS:  Who calculated -- excuse me -- the 182 gpm?
         MR. BUSLIK:  Okay.  This was initially calculated, I
     believe, by Westinghouse.
         DR. WALLIS:  What you get from Westinghouse is this 490. 
     That's what bothered me.
         MR. BUSLIK:  Westinghouse considered various paths on an
     event tree, which unfortunately I don't have with me.  If all three seal
     faces popped open, you would have 480 gallons per minute.  If the first
     stage does not pop open but the second and third stages pop open, their
     best estimate is 182 gallons per minute.  And there are various other
     things that were considered.
         DR. WALLIS:  So, you're dismissing the worst case, saying
     it's improbable.
         MR. BUSLIK:  I'm dismissing it based on the probability of
     occurrence for a loss-of-coolant event.
         Now, it could occur from a mechanical failure -- indeed, it
     has occurred, but under those circumstances, you're able to mitigate the
         It's more -- the problems we are concerned about is it
     occurring on a station blackout.  With the pump stopped or on a loss of
     component coolant water, ESW, there's a loss of seal cooling.  It's
     conceivable that the operator would not stop the pump, but it's against
     all his procedures, and with a high probability, he's going to trip the
         It is considered in PRAs.
         If you had a different model where these probabilities
     weren't as high, you might have to consider the operator error of
     failing to trip a running pump.
         Now, the other kind of failure has to do with the O-rings in
     Westinghouse pumps, and there the model assumes that they fail at two
     hours after a loss of seal cooling.  Essentially, the temperature makes
     them softer and they extrude out through a gap.
         How fast they'll extrude out depends on the temperature, it
     depends on the size of the gap, it depends on the pressure, and Dave
     Rhodes did not give any credit -- the operator, in an accident such as
     this, will de-pressurize the reactor coolant system.
         He didn't give any credit for a delay in O-ring failure or
     for that, and I mean he explicitly mentions that, it's not an oversight,
     and he must have a reason for it, but I don't know what that reason is. 
     It isn't documented.  It has to do with what experimental evidence he
     had.  There was experimental evidence for O-ring failure.  They did do
     tests on the O-rings.
         MR. SIEBER:  I presume there's only O-ring of importance on
     that drawing that you had?
         MR. JACKSON:  There's one in each stage, at least certainly
     in the first and second stage, of primary importance, the one that seals
     the moveable -- the ring that moves up and down, in the up-and-down
         MR. BUSLIK:  He explicitly mentions that he's talking about
     failure of O-rings in the first and second stages.
         Now, what's the time to core uncovery?  By the way, the
     uncertainty -- I did do a sensitivity study where I assumed that you got
     a 95-percent upward bound flow rate of 300 gallons per minute for this.
         E-Tech said that there was a 50-percent uncertainty from
     two-phase flow correlation, which was higher than what other people had
     said in the literature, but it was from their experience.  They expanded
     the uncertainty.
         DR. WALLIS:  So, this was come up with by your consultants,
         MR. BUSLIK:  Yes, that's correct.
         DR. WALLIS:  Did you multiply by two?
         MR. BUSLIK:  No.  Fifty percent, I interpreted, from 180
     would be 270, but there are other factors, friction factors and things,
     so I just took a number of 300.
         DR. APOSTOLAKIS:  Do you have anything against diagrams?  It
     would have been much easier to follow this is you showed an event tree
     to begin with, and second, the time axis and put all these things there. 
     It's really hard to follow.
         MR. BUSLIK:  That may be true.  There may be something
     against diagrams, because I find them hard to draw.
         DR. WALLIS:  You run 300 gpm per pump.  So, you have a
     four-pump plant, or what do you have?
         MR. BUSLIK:  There are three- and four-loop plants in
     Westinghouse plants.
         DR. WALLIS:  These are plant-specific, these scenarios, now.
         MR. BUSLIK:  Yes, but it turns out that the inventory in the
     four-loop plant is bigger than the inventory in the three-loop plant so
     that the times to core uncovery are about the same for a given leak per
         DR. WALLIS:  You're talking about a loss of coolant accident
     now with four pumps all leaking 300 gpm.
         MR. BUSLIK:  Yes, for one of the failure modes, that's
     right, and actually, Westinghouse verified that they're basically the
         I basically took -- it's a small conservatism that you'll
     get core uncovery in four hours whether you have the seals pop open and
     then the O-ring failure or the seals don't pop open and the O-ring
     failure, things like that.
         DR. WALLIS:  Did you run a LOCA scenario or something to
     figure this out?
         MR. BUSLIK:  They were run for me beforehand.  The results
     are given in one place in a Westinghouse document.
         Now, for non-Westinghouse pumps, I basically -- and this was
     in agreement here -- I basically used the same model as for a -- as far
     as pop-open and the same probability of pop-open as for a Westinghouse
     pump, but we assumed that the -- basically, the elastomers are better,
     and we assume they will not fail.
         They're, I think, of a different material.  They tend to
     harden instead of soften with temperature.  Indeed, the new Westinghouse
     O-rings, which we assume don't fail, also have that property.
         DR. WALLIS:  Now, this is another question we had.  You've
     got Westinghouse pumps with models.  You've got these other pumps where
     you're making an estimate that they're probably better than
     Westinghouse, so we'll use the Westinghouse number, but we haven't made
     an analysis of them.
         MR. BUSLIK:  There was some analysis for a particular big --
     it's difficult to really do a good analysis, because I don't think we
     have, for example, the dimensions and the design information for those
         DR. WALLIS:  If it's necessary to do it, then it has to be
         MR. CUNNINGHAM:  Maybe we can come back to that in a little
     bit, but there's a key point here that you're hitting on, which is the
     Rhodes model was developed based on a lot of analysis by Westinghouse
     and by the staff.  There is no equivalent model for the Bingham pumps or
     the Byron Jackson pumps.
         So, we've had to apply it, as Art has said, to these other
     plants, and it's to be, in one sense, some sort of bound on it, and that
     drives us in a particular direction in terms of what we need to do as
         DR. WALLIS:  What did the plants submit?  I mean this must
     have been an issue.  Did they just say we don't have a model and you're
     going to get your own or make your own assumptions?
         MR. CUNNINGHAM:  In the IPEs, they had their model, which
     was -- they have a model which is, in effect, very little leakage under
     these conditions.
         MR. BUSLIK:  I don't think that the -- for example,
     Combustion Engineering using a multiple Greek letter model where they
     essentially assume that the various stages in this pump are like having,
     say, three different diesel generators, and you may have some
     common-mode failure between them.  To me, it's not very sound, and --
         DR. APOSTOLAKIS:  I have another question.
         MR. BUSLIK:  Yeah.
         DR. APOSTOLAKIS:  To what extent did you rely on other
     people's work when you did this?
         MR. BUSLIK:  As far as --
         MR. CUNNINGHAM:  I'm sorry, George.  In what specific
         DR. APOSTOLAKIS:  Well, it seems that all these rates,
     gpm's, came from Westinghouse.
         MR. BUSLIK:  Oh.  Yes, except that they were verified for
     certain cases.  It happens that the 182 gallons per minute wasn't
     verified, but E-Tech, in a document that -- I think it's NUREG/CR-4294
     -- did do -- go through the calculations, and basically, the model --
     it's included in the uncertainties.
         It used a steady-state two-phase flow model where you had
     equilibrium between the phases and there was no slip, and it was all
     mixed up, homogeneous.
         DR. APOSTOLAKIS:  Now, you also relied on some probabilities
     that were derived by Rhodes?
         MR. BUSLIK:  That's right.
         MR. CUNNINGHAM:  David Rhodes is an employee of AECL who was
     under contract to NRC to do this work, in effect.
         MR. BUSLIK:  Right.  And it's not very different from the
     central estimate or the mean estimate from the three experts.  Of
     course, there's dependence there, because David Rhodes was an expert.
         DR. WALLIS:  The E-Tech model gave the 400 gpm.
         MR. BUSLIK:  Yes.
         DR. WALLIS:  So, what did that confirm?
         MR. BUSLIK:  Well, that did confirm -- actually, it -- one
     of the primary limiting factors there is the labyrinth friction factor,
     I guess.  I'm not sure what else is in the model.
         DR. WALLIS:  I guess, with all these different gpm's,
     though, I'd be sort of reassured if you could let us know that it
     doesn't matter if the flow rate is up to 500, because the risk analysis
     shows that it's okay anyway.  Then we would forget about all these
     uncertainties in the flow rate.
         MR. BUSLIK:  For the loss of component cooling water in ESW,
     it won't much matter, because even with the other flow rates, you don't
     have much time for recovery, okay?  So, you won't be able to recover.
         I think that's true.  I think, with 480 gallons per minute
     -- I don't remember how long it will take for core uncovery, but --
         DR. WALLIS:  But if you get into some different mode of
     failure which is more disastrous when you have these higher numbers,
     then I think it behooves you to show that there's not a problem.
         MR. CUNNINGHAM:  The basic situation, as Art has kind of
     suggested before, is yes, there were other failure mechanisms of the
     pump seals that could have much greater leak rates.
         They have a higher leak rate, but they have a substantially
     lower probability, in our estimate, by our estimates, of occurrence, and
     it's the trade-off between the reduction in time to core uncovery versus
     probability that's built into Art's arguments, and he's basically saying
     the ones that are the most important are the two, the pop-open mode and
     the O-ring failure.
         The other mechanisms, from a probability of leak rate, if
     you will, or probability of time to core uncovery, are not very
         DR. WALLIS:  So, if we get, then, to your bottom line, which
     I guess we have to get to before too long, it wouldn't change the CBF
         MR. BUSLIK:  No, it wouldn't.  It couldn't, because it
     changes the time you have for recovery, and it's not going to make --
         DR. SHACK:  Now, is that true for the 182 as well as the --
     the 300 is sort of bounded by the 500.  At least I have a bound there. 
     The 182 seems to me the number that kind of hangs out there.
         So, if that was 300 instead of 182, would it make a big
         MR. BUSLIK:  No.  These start at -- let me think.  If you
     had 300 gallons per minute, it will start in about 10 or 15 minutes into
     the accident, and it will take -- I assume that core uncovery will occur
     in two-and-a-half hours.  That's conservative.
         If you just had 300 gallons per minute constant, it would
     take about three hours to core uncovery from the start of the accident,
     and I've done a calculation like that, which you'll see.
         You see the result from station blackout.
         Does that answer your question?  I'm not sure.
         DR. SHACK:  I'm not sure.  I'm having a hard time, as George
     said, associating initiating events with each of these leak rates, you
         MR. BUSLIK:  It's because I started with what happens if you
     lose seal cooling to a pump, and I didn't start with the accident
         MR. CUNNINGHAM:  In all of these cases that we've talked
     about, the initiating events are loss of cooling to the seals.
         DR. SHACK:  Yeah, but there's the seal injection flow and
     then the component coolant flow.
         MR. CUNNINGHAM:  It's the loss of both of those.
         DR. SHACK:  I need both of those for all of these scenarios.
         MR. CUNNINGHAM:  Yes, that's right.  And then the different
     leak rates are associated with different combinations, if you will, of
     the three stages of seal failure.
         DR. SHACK:  Okay.  But I do need those two things for all of
     the scenarios.
         MR. CUNNINGHAM:  Yes.
         DR. APOSTOLAKIS:  What kind of sequence are we talking
     about, to have an idea of what space we're in?
         MR. CUNNINGHAM:  We'll come back to that.
         DR. APOSTOLAKIS:  In the imaginary time axis, what are the
     events that are competing here?  I'm losing coolant, and what are you
     trying to do to prevent --
         MR. BUSLIK:  You've lost cooling and possibly the ability to
     mitigate it, say, from a station blackout.
         DR. APOSTOLAKIS:  Okay.
         MR. BUSLIK:  The competing event would be the -- in the case
     of a station blackout -- would be to recover electric power.
         DR. APOSTOLAKIS:  So, the key element here is we have a
     competition in time, like we do in fires, where the bad thing is the
     loss of coolant --
         MR. BUSLIK:  Right.
         DR. APOSTOLAKIS:  -- and something terrible will happen
     after a certain time, and the good thing is that you are trying to
     recover power, and we have those curves that have been used in all the
     PRAs --
         MR. CUNNINGHAM:  Yes.
         DR. APOSTOLAKIS:  -- the probability of recovery.
         MR. CUNNINGHAM:  Yes.
         DR. APOSTOLAKIS:  Right?
         MR. CUNNINGHAM:  Right.
         DR. APOSTOLAKIS:  So, the question is now who wins the
         MR. BUSLIK:  That's exactly right.
         DR. APOSTOLAKIS:  And what is the equation you use for that? 
     What is the probability that I will recover power before I will --
         MR. CUNNINGHAM:  You're getting into the station blackout
         DR. APOSTOLAKIS:  I don't see any equations anywhere for it. 
     Do you have difficulty with software there, as well?
         MR. BUSLIK:  No, I can write equations.
         DR. APOSTOLAKIS:  Okay.  Those diagrams, though, really
     would have helped a lot.
         DR. WALLIS:  At least if there was some sort of summary that
     says, if you assume 182, this is the uncovery time and here's the
         MR. CUNNINGHAM:  What we've done is basically translated it
     to those conclusions in the context of the frequency of core damage.
         DR. WALLIS:  I think we have to move on.
         MR. CUNNINGHAM:  Yes.
         DR. WALLIS:  I think these are important points we've been
     raising, but I think, from now on, we should be able to get to the
     bottom line.
         DR. APOSTOLAKIS:  There is a report, Art, that has all these
         MR. BUSLIK:  There is something.  It's in draft form, and it
     will be out shortly.
         DR. APOSTOLAKIS:  But it will have diagrams and equations.
         MR. BUSLIK:  I will put diagrams and equations in it.
         MR. CUNNINGHAM:  What we'd like to do is go now to -- as I
     said earlier, we've got -- all of this issue of pump seal performance
     under these conditions has implications in station blackout accidents
     and loss of component cooling service water accidents.
         In the interest of time, we're going to jump through some of
     the slides.
         DR. APOSTOLAKIS:  In terms of presentation, I would have
     started that way, from the end and worked backwards.
         MR. CUNNINGHAM:  Okay.
         DR. APOSTOLAKIS:  Because it's really confusing, I think,
     for someone who sees it for the first time and you get into the details
     of the 182 gpm versus the other, and we're losing the big picture here.
         MR. CUNNINGHAM:  Yes.  We're back to the big picture here,
     or one of the big pictures, if you will, which is the implications to
     the implementation of the station blackout rule.
         DR. APOSTOLAKIS:  Okay.
         MR. BUSLIK:  So, the station blackout rule required that
     certain -- that each plant must be able to cope for a specified time
     with a station blackout.
         The time for each plant depended on, essentially,
     characteristics of the plant, which determined an estimate of how likely
     it would be for a station blackout to occur, and the intent of the
     station blackout rule was an industry average core damage frequency from
     station blackout of about 1e minus 5 per year, on an industry average
         Plants were either four-hour or eight-hour plants.  That
     means that plants were required to cope with a station black out of four
     hours, some plants, and others, eight hours.
         DR. APOSTOLAKIS:  So, you have to recover power, in other
     words, within four hours.
         MR. BUSLIK:  They have to show, under certain assumptions,
     that they're able to cope, some plants for four hours, other plants for
     eight hours.
         DR. APOSTOLAKIS:  What I'm saying is that is equivalent to
     say that you better recover power within four hours, because beyond
     that, you can't cope.
         MR. BUSLIK:  That's right.  There's a residual risk if they
     don't for a four-hour plant, and that's considered acceptable.
         DR. WALLIS:  So, if the core uncovers in two-and-a-half
     hours, you've lost these plants.  You haven't been able to do anything
     to mitigate this loss of coolant in that time?  Or have you?
         MR. BUSLIK:  There's a certain probability that the -- first
     of all, the two-and-a-half hours corresponds to a sensitivity study. 
     The analyses for coping were supposed to be best estimate analyses. 
     This is actually --
         DR. APOSTOLAKIS:  Why was that, Art?  I mean you are not the
     kind of guy who would say something like that.  Were you asked to do
     this best estimate?
         MR. BUSLIK:  This has to do with the rule.
         MR. CUNNINGHAM:  Coping using best estimate not traditional
     conservative regulatory analysis.
         DR. WALLIS:  I'm sort of confused, because we get this
     four-hour coping and then we're told the core uncovers in, you know,
     two-and-a-half, four, six hours, depending on which flow rates you
     assume, and I'm sort of saying does this matter.
         If it uncovers in two hours, does this mean this is a real
     loss of something, because you can't cope with things in that period of
         MR. CUNNINGHAM:  First it comes back to what's the
     probability of it occurring in two hours.
         DR. WALLIS:  If the flow rate is over something, then you're
     in real trouble when you weren't before.
         MR. BUSLIK:  No, because if electric power is not recovered
     for a four-hour plant, it's not a question that, if you lose off-site
     power, it's never recovered within four hours and it's always recovered
     after four hours.
         DR. WALLIS:  If you've lost the core before you get the
     power back, then you're in real trouble.
         MR. BUSLIK:  That's considered the frequency.
         DR. WALLIS:  You may not have time to do it.
         MR. CUNNINGHAM:  That's where you come into the probability
     arguments in the station blackout rule.
         DR. WALLIS:  If your flow rate can be big enough to get you
     in real trouble, then I think you worry about that, whatever you've done
     for probability, but if you can assure us that the flow rate is low
     enough that you'll never really get in trouble --
         MR. CUNNINGHAM:  That's one way to cope with the --
         DR. WALLIS:  -- then we'd be very reassured.  But these
     assessments are all very dependent on how much the flow rate is.
         DR. APOSTOLAKIS:  But they also have, Graham, curves -- and
     I guess the epistemic uncertainties there are not large, because there
     is a large database -- that give us the probability of recovering power,
     off-site power, as a function of time.
         MR. CUNNINGHAM:  That's correct.
         DR. APOSTOLAKIS:  So, it's not that for four hours the
     probability of loss of power is one.
         MR. CUNNINGHAM:  Correct.
         DR. APOSTOLAKIS:  In fact, the mean value is fairly low, as
     I remember --
         MR. CUNNINGHAM:  Yes.
         DR. APOSTOLAKIS:  -- on a nationwide average.  A couple of
         MR. CUNNINGHAM:  I think that's right.  There's a long tail
     due to certain types of weather conditions and things.
         DR. APOSTOLAKIS:  But it is an essential part of the
         MR. CUNNINGHAM:  But another way to think about it is that
     you want to maintain the probability of having core uncovery in two
     hours at a sufficiently low level that it's judged to be acceptable. 
     So, it's a probability of that core uncovery time.
         MR. BUSLIK:  Frequency.
         MR. CUNNINGHAM:  Frequency.  I'm sorry.
         DR. WALLIS:  We keep asking questions.  We have to get on. 
     I notice you've got a lot of detail on these slides, and if someone can
     somehow distill from this what we really have to worry about, then we'll
     finish on time.
         MR. BUSLIK:  On 14, you will see a table which indicates how
     the core damage frequency varied for the eight-hour plants, the plants
     which were required to cope for eight hours, and you see basically what
     their core damage frequencies were, and for the best estimate case or
     slightly conservative best estimate case of four hours for core uncovery
     and for two-and-a-half hours.
         MR. SIEBER:  Before you leave that, that's just for station
     blackout, but there's other initiators besides station blackout?
         MR. BUSLIK:  That's right.  That was the second part.
         MR. SIEBER:  So, you could almost say that this is like two
     orders of magnitude higher considering all initiating events, which
     would make it a dominant contributor to the total risk for the plant?
         MR. BUSLIK:  I don't understand the point.
         MR. SIEBER:  Well, you know, for example, three weeks ago,
     there was a loss of an emergency bus to the plant that lost safety
     injection flow and component cooling water flow to two pump seals, which
     did not fail.
         MR. BUSLIK:  This was Beaver Valley?
         MR. JACKSON:  Beaver Valley, yes.
         MR. SIEBER:  The probability of that happening is much
     greater than the station blackout, and so, the number you have as
     FSWLSP, which is your frequency of severe weather, which is a factor of
     probability in this whole thing, is two orders of magnitude.
         MR. BUSLIK:  But the point is, in the other cases, you may
     have had degraded ESSC, but you did have ESSC.  Even if you had a LOCA,
     you would have been able to mitigate it, and also, there's a question of
     recovery of those incidents.  It was recovered within three minutes.
         MR. SIEBER:  Yeah.  Two minutes and 45.  But if you look at
     the IPE for that plant, it is a high contributor to CDF.
         MR. BUSLIK:  Yes.
         MR. SIEBER:  Okay.
         MR. BUSLIK:  That I treated, as a matter of fact, for that
     plant, although I'm not going to give those specific results, but I did
     look at that for Beaver Valley unit one.  This event occurred at unit
     two, but I think the bus configuration is pretty similar.  But I treated
     that as a loss of component cooling water, ESW.  It's not station
     blackout, at any rate.
         So, plants which are required to cope with a four-hour
     station blackout can still cope with a four-hour station blackout,
     because core uncovery times are longer, using best estimate values.
         DR. WALLIS:  But if you use the 500 gpm, what does that do
     to you?
         MR. BUSLIK:  It's not a best estimate value.  You would
     uncover in less than four hours.
         DR. APOSTOLAKIS:  Why not do an uncertainty calculation? 
     The rule doesn't say that, right?  The rule is from conservative to best
         MR. BUSLIK:  I did a sensitivity calculation, and you'll see
     that it doesn't matter that much, if you look at the table for the
     eight-hour plant.
         MR. CUNNINGHAM:  The question that we had put before us,
     that we had to answer in a fairly short amount of time, was have we
     compromised the ground rules, if you will, the station blackout rule, by
     this set of assumptions, and we didn't try to go back and, if you will,
     do something more elaborate.
         We said have we done it, and I think the answer is this does
     not compromise our situation on the blackout rule.  That's the kind of
     bottom line.
         MR. BUSLIK:  That's the basic argument, and the risk is --
     yeah, that's right.  You still have an industry average one times 10 to
     the minus five per year.
         The other kinds of ways of losing seal cooling is loss of
     component cooling water and essential service water, and seal cooling is
     supplied, as you've seen, by seal injection and component cooling water
     to a thermal barrier in many plants, basically the B&W plants and the
     Westinghouse plants and Palo Verde.
         The other Combustion Engineering plants don't have seal
         The classic sequence in one in which, say, component cooling
     water is lost, and therefore, then, you may have seal injection, but the
     HPI and charging pumps are dependent on component cooling water for seal
     and pump motor cooling.
         You lost the charging pumps and you lose the -- and you've
     lost the component cooling water, so you get a seal LOCA with some
     probability, and also, you can't mitigate it, because the HPI pumps are
         DR. WALLIS:  So, this is a bad story but it's very unlikely?
         MR. BUSLIK:  You have to figure out how unlikely it is.
         DR. WALLIS:  Okay.
         MR. BUSLIK:  And then there are pumps without reactor
     coolant pump seal injection, and here you lose component cooling water
     and you get a seal LOCA, and if the HPI depends on component cooling
     water, you can't mitigate it.
         But there are lots and lots of different variants between
         DR. WALLIS:  Component cooling water -- is this one of those
     safety significant systems?
         MR. BUSLIK:  Yes.  It's safety-related.  Don't ask me what
     safety-related and important to safety mean, because I don't remember.
         MR. CUNNINGHAM:  Yes, it's important.
         MR. BUSLIK:  So, the charging pumps may not require cooling. 
     They can be air-cooled, or they could be cooled by ESW instead of
     component cooling water.  Then loss of component cooling water isn't of
     concern, but ESW, which is the heat sink for component cooling water --
     if you lose that, you may have a problem.
         You may have a back-up cooling system for the charging
     pumps.  Some plants have installed that -- Turkey Point, units three and
     four, H.B. Robinson, Three Mile Island unit one.
         You can mitigate a small break LOCA without HPI by cooling
     down and de-pressurizing using the steam generators and using the
     low-pressure injection systems.
         Now, it turns out the low-pressure injection system -- I
     believe the bearings there don't require cooling, it's only the seals,
     but if you're pumping cold water, you don't need to have cooling to the
     seals.  So, what they do is have a way of refilling the refueling water
     storage tank and continuing to pump cool water.
         There are other types of designs.  The Westinghouse reactor
     coolant pumps, if they use the new O-rings instead of the old, you
     decrease the probability.  It depends -- the importance will depend on
     the frequency for losses of component cooling water, losses of ESW,
     which depend on the design of those systems.
