United States Nuclear Regulatory Commission - Protecting People and the Environment

462nd Meeting - May 6, 1999

                       UNITED STATES OF AMERICA
                     NUCLEAR REGULATORY COMMISSION
               ADVISORY COMMITTEE ON REACTOR SAFEGUARDS
                                  ***
       MEETING:  462ND ADVISORY COMMITTEE ON REACTOR SAFEGUARDS
                                (ACRS)
     
                        U.S. Nuclear Regulatory Commission
                        Two White Flint North
                        Rockville, Maryland
                        Thursday, May 6, 1999
         The subcommittee met, pursuant to notice, at 8:30 a.m.
     MEMBERS PRESENT:
         ROBERT L. SEALE, Chairman, ACRS
         DON W. MILLER, Member, ACRS
         DANA A. POWERS, Member, ACRS
         WILLIAM L. SHACK, Member, ACRS
         ROBERT E. UHRIG, Member, ACRS
         GRAHAM B. WALLIS, Member, ACRS
         MARIO FONTANA, Member, ACRS
         THOMAS S. KRESS, Member, ACRS
         GEORGE APOSTOLAKIS, Member, ACRS
         JOHN J. BARTON, Member, ACRS
         MARIO V. BONACA, Member, ACRS.                         P R O C E E D I N G S
                                                      [8:30 a.m.]
         DR. POWERS:  The Committee will come to order.
         This is the second day of the 462nd meeting of the Advisory
     Committee on Reactor Safeguards.  During today's meeting the Committee
     will first consider the proposed resolution of Generic Safety Issue
     GSI-158, performance of safety-related power-operated valves under
     design basis conditions.  After that, if anybody thinks I know exactly
     what's going to happen in the meeting, I've got news for you.  It's a
     little confused.
         I think we will get a status report on Generic Safety Issue
     165, spring-actuated safety relief valve reliability, and I think we
     will get a status report on fire protection functional inspection
     program.  Then we're going to hear about the Westinghouse Owners' Group
     proposal for modifications of core damage assessment guidelines and
     postaccident sampling system requirements, which has been the subject of
     a subcommittee meeting.  The balance of the day will be devoted to
     proposed ACRS reports.
         A portion of today's meeting may be closed to discuss
     Westinghouse Electric Company proprietary information.
         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 statements or requests for time
     to make oral statements from members of the public regarding today's
     session.
         A transcript of portions of the meeting is being kept, and
     it is requested that speakers use one of the microphones, identify
     themselves, and speak with sufficient clarity and volume so they can be
     readily heard.
         To begin the morning session I want to make the Members
     aware that David Diec's last meeting has been held with us, and I want
     to take this opportunity to acknowledge the important work that he did
     with us and excellent work that he did with us in the course of his nine
     months with the Committee.  I know that he worked on several letters and
     reports with me and was an outstanding example of an engineer in
     training.
         MR. DIEC:  Thank you very much.
         DR. POWERS:  Now I want to introduce a note of sadness for
     the Committee.  We are losing a longtime member of the team, seven
     years, Donna Anderson has been a member of our team here, and she has
     discovered greener pastures to go to.  I can't imagine there would be
     such a thing.  Actually, I want to tell you how cruel and mean Donna is. 
     She made me write a letter of recommendation for her to leave.
         [Laughter.]
         MS. ANDERSON:  Thank you very much.
         DR. POWERS:  Donna's contribution to the Committee goes
     beyond mere technical skill and ability.  I have personally been
     impressed with exactly her team spirit and team contributions.  I know
     that the first time that the Committee met in front of the Commission
     while I was a Member that it was Donna who came back and gave me the
     best, most authoritative review of our performance, and it was
     immediately obvious to me that she had a real interest in this Committee
     doing well and that it was important to her to contribute to this team.
         After that initial exposure, I have seen numerous examples
     of where Donna was working for the best interests of the Committee as a
     whole and had a spirit of teamwork that set an example for us all.  So I
     thank you very much, Donna.
         [Applause.]
         MR. BARTON:  I am going to really miss her.  She's the only
     one that can read my writing.
         [Laughter.]
         DR. POWERS:  Let's see, may I ask are there any Members that
     have any opening comments that they want to make?
         Seeing none, we'll move to the first item of business, which
     is the proposed resolution of Generic Safety Issue 158 and, Dr. Bonaca,
     I think that you're the cognizant Member.
         DR. BONACA:  Correct.
         Yes, Mr. Chairman, we have Frank Cherny here of the staff to
     present to the ACRS the basis for the staff proposal to close GSI-158
     without imposition of new requirements on licensees.
         MR. CHERNY:  Good morning.  Before I start, I think John
     Craig wanted to make a few introductory remarks.
         MR. CRAIG:  Good morning.  As you know from the
     presentations that you've had, the past presentation by myself on
     generic issue process and the one from Ashok earlier in the week on the
     things that the office is doing with respect to the prioritization and
     self-assessment in the budget, our plates have been very busy.
         I'd like to apologize to the Committee for the switch in the
     agenda.  As we got ready for the presentation and got down to the final
     hours with respect to GSI-165, it became clear that we difficult have
     enough time to just turn the crank and make it happen.  We are prepared
     following Frank's presentation on 158 to go over an overview, a summary
     of the issues.
         Nothing has changed with respect to the proposed approach to
     resolution, but rather than come down here not fully prepared for the
     presentation, we thought it would be better to request that it be
     delayed.  So we can talk about 165 following the discussion on 158.
         As you know, some of the generic safety issues are older
     than others.  We're going to be talking hopefully about Generic Issue 23
     on coolant-pump seals in a few weeks.  We're working to identify I guess
     closure plans for the other generic issues as we discussed a few weeks
     ago, including those that were going to be addressed by the IPE program
     and some the IPEEE program.