         We looked quantitatively at 14 units, and nine of these
     units, the core damage frequency was below 1e minus 4.  The highest one
     was 1.4e minus 3 per year.  This is a preliminary screening estimate. 
     We have to look at it further.
         It wasn't a random sample of units.  I had a IPE database
     which gives me frequencies of losses of component cooling water, and I
     tried to pick ones which were high.
         DR. APOSTOLAKIS:  This is what confuses me, Art.
         MR. BUSLIK:  Yes.
         DR. APOSTOLAKIS:  The rule, as you said earlier, speaks in
     terms of averages.
         MR. BUSLIK:  The intent of it.  That was for station
         MR. CUNNINGHAM:  Station blackout.
         DR. APOSTOLAKIS:  Oh, this rule is different?
         MR. BUSLIK:  This is a generic issue.
         DR. APOSTOLAKIS:  So, we're not going by the average here?
         MR. CUNNINGHAM:  No, we're not.  Here the issue is we have a
     generic issue 23 on reactor coolant pump seals.  Is it generic?  Is
     there a generic solution to this problem?  And the answer -- what Art
     has been doing is saying is there anything generic about this, and we
     come back to it and we see great dependencies on plant-specific
         So, you can have a very low core damage frequency coming
     from these, you can have a higher core damage frequency coming on,
     depending on a series of plant-specific issues, and the bottom line, to
     get to it, is we need to follow up on them plant-specifically, not
         MR. BUSLIK:  Obviously, you could have a generic fix, but it
     wouldn't satisfy the cost-benefit criteria.
         MR. CUNNINGHAM:  That was in our proposed rule.
         DR. WALLIS:  You're not saying it's not a safety issue.  It
     still seems to remain a safety issue.  You're really concentrating on
     the word "generic."
         MR. CUNNINGHAM:  Yes.
         MR. BUSLIK:  That's exactly right.  For some plants, it may
     matter; we have to look more closely.
         DR. APOSTOLAKIS:  This 1.4(10) to the minus 3, even if you
     sharpen your pencil, how low can it go?
         MR. BUSLIK:  Oh, it can go low.
         DR. APOSTOLAKIS:  Lower than 10 to the minus 5?
         MR. BUSLIK:  I had a 20-percent probability of pop-open.  If
     that probability of pop-open became 1 times 10 to the minus 3, it could
     go lower.
         MR. CUNNINGHAM:  The key piece here is that you're applying
     the Westinghouse model to non-Westinghouse pumps.  That's a key piece,
     and that's why there's a big range in these things, and that's why we're
     not willing to say that that's a real number, if you will.
         DR. APOSTOLAKIS:  I'm a little bit confused how the
     calculation was done.  The 20 percent was epistemic.  The 10 to the
     minus 3 is aleatory.  So, how would that change change that?
         MR. BUSLIK:  I mean if I try to take in the uncertainty
     range, it becomes a big number.  The upper range becomes big.
         DR. APOSTOLAKIS:  But in terms of point estimates that you
     are doing now, I do not see how the .2 enters into the calculation.
         MR. BUSLIK:  Because I use mean values when I do -- I
     average over the epistemic uncertainty.  The 20 percent is the mean
     value of a distribution.
         DR. APOSTOLAKIS:  Of an epistemic distribution.  That issue
     arose many, many years ago, and the NRC had a workshop.
         How do you combine the epistemic uncertainties in level two
     with the aleatory uncertainties in level one, because in level two, the
     event trees go yes, no, yes, no, yes, no.  In level one, there is a
     fraction of time you go this way, a fraction you go that way.  We have
     the same problem here.
         Those things will be in the report you are about to publish?
         MR. BUSLIK:  No.  If I did something like that, I may come
     up with essentially a number for the 1.4 times 10 to the minus 3 plant
     -- first of all, it has to be looked at.  Maybe there are problems with
     the way the initiating event was treated.
         But if I did nothing but do an epistemic uncertainty and I
     said it's either zero or one, or essentially that, it could go up to 70
     minus -- I'd have two estimates, 70 minus 3 per year and zero,
     essentially, not zero but a small number, and what that would say is
     that you have to reduce the uncertainties, which we know already
     actually, before we could go ahead.
         MR. CUNNINGHAM:  A key piece of this is we're making the
     assumption -- to get to the 1.4e minus 3 -- that a Westinghouse seal
     model or a variation on the Westinghouse seal model, a Rhodes seal
     model, applies to a non-Westinghouse design pump.
         One of the things we're trying to do is get better
     information on whether -- what is an appropriate model for a
     non-Westinghouse pump.
         We've had some conversations with EPRI and with some others
     to try and see if we can come up with a better model for those pumps to
     reduce that uncertainty, if you will.
         DR. SHACK:  But you have the same problem with the
     Westinghouse plants, where if you really did it as a zero, one, rather
     than taking the mean of .2, you would end up throwing everybody, I would
     assume, at the one.
         MR. BUSLIK:  Yes, that's true.  It turns out that
     Westinghouse pumps, because they use a model -- many IPEs use the model
     more similar to our model.  If they came up with a high value, they did
     something about it.
         DR. SHACK:  But they came up with that value by plugging in
         MR. BUSLIK:  That's right.
         DR. SHACK:  And the question is whether that's a legitimate
         DR. WALLIS:  Maybe the number you plug in is itself
         Can we sum up here?  I think the key thing is whether you
     really know enough to close this issue, whether your strategy is
     something the committee is going to support.
         MR. CUNNINGHAM:  Maybe we can go to 22.  In the context of
     the emergency service water and CCW issues, we've got a couple of pieces
     of future work, which are basically we want to go back and look at these
     in more detail to try and come up with something better than what we
     think is somewhat of a bounding estimate on core damage frequency
     associated with these, and they are very plant-specific issues.  That's
     what our concern is.  So, we're going to do the future work.
         I guess, Jerry, there's one more slide, the summary slide,
     the conclusion slide, related to 23 itself.
         MR. JACKSON:  I guess our conclusion, then, that we're
     trying to make -- I'll give you the basis for our conclusion, was we'll
     think back to the Commission's SRM.  We proposed a generic solution to
     the problem, and the Commission ruled against that generic resolution,
     and they pointed out that they believed there was insufficient basis for
     gains in safety and that it wasn't a generic problem, and I think if you
     look through this analysis by Art, etcetera, it points out that it is
     truly a plant-specific issue, and the Commission also had concerns with
     our seal evaluation model, and they pointed out, as well, that the
     industry was addressing many of our concerns by changes in the IPE
     program, and if we look at changes that have actually been made in the
     plants, the station blackout rule has reduced the likelihood of seal
     LOCAs by the addition of alternate power sources, for one thing, and the
     IPEs have resulted in specific changes to this particular problem in the
     plants, like reducing the dependencies on cooling in certain instances.
         The maintenance rule itself has reduced the likelihood of a
     component cooling water, service water system failure, which affects
     this seal failure probability, and then, as we talked about earlier, the
     normal operation failures have improved.
         There have been none of the large leak rates, since even
     1980 was the last time we had one that anywhere near approached the
     makeup capability, and to sum up our plant-specific analysis that Art
     has done, I think we've shown that the station blackout -- when you look
     at the station blackout plants, applying our conservative model, that we
     still meet -- the intent of the station blackout rule is still met, and
     for the loss of component cooling water and service water, when you
     apply this model to the plants that we've looked at -- and Art looked at
     39 of the 74 and only found five plants that were screened out with the
     higher values.
         So, we believe that that shows that the majority of the
     plants have a low risk associated with this seal failure.
         So, to summarize, the staff concludes that closure of
     generic issue 23 is appropriate and would like to request your agreement
     on closing this issue.
         DR. WALLIS:  Do we have anymore questions from the
         [No response.]
         DR. WALLIS:  We have a presentation from industry?
         Thank you very much.
         MR. LOUNSBURY:  Good morning.
         My name is Dave Lounsbury.  I work for PSE&G Nuclear, Salem
     Station, and I'm here to discuss the WOG position.
         What I'd like to do in this package that we sent out, slide
     number two, three, and four is just there just to give you some sort of
     indication what the WOG involvement has been.
         I'm not intending to discuss each one of these items.  It's
     just there for a visual, so you can understand how much work has gone
         Here again this just all the work that we've done within the
     Westinghouse Owners Group and Westinghouse to resolve this.
         Part of our conclusions is the WOG supports the closure of
     GSI-23.  There's conservative analysis that has determined approximately
     21 gpm per pump, RCP leak rates at full pressure and temperature.
         DR. WALLIS:  So, you're saying 21 gpm, and you heard numbers
     of several hundred earlier on.
         MR. LOUNSBURY:  We'll get to that.
         DR. WALLIS:  Okay.
         MR. LOUNSBURY:  Emergency procedures are in place to cool
     down and de-pressurize the RCS, further reducing the expected leak rate. 
     I'd like to stop right here and discuss that.
         Part of the discussion that I heard was the 2.5 hours for
     uncovery of the core and the 300 gpm.  Westinghouse emergency operating
     procedures -- that's ECA-00 -- for station blackout events -- I'm only
     telling you this so you'll have an understanding of what the operators
     are actually going to do in these events -- they have directions to cool
     down and de-pressurize the plant using the steam generators, and that
     de-pressurization occurs at maximum rate.
         MR. BARTON:  And that depends on whether they recognize the
     alarm and respond in a timely manner, which they didn't do at Beaver
     Valley.  Luckily they got flow back in two minutes and 45 seconds, but
     they didn't do what they are supposed to do, which was shut down.
         MR. LOUNSBURY:  I agree, but for the station blackout, I
     think the operators would be pretty much aware they didn't have any AC
     available.  It's a different scenario.  But the point being is that the
     RCS would be de-pressurized in some amount of time, would cool down in
     some amount of time, and would significantly reduce the 300 gpm.
         Additionally, the loss of seal cooling is a safety concern
     only when no RCS makeup capability exists for an extended time -- i.e.,
     coping times.
         Testing and actual experience support the above statements.
         DR. WALLIS:  Could you say something about that?  Your
     testing supports this 21-gpm number?
         MR. TIMMONS:  My name is Tom Timmons from Westinghouse.
         Westinghouse, in conjunction with Electricity de France and
     Framitome, performed a test in France in 1985 on a full-scale,
     seven-inch reactor coolant pump seal.
         The steady-state leakage in that test was approximately 14
     gallons per minute, so that we believe, based on that test, which
     confirmed the best estimate leakage estimate of 21 gpm --
         DR. WALLIS:  This is one test.  Did you fail the seals in
     the way that was presented to us by the staff?
         MR. TIMMONS:  No, we did not.
         DR. WALLIS:  So, you were looking at a particular scenario
     where there's a small leak.
         MR. TIMMONS:  We were looking at loss of all seal cooling
     and see how the entire seal package behaved during that test.
         DR. WALLIS:  You had one data point?
         MR. TIMMONS:  That's correct.
         MR. BARTON:  Has there been any actual similar events at
     operating reactors in this country, where you've lost cooling and you
     had seal failure?  What was the leak-off rate?  Because there have been
     seal failures, right, due to loss of cooling?
         MR. TIMMONS:  There have been seal failures due to loss of
     cooling but not seal failures due to complete loss of cooling for an
     extended period of time.
         The only other data point was during a production test of a
     full-scale reactor coolant pump in which they were running a test of
     loss of seal injection and they lost power at the facility, resulting in
     a loss of component cooling water.
         So, there was a loss of all seal cooling to a full-scale
     pump in a test loop, and the maximum leakage in that case was about 13
     1/2 gallons per minute.  However, at about the time that the maximum
     leakage was occurring, component cooling water was restored when they
     restored electrical power, and so, that tended to turn the transient
         DR. WALLIS:  This 182 gallon per minute, whatever it is,
     came from Westinghouse.
         MR. TIMMONS:  That's correct.
         DR. WALLIS:  Hypothesizing some other scenario.
         MR. TIMMONS:  Yes.
         DR. WALLIS:  So, why is this conservative?
         MR. TIMMONS:  The 182 gallons per minute is a thermal
     hydraulic calculation based on a model of how the seal parts react and a
     model of the seal parts and the seal leak-off systems, and it assumes
     that the number one seal operates as designed and that the number two
     and number three seals don't.
         DR. WALLIS:  You say conservative is 21, yet you have a
     model which predicts 182.  So, for some reason you've discounted the 182
     if you say this is conservative.
         I don't quite understand.  And the staff uses a conservative
     of 300.  I don't understand what is meant by conservative in this
         MR. TIMMONS:  Twenty-one gpm was, again, from the
     WCAP-10541, assuming that you didn't have a number two seal failure or a
     number three seal failure.  The test data that we -- that was done by
     EDF showed it was 16 gpm.  So, it's less than the 21 that was predicted
     in the model.
         DR. WALLIS:  You did one test, and you didn't get the
     failure which would have led to 182.
         MR. TIMMONS:  Correct.
         DR. WALLIS:  It doesn't mean to say 182 will never happen.
         MR. TIMMONS:  It's a probability.
         DR. WALLIS:  So, what do you mean by conservative?
         Maybe we should move on.
         MR. TIMMONS:  Yes.
         MR. LOUNSBURY:  The risk associated with the RCP seal
     failures is not significant from the CDF.  Installation of
     high-temperature O-rings would provide a long-term passive solution.
         MR. BOEHNERT:  Have all the pumps -- all the plants put in
     those high-temperature O-ring seals?
         MR. LOUNSBURY:  No.
         MR. BOEHNERT:  Are they going to?
         MR. LOUNSBURY:  I don't know.
         DR. WALLIS:  This is something that came up in the
     subcommittee meeting.  There seemed to be this uncertainty of this
     wonderful material which works so well but it hasn't been put in.
         DR. SEALE:  We don't know.
         DR. WALLIS:  We don't know if it's being put in.  That seems
     strange that you don't know.
         DR. SHACK:  Is this a case that the seals continue to
     operate and they just haven't been replaced or is it a case they've been
     replaced with the old material?
         MR. LOUNSBURY:  My understanding -- and I can't speak for
     all the utilities, but there has been some position by utilities that
     they choose not to incur the additional costs of putting
     high-temperature O-rings until GSI-23 is closed.
         MR. BARTON:  What's the logic behind that?
         MR. LOUNSBURY:  Like I said, some utilities have taken that
     position.  I don't know what their justification is.
         DR. SEALE:  Oh, boy.
         DR. WALLIS:  If we close this issue, does it mean that they
     will or will not put these materials in?
         MR. LOUNSBURY:  I can't speak for each utility.
         MR. BARTON:  For safety's sake, we better hurry up and close
         MR. BOEHNERT:  Do you know how many plants have put in the
     new material?
         MR. LOUNSBURY:  Yes.  Seventy-five percent of the
     Westinghouse fleet of pumps have installed high-temperature O-rings.
         However, the WOG believes the NRC model assumptions are
     overly conservative, specifically the 20-percent probability of the seal
     popping open, which leads to your 182 gpm, and the 50-percent
     probability of the number one seal O-ring failure if the number two seal
     pops open.  The WCAP-11550 predicts a lower probability.
         DR. WALLIS:  The staff indicated it was 1 or 2 percent or
     something like that.
         MR. LOUNSBURY:  It's a single-digit number.
         DR. WALLIS:  Does it predict or guess?
         MR. LOUNSBURY:  Is it a prediction or a guess?  I don't
         MR. TIMMONS:  It's an assumption.
         DR. WALLIS:  That doesn't give ma warm feeling.
         MR. TIMMONS:  That particular behavior has been postulated
     by the -- a consultant to the NRC based on his professional opinion.  It
     has never been observed in a plant, never been observed in a test.
         MR. LOUNSBURY:  To continue on, the operating experience and
     test data do not show a high probability of excessive leak rates for
     loss of seal cooling events.
         The NRC assumptions are based on non-prototypical testing,
     and use of these assumptions may lead to unnecessary expenditures for
     plant modifications and analysis.
         DR. WALLIS:  What testing are you referring to?
         MR. TIMMONS:  It's our understanding that the NRC consultant
     postulated that the seals would pop open based on some tests that he did
     using non-prototypical-size parts and using hydraulic actuators to move
     the seal parts to the point where they would fail.
         DR. WALLIS:  You're referring to E-Tech?
         MR. TIMMONS:  I'm referring to AECL.
         DR. WALLIS:  Oh, Rhodes?
         MR. TIMMONS:  Rhodes?
         DR. WALLIS:  But he didn't do any testing.  He just did
     guess probabilities.
         MR. TIMMONS:  Well, the AECL laboratories were involved in
         MR. JACKSON:  We had a test program at AECL.  It was a
     scale-model-type test to demonstrate whether there was feasibility of
     hydraulic instability.  I think that's what he's referring to.
         DR. WALLIS:  And it did show it?
         MR. JACKSON:  That's right, it did.  It showed what
     conditions it would occur under.  It doesn't occur under all conditions,
     but that was the purpose of the tests, were to map the conditions under
     which it would occur, and they also did analysis of this phenomenon.
         MR. LOUNSBURY:  The WOG position is contained in WCAP-11550,
     which presents the Westinghouse RCP seal LOCA model, and in the
     correspondence with the NRC on proposed closure of GSI-23.
         Fundamentally, our biggest argument or concern -- and this
     has been going on -- is the 20-percent probability of the seal popping
     open.  The WOG disagrees with that number and with the 50-percent
     probability of the number one seal failing if number two seal pops open.
         DR. WALLIS:  How will we decide?  I mean the staff seems to
     have a 20-percent, which doesn't have all that much of a basis, and you
     have some other number which is much lower which doesn't have much of a
     basis.  What should be the basis of our judgement on this?
         DR. SHACK:  You said you mapped out the conditions under
     which this could occur.
         Now, what exactly does that mean?
         MR. JACKSON:  That means the approach angle that the seal
     must have.  It means that -- the degree of sub-cooling in the
     conditions, of the approach to this seal.  It shows at what back
     pressure this would occur, behind this seal.
         So, if you take -- these are all conditions that would
     affect the seal in actual operation, and so, you look at the conditions
     that would be expected in a real seal.
         For instance, if the back pressure behind number one seal
     were to be very low, failure of the second stage seal, for instance,
     then you could have popping open occurring.
         DR. SHACK:  Okay.  So, under these conditions, the
     probability is one.
         So, the real question, then, is what is the probability of
     these conditions occurring?
         MR. JACKSON:  That's correct.
         DR. SHACK:  And the face angles we're talking about are
     consistent with the design?
         MR. JACKSON:  Right.  We look at the face angles that
     occurred in the Westinghouse seal, and the conditions -- these change
     with the thermal conditions, because normally the seal is cool, so
     you're talking about what the seal will -- what will happen to the seal
     under loss of cooling conditions.
         MR. LOUNSBURY:  In answer to your question, the 20-percent
     probability and the difference between what we say in the context of the
     Westinghouse model -- they're using the results partially from our test
     data that we did and the work that was done with Westinghouse vice the
     test data that was -- I don't even know if they actually had a
     full-scale model but that they did with the NRC.
         DR. WALLIS:  We didn't have the benefit of your comments at
     the subcommittee meeting.  So, this is all new to me.
         Are there any other questions?
         [No response.]
         DR. WALLIS:  Thank you very much.
         I'll hand this back to you, Mr. Chairman.
         DR. POWERS:  I will recess us, then, until 10:30.
         DR. POWERS:  Let's come back into session.
         We're going to progress now on to one of the topics that's
     becoming a perennial favorite, status of the proposed final amendment to
     10 CFR 50.55(a), codes and standards.
         Dr. Shack, will you lead us through this effort?
         DR. SHACK:  Okay.  We're going to hear an update today on
     the status of this.  In particular, the part of the amendment related to
     the elimination of the requirement for licensees to update their
     in-service inspection and in-service testing programs every 120 months
     and the question of an addition of a requirement to perform volumetric
     inspections of these small-bore high-pressure safety injection lines.
         We'll hear from the staff, and then I believe NEI has
     requested an opportunity to comment on our letter related to the
     elimination of the 120-month update requirement, and Mr. Scarborough, as
     usual, will be leading us through the show.
         MR. SCARBOROUGH:  Thank you.  Good morning.
         My name is Tom Scarborough.  I'm with the Division of
     Engineering of NRR.
         With me is Matt Mitchell, also with the Division of
     Engineering, and we'd like to go over briefly the status of our two
     activities that we told you we would respond and come back to you with.
         One is the 120-month update issue for in-service inspection
     and in-service testing program, and the other is the high-pressure
     safety injection class one piping weld examinations.
         Just to give you a little background of where we are since
     we last talked to you, in December, as you remember, of '97, we
     published a proposed rule to incorporate by reference the '95 edition
     with the '96 addenda of the ASME boiler and pressure vessel code and the
     ASME code for operation and maintenance of nuclear power plants, with
     certain limitations and modifications.
         Then, in April of this year, we issued a supplement to that
     proposed rule where we indicated a possible replacement of the
     requirement for licensees to update their ISI and IST programs every 120
     months with a voluntary updating provision, and in May of this year, we
     had a public workshop where we had participants from the staff, the
     Nuclear Energy Institute, ASME, several nuclear utilities, and private
     citizens to talk about the update requirement and the need for it.
         Then, in June of this year, we received further direction
     from the Commission in terms of go ahead and finish the incorporation by
     reference of the '95 edition of the ASME code into the regulations and
     to defer the 120-month update issue until the next rule-making, and we
     followed that direction, on September 22nd, the final rule was published
     in the Federal Register, which incorporates by reference the '95 edition
     of the code, and in that rule, that's where we brought up the point that
     we would defer the issue on the HPSI class one piping weld examination
     while we evaluate an industry initiative.
         MR. BARTON:  What's the status of the 120-month update now?
         MR. SCARBOROUGH:  We deferred it from -- well, we separated
     it from the '95 --
         MR. BARTON:  -- '96 addenda.
         MR. SCARBOROUGH:  Okay?  And now what we're doing is what
     we're going to talk about right now, where we are with that status.
         MR. BARTON:  Okay.
         MR. SCARBOROUGH:  Okay.
         So, we issued in April of this year a proposed rule
     discussing the 120-month update.  The public comment period ended on
     June 28th, and we received about 34 comment letters from members of the
     public, and we've been reviewing those comment letters and working up
     responses to them and categorizing them.
         As we began drafting a Commission paper to discuss this
     issue before the Commission provided recommendations, we found that
     there was widely varying views, both external and internal, regarding
     the need for the mandatory updating of ISI and IST programs.
         So currently we're considering various options.  We've
     currently worked our way up to four options, and we're looking at those
     to see if there's any other options to try to resolve this issue.
         But we haven't reached a decision yet as to which particular
     option and recommendation that we might put forward to the Commission in
     the Commission paper.
         So, the next step of where we're going is we're preparing
     this Commission paper, we're getting comments back from the internal
     stakeholders.  We've pulled together the comments, public comments.
         Those have been addressed and responded to in terms of
     developing positions regarding them, but now we're bringing in all the
     internal stakeholders and their positions and developing a -- working
     toward a consensus document so that we can provide options and
     recommendations to the Commission.
         We plan to come back and brief you again in December, at
     your December meeting, and we have a subcommittee meeting that we're
     arranging, as well, and we intend to have a draft Commission paper for
     you at that time.
         Currently, our schedule is to complete the Commission paper
     by January 10th, year 2000, and following that, following direction from
     the Commission, then we would proceed with a final rule-making, in
     accordance with the direction from the Commission.
         That's where we are.
         DR. POWERS:  Do we have a good understanding of the
     positions, those advocating retaining and those advocating eliminating
     the 120-month update requirement?
         MR. SCARBOROUGH:  I think for the public comments, I think
     we do.
         I think we've gone through those pretty carefully and we
     have a pretty good feel.  Both sides make strong arguments for their
     case, for their position, which side they would lean to, but currently
     we're pulling in internal stakeholders, as well.
         There's a lot of comments and views out there that we
     haven't been able to pull in yet and factor into the mix of preparing a
     Commission paper.
         DR. POWERS:  Can you give me a thumbnail sketch of the
     arguments that those that want to retain the 120-month update
     requirement advance?
         MR. SCARBOROUGH:  In the sense of, for example, the
     cumulative increase in improvements in the ISI and IST techniques over
     time that would be -- that you might not see by an individual change but
     might grow over time, I think that's part of what -- one of the
     fundamental reasons that they feel that it would be a good idea to
     continue the mandatory 10-year update.  That's an example of one of
     their comments.
         The HPSI issue, to give you a little background on that, in
     the proposed rule that was issued in December of '97, there was a
     proposed back-fit that would have required licensees to supplement their
     surface examinations of HPSI class one piping welds in pressurized water
     reactor plants, PWRs, specified in the ASME code, was ultrasonic
     examinations, and as we started working through the public comments on
     that and coming up with a final rule, it was determined that, with an
     industry initiative that was working its way through at this time, that
     we would defer action and -- on this issue and continue to work with the
     industry on it in the rule that we put out in September.
         We did some preliminary risk studies that showed there was a
     nominal effect from not conducting the ultrasonic examinations or the
     surface examinations that were mandated by the code.
         So, in the final rule that went out in September, we
     endorsed but did not mandate the code provisions on surface examinations
     of HPSI class one piping welds, and we also discussed in there that
     there was an ongoing dialogue of what was the appropriate examination
     for these particular welds and that that would be dealt with in the next
         So, that's where we left it in September, the September
         On August 20th of this year, the staff had another meeting
     -- we've had several meetings with NEI and industry representatives --
     on the HPSI class one piping weld specifically and whether there was a
     need for interim action on this issue while the industry initiative was
         There's a major industry initiative on thermal fatigue
     that's going to go -- going to last until about the year 2001, and the
     question is should the staff wait until that industry initiative is
     complete before resolving this issue, and that's one of the items that
     was discussed at the August 20th meeting.
         The industry stated at that meeting that, in their view,
     there was no effective interim inspection activities that could be
     undertaken for the class one piping welds at this time, and in the next
     slide, I want to point out some of the technical constraints that were
     raised by the industry at the meeting on August 20th.
         First, there was the comments that it was a very difficult
     -- this small bore piping was a very difficult geometry to conduct
     ultrasound examination.
         Another was that the ability to reliably and effectively
     detect cracking had not been demonstrated with this type of equipment
     for this small piping and that it would require additional training and
     certification of inspectors to be able to perform this type of
         Another concern was the lack of appropriate weld
     preparation.  There would have to be a lot of grinding to remove weld
     crowns and such to be able to allow the inspection to take place, and it
     might cause additional indications to be observed during the
         Another item there was that the inability to size the
     indications reliably might lead to replacement of piping upon indication
     of detection, and finally, they pointed out that, if they did find
     indications, the inspection scope would be expanded as mandated by the
     code and it might go beyond what the original intent was in the sense of
     having a representative sample.
         You might end up with a majority of welds being examined far
     beyond what originally was intended as a representative sample.
         So, those were the points that were brought out by the
     industry at the meeting, and the staff considered them to be reasonable
     points, but industry did indicate that they are working to assess this
     inspection option for the small bore piping for HPSI class one and to
     develop possible procedures and guidelines for the small diameter piping
         MR. BARTON:  What kind of options would they be considering
     other than UT?
         MR. SCARBOROUGH:  I think one of them that's been mentioned
     has been monitoring.
         MR. MITCHELL:  As we understood it from the meeting that we
     had on August 20th, within the nine-month timeframe, primarily they
     would still be focused on ultrasonic procedures.
         It would be a matter of understanding, I guess, a little
     more about what the state of the art in UT is and how it could be
     applied to addressing this particular piping geometry for the purposes
     of detecting thermal fatigue cracking.
         DR. SHACK:  Do we know enough that inspection is really
     helpful here?
         I mean is it one of these things that, once the cracking
     starts, you're going to through wall in three months or something so
     that your chances of actually, you know, finding a crack except -- it's
     either not going to be there or it's going to be a leak?
         MR. MITCHELL:  That has been another point that's been
     raised by the industry in our discussions on this topic in that there
     may be other options such as temperature profile monitoring which are
     more effective at detecting the conditions which could lead to the
     cracking rather than pursuing the inspection options.
         The program which is being pursued by industry also has
     tasks in it to consider a monitoring program and the implementation of
     monitoring, along with the potential for inspection options.
         MR. SCARBOROUGH:  One of the options that had been proposed
     during the discussions with the industry was to substitute some of the
     larger piping diameter inspections that are required to be performed
     with a few small-diameter piping, and decisions regarding that option
     was that there were so many more small-diameter piping welds that you
     might end up having so many you wouldn't be doing any large-diameter
     piping weld inspection.
         So, that option was explored, but it wasn't felt that it
     should be pursued.
         So, based on this new information, including the low risk
     significance that was determined from the internal calculations
     regarding the weld inspection, regulatory action was deferred for nine
     months while the industry assesses the inspection option for the
     small-diameter piping.
         In the meantime, the staff will work with ASME to develop a
     code case for HPSI class one piping, which as Matt was talking about,
     might be a more structured sample for UT examinations, as opposed to the
     way it is now.
         Also, the Office of Research plans to participate on this
     thermal fatigue issue, possibly sharing reviews of samples and things of
     that nature to try to come up with a consensus opinion on this issue.
         And finally, we plan to clarify the status of the HPSI class
     one piping issue in the next rule-making, which is the 120-month
     rule-making that we're working on right now.  We plan to clarify where
     we are with this issue at that time.
         So, that's where we are on both these issues.  I'll be happy
     to answer any other additional questions you all might have.
         DR. SHACK:  Would you actually put some sort of interim
     status on HPSI in a rule-making?
         MR. SCARBOROUGH:  Just in the sense that, in the rule-making
     that went out on September 22nd, we did discuss that this was an ongoing
     issue, and because of that, we sort of left an open door there, and it
     would be good to provide some information.  So, we'll have to figure out
     some way to say it, just to let people know that it's a still ongoing
         DR. POWERS:  Is the situation that the NRC staff wants to
     impose these inspections and the industry doesn't want them to, or is it
     more complicated than that?
         MR. SCARBOROUGH:  I would say it's probably more complicated
     in the sense that there is real discussions going on in terms of what is
     the best possible monitoring or examination for these.  I think it's
     more than just one side wants the other one to do it and the other one
     doesn't want to do it.
         I think there's a real discussion as to what's the right
     thing to do here, and that was one reason why, in the September rule, we
     didn't mandate those surface exams, because there was a concern that our
     people are receiving an excessive dose to do these surface exams and
     it's not achieving them the goal that they wanted to have.
         So, I think there's a real technical discussion going on and
     not just one side wanting to do something and the other side not.
         DR. POWERS:  Well, my understanding is that the cracks of
     interest are those that are generated on the inside, not the outside, to
     begin with, right?
         MR. MITCHELL:  Correct.
         DR. POWERS:  So, an external examination tells you whether
     you've cracked through, I guess, but it doesn't tell you much about it.
         MR. MITCHELL:  Right.
         DR. POWERS:  Have we had a history of cracking in these
     particular pipes?
         MR. MITCHELL:  We have seen instances of thermal fatigue
     damage in these pipe systems, the most, I guess, notable and recent of
     which was the cracking which occurred at Oconee, I believe, in 1997 in a
     high-pressure injection make-up, dual-purpose line.
         DR. POWERS:  And what's the consequences of having cracking
     in that?
         MR. MITCHELL:  The qualitative assessment that the staff
     looked at, at least at the time of Oconee, was to observe that you're
     looking at a small-break LOCA potential, potentially affecting the
     system designed to mitigate a small-break LOCA in the high-pressure
     injection system, and to that extent, when we also noted, coming out of
     that event, that there was an apparent discrepancy in the code in not
     requiring volumetric exams on these particular piping welds was how this
     issue was raised between us and the industry.
         MR. BARTON:  What was the size of that weld, of the pipe?
         MR. MITCHELL:  I believe, in the case of Oconee, that was a
     two-and-a-half-inch-diameter pipe.
         MR. BARTON:  And the root cause of that failure was?
         MR. MITCHELL:  To the best of my knowledge, although I was
     not directly involved in that, it was attributed to thermal fatigue
     associated with a loose thermal sleeve in that nozzle location.
         DR. SHACK:  Keith, you had something?
         MR. WICHMAN:  Yeah.  Keith Wichman, DE.  A couple of
         I think Matt alluded to how this issue was originally
     raised.  The code, in error, did not require volumetric examination of
     high-pressure injection lines in PWRs.
         DR. SHACK:  Is that based on size, though?
         MR. WICHMAN:  Yes, less than four inches.  However -- and
     this was raised -- this was discovered because the class two portion of
     the -- on the code does require volumetric examination, so -- you know,
     class one versus class two.
         So, I wrote a letter to the code and raised this issue in
     1997.  This is how this whole thing started.
         Secondly, as far as being able to inspect these lines, the
     B&W Owners Group and Oconee, for example, which had the failure, Oconee
     unit two, are inspecting these lines successfully, okay, with UT.  These
     are two-and-a-half-inch lines, and I don't think the NRC staff agrees
     entirely with all the industry objections to inspection at this point in
         And finally, as far as strictly high-cycle fatigue, that's
     not the case with thermal fatigue, because you have -- you can have two
         If you have thermal stratification, you have very high
     bending stresses, and that's really low-cycle fatigue, okay?
         So, it's not -- you have a very complex mechanism at work in
     some of these lines, and it will not necessarily go through in three
     months, as you indicated.
         So, inspection can be effective.
         DR. SHACK:  Any additional comments?
         [No response.]
         DR. SHACK:  Thank you very much.  I suspect we'll be hearing
     from you again yet in the not too distant future, and Mr. Marion, I
     think you wanted to give us some insights on the 120-month update issue.
         MR. MARION:  Thank you, and good morning.
         For the record, my name is Alex Marion.  I'm the Director of
     Programs in the Nuclear Generation Division at NEI, and I recognize the
     initial request of this committee was to speak to you about the letter
     that you had drafted to the Commission on this elimination, but I
     thought we'd discuss an uncertainty in modeling techniques used to
     address GSI-23.
         That seemed to be the topic of the day, but really, I
     thought you would benefit from a focused discussion of industry's
     position on this elimination that's being proposed in NRC's rule-making,
     and what I'd like to do is kind of set the stage with some background.
         In 1993, a utility submitted a cost-beneficial licensing
     action -- CBLA, as they were referred to at the time -- that indicated
     that they could not identify any safety benefit in applying the 1989
     edition of the ASME code, and recognize this is in the '93 timeframe. 
     They did a cost analysis indicating that, for them to update their
     program, they estimated it would be on the order of about $250,000.
         Now, recognize this is one plant, but that cost estimate did
     not include a lot of the implementation associated with training,
     inspections, and testing that was not included in their current version
     of the ASME code.
         Now, when this was submitted to the NRC, the NRC recognized
     the generic implications of this and contacted NUMARC at the time, which
     essentially became NEI, and we began working with the NRC on the generic
     aspects of this issue that was raised, and in 1995, there was a Federal
     Reg. notice where NRC announced the intent at that time to baseline the
     1989 edition and consider eliminating the 120-month requirement.
         Fundamentally, industry supports the elimination of the
     120-month update requirement, and that position is based upon our
     understanding that there is no demonstrated increase in safety that's
     commensurate with the cost of implementing that requirement.
         It essentially is an unnecessary regulatory mandate.
         We believe that base-lining the '89 version of the code is
     adequate and sufficient, and the NRC, in their documentation supporting
     the proposed rule-making, essentially feels the same way.
         The industry submitted comments to the proposed rule-making
     on January 25th, and a copy of those comments were distributed to you,
     and I would like to draw your attention to particular areas.
         On attachment one, I would like to refer you to -- I am
     sorry -- enclosure one to that package, I would like to refer to page
     one, item one, potential effect on safety.
         One utility had conducted an evaluation in comparing the '89
     and '92 edition of the ASME code, and that evaluation identified 84
     changes, 77 of which were editorial, 8 were errata, 52 did not change
     any requirements, 22 reduced requirements, and 25 increased
     requirements, and these are requirements between the '89 and '92
     edition, but fundamentally, the utility concluded that none of these had
     any safety significance.
         I'd like to refer to --
         DR. POWERS:  This was the transition between the '89 to the
     '92 version.
         MR. MARION:  Yes.
         MR. BARTON:  It's a snapshot.
         DR. POWERS:  And we're talking about something that would be
     more like the 1992 to the 2002 version of it. Do you have any basis for
     thinking that this is indicative of the amount of change that you will
     get in that time period?
         MR. MARION:  It's hard to say until we see the 2000 version
     of the code or later versions of the code.
         DR. POWERS:  But you're asking people to prognosticate here,
     and it must be that you think that this is the kind of thing that you'll
     get in 2002 vis a vis the '92 version.
         MR. MARION:  No, we're not asking people to prognosticate on
     what it's going to look like in the future.  What I'm trying to do is
     give you a sense of the industry's evaluation of the '89 edition of the
     code and a comparison of the '89 to the '92 edition of the code.  That's
     the only purpose.
         MR. BARTON:  But you're asking for relief from the 120-month
     update forever, right?
         MR. MARION:  Yes.
         MR. BARTON:  So, some later editions of the code may, in
     fact, have safety implications and should be adopted by the industry.
         MR. MARION:  Well, whether the industry adopts the code is a
     separate question from the NRC incorporating the code in the regulation
     and making it a mandatory requirement.
         If a future edition of the code, indeed, contains provisions
     that relate to a safety improvement, then we support the NRC making the
     regulatory decision, based upon the safety threshold and incorporating a
     requirement of those safety provisions in 50.55(a).  We're not arguing
     about that.
         What we're arguing about is incorporating and mandating all
     of the other stuff associated with code provisions as this cycle of
     10-year updates continues.
         We have no argument about the safety case being made on
     provisions.  We're just concerned about wasting a lot of resources and
     doing all of the other things that the code requires on this 10-year
     cycle where utilities have looked at it and can't make a safety case for
         DR. POWERS:  I guess I'm struggling here a little bit to
         This group, the ASME, that makes this -- these are not
     Martians that land here with the intent of making life hell on the
     nuclear industry.  I mean I presume members from the nuclear industry
     participated in these -- in this code group to come up with these
     changes and whatnot.
         MR. MARION:  Absolutely, and I participate in one of the
     groups myself.
         DR. POWERS:  Okay.  So, why would these people create things
     that are simply burdens with no significance --
         MR. BARTON:  On themselves.
         DR. POWERS:  -- on themselves for no significant reason.  I
     mean there must be a reason they're putting in these changes.
         MR. MARION:  Basically, from the standpoint of standards
     development, there are two fundamental reasons for standards to be
     developed, and this is an opinion that I've been articulating to the
     standards community ever since I've been involved in the standards
     community, which has been about 23, 24 years, and those two reasons are
     very straightforward:  to capture current practice and to pave the way
     or develop a framework for the application of new technology.
         Now, the standards development organizations have been very
     successful as long as they've stayed within those two mandates and
     achieved those two objectives.  The difference is standards are for
     voluntary use.
         In this particular case, with regard to ASME -- and I
     believe it was cited in your letter -- 50.55(a) has existed since 1971. 
     So, for 28 years, we've had a regulation that mandates the ASME code.
         Now, back in '71 and through the '70s, that was the right
     thing to do and a lot of benefit was had in terms of improving
     construction design techniques and inspection techniques of the nuclear
     power plants.
         Now, today, people are taking a good hard look at these
     120-month updates, and they're questioning the safety case that must be
     made by the NRC if they decide to impose these code requirements in a
         Now, that does not disparage or cast any doubt on the
     standard development activity that resulted in the standard.
         Our basic belief is that the standards that come out of
     standards-development organizations have to provide value to the end
     users, and historically, that value has been demonstrated as long as the
     standard organizations satisfy the two objectives I mentioned a little
     while ago, and when that value is demonstrated, those standards will be
     applied by the end use industry, and I think the NRC is on record
     indicating that that's happened.
         There are several hundred standards that are used by
     utilities across the industry that are not mandated by 50.55(a), but
     they're in the design and licensing basis of the plants.
         There are only about 20 or so that are addressed by
         So, our point is to make the regulatory decision on
     revisions to 50.55(a) based upon the safety threshold.  If the safety
     threshold can't be demonstrated, then it should not be regulated as a
     mandatory action.  That's fundamentally where we're coming from.
         I'd like to quickly bring to your attention enclosure two,
     which is a tabulation of the burden on licensees related to this update,
     and this is -- the first page represents an estimate that was provided
     by one utility.
         The second page tries to capture the range, if you will, of
     costs based upon the input we've received from a number of utilities.
         So, the total cost of the industry is somewhere between 55
     to 155 million across all the plants.
         MR. BARTON:  This is the '89 and '92 update?  That's what
     this item is based on?
         MR. MARION:  Let me introduce Kurt Cozens.  He was involved
     in getting all this detail together to support this letter.
         MR. COZENS:  This is Kurt Cozens with NEI.
         The process of updating the code is a procedural cost of
     going through your entire program as it exists, comparing it to whatever
         These costs represent the procedural incorporation of
     whatever new requirements might be there, independent of the addition of
     the update.
         This does not include extra actions that might occur due to
     finding something through whatever and having to take additional
     licensees actions to implement some form of a code requirement.
         So, this is just the procedural --
         MR. BARTON:  This is like a change that has nothing but
     editorial errata data in it, it's going to cost $900,000 for each
     utility to implement?
         MR. COZENS:  There's a lot of work going on, because you
     have to validate how you stand against that requirement through all your
         MR. MARION:  Thank you, Kurt.
         I'd like to talk briefly about the rule that was issued in
     final form.  This was a revision to 50.55(a) that was issued the 22nd of
     this month, last week, essentially incorporating by reference the '95
     edition, '96 addenda, effective date November 22.
         In the rule-making package, the NRC indicated that they are
     giving consideration under a separate rule-making effort this question
     of eliminating the 120-month update.
         The situation we have now, gentlemen, is one of coherence,
     for lack of a better characterization, because right now, in terms of
     the regulatory process you have a requirement calling for a continuing
     cycle of updates and it's fundamentally unnecessary.
         There's no demonstrated safety benefit that's been
     established, and it calls for a continuing expenditure of resources that
     could and should be applied to matters of safety significance, and we're
     encouraging the NRC staff to expedite their decision-making process on
     this elimination, and we're looking forward to their decision, and we're
     hoping that the decision is based upon the safety threshold that's
     necessary and required to support rule-making on that particular item.
         To answer Dr. Powers' question earlier, I got into a little
     bit of a discussion of standards development, and I'd like to talk about
     that a little bit more.
         The National Technology Transfer and Advancement Act was
     issued in 1995, and there's an OMB, Office of Management and Budget,
     circular that provides guidance to Federal agencies on how to implement
     that legislation, and it's OMB Circular A-119.
         Fundamentally, it calls for Federal agencies to endorse
     codes and standards or to endorse standards, because when a standard's
     endorsed by a Federal agency, it automatically is characterized as a
     code, so let's just keep it in the term of standards.
         The guidance calls for the agencies to use rule-making to
     endorse these standards and make them effectively codes.
         Now, we don't have any fundamental agreement with that
     process except that the rule-making decision needs to be based upon the
     safety case being made and it should be consistent with the back-fitting
     rule, and that's fundamentally the differentiation we're making on this
     particular issue.
         We're not arguing about the merits of the standard.  We
     think the standard, if it provides value to the end users, whether
     they're utilities, constructors, architect engineering firms,
     consultants or whoever, they will be used.
         One position we feel very strong about is that the standard
     development process, whether it be through ASME, IEEE, ANS, ISA, should
     not be an extension of the regulatory process, and by that I mean where
     the NRC unduly influences the standard development organization to
     achieve NRC objectives that cannot otherwise be achieved by an open,
     public regulatory process in making decisions on rule-making.
         DR. POWERS:  Let me say, if I can understand this, you're
     saying that the NRC can flood this committee that makes these standards
     up with folks and create something that they would not ordinarily be
     able to do via the back-fit rule.
         MR. MARION:  Yes.
         DR. POWERS:  I don't understand the ASME standards
         I have been very curious about it, so we've had them here
     several times to discuss it with me, and they spend quite a little time
     explaining to me that, no, flooding it is not possible, that they
     restrict the membership so that there's no more than one-third from any
     particular group, identifiable group there.
         So, now, how would one go about flooding this if one wanted
         MR. MARION:  I would suggest that the way of influencing an
     organization, a standard development organization, is through the
     consensus process by holding on to a negative ballot, not justifying the
     basis for the negative, and precluding the work product from a writing
     committee to move forward until that negative is resolved, and
     oftentimes to achieve consensus, individuals will defer to the desires
     and expectations of the person casting the negative ballot, and I'm not
     just speculating on this, I would suggest that you refer to the
     transcript that was developed at the public meeting or workshop that Tom
     Scarborough referred ton this 120-month elimination.
         There were statements made by NRC staff involved in ASME
     code activities that support that, and I would let that speak for
         MR. IMBRO:  I guess I would maybe take exception to that. 
     This is Gene Imbro from the NRC.
         I think there have been many instances where ASME has put
     things in the code, you know, above NRC objection, that the ASME process
     has a second consideration ballot and that only requires a two-thirds
     vote to be approved.  So, I don't think it's a proper characterization
     that ASME can influence the code.
         I think, typically, there's only one person on each code
     committee, at most, and some code committees have none, no NRC
     representation.  So, I guess I would take exception to that.
         MR. MARION:  Well, the public record of that particular
     meeting speaks for itself, and I'd like to move on.
         MR. WICHMAN:  I would agree with Gene.  I was at that
     meeting, and I do not recall that that issue was as you state.
         MR. MARION:  Okay.
         Let me make it clear that the industry supports the
     consensus process.  That's been very important in the success of
     standard development over the years of nuclear energy, and it needs to
     continue into the future.
         But fundamentally, the products that come out of standard
     organizations need to be of value in today's environment, value to the
     end users, and I'm not talking about cost.
         I'm talking about fundamental benefit in your processes,
     whether it be a current practice or allowing you to apply a new
     technology.  That's where I'm focusing the question of value.
         In order to continue this, there needs to be participation
     by Federal agencies, by utilities, by consultants and others in the
     standard development process.  That participation is clearly the reason
     that the process has been successful over the years, and it needs to
     continue into the future.
         To give you a perspective the NRC has 141 staff people
     involved in 254 committees of 16 standard development organizations, and
     I'm not suggesting they're flooding the process.
         The consensus process will survive, but in the consensus
     process, every member has one vote or every participant has one vote.
         We believe that the use of rule-making is too slow and too
     rigid and it creates a lot of confusion, especially when rule-making
     decisions are not made or, rather, rule-making decisions are made on
     things that relate -- have no relationship to safety whatsoever, and I
     think that's where a lot of people are starting to question the basis
     for rule-making to continually endorse and mandate the ASME code through
     changes in 50.55(a).
         Fundamentally, the tenet of standards development is
     voluntary use, and the reason it's voluntary use is because the people
     developing these things are confident enough that the end users will
     apply their product, and I think that speaks for itself.
         There are many, many standards, as I mentioned earlier, used
     in the industry without NRC mandating their use through a regulation,
     and again, if the NRC decides to incorporate a standard in a regulation,
     then that incorporation must be consistent with the back-fitting rule
     and a safety case or a safety threshold must be determined.
         Let me just indicate that there is -- during this process of
     discussion, public discussion on this elimination that's in the proposed
     rule-making.  There's been a tremendous amount of discussion about the
     standards development process.
         As a matter of fact, we got on it a little bit today, and I
     want to make it very clear that our issue with NRC action is strictly
     with regard to rule-making, and the basis for that I think I've stated a
     number of times, but there is another aspect of this which is extremely
     important, and that is NRC's process of endorsing code cases and later
     editions of the code.
         The NRC currently uses regulatory guides to endorse code
     cases over a period of time.  Unfortunately, that period of time could
     be several years from the time that a particular code case was issued
     and approved by ASME.
         That process needs to be expedited and improved, and we feel
     -- and matter of fact, back in 1993, one of the recommendations we made
     to the NRC along these lines was that we think a way to expedite the
     process is to provide the NRC a six-month window of opportunity to
     identify whether or not a code revision or a code case is in direct
     conflict with an existing regulatory requirement, and if it's not done
     within a six-month time period, then the licensees will take as an
     acceptance of that particular code case.
         We feel that that would be -- will result in more
     streamlining, more focus of NRC resources in evaluating these code cases
     in the future.
         I'd like to just point out that there is a effort that's
     being spearheaded by NRC research in dealing with the National
     Technology Transfer and Advancement Act and the OMB circular, and it's
     part of direction-setting issue number 13, the role of industry, where
     NRC is focusing on the organization's participation and endorsement in
     standard development activities.
         Fundamental objectives, we support, and right now, they're
     spearheading an effort to foster better communications with all the
     standard organizations and try to identify a better way, a more
     efficient way, a more effective way for NRC participation and
     endorsement, and I'm, quite frankly, honored and pleased to be part of
     that process, and I think there will be some successful outcomes out of
         There was a meeting held in May, there's another one planned
     in November, and I think that's probably something, at the right point
     in time, this committee might be interested in hearing about, because I
     suspect that the NRC processes in terms of their participation in codes
     and standards will be something that sometime in the future is different
     than what it is now.