         Generic Issue 158 involves inputs from all of the offices. 
     We have now staff from Research who used to be in AEOD.  In addition to
     the support in the Division of Engineering, Technology, and RES, we have
     support from two other divisions within Research and from NRR and their
     representatives here today that are prepared to answer any questions
     that you might have related to the various aspects of this issue.
         So with that I'll turn it over to Frank Cherny.  Thank you.
         DR. POWERS:  John --
         MR. CRAIG:  Yes.
         DR. POWERS:  Before we go on, you indicated that you've
     got -- are putting together a plan of attack of all those outstanding
     GSIs.
         MR. CRAIG:  Yes, sir.
         DR. POWERS:  Is there an appropriate time for us to hear
     about that plan of attack?
         MR. CRAIG:  Since Jack Rosenthal has the lead for that, now
     the answer's clearly yes, and having said yes, I'll have to come up with
     a date.  But we'll do that, and we'll get back to you to do that.
         DR. POWERS:  Yes.  I think we've asked a couple of times
     where some sort of an overview for our own planning purposes and
     understanding, because otherwise we keep harping on what happened to
     this, what happened to this --
         MR. CRAIG:  Right.
         DR. POWERS:  And so if you could pick a time when you're
     comfortable with saying here's what the overall plan of attack, because
     we need to get those off the books so we can get into this new process.
         MR. CRAIG:  Exactly.  We'd be glad to do that.
         DR. POWERS:  That would be useful for us, again, not looking
     for something with a tremendous amount of formality to it, but rather a
     planning kind of discussion.
         MR. CRAIG:  We'll be able to do that.
         DR. POWERS:  Thank you, John.
         MR. CHERNY:  Okay.  We're here to discuss the staff's basis
     for proposing to close GSI-158.  What we're going to do this morning is
     present a number of elements that go into that basis for closure.  We're
     going to try and relate this GSI to the new GSI process that we were
     just talking about, and I'll go through a little bit on that.  We're
     going to talk about staff actions and activities that have taken place
     while we've been working on this issue, which have led us to the
     conclusion that we should close it.  We're going to talk about some
     requirements that are in place today that were not in place a few years
     back when analogous concerns were raised on motor-operated valves and
     resulted in the issuance of Generic Letter 89-10.  We're going to talk
     about some industry activities and initiatives that are going on related
     to these types of valves which are in the context of DSI-13,
     codes-and-standards type activities and other initiatives.
         Okay.  Just by way of a little background, the scope of this
     GSI is particularly broad.  It contains three valve types, pneumatic or
     air-operated valves, solenoid-operated valves, and hydraulic-operated
     valves.
         The basic safety concern that was raised or potential for
     safety that was raised at the time of the request to prioritize it, and
     that was for the potential for such valves to not perform satisfactorily
     under design-basis conditions based on the MOV experience that we
     learned from Generic Letter 89-10 and its predecessor, both in 85-03,
     this issue was prioritized in 1994, which we were just talking about how
     long some of these issues have been on the books.  This one would be a
     relatively young issue in that regard.
         Without going into great detail about the prioritization,
     the GSA was prioritized as medium.  It was not a medium issue based on
     the value-impact calculation, it was based on an estimated change in CDF
     of 1 times 10 -5 per reactor year at that time.
         Back in March, at least I think it was in March, we briefed
     the committee on the proposed change in the process for handling GSIs,
     the new management directive that is going to have a number, 6.4.  Built
     into that process, as you may recall, was something -- you know, there
     were a couple of early screenings that take place in that process, one
     of which is an initial screening which involves among other things a
     rather rigorous review of the proposed issue by a screening panel.
         It is our view today that if this issue was coming in today
     with a request to be prioritized and we applied the new, revised
     process, the issue would probably have received a much more initial
     review and we think would have been screened out as not being either a
     cost beneficial safety enhancement issue or a burden reduction issue.
         The concern about valve performance under design basis
     conditions is very similar to the MOV concerns resolved with the
     issuance of Generic Letter 89-10.  This Generic Letter was issued to
     ensure that licensees take actions necessary to comply with existing
     regulations.
         The POV operability under these same design basis conditions
     is also largely a compliance issue, thus we feel that under the proposed
     new management directive it probably would not have made it into the
     process at all.  It probably would have been kicked out in the early
     screening.  Now that is not to say that that is the real reason we are
     closing the issue, but I think that's interesting background.
         DR. SEALE:  The burden reduction screening requirement or
     whatever you want to call it, can that be either positive or negative?
         MR. CHERNY:  Well, the burden reduction initiatives are, at
     least on the front end are intended to be things where there is a
     potential for, you know, to use positives and negatives where it is felt
     to be that there would be a positive burden reduction for the industry.
         Now if you do a detailed evaluation, I think the answer to
     your question is yes, as a result of a detailed evaluation it could come
     out positive or negative.
         DR. SEALE:  The thing I am thinking of is you have an issue
     that is identified and one of the things that comes out of it is well,
     we ought to do this, but if we do this it's going to cost something in
     burden, and that is what I would call a negative burden reduction.
         MR. CHERNY:  Yes.
         DR. SEALE:  And there is room for that in that level of
     assessment?
         DR. POWERS:  Well, it seems to me that if it came out
     negative, Bob, it would have to be justified under the safety
     enhancement clause.
         DR. SEALE:  Well, then you would get into the cost benefit,
     I guess.
         DR. POWERS:  Well, unless it is a compliance issue.
         DR. SEALE:  Yes, right.  Yes.  Okay.
         MR. CHERNY:  Here is a summary of considerations.  Just sort
     of a quick run-through and we are going to talk about each one of these
     in more detail.