         One of the NRC principles of good regulation is clarity, and
     this is one of the five guiding principles, and by clarity, it means the
     regulation should be coherent, logical, and practical.
         There should be a clear nexus between regulations and agency
     goals and objectives, whether explicitly or implicitly stated.
         Agency positions should be readily understood and easily
         That's a direct quote from those principles.
         NRC's strategic planning activity has changed over the past
     several years, and one of the interesting things that's being identified
     -- and I hope I'm not responsible for that gentleman's condition back
     there -- nevertheless, NRC's implementation of their planning activities
     focuses on the attainment of four outcomes, and this is something that
     we've been hearing a lot in our interactions with NRC staff and NRC
     management over a number of issues.
         Those four concepts are very fundamental and
         First is maintaining safety, the second is reducing
     unnecessary licensee burden, third is increasing public responsiveness
     and communication, and lastly, increasing the effectiveness and
     efficiency of key processes.
         So, in conclusion, let me make it very clear that NRC
     decision-making related to regulation should be consistent with the
     provisions of the back-fitting rule and a demonstrated threshold of
     safety improvement.
         In this particular case of continuing the 120-month updates,
     there is no demonstrated increase in safety that is commensurate with
     the cost of implementation.
         We provided data to the NRC for the '89 code and a
     comparison of the '89 to '92 code, and we think the time to make that
     decision for the right reasons is here and now.
         DR. POWERS:  I guess I'm still perplexed.  You have this '89
     to '92 comparison, and it was what you said, and now there are a lot of
     things that were of an administrative nature.  There's some that
     weren't.  I don't know what they particular were, and I don't know their
     safety impact.
         But still, the issue here is not a three-year update, it's a
     10-year update.
         MR. MARION:  It's a forever, continuing update.
         DR. SHACK:  Yeah, but you want it to be never.
         MR. MARION:  In a holistic way, the entire code, most of the
     provisions that we've seen in '89 and '92 are not safety significant,
     fundamentally, what it's all about.  I believe Mr. Barton raised the
     question about something in the future that may have safety
     significance.  That's fine.  That should fall into a regulatory
     decision-making process.  We're not arguing about that.
         We're just saying the process of continuing this 10-year
     cycle and looking at the program in a holistic way is not providing any
     value to anyone.
         MR. MARION:  Well, here's my problem, one of my problems, is
     that if I looked in the sky tonight and I didn't see a comet, I couldn't
     attest to you that no comets are ever going to come by, and if I look in
     the right part of the sky for five years, I might not see a comet, and I
     couldn't still say that a comet would never come by.
         When people set up this rule a long time ago that requires
     this update in here, were they not thinking, gee, things change, and
     each individual thing that changes may not itself be very safety
     significant, but after I integrate enough of them together, they really
     are, and I don't see a way to easily have people go through an analyze a
     lot of little things and make sure that they come up to be a huge amount
     of safety significance, but because I've got this standards process of
     lots of bright people and knowledgeable people working on it, it will be
     a rational update, and I'll be sure to capture all these little things
     that together add up into a big thing.  I mean I don't see the back-fit
     rule being necessary here because of the way they set it up earlier.
         MR. MARION:  I'm not personally familiar with the thinking
     of the NRC at the time this was originally established as a regulation,
     but as I understand the position from the Office of General Counsel --
     and I don't know if there's anyone here from that office -- the thinking
     was to allow a mechanism through 50.55(a) to provide a process for de
     facto updates of future revisions of the code, okay?
         Now, as I understand OGC's position, if it's something other
     than a de facto update -- by that I mean update the code as published,
     no clarifications or exceptions, but if there are clarifications or
     exceptions, then, in effect that becomes a new regulatory position, and
     that new regulatory position has to be consistent with the back-fitting
     rule, okay?
         That's what I understand to be OGC's position that was
     articulated a few years ago.
         If you're interested in a copy of that letter, I know we
     have at it at the office.  I can forward it to you.
         But fundamentally, we're focusing on the regulatory process
     here as it relates to rule-making action, and the data provided by
     utilities to us so far have indicated there's no safety value in these
     cycles of 10-year updates that have occurred over the past several
     years, and fundamentally, if -- let's say in the 2000 edition of the
     code -- well let's go to the 10-year -- 2009 edition of the code -- I
     don't know if they're going to do one at that point in time -- if there
     are provisions in that version of the code that clearly identify a
     safety improvement to be had through the inspection process and
     activities, then that should be incorporated in a regulation.
         There's no question from the industry about that.  It's all
     of the other provisions that have no impact on safety.
         And that essentially concludes the comments that I have.  I
     don't know if there are any other questions.
         MR. IMBRO:  I just wanted to mention one thing, I guess as a
     point of clarification or maybe to take exception to one thing Mr.
     Marion said.
         I think he mentioned earlier in his presentation that the
     staff supported the '89 code as a baseline, and that's not true.
         As the rule presently on the street indicates, the baseline
     is the '95 edition, '96 addenda, and I think the question of whether or
     not we use the '89 code as a baseline is now -- is off the table.
         Any update -- 120-month update would be beyond the '95-'96
         DR. SHACK:  I guess that completes this session.  We'll
     probably hear more about the 120-month update in December.
         Back to you, Mr. Chairman.
         DR. POWERS:  Okay.  Thank you.
         At this point, I think I can go off the transcript.
         [Whereupon, at 11:23 p.m., the meeting was recessed, to
     reconvene at 1:27 p.m., this same day.].                   A F T E R N O O N   S E S S I O N
                                                      [1:27 p.m.]
         DR. POWERS:  Let's come back into session, and the next
     topic we're going to deal with is the proposed regulatory guide and
     design basis information, and John Barton, you will take us through
         MR. BARTON:  Thank you, Mr. Chairman.
         The purpose of the session this afternoon is to hear
     presentations and hold discussions with representatives of staff and NEI
     regarding a proposed NRC draft reg guide and design basis information.
         The staff has been working with NEI since 1990 in developing
     guidance on what constitutes design bases information as defined in 10
     CFR 50.2.  In October 1997 NEI published a document entitled NEI 97-04,
     "Design Bases Program Guidelines," and submitted a document for
     endorsement by NRC.
         After extensive interaction with industry on the subject,
     the staff has prepared a draft regulatory guide, DG-1093, in which the
     staff proposes to endorse industry guidance in NEI 97-04 as an
     acceptable method for meeting NRC requirements.  This afternoon staff
     will present the status of the draft reg guide, and also NEI will make a
     presentation regarding the 94-04 document.
         The Committee is expected to prepare a letter on this matter
     regarding the acceptability  of the draft reg guide.
         At this time I'll turn it over to Stew Magruder, who will
     take the lead for the staff.
         MR. MAGRUDER:  Mr. Chairman, I'd like to invite Russell Bell
     from NEI to sit up here at the table with me, if that's all right.
         MR. BARTON:  All right.  Stew Magruder and Russ Bell will
     make a presentation.
         MR. BELL:  Thank you, Stew.
         MR. MAGRUDER:  Good afternoon.  I'm Stewart Magruder from
     the NRR staff.  I'm in the Division of Regulatory Improvement Programs. 
     And, as Dr. Barton said, I'm here to talk about a proposed draft
     regulatory guide which would clarify the definition in 10 CFR 50.2 of
     design bases.
         The objective, as I just said, is to provide a clear
     definition, and so that's understandable to the staff and industry, what
     we mean by design basis in 50.2.
         For convenience, I've got the 50.2 definition on a slide,
     and I'd like to leave that up so we can refer to that for the rest of
     the discussion today.  I think it's important that we keep referring to
     that and understand that we're not attempting to change the definition,
     we're simply attempting to clarify it and make sure that we have a
     common understanding of the definition among the staff and the industry.
         I wanted to start out by briefly discussing the relevance of
     design bases.  In our discussions we routinely are asked why we worried
     about this and what's the importance of defining design basis or making
     a distinction between design basis information and other information.  I
     guess to start out with, as you see, design bases -- the term is used in
     many regulations; 50.34 describing the content of the SAR -- it will be
     used soon in the 50.59 criteria.  It's used to define reporting
     requirements, the GDC obviously refer to design bases, and Appendix B,
     criterion 3 on design control, refers to design bases.
         DR. APOSTOLAKIS:  How does that fit into the definition on
     the right?
         MR. MAGRUDER:  The term "design bases" is defined in 50.2
     because it's used in the regulations.
         DR. APOSTOLAKIS:  Oh, in the 2(a) requirement.
         MR. MAGRUDER:  The --
         DR. APOSTOLAKIS:  How do they fit into the definition of --
         MR. MAGRUDER:  The term is used in criterion 3, design
     control, which says a paraphrase that basically you need to keep control
     of the design bases of the plant.
         DR. APOSTOLAKIS:  Thank you.
         MR. MAGRUDER:  Yes, sir.
         DR. APOSTOLAKIS:  Now one last question.
         MR. MAGRUDER:  Yes, sir.
         DR. APOSTOLAKIS:  What's the difference between the
     licensing basis and the design basis?
         MR. MAGRUDER:  The design basis is a subset of the licensing
     bases.  The design bases refers to the actual design of the plant,
     whereas the licensing basis includes other elements such as programmatic
     elements, maintenance, QA.
         The last bullet here beyond just the utility of defining
     50.2 or defining design basis in 50.2, we believe that understanding
     design bases is important when you're making changes to the plant or
     you're evaluating conditions in the plant.  That's why we think it's an
     important issue.
         Very briefly some background information about how we got to
     where we are with this draft reg guide in discussions with the industry. 
     This issue has been with us for several years.  The engineering
     inspections are not the first sure time that this issue's been brought
     up, but for brevity I'll just start there.
         We talked about these issues in the late eighties, and we
     did big engineering team inspections.  In response to those inspections
     the industry developed guidance which was focused mainly on helping the
     licensees reconstitute their design bases, understand what information
     was important, and in some cases go back to their NSSS designers or AEs
     to retrieve information it doesn't have.  The term was defined in that
     document; however, it wasn't the focus of the document.
         The staff did a series of inspections to look at what
     licensees had done and published NUREG-1397 in February of '91.  And the
     Commission issued a policy statement in August of '92 which concluded
     that the NUMARC guidance was effective in allowing licensees to go back
     and reconstitute design basis, and more importantly that the Commission
     policy statement emphasized the importance of understanding your design
     basis and maintaining your design bases.
         Subsequent to that Millstone, Maine Yankee inspections and
     shutdowns led to obviously a greater focus on understanding design bases
     and controlling plant design bases, and then the Nine Mile Point issue
     here is one where we've had discussions with the industry on when they
     should report when they're outside design bases.  And as you're probably
     aware, we've undertaken proposed changes to the reporting requirements
     partly in response to that.
         At this point I'd like to turn over the rest of the
     presentation or the next part of the presentation to Russ Bell from NEI,
     who will go through the industry's guidance.
         MR. BELL:  Would you put this over there?
         Thank you, Stew, and thanks to the Committee for having me
     back.  It's about I think two months ago I was here talking about the
     FSAR update issue, and I'd probably respond favorably to an invitation
     to come back soon on 50.59.  Today is the third of what Tony Pietrangelo
     and I -- Tony is with me in spirit in the back there -- call it the
     triad of fundamental licensing issues that have been in play for a few
     years.  The FSAR was pretty well worked through as we talked about once
     before.  Design basis is reaching a climax, we think.  And 50.59 is also
     very well along with draft guidance out for industry and NRC comment.
         These issues are all interrelated, and in the case of design
     basis, as Stew pointed out, is the definition that appears a number of
     places, the fundamental building block, okay?  So it's very important to
     us as well as to the NRC.
         I've given you a package of slides.  For the sake of
     completeness, I included some -- in fact, Stew, I also have a background
     slide, I talk about the Nine Mile Point issue, which was very important
     in renewing discussion of this issue a couple -- a few years ago. 
     You'll see -- I'm just flipping through these because Stew's already
     done it.  We have a very similar objective in mind.
         We do add a second bullet in terms of our objective.  Not
     only is it important to have the common understanding of the definition
     to support the other regulations, but in and of itself the definition is
     important in the sense that design issues that come up, that are either
     identified from the past or come up in the future are characterized. 
     And they may be characterized as, you know, design discrepancies.
         To the industry if it's characterized as a design basis
     deficiency or a design basis issue, we take that extremely seriously, as
     your see, because of the way we define that term.  And we want that
     characterization when it's used to be appropriate.  It doesn't do the
     NRC or the industry any favors to characterize issues that aren't quiet
     so significant as design basis issues when in actuality there was never
     any question that safety systems would have performed their function,
     and so on.  So that's the other important part of this activity as far
     as we're concerned.
         Stew's word was "relevance."  My slide says "importance." 
     But again, similar material.
         I might start to get right into the discussion of the
     guidance on this slide.  And I'm sorry, I don't think they're numbered,
     but they are recognizable.
         As I understand it, the Committee probably received our
     August 19 version of this guidance.  Now in the last few days we've we
     think finalized that, and we've sent it -- this was after another
     discussion with the NRC, and we've sent that over to Dave --
         MR. BARTON:  We just got it for the first time, Russ.
         MR. BELL:  Okay.
         MR. BARTON:  We haven't had a chance to review it.
         MR. BELL:  It is very similar to what you may have had for a
     longer time, the August 19.  The few changes that are in there, your
     attention's drawn to them by rev. bars on the right-hand margin.
         This guidance is actually in the form of Appendix B.  What
     you've got there is Appendix B to our Document 97-04, which was an
     update of the document Stew mentioned that we did almost ten years ago,
     NUMARC 90-12.  We revisited that a couple years ago, and actually
     reaffirmed it.  Very little in the way of, you know, changes to the
     document, but the design basis issue on account of the Millstone lessons
     learned and the Nine Mile Point issue, we determined that we did need to
     take another look at the guidance that was out there.
         We did that, and after looking at 90-12, we made a few
     changes, added a couple more examples I think to the back, and reissued
     as 97-04.  The guidance you have here is just Appendix B from that,
     which zeroes in on the interpretation of the term "design basis" and
     contains all the examples.
         MR. BARTON:  Is there a specific reason that we're not
     asking for the whole document to be endorsed through the reg guide?
         MR. BELL:  The balance of the document -- in fact, look at
     the title of the document, "Design Basis Program Guidelines."  It was
     very much to do with, okay, licensees, this is how you could go about
     setting up design basis programs at your plant.  This is where you might
     go to look for design basis information.  This is how you might want to
     compile it.
         That really is the bulk of the material.  That's really not
     the issue in play and it's probably more a licensee call as to how he
     wants to do that.
         MR. BARTON:  Okay.
         MR. BELL:  The regulatory matter is the interpretation of
     the definition.
         MR. BARTON:  Okay, thank you.
         MR. BELL:  And that is covered pretty much by Appendix B and
     that is the piece we singled out.
         In the last year we again revisited the issue of 9704 and it
     was pointed out that we present the definition and we present examples
     of design bases but in between there was a missing link -- what we call
     framework guidance criteria for identifying or distinguishing design
     basis information from the bulk of design information.  I think that was
     a fair comment and we undertook to fill that gap with general and
     specific guidance and some additional guidance on doing that that would
     help you link, see how you got those examples from the definition, so I
     think that is what this latest guidance is going to do.
         It is formatted in a way that highlights what we think is
     very important, the linkage of design bases to the regulations, okay? 
     The design bases aren't all the design information at your plant. 
     Design basis functions are not all the functions performed by your SSCs. 
     They are the specific set of functions that are either required to be
     regulations or that you take credit for in the safety analyses, in your
     safety analyses to show you mean Part 100 limits, GDC-19 limits, that
     kind of thing.
         That is a key principle, as you will see on the next slide
     that we think this guidance focuses on, the other one being the
     distinction between design bases and what we call supporting design
     information, which is a separate underlying set of design information,
     much larger set of information, some of which resides in the SAR with
     additional design description, but much of which resides at the
     licensee's file specifications, detailed design drawings and so forth. 
     That is another key principle that we are trying to get.
         I will just mention that the format is to present those
     principles.  Because you mentioned what is the difference between design
     basis and licensing basis, because it is so important to understand the
     role of design basis in the regulatory framework we spend a fair amount
     of time discussing its relationship to other concepts like licensing
     basis still gave you the perfect answer on that, but there are a number
     of other relationships that we try and develop, again to underscore that
     understanding of what design basis are.
         We provide a number of examples.  Design bases functional
     requirements, design bases controlling parameters, which is where you
     will get numerical values that are the reference bounds for design, and
     then again examples of supporting design information.
         You are well aware then that we provided the NRC that on the
     28th.  You have received it.  We had a task force assisting us as we
     generally do on such things.
         We are pleased the NRC is on a course to endorse this thing. 
     That is an indication that we have really come a long way on this.  I
     think we have made some fundamental progress narrowing down a common
     understanding of this thing.
         There are a couple remaining issues I think Stu is going to
     comment on after I get through and they are on a schedule to provide the
     draft Reg Guide, as you know, by the end of this month.
         I also had the definition in my package but this is a much
     better idea.  These are our basic principles or key principles, the
     first thing you see in our guidance after our definition and it drives
     home that point that -- well,  a couple of points.  There are design
     basis functions.  We think those are tied directly to the regulations,
     the functions that are required to meet those regulations -- license
     conditions, orders and tech specs, also the functions that you credit in
     your safety analyses.  The tie to safety analyses is critical in this
     regard. It makes sense.
         Those are the limiting values for your parameters are used
     in the safety analyses.  That is the basis on which you received your
     license and so we think those actually become your design basis values,
     which is the other category of design basis information if these are two
     separate categories.
         The values themselves -- they may be specified in
     regulations;  50.46 has the 2200 peak cladding temperature right in the
     regulation, so there is a design basis numerical value that came right
     from the regulation.  Others might be chosen from a Regulatory Guide or
     other type of guidance document and used as an input to an assumption in
     your safety analyses.  Again, the tie to the safety analyses is very
     critical.  Those become the limiting values for the balance of your
     detailed design, so these are key principles.
         We call those general guidance in the document.  Specific
     guidance -- here is one I haven't mentioned.  The design bases functions
     include the conditions under which those functions must be performed --
     I must provide this much water from here to there in that much time
     against this much head.  I also need to know under what environmental
     conditions that might have to be performed, seismic conditions, fire,
     wind loadings.
         Those types of conditions under which design basis functions
     need to be performed would also themselves be considered design bases.
         Stu mentioned that they are a subset of the licensing
     basis -- the design bases are required to be presented in the SAR.  That
     came from 50.34.  That is how the applications were set up, so we think
     the design bases are located in the SAR.
         The last key principle is design basis information is at a
     fairly high level and it is recognized that underlying that is a
     significant amount of supporting design information.  I think the
     distinction is very important.  That is why we come back to it quite a
         I will not go through all of these.  I mentioned that we
     tried to place design bases in context with a number of other regulatory
     concepts and terms including these.  I mentioned Appendix B, licensing
     basis.  Some of these will come out as we continue.
         If you peeked ahead I can dwell on the aux feedwater for a
     little bit.  After the general and specific guidance and the discussion
     of relationships, we get to a number of examples.  There's a note in the
     front that says these examples are representative.  They are intended to
     be actual examples or all inclusive.  A given plant may have different
     design or additional design bases functions or values than are presented
         That said, we tried to pick a range of different types of
     things -- aux feed, BWR containment.  We included the MOV and turbine
     generator example at the suggestion of the Staff and at this point let
     me identify -- the guidance gives the licensee, and this has been true
     since back in 9012 -- the licensee had the flexibility to address design
     bases issues in a topic format.
         You could take the aux feed system and say every component
     in the aux feed system shall be seismic, EQ, you know -- tornado-proof
     and so forth.  On the other hand, that would create a very repetitive
     situation.  You need to repeat that kind of information over and over
     for system after system.  Why not take care of those topically?  That is
     what we mean when we say topical design bases.
         In the guidance we did a couple examples.  One very
     important one is a single failure criterion.  You can treat that
     topically rather than over and over.  Obviously numerous systems are
     required to meet the single failure criterion and seismic, tornado.  EQ
     is another good one, but I don't think we did the example on that.
         You won't be able to read this, but you have in your
     package -- this is simply a page from the package.  The aux feedwater
     example I will just comment for a minute it reinforced a couple of
     things I have said so far.
         In better understanding design basis, we identified two
     categories of information -- functions, design basis functions -- and
     the controlling parameters used as reference bounds for design.  This is
     where your numerical values will show up.
         On this side you'll notice we state a function, generally
     understood function of the aux feedwater system, and we link it to the
     basis in the regulation for that function.
         Over here you will find the "xxx" gallons, "yy" pressure and
     "in x seconds."  These are the parameters and the values typically taken
     from or used in the safety analyses as the basis for demonstrating that
     the design meets all the NRC requirements.  These are the key parameters
     used in the safety analyses, which are the bounding analyses for the
     balance of the design.
         Also, the you may not get from that that it needs to
     function without any AC power at all in the station blackout situation,
     so we have a separate item here, and for I am not sure all but perhaps
     many plants pressurizer vapor space is another limiting parameter used
     in design in the AFW system.
         There is a link here, a relationship to the refueling water
     storage tank.  That is a requirement here.  This shows how the topical
     requirements come in.  You notice the topic design bases are in that
     left-hand column and so tied to the regulation -- GDC-2 for natural
     phenomenon and so on -- so these have equal importance, equal status as
     those very functional, specific functional requirements that we were
     just looking.
         DR. BONACA:  Is this page out of your guidance?
         MR. BELL:  Yes.
         DR. BONACA:  It is?  Okay.
         MR. BELL:  Hopefully it is page 10.
         DR. BONACA:  I was just curious because nowhere I see it for
     the auxiliary feedwater system specification for how much each pump
     delivers but in mean in terms of decay heat, so the redundancy of the
     system is not mentioned and yet the FSAR, Chapter 10, has definitions of
     how redundant the system is supposed to be, so there is nowhere you have
     a requirement for that?
         Is it one of the issues being debated with the Staff?
         MR. BELL:  In fact, hopefully you found this one.  I am
     looking at my topical -- I want to say that we have got the single
     failure criterion here, don't we?
         DR. SIEBER:  Page 10.
         MR. BELL:  I apologize.  It is hard to read from here.
         DR. SIEBER:  That's it.
         MR. BELL:  Okay, so absolutely it needs to be redundant, and
     that comes straight from the --
         DR. BONACA:  But single failures means that you've got to
     have two trains but the FSAR establishes if you have to have three
     trains or the level of reliability of your specs, so that would be a
     requirement, right?
         MR. BELL:  That would be part of your -- that is how you
     meet this requirement, or how you meet the GDC --
         DR. SHACK:  And that shows up on page 11?
         MR. BELL:  Thank you, that's a good idea.  Let's go there.
         DR. BONACA:  What is there?
         MR. BELL:  How you meet that requirement, whether you have
     two trains, three trains, six trains, whether you have a DC pump as your
     diverse source instead of the turbine driven one, that becomes the
     description of how you meet that requirement.  That is the design in our
     view rather than the design bases, okay?
         You are right, that information, how you meet the
     requirement, that you have two trains or three trains and a turbine
     backup, that is in your SAR -- that is very important design information
     that was reviewed and approved by the NRC in granting a license and you
     maintain that information complete and accurate and so forth, so I think
     that is an excellent example of a distinction between the design bases
     and the design.
         MR. BARTON:  But it is also the basis that the Staff has got
     for not endorsing the examples in Appendix B, and what they are trying
     to endorse is your Appendix B with several exceptions, and when you take
     into account the exemptions they have got for Appendix B, you kind of
     get to what is the value of endorsing the NEI document.
         DR. BONACA:  Because that exception is humongous.  I mean if
     you go through and you take that exception, it makes a big difference on
     every system.
         I mean if -- I mean there were expectations after TMI that
     your aux feed system would be more available, so therefore there was an
     expectation that you would have three redundant systems and certain
     diversities in the system and sources and so and so forth.
         All that stuff is specified in Chapter 10, if I remember the
     FSAR, and so if you do not specify those things, you have a very simple
     definition in fact, and you don't meet those requirements of the
     regulation right?
         I mean if you are supposed to have a three redundant system,
     which means an unavailability of maybe one in ten to the minus five, on
     demand, that is a requirement, right, in the design basis -- or is it? 
     I am trying to understand.
         MR. BELL:  Well, you absolutely need to maintain redundancy
     or else you are not meeting the GDC.  If you are saying, well, I have
     got four trains and I was licensed that way and I think I might want to
     take out one of those trains, I will still be redundant, that would be a
     change to the design that would clearly involve an decrease in the
     reliability, let me put it that way, in the system -- presumably.
         In 50.59 language it would involve an increase in the
     frequency of an accident or a likelihood of a malfunction and you would
     clearly be into a space where you need to go talk to the NRC about that,
     so that is not something obviously we are talking about a case that is
     somewhat hypothetical but that type of information, again how you
     deliver that "xxx gpm" against that much pressure, that becomes the
     design as opposed to the design basis.
         Dr. Barton, you are absolutely right.  That is one of the
     few remaining issues we have.  I can't argue with you that it is a minor
         MR. BARTON:  This is a major issue with what is really being
     endorsed when the NRC really says, hey, we are endorsing the Appendix
     except we're not and that is really what the Reg Guide is doing  and I
     am totally confused as to what we are really accomplishing here when we
     don't seem to have come to closure on some major issues, this being one
     of them.
         DR. BONACA:  The other thing is that these things have a
     long history.  I mean the reason why, for example, the number of
     redundances in aux feedwater systems were increased was in part because
     for the Westinghouse plants they had an isolation system that went in
     because of steam line break concerns that isolated all the main feed
     every time you scram, and that was a big concern because suddenly you
     went from plants which normally did not isolate main feed, so you always
     had main feed to a new generation of plants that had no main feed
     because you isolated because of steam line break concerns, and now you
     have to have more auxiliary feedwater pumps to deal with the fact that
     you were by design removing available main feedwater systems, okay?
         So, you know, that stuff brings in a history on development
     of these power plants which were reflected in the Chapter 10s of the
     FSARs that is fundamental to the design and that is really the design
     basis of the plant.
         I think that is the point Mr. Barton is making, that it is a
     significant issue.  There are not only four issues here, they are big
         MR. BELL:  There is no question that is important design
         DR. BONACA:  I just wanted to get a sense of how far apart
     you were.
         MR. BELL:  Well, one of our concerns -- I didn't list it an
     objective.  It goes without saying you want a definition that is clear,
     implementable, workable.  One concern that we have with that remaining
     issue with the staff is once you begin to include certain design
     information as design bases, it may become very difficult to draw that
     line.  And where does it, you know, where does it stop?
         The thing we know we don't want is to identify something as
     design basis where you're setting yourself up for a fall somewhere.  It
     might be a minor, or I should say a less significant matter, one with a
     small discrepancy, and it would not undermine the ability of the system
     to perform its function.  That's where we've drawn the line at the -- if
     you preserve the ability to perform that function as credited in the
     safety analysis, that's where we think we've got a workable space to
     work in.
         So -- and you can see the range of the type of information
     here.  Take the third bullet, the system design pressure of the system. 
     By that I mean the, you know, kind of ASME code maximum internal design
     pressure of the system.  It might be 1,500 PSIG.  To go back to the
     design basis function here, we could say that it might be 500 gallons a
     minute against say 1,200 PSIG if, for example, the design -- if this was
     elevated from what we call supporting design information to design
         This is a very important aspect of design.  There's no
     question about it.  It's essential to have a robust design to support
     the design basis AFW function.  But, if you find one day that your
     actual AFW system piping or a portion of it may be capable of
     withstanding only 1,450 PSIG, okay, we don't think you want to be in the
     position of declaring that to be an out of design basis situation
         We would say like all discrepancies you would evaluate that
     first as am I operable? is it reportable? and now is it a design basis
     matter we can categorize.  We would say that the capability to perform
     that function is still preserved, okay?  And that's an indication that
     this type of parameter would not be a design basis controlling
     parameter.  That's where we come from, and that's our rationale.  Very
     important design information and certainly figured prominently in the
     staff's review of the design originally.  And if there is a discrepancy,
     obviously it needs to be appropriately dealt with.
         But anyway, I think that's probably enough on that.  I think
     I've underscored some of the key principles, the structure, the
     guidance, the tide of the regulations that we think is so important, and
     the distinction between supporting design information.  Again there's --
     when discrepancies are identified, it's important that they be properly
     characterized and not mischaracterized as design basis issues when in
     fact there was never any question that design basis functions would have
     been performed.
         Just to wrap, we'll keep working with -- in fact we have a
     meeting on the 14th to try and address these remaining issues.  I expect
     we'll issue a revised 97-04, and obviously comment on the staff's draft
     reg guide as necessary.
         If it's all right, I'm going to stick around while you
         MR. MAGRUDER:  Yes, in case there are questions.
         MR. BELL:  Do you want to?
         MR. MAGRUDER:  Yes, let's switch.
         As you've pointed out, there are some significant
     discrepancies or exceptions between the staff and NEI still remaining. 
     I would like to say, though, that this list is much smaller than it was
     a year ago, believe it or not.
         MR. BARTON:  Yes, but you've had several meetings in the
     recent past and several revisions to the NEI guidance, and you still
     have these large exceptions.
         MR. MAGRUDER:  We still do.  That's correct.  That's
     correct.  Our goal is to endorse the industry guidance.
         MR. BARTON:  I understand --
         MR. MAGRUDER:  If that's not possible, we think it's
     important enough that we would issue a reg guide on our own to make
     clear what the design basis information is, because you're absolutely
     right that there are some significant differences.
         And I'd like to try and explain why the staff feels the way
     it does on these issues.  And our goal obviously is to put this together
     in a manner that's understandable and ask the Commission to publish this
     for public comment to get more input on the process.  But your views on
     the subject are important to us and would be welcomed also.
         There are four major issues that we are taking exception to:
     redundancy and diversity, design basis values, normal operation, and
     testing and inspection.  And we've concluded a fifth exception in the
     reg guide just basically stating that the examples are not based on the
     staff's viewpoints, they're based on the industry guidance.
         MR. BARTON:  It says if the industry uses them, the
     industry's out there hanging on a limb, because you don't -- you guys
     don't agree with that.
         MR. MAGRUDER:  That's pretty much correct.
         We would, if they looked carefully, it would be clearer
     which examples we agree with and which we don't, but we agree that it's
     not an ideal situation.
         I'll start with redundancy and diversity, which we've talked
     about already here.  The staff believes that it's not sufficient to
     include the statement that the system will be redundant and diverse and
     meet single failure criteria in the design basis, and that -- a brief
     discussion of how the system is designed to be redundant and diverse
     should be included in there.  That we think that redundancy and
     diversity are design parameters that need to be addressed in the design
     bases.  And that's basically why we think that they should be included.
         Design bases may include credited features beyond those
     required to meet single failure criteria, and we think that it's
     important to include those.  Examples would be there are other design
     requirements that go into design such as seismic requirements or
     separation requirements.  In addition, there are some instances, as Russ
     has alluded to, where a plant chooses to install three trains of a
     system where only two would be strictly required for a single failure. 
     We think that the fact that it was designed with three trains and the
     staff reviewed it and, you know, for robust overall plant design with
     three trains, it's inappropriate to say that only two trains are
     therefore design bases and one train is not included in the design
     bases.  That's our basic position on that.
         Design bases values is another exception, another area where
     we're still working with NEI.  The design basis definition includes we
     think all functions, both -- and that would include active and passive
     functions of an SSC.  It also includes values associated with functions
     that assure an SSC can perform its required functions.
         Russ already talked about the system design pressure for the
     aux feedwater system as an example.  We think that the integrity of the
     AFW system piping is critical to performing the safety function of
     getting water into the steam generator.  So we would think that the
     function of maintaining integrity should be included in the design
         MR. SIEBER:  Can I ask a question?
         MR. MAGRUDER:  Certainly, sir.
         MR. SIEBER:  Just using that as an example, and the further
     example of the discovery that it did not meet the original design
     pressure, obviously there's relief valves there, but I don't see them
     specified anyplace, and one could construe that if you could accept a
     lower design pressure, also lower the relief valve setting to protect
     that piece of pipe and thereby create the possibility of an accident
     should you get an overpressure in the system which would relieve and rob
     you of flow.
         MR. MAGRUDER:  Um-hum.
         MR. SIEBER:  And so where does the subcomponents like relief
     valve settings or other instrument settings that are designed to protect
     the integrity of the system fit in?  Is that in some notebook someplace,
     or is it in the design basis or a design value?
         MR. MAGRUDER:  We think that the relief valves or other
     components such as that, that their functions are important, and that's
     the reason why we think system design pressure should be included in
     there, because when you size relief valves, obviously you need to know
     what the important parameters are.  The valves themselves, a description
     of the valves themselves we don't think should be included in design
     basis.  That's supporting information about how the plant is designed. 
     But the fact that you need to design it so that it doesn't -- it can
     relieve -- to maintain 1,500 PSI is inferred from the design bases.
         MR. SIEBER:  Right.  Thank you.
         MR. MAGRUDER:  The third bullet here talks about code inputs
     that we think should be included or may be included at times in the
     design bases.  An example of that is the cumulative usage factor used in
     the fatigue determination for other ASME code requirement for design.
     Where they are values associated with design basis functions we think
     they should be included as part of the design bases.
         Normal operation is another issue here.  I think that if I
     had to characterize these, I think the first two issues we talked about
     are probably the most significant issues that we have.  The remaining
     two are important but less significant, I would say, and the reason I
     say that is I think we are closer to agreement it covers a smaller
     population of SSCs.  We think that it is important to understand that
     design bases values and functions can be generated or inferred from
     normal operation as well as accident conditions in that systems that are
     only required during normal operation also have design bases.
         An example of this is the fuel that in most cases the most
     limiting conditions are found during normal operation and most of the
     design inputs are based on normal operation, so we don't want to leave
     the impression that safety analyses or the Chapter 15 analyses alone
     provide the design bases for the plant.
         DR. SIEBER:  Maybe I could ask another question.
         MR. MAGRUDER:  Of course.
         DR. SIEBER:  If you move to risk inform regulation you
     somehow or other shift your emphasis from Chapter 15 to another set of
     incidents that could occur at the plant.  Does that change the design
         MR. MAGRUDER:  Under the current scheme, once we are through
     with Option 3 or whatever, if we define a new set of design bases
     accidents or include severe accidents in the analyses, then the design
     basis of the plant would change, but the design bases are derived from
     requirements in other regulations so they would follow from the
     requirements in the regulations.
         The next issue is testing and inspection.  The point here is
     that many general design criteria specify that design systems should be
     designed so that they can be tested and inspected and Staff feels that
     testing the capability, is an input into the design and should be
     considered design bases.
         I would point out though that we are rethinking that issue
     and the issue comes down to whether testing and inspection are functions
     and required functions and whether it is performed by the system or on
     the system, and so I think we are still -- we get into these discussions
     on these issues and I think we can talk some more about that.
         For completeness, I would like to point out, as you
     mentioned, Mr. Barton, that the examples as currently written in the
     guidance do not reflect all the Staff positions in the draft Reg Guide
     so that we have included that as an exception as well.
         That concludes my presentation.  I am sure Russ and I would
     be happy to answer any more questions, if you have any.
         DR. UHRIG:  What is the implication of including, for
     instance where you have optional three trains instead of two of
     including it in the design basis?  This then brings it into the tech
     specs and all the rest of the requirements?
         MR. MAGRUDER:  No, we are not attempting to redefine the
     tech specs.  Some systems which are covered by tech specs -- let me put
     it this way.  Many more systems have design bases that are included in
     the tech specs and the tech spec treatment is separate from the
     definition of design bases.  I don't know if that answers your question
     or not.
         DR. UHRIG:  Well, in going back to the case where it was
     four trains versus three trains on instrumentation and it was a question
     of who got the margin, the margin for operation or the margin for
     safety, I sort of see the same issue evolving here.
         MR. MAGRUDER:  We are not attempting to solve that issue
     with this discussion here.  I am not an expert on tech specs, so I
     couldn't answer that question I don't think.
         DR. UHRIG:  I don't really see what the issue is then.
         MR. MAGRUDER:  I am not sure I understood --
         DR. UHRIG:  The difference between the two positions.  What
     is the significance of including that third train in there?
         MR. MAGRUDER:  Oh, I see what you are saying.  Okay.
         DR. UHRIG:  What is the practical aspects of it?
         MR. MAGRUDER:  The practical aspects are that we think it is
     important that the operators understand why three trains were installed
     in the plant and why the Staff reviewed or approved the design with
     three trains.
         There may be other reasons that are not immediately obvious
     to the operators why there's three trains there, and we think it's
     important to include all the design or all the facility and the design
     bases so that the operators will understand the importance of it.
         DR. KRESS:  Did those extra -- I will call them extra trains
     play some role in the original decision to grant the license?
         MR. MAGRUDER:  Very likely they would.  They could have.
         DR. KRESS:  If they did, that to me would be a reason to
     have them in the design basis.
         DR. BONACA:  To give an example, you know, if you look at
     many Westinghouse plants, they have what they call the G spec, which is
     the General Spec, and then they have the E spec, which is the equipment
     spec.  They are cookbook specification design to build, and if you go
     through those and you can read through what requirements are coming from
     the regulation.
         In fact, the question I was going to ask is, you know, this
     is in existence already. The designers had to deal with these issues and
     they didn't put in four pumps because they liked to spend more money and
     put in pumps.  I mean there was some requirement there that came from
     somewhere.  I quoted before the requirement of isolation for the
     Westinghouse plants, that they had a concern that if you had a steam
     line break that you would have a runout condition and overcool and
     return to power, so they put an isolation system on the main feedwater.
         Well, suddenly you have this totally different design where
     all your main feedwater system, which we have pumps running, are
     isolated, so you are putting more demand on the auxiliary feedwater
     system.  They resolved that by going to three trains as a minimum
     commitment.  Actually, the packet explains it, also tells you when you
     have to deliver the water, for example, before you dry out the steam
     generator, so they have some calculation to show dryout time and the
     time for delivery.
         So those things I mean have -- that's the point you are
     making.  Exactly right, Tom.  They were in the original design.  Without
     it, you could not make a PRA because you wouldn't know how many
     redundancies you have in that system.
         DR. UHRIG:  But there are cases were -- and again I go back
     to this example of the instrumentation trains.  The fourth train was put
     in for the purpose of giving you additional operational flexibility in
     the event that you had one train out for testing and you had fault,
     instantaneous  failure on the third train, if you had a three hour to
     four requirement, which is what got imposed on this instead of the two
     out of three -- the original intent was to have two out of four -- which
     would have been just the same from a safety standpoint as a two out of
     three, but the three out of four got imposed because they wanted
     additional margin.  Of course, we wanted the additional margin at that
     time for purposes of operational flexibility, and it was -- I don't
     remember -- 10 million dollars or something was put in there
     specifically to gain that margin that's got lost. Eventually it got
     resolved but it was years.
         MR. BELL:  If I may, I heard a couple things I just wanted
     to speak to and one is this notion that, well, it was considered at the
     original time of licensing.  It may have been very important and might
     make it in this category of design basis.  You see, that is exactly the
     problem.  An enormous amount of information was considered, okay? --
     even more than is summarized in the SAR, so as a criterion we find that
     to be not determinant --
         DR. KRESS:  It's not a real good quantitative --
         MR. BELL:  Okay.  Our goal is to have a scope that is
     finite, meaningful -- okay -- we want to distinguish design bases as a
     meaningful term, meaningful concept from the balance of design.
         You know, the folks who have got three trains versus four
     trains, fluid systems, I&C systems may of course know why they have
     those.  They frankly don't need us to tell them, well, it's design basis
     or it is not, to remind them how significant it is, so your question
     about, well, what is the difference I think is very valid, and I think
     it has come up at every meeting we have had, trying to remind ourselves
     why this is so important.
         DR. BONACA:  But, see, you are telling me that if you can
     deliver and can remove decay heat, it doesn't matter if you can do it
     with one pump, five pumps?
         MR. BELL:  If you only have the one pump, you are going to
     be in violation of a GDC requirement.
         DR. BONACA:  That's right.  GDC is implying redundancies and
     diversity and the design basis defines what it is.  I mean it is in the
     FSAR, so it is just hard for me to understand how that specific piece of
     information would not be critical.
         We would discuss here in the ACRS in fact the validity of
     existing PRAs given that there are discrepancies in the design basis. 
     Well, assume there are no discrepancies in the basis, but you don't know
     if a system is two redundant or three redundant.  You can never know
     what the PRA will give you.  I mean then we can forget about that
     because that is exactly the question the PRA will ask.
         DR. KRESS:  Why does the PRA necessarily have to be tied to
     the design basis?
         DR. BONACA:  Well, as a minimum you have to understand how
     many times you can deliver a function to have an availability for the
         MR. BELL:  We would say, of course, the PRA reflects the
         DR. KRESS:  Ought to reflect the design.
         MR. BELL:  Well, the design basis is almost a term of art
     that the regulators have used and licensees have dealt with.  You know,
     in field it really has very little meaning to folks, but it is used
     throughout the regs.  We need to understand what it means.
         It is misused at times when design issues come up -- because
     I am down a train, it does not mean -- down a train might be
     maintenance.  It does not mean I am outside my design basis.  We would
     not want it to go that way.
         I would still have redundant diverse capability as I must to
     meeting not only -- you know, I misspoke earlier.  If you had only the
     one pump not only would you be in violation of the GDC but you would
     also be out of your design bases because the single failure criterion,
     as I mentioned before, we would consider that part of the design bases.
         DR. BONACA:  Don't take the one literally.  I just wanted to
     give you the difference between one and five.
         DR. UHRIG:  The difference between two and five may not make
     any difference.
         MR. BELL:  To bounce these issues off of our principles, the
     redundancy, diversity issue, okay -- how is that tied to the
     regulations?  You remember that is very important to us and it is one of
     the key principles that we have up in front of our document.
         Well, the tie relies by the single failure criterion. That
     is as far as the regulations go, and so we would say that the design
     basis of the system needs to satisfy the single failure criterion, and
     that is as far as the design bases would go.  How you do that would be
     part of the design, a very important part of the design but still part
     of the design.
         MR. MAGRUDER:  And the Staff would say that just stating
     that you are redundant and reverse and you meet single failure is not
     sufficient, that the parameters, the design basis parameters, as
     discussed in the definition, include how you meet redundancy and
     diversity, so that the two pumps or the three pumps or three trains or
     however many trains you rely on, aside from what you installed for ease
     of maintenance or whatever, that is a separate issue.  I understand now
     the issue you are talking about, that the Staff feels that that
     fundamental design information is design basis.
         DR. UHRIG:  Well, it was more than ease of maintenance, it
     was a case of remaining in operation if you had a glitch -- when you had
     one channel out -- that kept the plant operating.
         MR. MAGRUDER:  Okay.
         DR. UHRIG:  Otherwise it would have gone down.
         DR. KRESS:  Well, certainly you would think diverse implies
     an entirely different kind of system to provide the function and the
     description of that in the parameters, how it works, ought to be part of
     the design basis rather than just saying it is diverse.
         MR. MAGRUDER:  Right.  That is our position.
         DR. KRESS:  Yes, but if you have more than one or two of
     these that are needed to meet your design basis requirements in the
     rules, then probably those spares that were put in there for some other
     reason might not have to be part of the design basis.
         MR. MAGRUDER:  Right, and we want to make sure that the
     operators and the engineers at the plant understand why they are all
         DR. KRESS:  Why they are there.
         MR. MAGRUDER:  Right.
         DR. UHRIG:  But it isn't the case that you have to have
     these two.  It is "two of" that are the requirement.  It doesn't make
     any difference whether it is number one or number two or number one and
     number three -- it's a two out of three or two out of four requirement. 
     There is no specific two.
         MR. MAGRUDER:  That's true.
         DR. POWERS:  But --
         MR. MAGRUDER:  That's true, but there's probably, like we've
     stated before, there is a reason why all those were installed and the
     reason why they are there is important, and it may not be for
     redundancy.  It may be for another reason.
         DR. SIEBER:  Well, regardless of the reason your design
     basis ought to at least recognize that they are there, right?
         MR. MAGRUDER:  Right.  That's correct.
         DR. SIEBER:  Then you could spell out further what
     combination meets the design requirement or the licensing requirement.
         MR. MAGRUDER:  Exactly.
         DR. KRESS:  If there is a system put in or component put in
     by the designer and the licensee because he wants it there for some
     reason, it helps him do his job, but it's not needed to meet your design
     basis requirement or your GDCs or anything.  It is just there for his
     use.  I would view that as something like margin that ought to be his --
     he ought to be able to put -- if he doesn't want it anymore, he ought to
     be able to throw it out and he shouldn't have to worry about it being in
     the design basis.  Is that the feeling --
         MR. MAGRUDER:  I think the Staff would agree with that also.
         DR. KRESS:  Okay.
         DR. POWERS:  I don't understand that.
         DR. KRESS:  Well, I don't understand what the problem is
         DR. POWERS:  It seems to me they gave an answer that I
     wouldn't have given.
         DR. KRESS:  Yes.
         DR. POWERS:  Four systems and --
         DR. KRESS:  And you only need two --
         DR. POWERS:  -- and you only needed two, but it seems to me
     your design basis would still have all four described.
         MR. MATTHEWS:  The Staff would agree with you.  The design
     basis would still include all four systems.  The design basis can be
     altered.  This isn't inalterable, but it is the design basis for
     whatever reason.
         DR. SEALE:  In order to meet the two out of four requirement
     all four systems have to be of a certain qualify.  They have to meet the
     design basis.
         DR. POWERS:  You have got a two out of three requirement but
     you put in four.  I still think you need to have all four.
         DR. SEALE:  That's right, because all -- the two that are
     there at the time have to meet the requirement.
         MR. MATTHEWS:  Because whichever two they might be, and they
     may be any of the four, so --
         DR. KRESS:  Right.
         DR. UHRIG:  The issue that came up originally was not design
     basis.  It was tech specs.
         DR. BONACA:  We are confusing the things.
         DR. UHRIG:  That is why I was wondering whether this implied
     tech spec --
         MR. BARTON:  Don't confuse the issue here.
         MR. MAGRUDER:  No.
         MR. MATTHEWS:  No.  It does not also afford an opportunity
     for discussion of what treatment rules need to be applied.  It is a
     question of what the design basis is and then your treatment rules deal
     with that design basis -- excuse me.  I am David Matthews, Director of
     the Regulatory Improvement Programs.
         I wanted to add that although we characterized it that the
     Staff views it this way, or the Staff is of the opinion, that is clearly
     how we articulate it, but we view the positions we have expressed as
     deriving from the definition that we put up on the board.  That is why
     we continue to go back to that.
         We take reliance on these interpretations out of words like
     "specific function" and ranges of values and controlling parameters.
         Those are the bases for us establishing these positions.  It
     is not just a question of our preference or what we would like to see. 
     We think that is what the regulation has directed us to identify is
     design bases.
         I think Stew did a good job of clarifying that, but we are
     sometimes cast into the vernacular of speaking as if it's just a staff
     preference.  It's really not a staff preference in this instance, it is
     a staff interpretation of what the regulations require.
         I wanted to add another comment that we have gone hammer and
     tong on some of these issues, as you might expect, and we have not
     reached consensus on all issues, although I think, as was also commented
     on, we have come to closure on many, many issues, like a lot of the
     regulatory process issues we've been discussing over the last couple
     years with all of you, 50.59 and issues related to FSAR updating, there
     was a lot of areas that needed clarification.  So I think we have come
     to closure on a lot of those areas.  And we're continuing to work, and
     we do have a goal of endorsement.
         And as Stew also mentioned, ACRS input on these specific
     points, given the breadth of your experience in this area, would be
     appreciated.  But we are committed to generate a draft reg guide for
     Commission consideration by the end of October.  We have not decided at
     this juncture to go forward with a separate guide.  The significance of
     the remaining discrepancies, as we meet once again in the near future
     with NEI, may warrant such a separate guide, and in that regard Dr.
     Barton and I appreciate that there's a point where you have to make that
     go/no go decision or you end up with a questionable -- a document of
     questionable utility.
         MR. BARTON:  Right.
         MR. MATTHEWS:  In all our activities of the last few years
     in bringing to closure some of these issues, we have tried to look for
     the practical impact of our outcomes with regard to what Sam Collins
     likes to refer to as at the interface, which is clearly on the plant
     floor and in the interactions at the staff and licensee level.  So, you
     know, if it isn't going to work there, there's probably very little
     utility in generating such a reg guide.  So we want that to be the
     ultimate test with regard to whether we would go with a separate guide
     or utilize the NEI document with a limited number of exceptions that
     might be warranted and appropriate.