         We have concluded as a result of the work that we have done
     on this issue that current regulatory requirements for these kind of
     valves are adequate, and we will talk about that a little more as we go
     along.
         We have also decided that no new generic cost beneficial
     safety enhancement has been identified, and we don't think we can
     identify one.  One thing that has occurred since the MOV Generic Letter
     was issued was the maintenance rule has been issued, and as most of you
     know, the maintenance rule has some pretty good things for risk
     significant component and systems in it which include identification of
     risk-significant components, trending of their performance, establishing
     goals for their reliability and taking appropriate action when those
     goals are not met.  That would have, we feel, been a significant
     contributor to the MOV situation had it existed at the time.
         Another thing that is about to be implemented is the NRC
     risk-informed inspection and assessment process, which is going to
     result in inspectors focusing on risk-significant components and
     verifying that appropriate corrective actions have been taken for those
     kinds of components.
         DR. POWERS:  It seems to me that the generic issue here had
     two components.  One was valves simply not being properly maintained or
     failing, and the other one was the question of whether static testing of
     the valve was indicative of its performance under DBA conditions.
         What you have listed here doesn't seem to address that
     question of static versus dynamic testing.
         MR. CHERNY:  Well, as I said on my earlier slide, the
     original concern that was identified when we were asked to prioritize
     the issue was the second of the two things that you mentioned, so our
     work has encompassed both things, both points that you just made, okay,
     the general maintenance problems and general upkeep problems, and
     setting up problems and so on, and the other case too, where there is
     concern about whether they would perform under the design basis
     conditions.
         We have looked at both things.  There may not be a specific
     bullet here that says that, but I think that as we go along it will be
     more clear.
         DR. POWERS:  Okay.
         DR. MILLER:  On the issue of testing, are you going to
     address why it couldn't be dynamically tested?  Is there a reason for
     that?
         MR. CHERNY:  The issue of the dynamic testing actually is
     quite analogous to the MOV situation and let me try and get into that a
     little bit more as we go along, if I could.
         Another thing that is going on, which we are going to talk
     about a little bit, is there are improvements in the industry approach
     to addressing POV performance which are somewhat recent and also the
     kinds of things that when Generic Letter 89-10 was written did not exist
     for MOVs at all.
         There are owners group and utility activities going on
     specifically in the area at this time to address air-operated valve
     reliability and a lot of the things they are doing can be extrapolated
     to the other two valve types in the future.
         Another thing that is going on is the ASME has an OM code
     for inservice testing and the requirements for air-operated valves are
     continually being updated in there.  At the present time there is a lot
     of effort being put into writing a risk-informed code case which is
     being specifically written for air-operated valves and hydraulic
     operated valves, and it's fairly far along in the approval process.  I
     think it is at the ASME OM committee level as we are talking here.  The
     Staff has been actively participating in the writing of that case and so
     our input will be in there.
         On the next slide we have a listing here of some things that
     we have done to learn and to understand more about POV performance as we
     have been working on this issue, and as it says on the lead bullet
     there, we feel that the input from these things, these various
     activities support the lack of an identified generic cost beneficial
     enhancement and support issue closure.
         The Staff has spent a lot of time reviewing LERs of various
     POV failure events.  We have also had contractor INEL review LERs of POV
     failure events and also do some reviews of some NPRTDS input in that
     area, and we have gotten a lot of understanding of the different kinds
     of failures.  A have a separate viewgraph coming up on that subject
     which will talk about it slightly more.
         We have also reviewed some of the accident sequence
     precursor program evaluations that have been performed, particularly the
     last few years, and I have a separate viewgraph on that one.  We have
     had a contractor working on some plant-specific PRA sensitivity studies
     that show that a few POVs can have significant impact on CDF.  What we
     have learned from those studies.
         We have looked at representative PRAs that represent every
     type of NSSS type of plant.  We have found that if you raise the failure
     rate high enough for these valves, what you find is that you can raise
     the CDF high enough to be at a level of concern, but what you find out
     as you do those evaluations is that the types of valves that are
     responsible for raising the CDF are just a very few per plant, very few
     really risk-significant valves per plant, and they tend to be completely
     different from plant to plant.  They are not the same valves from plant
     to plant -- very plant-specific.
         DR. POWERS:  When you find something like that, don't you --
     is there some move to say, okay, well the GSI really needs to be changed
     from valves as a general class of things to valves that have significant
     impact on CDF?
         MR. CHERNY:  I think what it has convinced us as we have
     gone through and done all this work is that resolving this generic issue
     as it was originally constituted is not amenable to a generic fix, if I
     can call it that.
         DR. POWERS:  I mean I can see how that would come about. 
     Later when you said, okay, the valves that are influential in CDF are
     different in every plant and ergo it is not subject to a generic fix,
     that might well be, but my question is of more of a philosophical
     nature.
         DR. SEALE:  Where do we draw comfort?
         DR. POWERS:  Well, you have a generic issue that says look
     at all these valves and you say, well, gee, most valves not surprisingly
     are fairly inconsequential if they fail individually, but now you have
     something that is significant, and that is that there is a subset of
     valves which do affect the CDF and maybe you want to start focusing your
     attention onto those, and you might subsequently discover this is not a
     generic fix because every valve is different.  I mean that's a very
     conceivable thing, but --
         MR. FLACK:  Yes, if I may, John Flack from Research.
         What you try to look for is a common thread, something that
     is generic even in the valves that you find propagate to the top.  If
     you see a similar type of environment, similar types of maintenance
     procedures that apply to those particular sets of valves even though
     they may fall into different systems if they generic valves in the sense
     of being air-operated valves and are seeing the same types of
     environments that might affect its performance, for example, you may
     still pursue it as a generic issue, but at some level I mean certainly
     you get into a very plant-specific nature of the fix and then it becomes
     no longer a generic issue.