         Upcoming management review of this issue is going to be
     continuing through October as we progress.  So, you know, we do not have
     the final answer on this yet, but we will look forward to facilitate or
     inform that process.
         DR. POWERS:  I guess that brings us to the question that's
     uppermost in my mind right now, what is it that we're going to produce?
         MR. BARTON:  We're going to produce a letter.
         DR. POWERS:  We don't have enough information to produce a
     letter, I don't think.  I don't even understand the discrepancies
     between the two positions based on these presentations.
         MR. BARTON:  Well --
         MR. PIETRANGELO:  Can I add something?  I think I can help
     Dr. Powers on that last one.
         Tony Pietrangelo, NEI.  The issue you just went through on
     the redundancy and diversity, I mean, if we're going to be convinced
     that the number of pumps or trains or whatever is a specific value or
     range of values chosen for controlling parameters with reference bounds
     for design, fine.  Call it design basis.
         I don't think that's the most significant issue.  It really
     doesn't have any practical impact on anything in the field in terms of
     calling the number of trains design basis or not.  So that one I'm less
     concerned about, because again it doesn't have any practical impact. 
     The big one for me is the one that Russ went over on whether the design
     pressure of the piping is part of the design basis.
         MR. BARTON:  The design basis values argument.
         MR. PIETRANGELO:  That's right.  That's right.  We think
     that's a step beyond what's required by regulation or the function
     credited in the safety analysis.  If we found a design discrepancy in
     the piping, we wouldn't be able to make a call at the outset of whether
     you're inside or outside the design basis of the plant.  If the staff in
     the staff view of choosing 1,500 pounds is the design basis pressure,
     you're already outside the design basis of the plant.  We would have to
     evaluate it and look at things like relief values and overspeed trip
     settings and what you pressurize the header to and what that does to
     flow to see if we met the 500 GPM at 1,200 pounds which you've got
     credited in the safety analysis.  But by going one step down to things
     that I use to assure myself that the actual function will be achieved,
     that's different than the 50.2 value.
         That's our point.  And that's what I think is the big
     difference between the two positions.  We think we can appropriately
     bound the 50.2 definition using our general and specific guidance.  But
     the exception the staff took on this design pressure one would make it
     practically unbounded.
         I don't know -- and what really raised this issue, and most
     of you are probably aware of it -- was this Niagara Mohawk blowout panel
     issue where a bolt was missed on the blowout panel, and the lift
     pressure went from 45 PSF to 55 PSF.  It was designed to -- for the
     integrity of the secondary building, which was 80 pounds.  So it still
     met its design basis function, yet that was called outside the design
     basis of the plant, one hour reporting, and even in the discussion
     between the licensee and the NRC, the position in the NRC letter was
     that design basis was anything the staff relied on to approve the
     design, quote unquote.  And that's really what we've been up against the
     last year, trying to struggle with and get a bounded, accurate
     description of.
         So that's what's at stake here, and I hope that helps you,
     Dr. Powers, on what the issue is that we're trying to address.  But the
     redundancy/diversity thing, I mean, again, we can go either way on that. 
     I think the other two are also less important.  We've already put normal
     operations in our definitions.  We don't think testing and inspection
     are really 50.2 functions.  But it's really the first issue on where you
     draw the line from design to design basis that has the most impact.
         DR. KRESS:  Are we necessarily stuck with this 50.2
     definition, because that seems to me like the problem.  Everytime I read
     it, I read something else into it, and it's awfully hard --
         MR. PIETRANGELO:  Well, at this point I think we are, Dr.
         DR. KRESS:  We are stuck with it; okay.
         MR. MATTHEWS:  Notice my white knuckles gripping the table.
         Let me simply answer yes, I think we are, unless we were to
     demonstrate or somebody were to come to us and demonstrate that it isn't
     serving a useful purpose.
         MR. BARTON:  Does that help you clarify --
         DR. POWERS:  I'm appalled at how little I can understand
     what the differences in the positions are.  I mean, it's just not laid
     out in the way I can see that -- I seem to have a pretty good layout of
     the staff's position on some things that apparently are the questions. 
     I just don't understand where the other people are coming from.
         DR. SEALE:  It's very ecclesiastic, isn't it?
         DR. POWERS:  No.  It's not that either.  It's just
         If we're going to write something on this, maybe we should
     walk back through Mr. Magruder's presentation of positions and
     understand where the difference is.  Right now quite frankly do not
     understand this.
         MR. MAGRUDER:  We can certainly do that, or we can try that,
     Dr. Powers.
         DR. POWERS:  Well, I've got a problem.  I've got another six
     speakers coming today.
         MR. BARTON:  You've got 15 minutes.
         DR. POWERS:  And you guys just have not given me a
     presentation that I can write anything on.
         MR. MAGRUDER:  Okay.
         MR. BARTON:  You've got 15 minutes to try and do it, and I
     wouldn't spend much time on the testing --
         MR. MAGRUDER:  No.
         MR. BELL:  I'd spend most of the time on the design basis --
         MR. MAGRUDER:  Let's try to do the design basis values
         MR. BARTON:  Design basis value is the biggie.
         MR. MAGRUDER:  The first point I think from the definition
     is that the definition talks about specific functions to be performed. 
     It doesn't say only active functions or only passive functions.  It just
     says functions.
         DR. KRESS:  Is there any disagreement there?  You guys agree
     that passive and active are part of the design basis?  So that's not an
     area of disagreement, that first --
         DR. POWERS:  You see, I'm already getting into trouble. 
     These are the ones that I thought were the problems.  And now they're
     not problems.
         MR. MATTHEWS:  Could I maybe -- let's try an illustrative
     example to try to bring focus to it.  We would use -- forgive me for
     this, Russ -- your handout, which is the one on auxiliary feedwater
     system, and go to the page which NEI has entitled "Examples of Auxiliary
     Feedwater Systems Supporting Design Information."  That would be -- it's
     page 11.
         MR. MAGRUDER:  Yes.
         MR. MATTHEWS:  And what I'm going to suggest is that the
     three bullets on page 11, if you're all there, all three of those would
     be statements which in the staff's view should be viewed as falling
     within the definition of design basis and treated that way in the FSAR. 
     And all three of them, just happenstance they demonstrate the three
     principal areas that the staff is concerned about.
         The first one addresses the specificity that the staff
     believes the definition calls for in terms of specific functions, and
     addresses the issue of redundancy and diversity.  The second one
     addresses the issue of the staff's concern that design bases aren't
     confined to mode or conditions such as normal, accident, off normal. 
     And the third one relates to the design basis values that the staff
     views as being design basis information, such as piping design pressure,
     temperature.  So, you know, as an illustrative example --
         DR. POWERS:  No, it's not an illustrative example of
         MR. MATTHEWS:  Well, the staff --
         DR. POWERS:  It's a set of issues.  What do you disagree
     with him on?
         MR. MATTHEWS:  Are you asking that question of NEI?
         DR. POWERS:  Yes.
         MR. MATTHEWS:  Okay.
         MR. BELL:  I think as Tony indicated, the first one is the
     redundancy/diversity issue, and in terms of its practical impact, it's
     probably very little.  And I think his words were we can go either way
     on that.  We have another meeting scheduled to resolve these.
         The second one, these are legitimate uses of the aux
     feedwater pumps.  However, they are not the functions credited in the
     safety analyses for that system, nor would I expect that they be the
     source of bounding or reference values for the design of that system. 
     In other words, the accident demand on the AFW I would expect to drive
     the design, because it's the most limiting.
         So the fact that it's used during these other modes is part
     of the design, not part of the design bases.  To include these would
     violate one of the principles, that being the tie to the safety
     analyses, and the reference bounds for design.
         DR. POWERS:  So what you're saying is these functions, the
     auxiliary feedwater system, are not the limiting function for that.
         MR. BELL:  I would expect not.  I'm not a designer, but --
         DR. POWERS:  Out of hypothesis.  Hypothetically --
         MR. PIETRANGELO:  For example, Dr. Powers --
         DR. POWERS:  Hypothetically, they are not.
         MR. PIETRANGELO:  You could use an aux feed system --
         DR. POWERS:  No, I'm trying to understand.
         MR. PIETRANGELO:  Okay.
         DR. POWERS:  We'll say hypothetically they're not.  There is
     other function performed by the AFW that you really think is really the
     limiting design, taxes it the most.  So it's just an omission on their
         MR. PIETRANGELO:  An omission on --
         DR. POWERS:  The guy that wrote this just left out one of
     the functions
         MR. BELL:  No.  No.  In fact, the safety or the design-basis
     function of this system is of course the one, you know, in the table a
     couple pages back.  This is the function credited in the safety analyses
     that upon loss of main feedwater, he needs to provide for heat removal
     from the core.  These other functions -- so this -- so you would not
     list that function back here.  These are other functions that might be
     performed by the AFW pump.  Okay.
         MR. PIETRANGELO:  For example, on startup a lot of people
     feed their steam generators with aux feedwater pumps, particularly if
     they don't have a startup feedwater pump.  But that's not part of the
     safety analyses that the staff goes through on this.  That's just nice
     to have that was built into the system.
         That function we don't think -- although we do say in our
     general and specific guidance that normal -- you should consider normal
     operations as being a potential for being the bounding condition, and on
     the fuel, that's probably correct.
         MR. BARTON:  But for a plant that doesn't have a startup
     feedwater pump, this auxiliary feedwater pump is part of the design
     basis for that plant, right?
         MR. PIETRANGELO:  No.
         MR. BARTON:  No?
         MR. PIETRANGELO:  The function -- not by our -- the
     principles that we laid out.  That function is not required by the
     regulation and it's not credited in the safety analysis.
         DR. SEALE:  Is it required to run the plant?
         DR. BONACA:  Because in the safety analysis you have it only
     as a backup to the loss of feedwater or feedwater line break.  That's
     the point they are making.
         MR. SIEBER:  But I'm not exactly sure what the harm is in
     listing it as one of the design basis, because you actually do have to
     design it to run in, for example, the startup mode.  I mean, it just
     doesn't happen to work out that way if it's designed just for loss of
     main feed.
         MR. BELL:  Now you are into -- you've --
         MR. PIETRANGELO:  Should I do a one-hour report to the NRC
     if I can't feed with -- starting up with the aux feedwater pump?
         MR. BARTON:  I see where your problem is, but I don't know
     how to resolve it.  Your problem is there are always going to be on
     one-hour reports always outside the design basis --
         MR. SIEBER:  If it doesn't work and you can't start it up,
     then you don't start up.
         DR. BONACA:  Right.
         MR. PIETRANGELO:  What safety issue?  Why should the NRC get
     involved with that aspect of it?
         MR. MATTHEWS:  The staff's of the view that the reporting
     issue is separate from this issue.
         MR. MAGRUDER:  Right.
         MR. MATTHEWS:  The regulations that exist today do have
     these issues crossing because of the definition of reporting
     requirements being tied to whether you're inside or outside design
     basis, but we have proposed a rule that would --
         DR. SEALE:  Separate those two.
         MR. MATTHEWS:  Separate those two issues.
         So the reporting issue is not the one that --
         MR. BARTON:  All right, Tony, what's left?
         MR. PIETRANGELO:  What's left is -- even though the
     reportability aspect is gone -- and Dr. Bonaca would probably know this
     better than anyone up here -- how many plants have gone through this
     design basis issue, okay?  We find a lot of discrepancies when you go
     through design basis reconstitution programs.  A lot of them are paper,
     a lot of them are in the field, and a lot of them have to get evaluated. 
     We've lost quite a number of plants in the last couple of years spending
     a lot of money trying to address this issue.  And that's why we put in
     our letter about the characterization of what the design discrepancy is.
         When you say a plant doesn't meet its design basis, that
     ought to mean something significant, not that you can't feed, you know,
     to start up with your aux feedwater pump, it ought to mean something
     like you can't place the plant in a safe condition following an
     accident.  That's what we're talking about here.  And that's the danger
     of trying to say a lot of these bullets on the left here are, you know,
     part of the 50.2 design basis.
         MR. BARTON:  But some of --
         MR. PIETRANGELO:  So it's beyond reporting, it's a
     characterization issue also.
         DR. BONACA:  Let me just go back again.  If you go back to
     the original design, it's because -- one of the unfortunate things, that
     on one side we have the industry, the other one we have the regulators. 
     But the guys who designed these plants, wrote the book on how you do it
     are not here.  But if you go to the book, having read it, it doesn't say
     anything about these conditions for the auxiliary system, because design
     of the system was for the most limiting conditions, which is full power,
     and we assume if you lose all feedwater -- or you have a feedwater line
     break, which case is more limiting, and from that you derive limiting
     conditions going to the design of the system.
         Some of those are relegated to design basis, because they
     have regulatory significance.  But the point is that -- so I can
     understand why, you know, someone's definition -- I mean, some of this
     may define expectations of the systems for which there is no basis
     anywhere at the site.  I mean, because it was never evaluated under
     these conditions.  It had no limiting.  You use it as a system, but
     there is no basis.
         MR. SIEBER:  I guess your argument stretches right back to
     the definition in the next to the last line.  It talks about postulated
     accidents as opposed to any other form of operation.
         MR. PIETRANGELO:  Although we're not excluding.  If normal
     operation happens to be the bounding condition for the thing, fine.
         MR. SIEBER:  Like the fuel.
         MR. PIETRANGELO:  Like the fuel.  Exactly.
         MR. SIEBER:  I understand.
         MR. PIETRANGELO:  All right.
         DR. POWERS:  I think we've got a problem here.  I don't
     think we can write a letter.
         MR. PIETRANGELO:  You can copy our letter.
         MR. BARTON:  Well, where do you want to go from here?  We've
     got five minutes.
         DR. POWERS:  Yes.  I mean, it seems to me that the situation
     is they're not done with their deliberations, and they certainly have
     not toned down the differences in opinion closely enough for me to
     understand them.  If these are the ones, the slides related to the staff
     positions, then I find out every other one of them the NEI didn't have
     any troubles with.  I don't know which ones they have troubles with and
     which ones they don't.
         MR. BARTON:  Well, I think we're down to the design values
     as the issue that we can't seem to get closure on.
         DR. POWERS:  So you're saying that out of all of this, the
     only thing that we have to worry about is the design basis could include
     values that are code inputs and values associated with function, assure
     the SSC's will perform the required function.  That's it?  That's the
     only difference in opinion here?
         DR. BONACA:  That's the one that --
         MR. BARTON:  Yes, I think so.
         DR. BONACA:  Dr. Pietrangelo said was the --
         MR. BARTON:  I think between now and the end of October the
     staff and the NEI will come to some closure on the other three issues. 
     That's what I heard here, between -- I heard NEI and Dave Matthews
     describing.  I think those three will come to a mutual resolution by
     which you can take the reg guide and endorse the NEI document.  I have
     not heard the path to resolution on the design basis values question.
         DR. BONACA:  Let me ask a question to see if he clarifies
     it.  It will take just about ten seconds, and he can provide an answer.
         Now if I understand it -- let's take the example of the
     third bullet, system design pressure is excess PSI in temperatures dot
     dot dot.  That has to do with -- say that you have a pipe for which you
     have a commitment in the FSAR to pass say steam, and you have a certain
     pressure for 1,000 PSI, okay?  And certain temperature.  There are
     limits for those two values that you use in the design.  I mean, that
     you have to deliver in an accident analysis or whatever.
         Now you go out and get pipe that is capable of 2000 psi and
     twice as high a temperature as that.  Is the position of the NRC that
     now you are bound to have 2000 psi and I mean what was procured, is it
     what you would consider your design basis for the pipe, the procurement
     values, or the process parameters that is described with the 1000 psi
     and the temperature?
         MR. WESSMAN:  Let me try and help out, Stu.  This is Dick
     Wessman from the Division of Engineering.
         No, I don't think the Staff is looking at things like
     procurement values.  I think we are looking at things that develop
     margin to support that function, and so the concept of it has to be
     able -- the function is 1200 psi and the Staff would view as a design
     basis value that there is -- the margin that gets you the 1500 pound
     pipe, and then the designer buys whatever the right code is that gets
     that margin.
         I think we tend to think the same way in the area of
     cumulative usage factor.  That would be to us a design basis value and,
     yes, if the licensee discovers that they have exceeded the CUF of one,
     they would be outside the design basis and they would need to report it
     to us.  It may mean that the analysis is detailed analysis or some other
     analysis determines that no, they are not really outside of 1.0, or they
     really are, and yes, they must make a replacement, but these are the
     type of numbers that provide this margin that I think where we on the
     Staff think they are essential in reaching that decision on a design
         DR. BONACA:  So essentially it would be a process parameter
     times some factor that you have for ASME codes or whatever that is a
     standard process?
         MR. WESSMAN:  Yes.
         DR. BONACA:  Which is not a procurement value but it is
     somewhere below?
         MR. WESSMAN:  We are seeking that assurance of margin we
     think fits within this overall concept of controlling parameter. 
     Obviously NEI and the Staff are not in agreement on this or we wouldn't
     be having this discussion.
         DR. BONACA:  And NEI would propose what?
         MR. WESSMAN:  NEI would propose -- I am speaking for Russ --
     that the bounding value of just 1200 psi and x flow is all that is
     necessary, and we are seeking that margin on it.
         DR. SHACK:  If I go to the NEI guidance document, is it this
     last phrase in the definition of design basis values that causes the
         MR. BARTON:  What page are you on?
         DR. SHACK:  I am on page 1 of the draft guidance of Appendix
     B, and they are defining design basis values.
         Do you guys want to put a period after "standard or guidance
     document"?  Would that make you happy?
         MR. BELL:  How would that change the meaning?
         DR. SHACK:  It is just that the values then would be set by
     the safety analyses from the code, the standard or guidance document. 
     As I understand it, you guys then want to restrict that to only those
     values which are necessary to meet the design basis functional
     requirement as in Chapter 15.
         MR. WESSMAN:  I think we get closer with the period, but I
     think we have to sit and think about it a little bit and again discuss
     it with NEI.  I mean this has been an ongoing struggle and this has gone
     on in quite a succession of meetings.
         MR. BELL:  I would have just added to Dick's answer, which I
     appreciate, you are right.  We would choose the process parameters and
     we would say that the design provides the margin to assure performance
     and design basis functions, so when we identify design bases I am not
     sure -- you know, margin does not come into it, except that design bases
     values themselves have margin. We are not on the ragged edge when we say
     500 GPM at 1200 psi.
         DR. KRESS:  I think that is where the problem is.  We've got
     all sorts of margins floating around.
         MR. BELL:  Yes.  That word almost doesn't come up in our
     meetings and I think that is appropriate.
         Our view is the design is -- you provide a robust design to
     assure that you perform those design basis --
         DR. KRESS:  You should put the margins in your value in the
     first place and not say, well, we are going to put a value but we are
     going to come in lower to get margin.  You should have the margin built
     in there in the first place.
         MR. MAGRUDER:  Right -- and the licensee chooses --
         DR. KRESS:  And then we wouldn't have this argument.
         MR. MAGRUDER:  Right.  The Staff agrees.  The licensee
     chooses whatever margin they want.  I mean it is based on code guidance
     in a lot of cases, but whatever the licensee picks as their design value
     we believe is the design bases because it controls not only that piping
     but it controls the design of the rest of the system and other
     interfacing systems too, so that is why we feel that value is critical.
         DR. BONACA:  But there are always two values because there
     is one from the analysis that says 1000 psi and then there is the one
     that the DAE implements, the 8 in 1000.  He went back to some kind of
     guidance from the ASME code and said apply 10 percent or apply 20
     percent and then that was the value to each measure.  Now then he got
     something that was more capable than that so he can get that, so the
     question is -- there are three values and the question is which one do
     you pick.
         It seems to me that you are at both ends of that spectrum. 
     One says the process parameter, one says I don't know what --
         MR. MAGRUDER:  Well, we'd take the middle one, I think.
         DR. BONACA: -- so there is some confusion.
         MR. MAGRUDER:  To choose other than the process parameter
     you are sacrificing the principle about the tie to the safety analyses. 
     It is only the process variables that come from there.
         MR. PIETRANGELO:  It might be licensing basis --
         DR. KRESS:  We can hear you but he can't.
         MR. PIETRANGELO:  It is not that those other values aren't
     important and it's not that they are not described in the SAR.  Most of
     that is described in the SAR, but it is different from what is credited
     in the safety analysis.  We are trying to make 50.2 in the context of
     nuclear safety focus on fission product barrier integrity.
         We went through this whole discussion last year on 50.59 and
     I think we came down the right way when we came through that discussion. 
     We think that the guides we put together on design basis is consistent
     with that 50.59 guidance, okay? -- and again, just because it is not
     50.2 doesn't mean it is outside the licensing basis.  In fact, most of
     this stuff is, but it is in terms of how do you appropriately bound that
     term and characterize issues that come up in the field that matter or
     are of concern to us.
         DR. KRESS:  And George, this has nothing to do with the PRA.
         MR. PIETRANGELO:  Yet.
         DR. POWERS:  I am coming to wish the PRA did have something
     to do with it.
         DR. POWERS:  I think that we are going to have to move on.
         MR. BARTON:  Any other questions?
         [No response.]
         MR. BARTON:  I thank the Staff and NEI for their insights
     and opinion, et cetera, et cetera.  Thank you.
         I will turn it back to the Chairman.
         DR. POWERS:  The next topic we are going to deal with is the
     proposed resolution to Generic Safety Issue B-55, improved reliability
     of Target Rock safety relief valves.
         Jack, you are going to take us on this one?
         DR. SIEBER:  Yes, sir.
         For your information, the information that was provided to
     the committee was developed by the Staff and is in Tab 16 of the black
     book.  We also got a copy of that in the mail, I believe, and actually
     this is a pretty old issue.
         The first occurrence of this occurred in the 1970s and was
     described in NUREG-0462 in June of 1978.  By my count, and this may be
     different than yours, there's 22 older BWRs affected and it includes 166
     safety or power operated relief valves, all power -- pilot operator
     relief valves built by the Target Rock Company.
         I am aware of at least one PWR that has the same kind of
     valve that did not have the same kind of problems.  The early valves in
     about half of those plants were three-stage valves and in the later ones
     were two-stage valves, and the problems that existed at the time were
     spurious opening with excessive blowdown, failure to open at the set
     point -- in other words, the pressure went beyond the set point before
     it opened, and sometimes accompanied by excessive blowdown, a third
     problem was that it opened properly at the set point or within the
     tolerance of the set point but failed to reseat after blowdown, or
     lastly excessive leakage.
         It turns out that the older three-stage valves do not have
     the set point drift, they don't exhibit that to the extent that the
     two-stage valves will do.
         During this session the Staff will describe and discuss the
     issue, fixes, repairs, remediation, actually greater tolerance on the
     setting of the set point and the current status of this valve issue with
     the intent to try to close out this Generic Safety Issue.  I am sure
     they would like to do that today, at least with us, but I think that t
     have a little bit more additional time should we need to consider that,
     but certainly by the end of the year it would be appropriate to meet
     their goals.
         So I would like to introduce the Staff members.  Could you
     introduce yourselves and begin your presentation, please.
         MR. HAMMER:  Thank you.  Yes, my name is Gary Hammer.  I am
     in the Office of NRR.  I have with me my supervisor, David Terao, and
     there are several other NRR Staff here as well as Research, who can help
     me if you have questions.
         As you mentioned, this is an old issue.  You can tell that
     by the nomenclature, the B-dash and the 55.  They don't use that
     designation anymore for generic issues.
         DR. WALLIS:  They must be very old.
         MR. HAMMER:  Yes, I think the B-dash designation comes
     around the TMI time period, the late '70s.
         DR. WALLIS:  Most things that have the new nomenclature are
     pretty old too.
         DR. SEALE:  They are mature, Graham.
         DR. WALLIS:  I wish I were.
         MR. HAMMER:  On BWRs safety relief values -- this is just a
     real quick background -- are required for basically two functions.  One
     is overpressure protection and the other is the ADS function, which is a
     part of the emergency core cooling for a BWR.
         The Target Rock valves are pilot-operated valves with
     auxiliary actuators that are pneumatically powered.
         The original design was the three-stage design and the
     two-stage design was developed a little later.  Page 4 of your slides
     has these illustrations.
         You can see there is the main stage which has a big piston
     and a disk that controls the main flow stream in both of them.  One of
     these is shown at a right angle.  It is supposed to be the other way,
     but anyway, for illustration purposes, and here on the top of the valve
     is the air diaphragm actuator that is controlled by solenoid valves so
     that you can actuate the valves with external power regardless of what
     the system pressure is.  That is basically -- let's see.  Okay.  Let's
     go back.  I am not quite finished with that slide.