         I think some of these valves do apply across systems, which
     may it more difficult.  You may have some in the aux feedwater system,
     MSIVs might be affected, so there is always this difficulty of trying to
     find something generic that you can really work on and fix versus, you
     know, the plants should be taking care of this themselves as part of
     their performance -- maintenance rule performance, for example.
         But you are right.  I mean there's this line there that is
     drawn that you try to still work it as a generic issue but ultimately it
     comes down to plants --
         DR. POWERS:  Here is what I am concerned with.  You go
     through and you look at these valves as a generic class and you say,
     gee, there's only one failure per thousand plant years and things like
     that, or you come up with some statistic and you say, gee, this is
     closed.  I just don't have any problems with these valves except perhaps
     on an individual plant basis, but hidden within that is an actual issue,
     that there are some valves that just deserve more attention than the
     others, and I am afraid that the conclusion which, true, is applicable
     to a vast majority of valves, gets applied to those that deserve this
     closer attention.
              MR. ROSENTHAL:  Can you put up slide 3, please?
         Jack Rosenthal, RES.
         It's the very maintenance rule that says that licensees will
     go look at their plants and figure out which are important valves and
     establish a program to address those valves.  And I know as part of
     AEOD's former life, we did go to seven plants and licensees, in fact,
     under the maintenance rule had examined their plants and had identified
     specific valves that were important, and some of these valves have high
     risk achievement worths, but there are -- but the point is that there's
     programs in place to address those single-valve issues, and that's why
     the top -- we've tried to make this presentation like a very top-down
     presentation, is that's why we feel that no new requirement is needed.
         DR. POWERS:  That's a good point, Jack.  Thanks.
         DR. BONACA:  In fact, I have a question regarding the
     report.  The report postulates, you know, ten times the failure rate and
     then 30 times the failure rate just to determine the sensitivity, but
     then it reacts to that kind of findings of sensitivity by saying maybe
     we have to recommend some additional programs.
         The bigger question is, do the failure rates that we
     experience come close to those kind of factors?  What I mean is the
     sensitivity, are the numbers used in the sensitivity analysis -- do they
     have any relationship with the failure rates observed in the field?  I
     don't think so from what I saw.  It wasn't very clear.  I mean, it was
     clear up to a certain point, but there were certain recommendations that
     were inconsistent with that kind of relationship between what you
     postulate for a sensitivity and what you see in the field which
     represents those.
         MR. FLACK:  Yes, I think that's a good question.  I mean,
     when you do the sensitivity study, you ask yourself the question of
     whether these valve rates could get as high as you use in your
     sensitivity studies, and then what would cause them to get there, and I
     think Frank may address some of that later on, about finding things that
     would drive the valves that high.  I mean, it's just, you know --
         DR. BONACA:  It would be good to put that issue in
     perspective because the report is somewhat moot on that issue.
         MR. CHERNY:  Well, let me make a couple comments on the
     report, if I may.  This is probably a good time to do it.
         As I said, we have done some plant-specific sensitivity
     studies.  You have the -- I think the July 1997 version of that report,
     I believe is what we had in the package.  The people out at INEL are
     currently working on revising that report to address a number of peer
     review comments that we have received from other offices, so the report
     is still being finalized as we speak.
         You mentioned the failure rates.  One of the peer review
     comments that we -- and we've had a lot of discussion about failure
     rates -- one of the continuous peer review comments is sort of along the
     lines that you've asked about the failure rates and whether what we've
     used is high enough and so on.
         As you probably recall from looking at that report, INEL
     took a look at 44 IPEs to come up with the failure rates that were used
     in those sensitivity analyses, and I think the version of the report
     that you have I think they had used like the second highest failure rate
     or something like that.
         To address the peer review comments, they've taken the
     highest one and they're going back and doing some reanalyses with that,
     and that is probably the -- probably, as I speak, the final version of
     the report is probably going to show rather than the multiplier times 30
     and so on that you were mentioning, I think it's going to have just the
     bounding failure rate calculations in it.
         And there are still some people -- by the way, that failure
     rate is three times ten to the minus two, the one that they're going to
     be using, at least as we last talked about it.  There are still some
     people that feel that under certain conditions, that's still not a high
     enough failure rate, but I think it's -- from what we have seen in the
     sensitivity studies, it is a high enough failure rate to show, you know,
     the nature of the concern, that it's confined, that the risk significant
     contributions are confined to a very few valves.  As Jack was just
     saying, they are the same kind of valves that the industry was supposed
     to be focusing on because of the maintenance rule.    So, you know,
     we've learned -- without going to failure rates, I mean, you have some
     people that talk about the MOV case and there were certain MOVs when we
     first started doing dynamic testing that, you know, under those kind of
     conditions, had a failure rate of one, for example, okay?
         And you could put failure rates like that into these PRAs
     and you could do those kind of calculations, but in terms of the number
     of valves and what the contributions are, you wouldn't learn any more,
     you would just crank out higher CDF numbers by doing that.  So we're not
     really thinking of putting those high failure rates in at this time.
         Any other questions on the sensitivity analysis?  Because I
     wasn't really going to get into any more detail on that unless you all
     want to.
         DR. BONACA:  Just one observation, too, that some plants are
     better than other at doing certain things.
         MR. CHERNY:  Right.
         DR. BONACA:  For example, bleed and feed.  Okay.  And so
     that is a plus for the plant.  But of course, if you have that success,
     then the reliance on the equipment that you use for the bleed and feed
     becomes very important, okay?  That shouldn't be a penalty for the
     plant; it should be actually the fact that those plants achieve a much
     lower core damage frequency because they're good at that kind of
     function, for example, should be recognized.  And of course, anything
     that will prevent that success also comes out as a penalty in the
     report.  I don't think the report puts that in perspective sufficiently. 
     Identifies some sequences, but it doesn't put it all in perspective.  So
     it gives an impression that certain types of plants are much worse
     because they have the sensitivity to this POV.  It doesn't, however,
     show that they have really much lower core damage frequency because
     they're successful in some functions like bleed and feed.
         Just an observation, the report doesn't have --
         MR. CHERNY:  Just to comment on that, the report is somewhat
     limited in the way it's written because that's how the scope of work for
     the contract was written.  We asked them to do just that kind of work
     and they stopped there they were asked to stop.
         DR. POWERS:  Let me understand a little better.  INEL goes
     in and they look at -- and they come up with these failure rates and
     they put it into the sensitivity study. Now, the failure rates they're
     looking at are failure rates of what?  Things like installation errors,
     maintenance errors, things like that?
         MR. CHERNY:  Yes.  I have a viewgraph and a couple of pages
     that talk about the kinds of things that were considered and the kinds
     of things you find in a typical LER search, which all enters into that
     kind of a failure rate.
         DR. POWERS:  Well, what I'm -- I'm coming back to the
     definition of the issue again, is at what -- how do they adjust that
     number -- that's an experiential number, I assume -- to address this
     question of does the valve fail under the accident conditions?
         MR. FLACK:  I think's a -- you're talking about a capability
     type question, and that would be a compliance type question.  That
     wouldn't be a performance under demand type question.
         DR. POWERS:  It's a question of exactly what the LER -- I
     mean the generic issue has two parts to it.  It says a concern that
     testing under static conditions may not be able to predict how the valve
     will perform under design basis conditions, okay?
         MR. FLACK:  That's -- yeah.
         DR. POWERS:  And so, I mean, it seems to me that you have a
     certain frequency that you know the valve has been unable to do its job
     for a variety of reasons, and since you haven't had a whole lot of
     accidents, you've got to say, okay, now I've got to adjust that for the
     fact that this valve may not perform under the actual accident
     conditions because I haven't tested them under actual accident
     conditions, and I'm wondering how you do that.
         MR. CHERNY:  Well, how you do it is -- or at least one way
     that you do it is the same way they did it on the MOVs.  You have more
     advanced diagnostic equipment that people are using these days.  There's
     a lot of things that have been learned from all the testing that was
     done on the MOVs that can be extrapolated to these other types of
     valves, too.  There is more advanced diagnostic equipment being
     developed for these other valve types I think as we're sitting here, and
     when we talk about some of the Owners Group activities and so on that
     are going on, we'll get into that just a little bit.
         But as you may recall, as much a concern as that was on the
     MOVs, the Commission decided at the time that there were enough
     regulations on the books to cover the issuing of that generic letter and
     its many subsequent supplements.
         DR. POWERS:  That is an approach, I suppose.  What you do is
     an analytic approach, I would have thought an experimental approach, but
     maybe you can do it analytically.  Where is it done?  Where can I go
     read about it for these valves?
         MR. CHERNY:  I don't know that we have anything --
         MR. ROSENTHAL:  I think that it's embodied in, in fact, the
     licensee's identification of valves.  Let me say that we've struggled
     over this thing where PRAs were the reliability, and we have a
     capability or a testing issue, and how do you make this bridge between
     reliability and capability, and it's clear to us that to just simply
     jack up the failure rates or jack up a common mode failure rate beta
     factor, of course it will give you a high delta CDF, but that's not what
     you're really trying to model when you're looking at capability, okay. 
     And the sensitivity studies show mostly that if you make the failure
     rates high enough, beyond that which you even observe, yes, you'll get
     high CDF.
         So now you go to something like risk achievement worth,
     which asks the question, okay, I have a perfectly acceptable failure
     rate for the valve, but what would happen if, in fact, the valve
     wouldn't work at all, and you identify those valves at your station who
     have high risk achievement worths, low failure rate, high risk
     achievement worths, and those are the very valves that one should ensure
     will work, and that a good -- okay.
         So now, individual licensees, and as I said, we went to
     seven plants, so that's a pretty good sample of America --
         DR. POWERS:  We'll get into that sampling issue --
         MR. ROSENTHAL:  Okay.
         DR. POWERS:  -- as the day goes on.
         MR. ROSENTHAL:  Okay.  But licensees in fact have been doing
     that.  They take their IPE, they take their review boards and they
     figure out which are those valves which are important to them, and then
     -- I mean, but they're doing that under existing requirements.  And then
     for those valves, yes, we would -- we've been working with them, it
     would be very appropriate, and a good practice would be to do dynamic
     testing using test equipment and ensure that they would work.  But that
     activity, in my mind, although not across the industry and not uniform,
     is, in fact, going on at many plants.
         DR. POWERS:  Okay.  I'm still struggling here, and a lot of
     it has to do with the general philosophy of JSIs here, but, I mean, you
     seem to have said, okay, yes, I know that there are valves that
     contribute to CDF and there are valves that don't, okay?  But it's not
     an issue because the licensees are taking care of it under the
     maintenance issue.  But then you said, but it's not uniform across -- it
     seems now I'm back to a generic issue.  Why isn't it uniform across the
     industry that those valves that are important to CDF are getting this
     higher attention?
         MR. CRAIG:  We have had a discussion of that issue for
     several hours over the past few weeks, that very issue, and the answer
     is not as perhaps satisfying as we would like it to be, but the logic
     that we I suppose are relying upon goes in part to the experience from
     the MOVS where we see that some of the -- the testing programs and
     analytical techniques, the good ones, we believe are adequate to
     demonstrate that the valves will function under design basis condition. 