         Just as general statistics there are 11 BWRs that currently
     have the three stage valves; also, 11 have the two-stage valves.
         DR. SHACK:  Of the 11 with the two stage valves, how many of
     them have always had three stage valves?  Are these the original valves?
         MR. HAMMER:  I believe that is true, except for Limerick
     Units 1 and 2, which recently installed --
         DR. SHACK:  So it is nine out of the 11 are sort of
         MR. HAMMER:  That's correct.  Now there are some BWRs which
     are no longer operating, like Shoreham, Millstone and Browns Ferry 1,
     which also had Target Rock valves.  I think those were all two stage
         The newer plants have a little different design.  That is
     shown on page six of your slides, just for interesting background
     information.  This is what they look like.  They are much, much more
     massive than the pilot-operated valves.  They have very large bonnets
     and spring mechanisms.
         The pressure basically has to overcome the spring force in
     order to open.  There is no pilot involved and they also have the
     pneumatic actuators that physically compress this big spring, so those
     are quite a bit different in design.
         As mentioned earlier, there were several three stage
     inadvertent blowdowns back in the 1970s, which were most troublesome and
     basically when that happens you have an uncontrolled blowdown into the
     suppression pool, which causes the plant to be shut down.
         You basically have a small break LOCA that you are trying to
     manage, heating up the pool.  It was fairly undesirable.  It is not
     something that can't be coped with, with the available safety equipment,
     but nevertheless it was something that the industry wanted to remedy,
     and they designed the two stage valve as a modification for that.
         What they did is they essentially replaced the top works,
     which is this part of the valve.  This is a blowup of just the pilot
     stage of that other valve that I showed you a moment ago.
         And what happens is this parting line here where these bolts
     are bolted to this flange, basically you just hook the old three-stage
     actuating mechanism off and put on the new two-stage, and what they
     eliminated was basically a second stage, i.e., now it's only two, a
     pilot and a main, instead of having an intermediate which -- and it was
     this intermediate stage being actuated that was causing the blowdown
     problem.  So essentially they cured that problem with this particular
     fix.  There began to be problems with the two-stage design, though,
     and --
         DR. WALLIS:  You've turned it around or something?
         MR. HAMMER:  Beg your pardon?
         DR. WALLIS:  Turned it around.  The three-stage doesn't look
     like your picture, that's all.  You say you fixed the three-stage by
     making it a two-stage.
         MR. HAMMER:  Oh, okay.  Go back to --
         DR. WALLIS:  I have to sort of mentally turn it around to do
         MR. HAMMER:  Yes.
         DR. WALLIS:  Yes.
         MR. SIEBER:  Yes.
         MR. HAMMER:  Yes.  As I mentioned, this is not oriented
     correctly for illustrative purposes.  It really should be turned 90
     degrees to the right.
         MR. BARTON:  Then you have to turn your head to read the
         MR. SIEBER:  Yes.
         DR. UHRIG:  Is there an error in this footnote on page 7
     about Limerick?  This is opposite to what I understood you said.
         MR. HAMMER:  Oh, I'm sorry.  Maybe I did say it wrong.  They
     have had two-stage valves since their initial startup, but recently
     installed three-stage valves.
         DR. UHRIG:  Which is going the wrong way.
         MR. HAMMER:  Well, it turns out the three-stage valve has
     had better performance, so they've gone back to a previously known
     quantity and they've had success with it at another plant, and --
         DR. UHRIG:  I must have misunderstood you.  I'm sorry. 
         MR. HAMMER:  Yes.  Yes, you're right, it is going in the
     other direction.
         DR. UHRIG:  So the three is really the better --
         MR. HAMMER:  It has turned out to be the better.
         DR. WALLIS:  It has been replaced by a two-stage?
         MR. HAMMER:  Can you repeat that?
         DR. WALLIS:  It has been replaced by a two-stage?
         The picture that you showed us with the color, which I'm not
     sure is in here.
         MR. HAMMER:  Okay.
         DR. WALLIS:  That was used to replace the three-stage?
         MR. HAMMER:  This was the two-stage design, which is
     basically the top works that couple onto the old three-stage body.
         DR. SHACK:  Yes, they replaced the three-stage in some
     plants with two stages.  It was a fix.
         MR. HAMMER:  Right.
         DR. WALLIS:  But it was not a good fix, because the
     three-stage is really better.  Is that what I'm hearing?
         DR. SHACK:  All fixes are not good fixes.  We couldn't say.
         MR. SIEBER:  Well, they solved one problem and bought into
     another one.
         MR. HAMMER:  Right.
         DR. SHACK:  I guess that was my question.  What did they do
     for the three stages to fix the blowdown problem that -- when it didn't
     replace?  Change the maintenance procedures?
         MR. HAMMER:  Yes.  I'll get to that.  Yes.  They started to
     have problems almost as soon as they put in the two-stage valves with
     sticking.  They had quite the opposite problem.  They wouldn't open at
     the correct pressure, they would stick, and it had positive set point
     drift, and that became troublesome as well.
         So some people, like I noted a moment ago, there were
     several plants that kept the three-stage design.  For those GE issued
     some recommendations to raise the simmer margin, which is the difference
     between the valve actuation pressure and the operating pressure, and
     that made them less prone to leak and to inadvertently blow down.  They
     also improved the maintenance procedures and the testing frequency, and
     basically that has proved to be successful.  There have been very few
     blowdowns since those events in the seventies.
         But at the time the blowdowns were occurring, and shortly
     after that, into the early eighties, the staff prioritized a generic
     issue to investigate the problem, see how serious it was, and based on
     the three-stage concern of the blowdown, the increased LOCA situation,
     it was prioritized as medium.  But at the same time you started having
     these two-stage events were sticking, and that was also put into the
     generic issue, and really that's the issue that we're left with today.
         In a significant event which occurred in 1982 at Hatch
     involved upward set-point drift of all 11 valves, and that was
     troublesome to the staff.
         DR. UHRIG:  Was it a common mode failure?
         MR. HAMMER:  Yes, common mode failure.  The owners' group
     formed not long after that, and they began to investigate the problem,
     and they contracted GE to develop a resolution for the problem.  In
     1984, about a year later, GE issued their findings based on
     investigations of several valves, taking them apart, doing some
     laboratory work.  They even did some analysis work to see how
     significant the problem was, how much overpressure the system could
     withstand and still have a safe system.  And they came up with these
         They found that at that time it looked like more of the
     drift was coming from up in this area of the stem, called the labyrinth
     seal area.  This stem also has to lift up in order for the pilot to
     change position, and it looked like they were getting some misalignment,
     poor clearances and this kind of thing, so they issued some
     recommendations regarding that to improve those measurements and
     refurbishment when they were refurbished.
         As I mentioned, they did some analysis work, and they were
     able to demonstrate that even with 10-percent drift on all valves, you
     still had a significant amount of margin.  You could stay within the
     ASME allowable pressure of 110 percent of the design pressure, even with
     that kind of drift, which is a nice thing to be able to fall back on,
     but you're still left with this issue of compliance, the valves don't
     meet their technical --
         DR. WALLIS:  I need to ask you, that margin would exist
     maybe for other reasons as well, so you've now eaten it all up with this
     one cause.  Drift has now eaten up all the margin.  If it's 10 percent
     and you've gone from 100 to 110, drift has now eaten up all the margin
     that may have been there for some other reason as well.
         DR. SHACK:  No.
         DR. WALLIS:  Am I misunderstanding?
         DR. SHACK:  All it is is he just wants to make sure he
     doesn't overpressurize his thing, and so this thing has to lift before
     he overpressurizes the vessel, and all he's saying is that even with
     this drift, he's still going to relieve the vessel before it gets to its
         DR. WALLIS:  Yes, but I think what he was then saying was
     there isn't any margin left.  It was 10 percent before --
         MR. SIEBER:  You can't go any further.
         DR. WALLIS:  And now he's taken it all up with this drift. 
     There's no more margin left.  Is that still true, what I said?
         MR. HAMMER:  Well, it depends on how you define margins.  By
     definition, you still have significant structural margin; even if you've
     reached the ASME limit, you're allowed to reach that for upset events. 
     And so what you're doing is getting closer and closer to that limit.
         MR. SIEBER:  But the set point is set by tech specs, the
     tolerance, right?  The staff at one time for some plants -- from plus or
     minus 1 to plus or minus 3.  I'm not aware that they went any further
     than that.
         DR. WALLIS:  Percent?
         MR. SIEBER:  Percent.
         MR. HAMMER:  That's currently the situation.  We have a --
         MR. SIEBER:  So if you have a profile of plants that are
     regularly exceeding plus or minus 3 percent, my memory is that you sent
     in an LER, listed the valves and the as-found pressures, and sent them
     out to a shop, got them refurbished, tested, put them back in the plant,
     and you could do that refueling after refueling.  How does the staff
     tend to cause further improvement or at least compliance with the tech
         MR. HAMMER:  Right.
         DR. SEALE:  What's the process?
         MR. HAMMER:  Yes.  The process of filing an LER, that's
     interesting, and the LER's I've been seeing on this issue address fairly
     well the corrective action part of it, which is something that's
     important.  You don't want to just put them back in service having reset
     the set point and then have this happen all over again.  You want to
     have something that's going to make it better.
         MR. SIEBER:  Do you have data that shows that the number of
     exceedences of the set point is declining through the years?  This has
     been going on for 20 years.  Anything like that?
         MR. HAMMER:  Well, yes, I was going to present the data a
     little later.
         MR. SIEBER:  Okay.
         MR. HAMMER:  I'll show you where --
         MR. SIEBER:  We can wait until you get to it.  Okay.
         MR. HAMMER:  Okay.  Okay, there was one other bullet there. 
     After they issued this report identifying a labyrinth seal area as the
     primary area where this stiction was occurring, they started to see
     greater and greater occurrence of disk sticking, and going back to the
     drawing again, what they were seeing when they would take the valves
     apart and do microscopic examination, they would see corrosion in this
     conical seating area of the pilot disk, and they would do diagnostic
     tests to measure the force it took to pull it out, and they found some
     significant sticking in that area.  So that became more and more the
     focus, and this was after the issuance of that report.
         So -- well, I'll tell you what I need to do.  Let me show
     you that plants that have a three-stage valve.  This is what they --
     this is just some various statistical information showing you the
     numbers of SRV's.
         A lot of the three-stage plants rely primarily on the
     regular spring safety valves for overpressure protection.  Some have a
     few power-actuated relief valves, and the SRV's are in this column. 
     They're generally BWR 3's and 4's, with the exception of Limerick that
     we've recently added to this table.  It's got a lot of valves. 
     Two-stage plants are generally BWR 4's, with the exception of Pilgrim,
     which is a little different design, and they have only, as you see on
     the table here, four safety valves.  So they were the focus of GE's
     study in terms of a bounding situation.
         If you're going to have a problem as a result of sticking of
     valves, you would have the most effect on this one, because you'd be
     affecting the overall relieving capacity the most.  So -- and Pilgrim
     had had a significant amount of sticking.  So they -- so in 1984 they
     embarked on an interim solution.  They put in a new disk design,
     Stellite-21, that they felt would or should perform a little better.  It
     shouldn't have the -- they thought it shouldn't have the interactions of
     the carbides that were in the disk microstructure right at the seating
     area, and even though you would get the corrosion, these large carbide
     particles would not interact so negatively.
         DR. KRESS:  When they made this change, did they develop --
     when they made this particular change, did they develop a prototype of
     the new valve and stick it in a test bed and test it for quite a while,
     or did they just make the change and stick in the reactor?
         MR. HAMMER:  They -- well, I'd have to refresh my
     recollection about what exactly they did do.  We did get a report from
     them about their investigation.
         DR. KRESS:  Um-hum.
         MR. HAMMER:  I think it involved some actual laboratory
     testing to measure the sticking forces and this kind of thing.  But as
     I'll get into later a discussion about how the owners' group and the
     industry really came to understand the nature of this sticking problem a
     little better, that they really didn't understand at this point in time.
         So what they did was they came up with this interim fix.  At
     about the same time or a little after that the staff encouraged the BWR
     owners' group to also pursue a permanent resolution, whether it would be
     to adopt Pilgrim's interim resolution or to come up with a separate one,
     and along in 1985 they came up with a new disk material that they wanted
     to try, a precipitation hardening stainless, pH 13.8 MO, which they felt
     like would not corrode in this environment as much as the cobalt alloy,
     the Stellite alloy would.
         DR. POWERS:  What is it that precipitates in that alloy?
         MR. HAMMER:  Beg your pardon?
         DR. POWERS:  What is it that's precipitating in that alloy? 
     The pH 13?
         MR. HAMMER:  I don't think I can tell you what that is,
     really.  I don't know whether it's an austinetic or what it is.  I think
     it's a very hard alloy.  You needed a very, very hard material for this
         DR. WALLIS:  I'm looking ahead to the next two slides.  You
     seem to -- the history seems to be they get an idea, they try it, and
     after a few years it didn't work so well, so they get another idea, they
     try it, after a few years it didn't work so well.  They still seem to be
     in that state today.
         MR. HAMMER:  Well, yes, that's basically been the process,
     in a way of speaking, that they would start down some path and not be
     able to achieve much improvement, and then start on something else. 
     That's true.  We think they're in a little better shape today, though,
     than they were.  We'll go into that a little later.
         And they initially had some success with the stainless steel
     material.  That was installed in several reactors.  I think they put in
     like half of the complement for the plant in at a time, so they could
     have some basis for comparison with the Stellite data, and -- but then
     they started to see some sticking in that as well, and beginning in 1987
     I think they started to see that they were sticking just about as bad as
     the Stellite 6B disks had been sticking.
         I guess what I left out of here is what's happened to
     Pilgrim at about that time, and of course they've had a couple of cycles
     there by the late eighties, and it turns out their data was looking
     pretty good for the Stellite-21.
         DR. WALLIS:  So is anybody going to tell us if this is
     risk-significant or not?
         MR. HAMMER:  Beg your pardon?
         DR. WALLIS:  Is this risk-significant, all this sticking and
     not sticking?
         MR. HAMMER:  Yes, I'm going to try to address that.
         DR. WALLIS:  Get on to that, too?
         MR. TERAO:  This is David Terao.  I just want to be clear
     that at this point, this is still historical data; we haven't gotten to
     the fix yet.
         DR. WALLIS:  Just wonder where it's going.
         MR. TERAO:  Okay.  We're just talking about the problem so
     far.  We haven't told you what the solution is.
         DR. WALLIS:  Where we are today would seem to be important.
         MR. TERAO:  Right.  So if maybe we could just hurry through
     the --
         MR. HAMMER:  Okay.  Well, we'll pick up the pace a little
     bit, if that'll help.  Okay.
         In 1990 the BWR owners' group revised their plan again, and
     this is a key point.  They started to concentrate on the environment
     that the valves operated within, talking about the internal steam
     environment.  What they found was that there's not really steam in
     there, it's almost pure oxygen from the radiolytic gases that are
     generated in the reactor, and it's a stoichiometric mix of hydrogen and
     oxygen, and so it's a very corrosive environment.  And so they
     concentrated on that and said well, gee, maybe we can, you know, make
     the environment less corrosive, which is what they've done.
         DR. WALLIS:  How does it get to be that way?
         MR. HAMMER:  How does the radialysis occur, you mean?
         DR. WALLIS:  That all the oxygen and hydrogens have
     accumulated in this place rather than --
         MR. HAMMER:  Okay.  What happens is the valves are at a
     slightly subcooled temperature because --
         DR. WALLIS:  Is there condensation going on?
         MR. HAMMER:  Yes, there is condensation.
         DR. WALLIS:  -- breakup of the condensables, okay --
         MR. HAMMER:  The condensate just runs back out of the valve.
         DR. WALLIS:  That's what it is.  It keeps concentrating.
         MR. HAMMER:  Yes, and it keeps concentrating.  It only takes
     a very short time for it to reach a saturation condition.
         In parallel with that, the Owners Group about that time
     recommended a parallel approach which was to put in a pressure actuation
     system, which would externally actuate the valves with power.
         DR. WALLIS:  It's interesting -- excuse me -- if it had
     leaked enough, it would have just swept out this oxygen and you wouldn't
     have the problem, or am I --
         MR. BARTON:  Cheap modification.
         DR. SIEBER:  Now the installation of the pressure switches
     is contrary to the current version of the code for a self-actuated
     valve, is that correct?
         MR. HAMMER:  Yes.
         DR. SIEBER:  And would there be code relief for an exemption
     from that code requirement to rely upon the pressure switches as part of
     the actuating mechanism?
         MR. HAMMER:  You are asking whether the code would allow
     pressure actuation --
         DR. SIEBER:  Does it now and, if not, will the code be
     changed or will an exemption be granted?
         MR. HAMMER:  Okay.  I can give you a little status on that.
         We feel like, as I am going to cover here, we have reviewed
     the pressure actuation system and feel like it is a reliable system
     therefore we feel like it is sufficient to counteract -- counteract
     being the key word -- the effects of setpoint drift.
         Does it completely meet the code of record?  A lot of the
     old plants that we are talking about didn't have provisions in the ASME
     code for using power actuated relief valves in this way.  Now the later
     BWR-6s incorporate this into their design.  They take credit for the
     power actuation mechanism and so there's been discussions between the
     Owners Group and the ASME code and what they have basically come up with
     is that since this is covered in the later editions of the code what the
     licensee would have to do in order to get formal credit for this
     overpressure protection function are the pressure switches.
         They would have to reference the newer code edition and then
     resolve any inconsistencies between the new code and the old code that
     might exist in that area, so it is something that is -- I consider it a
     fine point.
         DR. SIEBER:  It is a path to a solution --
         MR. HAMMER:  Yes.
         DR. SIEBER:  -- but maybe not the most desirable path, but
     it's almost a combination hardware and legislative?
         MR. HAMMER:  Yes.  Well, something that can be said for
     their pressure switches, it is not, they are not susceptible to the
     corrosion sticking.  There are problems with electrical I&C systems, but
     not the same kind of thing that you have got going on here.
         Okay.  I was going to give you a little current status then
     on where we are at today --
         DR. SIEBER:  Let me ask one other question.
         MR. HAMMER:  Okay.
         DR. SIEBER:  I would presume that the phenomenon that is
     going on is corrosion and so now you put a pressure switch and then when
     you later on, at the next refueling or whenever you test the valves, you
     test them with the pressure switch and pneumatic mechanism intact, which
     then the valve would test okay.
         Does that mean you don't clean out all the corrosion and the
     next time you test it it doesn't work at all or just, you know, where do
     you end up in the further maintenance because a fix that comes in from
     the side, if you know what I mean, will cause somebody to say everything
     is just fine and then the maintenance won't occur and the corrosion gets
     worse -- is there a discussion or a plan that relates to that kind of a
         MR. HAMMER:  Well, I could tell you, I just looked at an LER
     from Browns Ferry.  Now Browns Ferry has put in the pressure switches,
     as you can see at the bottom of this slide.  They are one of the plants
     that have done that, yet they still credit the mechanical actuation of
     the valve.
         They took these valves off and tested them.  There was
     significant setpoint drift when they did the certification testing, and
     they had to report that even though they got the pressure switches.
         DR. SIEBER:  Okay, and so you sent them over to Wylie or
     someplace like that and do not use the pneumatics to test the valves?
         MR. HAMMER:  They do not, no.  When they test the mechanical
     setpoint, they are just testing that by itself.
         DR. SIEBER:  Will all licensees do that?
         MR. HAMMER:  That is required by the ASME code.  You are not
     allowed when you do the test to use a power actuated assist mechanism to
     determine what the setpoint is, if that is your issue.
         DR. WALLIS:  When they do a test, they take this thing away,
     they put it on some test facility and test it?
         MR. HAMMER:  Right.
         DR. WALLIS:  That's how they do it?  So do they clean it up
     ahead of time or sweep out the oxygen or do anything different?  I mean
     is thing as tested on the test the same really as the thing existing,
     having sat in this environment in the plant?
         DR. SIEBER:  I might be able to answer that.  They put it in
     a box, put the box on a truck --
         DR. WALLIS:  Seal it up --
         DR. SIEBER:  Yes, and seal it.  It's in plastic because it
     has been in containment.
         MR. BARTON:  It's contaminated --
         DR. SIEBER:  And it is sent 500 miles or 1000 miles on this
     truck, a whole bunch of them usually, and it goes into a lab so the
     environment that it is in is different.  It's not hot --
         DR. WALLIS:  So there's no pretest maintenance or anything
     like that?
         MR. HAMMER:  No.
         DR. SIEBER:  No.  It just goes in a bag.
         MR. HAMMER:  The setpoints, the as found setpoints that are
     reported are the first lift and we have seen a lot of setpoint drift
     when we do that, so apparently the shipping or the handling and that
     kind of thing doesn't have any effect in breaking the bond.
         DR. SIEBER:  Well, the valves themselves, the springs and
     all, are pretty strong.
         MR. HAMMER:  Yes, they are substantial components.
         Let's see.  Brunswick developed a process whereby they could
     apply this platinum coating with an ion beam process.
         The Owners Group tried something before, which was to
     disperse a small amount of platinum throughout the melt of the disk.
     Such that there is a very small, 0.3 percent.  And
     and that didn't change the metallurgical properties of the disk, but it
     did provide some platinum.
         Now that didn't work very well, but at the same time
     Brunswick developed their own process, whereby they applied this ion
     beam coating of platinum, and they've had very good results with that.
         We think there's a few reasons for that.  The platinum
     applied in that way gives a greater surface area and contact with the
     oxygen and hydrogen that you're trying to recombine, and it also
     provides a barrier between the oxygen and the underlying Stellite, so
     that the Stellite's not able to corrode.  They've had very good success
     with that.
         As I mentioned earlier, Pilgrim has also had good success
     with their Stellite-21, and Cooper has decided to also install
     Stellite-21.  They have a cycle of operating data with that, and that
     also looks fairly good.  And there is a short table showing you the
     status of what all of these plants that have two-stage valves are doing
     as of now.  They've either all installed pressure switches or new disks,
     one type or the other, and Fitzpatrick is the only one that hasn't done
     it yet, but they've committed to do that in the fall of 2000.
         Now as a -- they did get a few unexpected high pops on some
     of the ion beam disks, and they weren't really all that high.  I think
     they were in the 3 to 4-percent range, which is fairly low compared to
     some of the other data we had seen earlier with the Stellite disks.  But
     nevertheless they decided to investigate that and they found that some
     of their maintenance practices had not been followed properly.
         Some of those maintenance practices were performed by Target
     Rock personnel, so right now the owners' group has a corrective action
     program.  They're going to be auditing Target Rock at their corporate
     office to see if they have some breakdown in their organization or if
     there's some problem in the field with the way they're training the
     individuals that do the maintenance.  So they've assured us that they're
     going to get to the bottom of that, and they're going to do some of that
     this fall.
         So -- you had asked about the data, and I was going to show
     you, here's the way these valves were performing in the form of a
     histogram, a statistical sort of analysis, for the Stellite 6B disks,
     and this is data that was taken up until 1995, which was the point in
     time where we started to see some of the ion beam disks be installed. 
     So this is all data that we know looks pretty bad because of all the
     sticking.  You can see this is not a normal distribution.  It's highly
     skewed in the positive direction.  They've got a big group of outliers
     here that are even greater than 10 percent drift.
         DR. WALLIS:  What is your criterion for acceptability of
     something like this?
         MR. HAMMER:  Well, I guess the short answer is that the
     plants have a technical specification that says you've got to meet a
     certain value, and that's either plus or minus 1 percent or plus or
     minus 3 percent if they've justified that.  If they don't meet that,
     they're pretty much forced into taking corrective action to improve the
     performance until it does.
         DR. WALLIS:  So we could say looking at this --
         MR. HAMMER:  Coming up with a program --
         DR. WALLIS:  This is a significant number of plants or
     whatever that don't meet the tech specs with this kind of a picture.
         MR. HAMMER:  Right.  Right.  Yes, so there was -- yes, I
     mean, your point's well taken, there were so many data points that just
     didn't meet the criterion at all.  And this is a large number of data
     points, so this is statistically valid, and you can see the average
     drift there doesn't look that high.  It's 2.81, but it's got a big
     spread, and you can see that reflected by the standard deviation
     point -- I mean, over 4 percent.
         DR. KRESS:  Is a negative drift just as bad as a positive
         MR. HAMMER:  The negative drift is in the calculation of the
     standard deviation as well as --
         DR. KRESS:  Is it just as bad to have a negative drift as it
     is a positive?