     We're seeing those implemented at plants.
         We are trying through the various Owner Groups' activities
     to work with the industry to get them to make those kinds of practices
     more broad-based, in fact, implemented at more utilities.  We believe
     that as a result of the activities to identify the risk-significant
     valves, both the utilities, the Owners Groups and the staff will have
     the scope of potential valves to look at pretty clearly identified and
     will know which valves to look at to see whether or not these improved
     testing and diagnostic programs are being implemented for those -- for
     the risk-significant valves at an individual plant.
         So that's -- that thrust of working with the industry,
     working with the ASME to address this, if you will, is the approach that
     the Commission directed us to take when it made its decision on
     direction setting issue 13 industry initiatives.  So that's the approach
     that we're taking.  That is not to say that a different approach akin to
     the generic letter on motor-operated valves wouldn't be a little more
     satisfying in some respects, at least from the regulator's perspective
     or the inspector's perspective.  It's a little more definitive, I think. 
     The former is a little more diffuse.  Maybe the lead time is a little
     longer than the generic letter approach that we used on MOVs.
         DR. BONACA:  Well, I have a question on the report along
     this same line of thought.  The report identifies a specific type of
     plant that has sensitivity to POVs in two different systems, and that's
     the Westinghouse type of plant, three loops and four loops.  The
     question is, does the Westinghouse Owners' Group have activities right
     now focused on improvement of those POVs?
         MR. CRAIG:  Yes.
         MR. TERRO:  This is David Terro.  I am with NRR.
         Well, first of all it is not only the Westinghouse Owners'
     Group, it is a joint owners' group that's addressing the issues of AOVs,
     so it includes Westinghouse Owners' Group, the BWR Owners' Group, and
     CE, as well as B&W Owners' Group.  And this AOV JOG, Joint Owners'
     Group, was formed about a year ago, and at this point the staff has been
     following the activities of the JOG, but has not formally met with them.
         The first meeting is going to be June 3 of this year, and at
     that point we will find out more definitively what the formal JOG
     program is for addressing the AOV concerns.  And so at this point NRR
     has not taken any action, any further regulatory action, as far as
     issuing any generic letters or information notices until we've had a
     chance to discuss this issue with the industry.
         DR. BONACA:  So you view this interaction as important.
         MR. TERRO:  Well, at this time we view it as important, but
     we are not -- let's say we don't know the extent of the concerns for
     AOVs as -- if you look at the MOV concerns, we don't know how those MOV
     concerns carry over to the AOV side.
         The concerns are similar, but the extent of the concerns
     could be different, as well as the scope of the valves that are
     affected.
         DR. BONACA:  Thank you.
         MR. CHERNY:  The next bullet on the viewgraph talks about a
     draft AEOD area study on AOV operating experience.  Jack was mentioning
     a few minutes ago that there have been site visits to seven plants, and
     there's been a number of detailed findings written, and there is going
     to be a report published on that in the very near future.
         We know what the general findings are from that, and I've
     got in your handout a couple pages of summary findings from that work,
     and we also have here today the project manager for that work, formerly
     of AEOD, who if you really want to get into some of those things, we can
     have him talk about that.  It depends upon how you want to do it.
         I would suggest doing that after we finish a few more of
     the -- a little bit more of the briefing.
         Another thing, and just to give you a little bit of an
     insight as I guess we got from how much involvement in, you know, plant
     events POVs that are not motor-operated valves have.  There's two
     studies quoted here, two reliability studies that AEOD had done, one on
     auxiliary feedwater systems, and another on emergency diesel generator
     systems.  And as it says there identify POVs as causing only a small
     fraction of system failures.
         In the case of the auxiliary feedwater study, that covered a
     period of nine years from 1987 to 1995.  During that period there were
     2,000 unplanned demands on such systems and 65 unrecoverable train
     failures.  For the emergency diesel generators that covered a period of
     seven years, 1987 to 1993.  There were 376 unplanned demands, eight
     train failures.  We consider the auxiliary feedwater systems and
     emergency diesel generator systems to have sufficient reliability and
     depending upon who you talk to that's done a detailed review of those
     studies, they were either only a small fraction of system failures
     related to POVs or none, depending upon how you interpret the data.  So
     it's very small, very small contributor.
         DR. POWERS:  And when they looked at this the kinds of
     failures they were looking at were of the installation and maintenance
     variety, or was it a performance-under-accident-condition variety?
         MR. CHERNY:  Can one of the former AEOD people help me with
     that?
         MR. ROSENTHAL:  The diesel generator study starts out by
     taking actual on-demand failures in the middle of the night where the
     4160 bus goes dead and asks does it load.  It dismisses the monthly
     data, because we know that that's stylized testing data.  It does
     include the typically an integral ECCS test of refueling outages, which
     is another integral test.  So I think that that's a fair representation
     of how the diesels will work under real accident conditions.
         For the auxiliary feedwater study, again it takes actual
     demands, and I think it is a fair representation.  It doesn't use
     monthly test data again, although, you know, we're taking aux feedwater
     performance given a reactor trip.  We're not able to observe auxiliary
     feedwater performance following a steam line break in which because of
     the depressurization the delta P's across the valves might be somewhat
     different.
         DR. POWERS:  But isn't that --
         MR. ROSENTHAL:  But it is as operational and as real demand
     as you can get.
         DR. POWERS:  But I thought it was this higher delta P
     that -- I remember my former colleagues, Michaelson and Catton --
     railing on this issue at some length it was the delta P that was the
     issue.
         MR. ROSENTHAL:  In terms of the capability.
         DR. POWERS:  Of the valve.
         MR. ROSENTHAL:  We'll get to the capability side.  But, I
     mean, you know, what we want to do, and you struggle with this, is that
     if you do a sensitivity study, and I say that all AOVs have a 3-percent
     failure rate, then I get a bad answer.  Well, that's fine.  That's a
     sensitivity study.
         So now to just pick up on Mario's point, so now you do a
     little bit of reality testing.  One thing you say is wait a minute,
     there are hundreds of AOVs using the BWR scram circuit -- scram system. 
     So if I have such a failure rate, then I ought to be observing AOV
     failures every time I scram the reactor.  And I don't.  So I know that
     in fact at least the average reliability has got to be better than that.
         Okay, there are hundreds of AOVs at some reactors, so I
     ought to be routinely -- I'm only talking the reliability side now --
     every time I take a reactor trip, I ought to be reading about an AOV
     failure if it's 3-percent failure rate, and I don't.  So I know that
     it's better than that.
         And then the last thing was to look at these reliability
     studies that the Committee has been briefed on before, and said okay, on
     the reliability side, and under those accident conditions that we can
     observe, are we seeing a problem, and the answer is no.  That's not to
     say that there aren't valves that individual licensees have found
     important, have high-risk achievement worths, that there have been at
     least in prior years ASP events that -- individual events.  And that's
     where it stands.  We'll get into the capability issue later.
         MR. CHERNY:  The purpose of this viewgraph is to show just
     kind of a typical breakdown when you do a LER search on POVs, AOVs or
     HOVs.  You get, for a typical year, for one valve you get -- you tend to
     get a breakdown sort of like I have got tabulated here.  And this isn't
     intended to be any particular search, it is just sort of a
     representative thing.
         But the main point here is that you find when you look --
     spend a lot of time looking at these, that you get 50 percent human
     errors reported in the LERs and very commonly it is things like failing
     to follow maintenance procedures.  And, you know, these are older LERs,
     most of them are reflecting experience before the implementation of the
     Maintenance Rule and we are expecting the Maintenance Rule to help
     alleviate a lot of this kind of stuff for the risk significant valves.
         Now, we were just talking about the ASP program.  The staff
     has done a review of the last several years of the ASP evaluations.  I
     am told that back in 1994 there was a significant change in the ASP
     methodology, so we haven't gone back too far because if you do that, you
     wind up comparing apples and oranges, and you can't really learn
     anything from that.
         So what we have learned from what we did do, I got tabulated
     up there with the ASP screening criterion is.  And a couple of
     interesting points, prior to 1995, regardless of what methodology you
     used, there were two to three POV events per year that contributed to
     events that exceed that criterion.  But the interesting thing is that
     there haven't been any POV events that exceed the screening criteria for
     the last three years of the ASP program, there haven't been any.
         So that seems to be an indicator that utilities are starting
     to pay more attention to these kind of valves.  The Maintenance Rule is
     starting to kick in.  Owners Group activities are starting to have some
     benefit and things like that.  So this is not -- you know, this is not
     an all-conclusive kind of thing, but it shows you an indicator and a
     trend kind of thing.
         Now, we have been talking about Owners Group activities and
     utility efforts and I might make mention of the fact that one of the
     things that the Maintenance Rule requires you to do is to take industry
     experience into account when you are evaluating your component
     performance and reliability in setting the goals.
         As Dave was saying a few minutes ago, this JOG AOV is
     relatively young, but there is an Air Operated Valve Users Group that
     was formed in the early 1990s, it has been around a little bit longer,
     and I have got just a few words there on what, you know, we think they
     are doing.  Some of our people have participated in some of those
     meetings, and so we sort of know what they have been talking about.
         Recently, they formed this JOG AOV Users Group and, you
     know, by attending at some of the public sessions where they have let us
     sit in, we sort of know what they are doing, but our first real briefing
     on all this activity is going to be at the public meeting on June 3rd
     with is going to be held here at NRC headquarters.
         So just to restate our bottom line, we are proposing to
     close GSI 158.  We have concluded that current requirements are
     adequate.  We have concluded that, from our own evaluations and from
     ongoing activities that we know are getting underway from the industry
     and the Owners Groups, we know from things that are going on in the ASME
     code development, implementation of the Maintenance Rule, we are going
     to be starting the NRC risk-informed inspection processes and so on,
     that POV performance is being addressed.
         Our feeling is that, you know, we are going to watch these
     thing, take these kind of things into account.  The Commission has been
     encouraging us use industry initiatives and codes and standards
     developments and things like that to address problems of this type, and
     if we still feel that the payback on utilizing all those things is not
     sufficient, then some sorts of plant-specific actions will have to be
     taken.  But we feel that current requirements are in place already to do
     that kind of thing.
         So that is really the end of my basic presentation.  I do
     have, as I said before, the project manager for the AEOD studies is here
     to talk about some about some of those findings if you all want to hear
     them.
         DR. POWERS:  I guess I am slow.  I am still asking this
     question, do the valves that are risk significant work under actual
     dynamic conditions of a DBA accident?
         MR. CRAIG:  Let's go to backup slide number 1.  I think the
     answer to the question has several parts.  The first one is based on the
     MOV experience and the improvements in testing programs and analytical
     techniques to evaluate the valve performance.  As we have concluded, as
     a result of that effort, what it takes to ensure that the valves will
     work under design basis conditions, that that information is being
     transferred to and we are building upon that in the other classes of
     valves.
         DR. POWERS:  Where can I read about that?
         MR. CRAIG:  That process is going to be evolving.  There is
     not a report that talks about that because it is largely going to be
     dealt with in the compliance arena between NRR and the various -- the
     Joint Owners Group.  And if there is a determination that is made for a
     particular valve type that some additional testing is needed, either the
     industry or we will do some research to test the valves on the design
     basis conditions if that turns out to be necessary.  That is part of it.