         MR. HAMMER:  No.  Actually, in terms of overpressure
     protection, it's not.  But the ASME code for testing basically says that
     you have to meet a limit on both.  And the tech spec has a minus limit.
         DR. KRESS:  Okay.  So as far as regulatory space, it's just
     as bad.
         MR. HAMMER:  Right.  But it could be argued there's a
     different safety significance on the minus end --
         DR. KRESS:  Okay.
         MR. HAMMER:  Than the plus end, obviously.
         DR. WALLIS:  There's an adjustment -- you go ahead.
         MR. SIEBER:  This gets back to my earlier question.  If a
     valve fails to lift at its set point or a number of valves, you file an
     LER, mail it in, tell the lab or the manufacturer, you know, see what
     you can do about this.  They refinish the valve, you put it back in. 
     You could actually do that for many years unless somebody steps in and
     says this kind of performance cycle after cycle is unacceptable.  Has
     the staff or the region or anybody ever done that, where relief valves
     have consistently failed to perform as expected?
         MR. HAMMER:  Yes.  On my last slide I'll talk about the
     regulatory mechanisms that we have to take action.  But I think one of
     the important things that has happened in recent years was the --
     regarding problems like this -- was the issuance of the maintenance
     rule, which basically says that for a valve or any component like this
     the licensee is compelled to come up with an aggressive corrective
     action program to -- now that took effect in 1996, I believe, so a lot
     of this data we're looking at was pre-maintenance rule.  But I think
     with that and some of the other regulatory mechanisms we have, licensees
     are pretty much compelled to not live with this kind of a situation.
         DR. BONACA:  For these statistics, I mean, do you have many
     repeats for the same valve, or are they scattered through the whole
     population of these SRV's.
         MR. HAMMER:  It's fairly scattered.  It didn't seem to have
     any correlation between actual valve, valve position -- all plants had
     drift, significant drift at one point or the other.  It didn't -- it
     wasn't plant-related.  The average of -- if you take the average of all
     the drift, year by year, you can see it go up and down a little, but not
     a lot.
         DR. BONACA:  So if left in the field now the same valve
     could one day have a drift of 4 percent and another time have a drift of
     2 percent?
         MR. HAMMER:  From one outage to the other.
         DR. BONACA:  Well, assume that you left it, and there is a
     history -- I don't know if there is -- but would the same valve have
     always the same drift pretty much, or would it be --
         MR. BARTON:  No.  No, I don't think you'll find that.
         DR. BONACA:  Okay.  There was no correlation of that type.
         MR. HAMMER:  No, it didn't -- fairly random I guess is the
         DR. WALLIS:  How about repeatability?  It goes to a test
     stand, you pop it, then reseat it again and pop it again.  Do you do
     several?  You just pop it once.
         DR. SHACK:  It's the first pop that's the --
         MR. HAMMER:  It's the first pop that counts.  Now if you
     want to do a signature to find out if it drops on the second pop --
         DR. WALLIS:  Does it go back to its original set point, or
     does it -- what does it do if you pop it again?
         MR. HAMMER:  If you pop it again and it's the corrosion
     sticking, generally it goes back pretty close to what the set point's
     supposed to be.
         DR. WALLIS:  I would think it would.
         MR. HAMMER:  That's one of the signature tests that you can
     do to see if it's corrosion sticking.
         MR. SIEBER:  Now this 6B data is pretty early data.
         MR. HAMMER:  Yes, this is pre-'95, and it's --
         MR. SIEBER:  And the other ones you're going to show us are
     later on?
         MR. HAMMER:  Right.  Right.  Yes --
         MR. SIEBER:  Why don't we look at that?
         MR. HAMMER:  Right.
         DR. WALLIS:  There's a correlation with time or with
     material, one or the other.
         MR. SIEBER:  Or both.
         MR. HAMMER:  Here's the histogram for the IM beam data.  You
     can see --
         MR. SIEBER:  Now this is pretty late.  Right?
         MR. HAMMER:  It's about the same size chart, which is
     unfortunate.  I mean, this is -- you can see the -- but this only is
     like a, you know, goes from minus 6 to 6, and all of the data is between
     4 and 4.
         DR. KRESS:  Is that considered better performance than the
     other one?
         MR. HAMMER:  Yes.  Yes, this is much better performance, and
     you can see it reflected in the average drift, which means that we've
     got an equal or more number of minus drift than we do plus drift by
     having a negative average.
         DR. WALLIS:  I was going to ask you about that, because this
     drift is from some zero.  Now the zero is determined by having been
     tested at its set point prior to installation and adjusted in some way?
         MR. HAMMER:  Yes.
         DR. WALLIS:  How closely to zero does it get when it's
         MR. HAMMER:  Well, they're required to set it within plus or
     minus 1, plus or minus 1.  So you could have some scatter within the
     plus or minus 1, and unfortunately that -- you suffer that penalty
     later, maybe.  But a lot of facilities are able to set it tighter than
         MR. SIEBER:  Yes, but it is difficult, and it takes a lot of
     pops.  On the other hand, what it does is give you a spread within the
     distribution that reflects your inability to set it at exactly zero or
     at exactly the set point, along with whatever's happened over the
     18-month or 2-year cycle.  Just makes it wider.
         DR. KRESS:  Can you superimpose that other slide, the
     earlier one, or just set it up there along with it, just to --
         MR. HAMMER:  Actually I have a slide where I squeezed all
     three of these together.  Maybe that's --
         DR. KRESS:  Now if I were looking at the top slide and the
     bottom slide, and consider some sort of a statistical significance test
     of it, I would judge them equally as bad, probably.
         MR. HAMMER:  You would judge --
         DR. KRESS:  I would judge the second slide equally as bad as
     the top one if I did a statistical analysis of it.
         DR. SEALE:  The second one or the third one?
         MR. HAMMER:  I'd have to differ with that.  This is, as I
     mentioned, this has got drift all the way out here.  There's a tail
     that's not shown on this --
         DR. KRESS:  That's because you've got a lot more data.
         DR. POWERS:  Let's say, Tom, that you were -- that these are
     normally distributed for fun.
         DR. KRESS:  Just for fun would help.
         DR. POWERS:  Okay.  To what questions you would ask, what
     question you'd ask, are the means from the same population?
         DR. KRESS:  Yes.
         DR. POWERS:  And --
         DR. KRESS:  A statistical --
         DR. POWERS:  That would be a student's T test.
         DR. KRESS:  T test.  And you're going to do an analysis of
     variance, and ask if the variance is significantly different.
         DR. POWERS:  Yes.
         DR. KRESS:  And --
         DR. POWERS:  That's an F test.
         DR. KRESS:  Yes, F test.  I think your probably get
     something like well, they're pretty close to each other.  But without
     doing it I'm not sure.
         DR. POWERS:  Yes.
         DR. WALLIS:  This is because of the inference of the small
     number of tests in the bottom figure.
         DR. POWERS:  No, it's the -- the difficulty lies in the size
     of the standard deviation, and the fact that they're from different
     sample sizes, you can compensate for that.
         DR. KRESS:  You can compensate.  That's part of the --
         DR. POWERS:  The problem really is the standard deviations
     are so big here.
         MR. HAMMER:  Yes.  Well, when I computed these standard
     deviations, I followed the rule that you see in textbooks of including
     in the formula N minus 1 points rather than N if it's a number less than
         DR. SHACK:  He's not arguing over that computation.  He's
     now arguing over the significance of the difference that you see between
     the two, which is a different statistical test.
         MR. HAMMER:  I'm not sure.
         DR. POWERS:  There are two questions that you have:  Are the
     means significantly different? and are the standard deviations
     significantly different?  And I guess I have to admit, Tom, I think the
     means will come out to be the same within a substantial confidence rate. 
     I will bet that the standard deviations don't.
         DR. KRESS:  Yes, it looks like the standard deviation is
     going to be smaller.
         DR. POWERS:  Yes, that's because the number in the F test,
     anything -- get two or three in the --
         DR. KRESS:  But it's not much of an improvement.
         MR. SIEBER:  No, but there's one that they haven't showed
     yet, which is the application of the pressure switches, at 3 percent,
     everything else disappears.
         DR. POWERS:  If we looked at the bottom --
         MR. SIEBER:  Tolerance of the electrical equipment.
         DR. POWERS:  And compared to the top one, I say that those
     two are different.
         DR. KRESS:  I would definitely say so.
         MR. HAMMER:  I have to apologize.  I had a cold earlier this
     week, and I'm having an awful hard time hearing you gentlemen.  Is there
     a --
         MR. SIEBER:  I think what we're searching --
         MR. HAMMER:  Some question that I could --
         MR. SIEBER:  Yes, I think what we're searching for and we're
     not quite getting it because it probably isn't there is that we're
     looking for a correlation that would tell us that through history, time,
     all these fixes, the problem is getting better --
         MR. HAMMER:  Yes.
         MR. SIEBER:  Getting solved.
         MR. HAMMER:  Okay.
         MR. SIEBER:  And we really don't have that, and we're -- I
     think that's what we're all trying to get at.
         MR. HAMMER:  Okay.  All right.
         DR. SHACK:  Well, he thinks he's demonstrated it here, and
     the question is, has he?
         MR. SIEBER:  Has he, and the answer is probably not.
         MR. HAMMER:  Yes.  Well, you know, we thought about this,
     how would be the best way to present this data in some concise fashion,
     and we tried a different approach.  Let me show you a backup slide that
     I've got, and actually we got this suggestion from Mr. Sieber last week
     to try to plot this kind of a -- let's see, it needs to go a little
     higher.  Okay.
         Now this has got some -- this isn't a perfect representation
     of -- because there's something arbitrary about it.
         What I've done is I've tried to plot percentage of set
     points that were greater than plus 3.  Well, the plus 3 is an arbitrary
     basis for comparison.  So if I'd picked 4 or 5, then a lot of these
     points that are down here are all of a sudden going to fall to zero.  I
     think you have to realize that when you look at this.
         So it's not a -- but the thing you can see is that all of
     these round dots are way up here in this range where you had, if you
     were using a plus 3 percent criteria, all of these points were, you
     know, in the 30 to 50 percent range, were above that --
         MR. SIEBER:  It would also appear --
         MR. HAMMER:  And here are the other materials down here.
         DR. UHRIG:  The ion beam suddenly went bad in '98.
         MR. HAMMER:  Well, you see, that's the funny thing about
     this plot.  This is only based on a couple of points, because, you see,
     what you do when you try to divide it by year, you don't have very many
     points per year.  So now you've got a really heavy weight on a single
         MR. BARTON:  That's right.
         MR. HAMMER:  And the other thing that's not reflected in
     this kind of a representation is yes, you've got 20 percent failed this
     criteria, but this valve was only -- I think there was two valves.  One
     was 3.1 and one was 3.9, or something like that.  Some of these valves
     were -- you've got to remember were greater than 10 percent.
         DR. SHACK:  How many cycles of the ion beam have these
     plants been through?
         MR. HAMMER:  I think Brunswick has had three on all -- both
     of their reactors.  Hope Creek has two -- one cycle, excuse me, one
     cycle at Hope Creek.  Fermi has installed them --
         MR. BARTON:  They're in their second cycle.  They had some
     last cycle and they tested them, and one of them was a 3-percenter -- a
     3 point something.
         MR. HAMMER:  Oh, I was not aware of that.
         MR. BARTON:  Now they're in their second cycle.
         MR. HAMMER:  Okay.  Now they installed a full complement, I
         MR. BARTON:  Yes, they did.
         MR. HAMMER:  Okay.
         MR. BARTON:  They got all 15 ion beams.
         MR. HAMMER:  Okay.  And we were expecting that data a little
     later this fall, I believe.  Does that sound correct?
         MR. BARTON:  Their outage is next spring.
         MR. HAMMER:  Oh.  Okay.  Okay.  So we won't have that.  But
     we're hopeful that --
         DR. SHACK:  A platinum coating is not terribly wear
     resistant, and it's not very thick.
         MR. HAMMER:  Yes, it's --
         DR. SHACK:  The ion beams drives it in a little ways.
         MR. HAMMER:  Yes.  My understanding is it's only a few
     molecules thick, and it has to be reapplied each cycle.
         DR. SHACK:  Oh, they do reapply it each cycle.
         MR. HAMMER:  Um-hum.
         DR. SHACK:  Yes, so the ion beam, just make sure it lasts
     the cycle.
         MR. BARTON:  Gets it through a cycle.
         MR. SIEBER:  Now this will be a challenging question, but
     can you make a conclusion about anything by looking at that, and if so,
     what would your conclusion be?
         MR. HAMMER:  Okay.  Yes.  In my thinking, realizing what
     I've done here and how I've contrived this, it does show that -- some
     significant improvement, I believe, over the previous valve performance,
     all of these round dots up here, Stellite 6-B being so high, I believe
     that that's what that tells me, especially realizing that some of these
     exceedences here over 3 percent were so slight, and many of these were
     so great.
         That coupled with this thing, which tells me that I've got a
     tighter band of the data around zero -- well, I can say that about the
     ion beam.  The Stellite-21 is still skewed to the right, but it's bound
     by a much smaller band.  Now that's reflected in the standard deviation
     here.  You've got a much lower number for both of these than you do --
     so those two together help me with that.
         Mary Wegner, who was formerly with AEOD, and who used to
     compile data and look at it and analyze it and stuff, has been kind
     enough to -- even though she's not in AEOD anymore -- to put together
     another viewgraph for me.
         This is a backup slide I don't have in the package, but
     she's attempted to plot the averages of all of the plants -- there's a
     different symbol here for each plant -- by year.  Now this is just
     average of all of the valves, so, I mean, it won't tell you anything
     about any particular test.
         So you can see how that moves it around and this is the
     average of the averages, if you will, this line that goes up and down,
     and this has basically come back down because what happened in '97 and
     '98 was we added in some ion beam data.
         DR. WALLIS:  Well, this looks a bit like the story that you
     presented early on, that every three or four years there seems to be
     some new thing that goes wrong and it goes up again.  Here there is no
     consistent trend over this period of time.
         MR. HAMMER:  Right, and this probably isn't the best type of
     a statistical analysis to look at because it doesn't tell you the spread
     of the data.  It's just an average.  All of these points are just
     averages and then this is the average of the averages.
         DR. WALLIS:  So any measure of an average against some
     criterion, you are suggesting 3 percent might be a criterion, and it
     looks here as if at least half the points are most of the time above
     that 3 percent, so it's not all that reassuring.
         DR. SIEBER:  I am not sure that is a really good way to try
     and get at what we are trying to understand.
         DR. WALLIS:  You've plotted it some other way to look
     better, is that what you are saying?
         MR. HAMMER:  To give you some idea -- I didn't know you
     would want to get into this to the degree that we have, but I also
     brought along another histogram.  Now this is not a Target Rock valve. 
     This is one of the spring safety valves, the Dickers model, that was one
     of those that I showed you earlier.
         Now you can see out here they have some valves, some
     population that's greater than 3 percent, but they have an equal amount
     that is less than three.
         The thing that is interesting about this is -- I mean if you
     want to say that Target Rock is on a par with these or not, you know, I
     mean you could make that comparison, but the interesting thing is that
     there is the spread.  It is centered around zero and they are not
     perfect but these are considered to be really nicely performing valves.
         DR. WALLIS:  It is kind of interesting that zero is one of
     the least likely of these values.
         MR. HAMMER:  Yes.  Right.
         DR. KRESS:  I think that is an artifact.  You have to really
     draw it with a perf through the thing, use all the data to fix the
     curve. That is not a double mode curve, I'll bet you money.
         DR. SIEBER:  Maybe you could go to your conclusions?
         MR. HAMMER:  Okay.  We need to get moving here.
         Based on all of that, we believe that based on the success
     for the three stage valve since they have improved the performance since
     the 1970s, we don't believe there is any improvements that are necessary
     at all for the three stage valves.
         They were the valve that this issue was initially
     prioritized for.  The improvement is far beyond the value impact
     statement that was made in the assumption for the prioritization so we
     feel like we have got a pretty good case for closure on that.
         For the two stage valve, we are not saying that the
     performance is perfect, but we feel like because of the large margin in
     the system, which is rather tolerant of setpoint drift it is not a very
     safety significant phenomena.
         DR. KRESS:  The margin to the design pressure of the piping?
         DR. SIEBER:  Right.
         MR. HAMMER:  Yes.
         DR. KRESS:  Are there other functions of these valves like
     rate of depressurization needed to avoid something like a
     pressure-driven dispersion of material in case of an accident?  Is the
     rate of depressurization important and does this affect the rate.
         MR. HAMMER:  Rate of depressurization -- you mean once the
     valves open --
         DR. KRESS:  Yes.  I am assuming you pop open all the valves
     at some pressure.  I presume the rate is high -- the pressurization is a
     little higher because it is at higher pressure because they are
     sticking -- well, some of them not open at all.
         DR. POWERS:  Well, it's all going to be tripped -- I mean if
     there is automatic depressurization, they are going to be open.
         MR. HAMMER:  Now the automatic depressurization functions --
         DR. KRESS:  It doesn't affect the ADS function is what you
     are saying?
         MR. HAMMER:  It doesn't affect the ADS function at all, yes.
         DR. SHACK:  This is really a setpoint -- you know, this is
     pressure vessel overprotection.
         DR. KRESS:  It's strictly overpressure protection we are
         MR. BARTON:  All these don't have to lift either, you have
     got -- there's extra valves there.  You may only need nine valves but
     you have got 14 on the steam line.
         DR. KRESS:  Yes, but a lot of the time it is just one of
     them that does that job, because it's set at the low value.
         DR. POWERS:  I think you are thinking about PWRs.  These are
     BWR things.
         MR. BARTON:  Yes, this is BWR stuff.
         DR. KRESS:  I knew that.
         MR. BARTON:  All I am saying is if some of these stick, you
     are over-designed, to put more valves on the steam line than you need --
         DR. KRESS:  I caught a few of them.
         MR. HAMMER:  Okay, and the third bullet there is we feel
     like the industry actions have significantly improved or counteracted
     the effects of setpoint drift by using the ion beam platinum or the
     stellite 21 disks.  We feel like both of those things will be performing
     rather well right now and even though not formally credited for
     overpressure protection, it is sort of a -- I think it's been called a
     suspenders and belt type thing.
         You can add, you can increase the reliability.  It is a
     reliable system.
         So based on that, the Staff is not recommending any new
     regulatory requirements as a result of this issue, and we have got a
     fallback.  If the setpoint performance does not continue to be adequate,
     we feel like there are already sufficient regulatory mechanisms
     available to pursue any needed improvements -- for example, adding
     pressure switches.
         If valve disks just don't perform like we see them
     performing now, and they have been performing at Brunswick and Hope
     Creek, and the pressure switch option is available and, you know, we
     could pursue that with the industry and we feel like we've got three
     mechanisms for pursuing those things and there are even other things
     that I haven't listed such as the general design criteria and some other
     things but here are the three big ones, I believe -- the Appendix B
     criterion, which is quality assurance, and, as I mentioned earlier, the
     maintenance rule, and there is also 10 CFR 50.55(a) codes and standards,
     which comes into play because that governs the inservice testing
     requirements for the valves.  If you don't meet those requirements, you
     have to find out the cause and take corrective action.
         So this is what we are proposing.  I guess that is all the
     slides I have.
         DR. SIEBER:  I might point out, while we are wrapping up,
     that Mr. Joseph Ondish, BWR Owners Group, is here.  He tells me he
     doesn't plan to make a presentation but I wanted to acknowledge he is
         MR. HAMMER:  I guess that is all we have right now.  We
     would be glad to answer any further questions.
         DR. SIEBER:  Are there any further questions from the
         DR. KRESS:  These valves -- are they tested every cycle,
     fuel cycle?  How often are they tested?
         MR. HAMMER:  I'm sorry?
         DR. KRESS:  How often are these valves tested?
         MR. HAMMER:  Oh, how often are they tested?  The ASME code
     generally governs the frequency, but in the case of these BWRs, and this
     goes back to the three stage problem, they test them more frequently
     than the code requires, which basically puts them into testing every
     other cycle.
         DR. KRESS:  Every other?
         MR. HAMMER:  So every two cycles they will have tested all
     of the valves.
         Now there is a penalty portion of the ASME code -- now this
     is interesting.  If you fail a test, you have got to pick two more and
     test them for every one that fails, so what happens at a lot of plants,
     they send all of their valves every outage because they know they are
     going to have some --
         DR. KRESS:  I understand.
         MR. HAMMER:  You don't want to have that on your critical
     path, having to yank another valve off.
         DR. KRESS:  Do any of the valves every stick closed and not
     open at all?  They've got this percent drift, but do they ever stick
     completely closed and not open at all?
         MR. HAMMER:  We have never seen that.  We have seen some
     that were stuck to the point where if you pressurized it high enough to
     lift it you would have exceeded the design pressure --
         DR. KRESS:  The design pressure --
         MR. HAMMER:  -- and so they just stopped the test at that
     point and say its adrift, but then in later diagnostic tests they take
     those valves apart and they use a pulling mechanism and they measure the
         Now that has been done in a lot of cases, to see just what
     the forces were, so the answer is no.  If the pressure got really high,
     they would open.
         DR. KRESS:  I think most of those valves have a way to
     manually open them if you have to?
         MR. HAMMER:  Yes.  Yes, the operator can open them simply by
     turning a switch if he wants to with the electrical, pneumatic
     actuators, and we mentioned earlier the ADS function, which is
     completely automatic.
         DR. KRESS:  What I am searching for is to see if I can find
     any risk significance to this problem and for the life of me I can't
     find any.
         MR. HAMMER:  Well, it is interesting.  I think the more
     important function that the valves do perform in the ADS function.
         If you didn't have that, there would be certain LOCAs that
     you would have trouble --
         DR. SIEBER:  There may be some risk significance associated
     with failure to reseat, just continue to blowdown to the suppression
     pool, but I don't know what that number is, but that problem has
     basically been solved a number of years ago.
         MR. HAMMER:  Yes.
         DR. SIEBER:  The failure to reseat.
         MR. HAMMER:  Well, in terms of risk significance on BWRs for
     LOCAs, it is generally a small contributor to the overall core damage
     frequency, and that is mostly because of all the makeup systems that you
     have on a BWR.
         DR. WALLIS:  When we make decisions like this, I think we
     should look at the consequences.  You have given us this new information
     that they test all the valves each cycle?  That means they have to have
     spare valves so they can ship away one group and leave the others on,
     put the other ones on?
         MR. HAMMER:  No.  They usually -- now some plants do have
     spares but not all.
         DR. WALLIS:  So now if you close this issue, are they going
     to stop testing all the valves?  Are you going to stop getting the
     information --
         MR. BOEHNERT:  No.
         DR. WALLIS:  Or are they going to keep testing all the
     valves every cycle? So you are going to keep getting information about
     valves --
         MR. HAMMER:  Yes.
         DR. WALLIS:  -- if you close the issue.
         MR. HAMMER:  Yes.
         DR. WALLIS:  The same way you do today.
         DR. SHACK:  They didn't pass any new rules.
         DR. WALLIS:  Yes, but I mean --
         MR. HAMMER:  Right.
         DR. WALLIS:  -- there might be some incentive after the
     issue is closed to say the valves are no longer such a problem, we won't
     test so many --
         MR. HAMMER:  We are not proposing to relax any requirements
     at all.
         DR. SIEBER:  My impression is that if you close the issue
     nothing will change.  If that is incorrect, maybe you can --
         MR. BARTON:  Hopefully the valves will get better.
         DR. SIEBER:  If we start using more platinum with the
     pressure switches on.
         MR. HAMMER:  Right.
         DR. SIEBER:  But is that or is that not the case?
         MR. HAMMER:  Yes.
         DR. SIEBER:  Nothing will change?
         MR. HAMMER:  Yes.  In my discussions with the Owners Group
     they have advised me that they plan to continue with their effort to
     evaluate the setpoint drift, pursue any fixes that are necessary in the
         DR. SIEBER:  Any further questions?
         [No response.]
         DR. SIEBER:  If not, I would to thank the gentlemen from the
     BWR Owners Group and the Staff for their presentation and turn it back
     to you, Mr. Chairman.
         DR. POWERS:  Okay. What I want to accomplish tonight is to
     try to hit each one of our Class A letters, okay?  I don't think I
     intend to do anything at all on the Class B letters tonight; that is,
     GSI-148, the B-55 issue and the design basis issue we won't get to at
         I guess we can get off the transcript at this time.
         [Whereupon, at 4:22 p.m., the meeting was concluded.]

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