         The other part of it is based on, in part, the second bullet
     that we see up there, based upon the looks at the plants that were done
     by Dr. Orenstein.  And his conclusion, looking at those, was that there
     are programs that are out there that are capable of ensuring they
     perform under design basis conditions, and he can talk to that in more
     detail.
         DR. MILLER:  Okay.  I would like to hear that.
         MR. CRAIG:  Okay.
         DR. MILLER:  You say there are programs.  Does that include
     dynamic testing?  Have we tested these valves, or any of these valves? 
     I keep hearing we are going to, but I don't hear that we have.
         MR. ROSENTHAL:  Hal, why don't you go sit up at the table. 
     I think you will be here for a while.
         MR. ORENSTEIN:  Good morning, my name is Hal Orenstein.  A
     lot has been said about the work that we have been doing in my former
     life in AEOD and my present life in Research.
         Essentially, we initiated the program about two years ago in
     which we had the assistance of Idaho Nuclear National Engineering and
     Environmental Laboratory accompany us.  We tried to encapsulate the
     status of air operated valves.  We were not looking at SOVs or hydraulic
     reoperated valves, we were focusing on the air operated valves.  We
     chose to visit seven different sites in which there were 10 reactors. 
     We chose the plants to visit to see what was happening out there, in a
     manner, to try and get a good mix.
         We visited -- I won't get them in the exact order, but it
     was Palo Verde, Palisades, LaSalle, Three Mile Island, Turkey Point,
     Indian Point 3 and I am not sure if I mentioned Palisades.  But, anyway,
     if I didn't get all seven, I got pretty close.  We visited each of the
     four reactor manufacturers' types.  We visited all the new plants.  We
     also had a pretty good mixture of architect engineers who had built the
     plants.  I think I left out Fermi and LaSalle.  Anyway, you had cases
     where the utility was the architect engineer as well.
         In any event, what we found, and I have been a participant
     in the Air Operated Valve Users Group meetings from the second meeting
     through the number 16.  I think I missed one or two that I was unable to
     make, but I do make presentations at each of those meetings trying to
     highlight some important AOV issues and operating experience that has
     occurred through time.
         What we did was, when we went to the plant, what we found
     was two of the plants were of great interest to us because Palisades and
     Fermi were considered to be lead plants.  They had a contract --
     actually, they were receiving funding from EPRI, and what they were
     doing is they were setting up an air operating valve program and they
     were being funded to try to determine what valves are important, that
     they should know more about, as well as to try and determine whether or
     not the calculational methodology that has been developed under the MOV
     program by EPRI was applicable or might be transferrable to air operated
     valves.
         In particular, you get a wide diversity of what was
     observed, but what we found the people at Palisades being the lead plant
     had done a very thorough job in identifying plants of -- valves of
     importance, and we found that just about -- not all, but most of the
     plants had gotten to different degrees of completion of examining the
     valves, and a good deal of this work was not an added burden from the
     standpoint of separate AOV program, it was really a combination of using
     the -- applying the maintenance rule methodology with expert panels
     trying to superimpose on it or use the IPE results to try and
     characterize the valves through each function that it would have,
     through all combinations of events, and the plants, for the most part,
     did a decent job identifying valves in their report, which is presently
     in draft which we are trying to get out.  We have a table which
     indicates how the plants divided up the population of valves, and
     amongst them how many were determined to be important from the
     standpoint of risk importance.
         Again, we have a nonuniversality of terms, what people
     considered to be important at one plant that may not have been important
     to another, which we may or may not consider to be important here.
         They were concerned about releases, they were concerned
     about operation during -- recovering from transients.  There was a very
     wide array of things that they were looking at.
         But the bottom line was this:  Fermi and Palisades were both
     being subsidized, should I say, being supported by EPRI funding, and
     they were doing calculational work.  Fermi had yet, at the time we were
     there, to determine what they were going to do with regard to actual
     testing of valves.  They did hire an outside organization, I believe it
     was Sargent & Lundy, to help out with the calculational techniques.
         On the other hand, Palisades had done a large amount of
     static testing and they are in the process of getting ready to do
     dynamic testing, and they were doing all the test work themselves,
     whereas the Fermi plant, the impression I got was if and when they were
     going to do actual testing, they would probably bring in an outside
     contractor to do the work.  There are several companies out there who do
     provide these services.
         Another plant that we visited that we had a very good
     understanding of what was happening was Palo Verde.  They had
     implemented their own air-operated valve program back in 1989 when they
     had common cause failure of four CCV valves in their, I guess, the
     atmospheric dump valves had failed.
         They had actually, by the time we were there in late '97,
     had categorized the valves, found out in many cases which ones had
     specific risk importance, and they had done a lot of static as well as
     dynamic testing.  In their case, we got into some interesting
     discussions about what margin they had at the valves, what was adequate
     margin, what they were finding, and in many cases, they had done
     testing, dynamic testing, not so much because of -- I should be fair to
     them.  They had done some testing from the standpoint of risk
     importance, but they had also done some testing from the standpoint of
     what they had observed, certain valves were acting sluggishly.  But they
     seemed to be in the forefront.
         LaSalle plant had done a lot of work in static testing, had
     not done any dynamic testing as we knew it.
         When we went to Turkey Point, we found a very interesting
     situation there, where they were doing a lot of work from the standpoint
     of fixing problems with the valves as they had them working on a
     day-to-day basis, and their position was they were not going to do the
     type of thing that we are talking about today; that is, they are not
     concerned about verifying capability of certain valves that would be
     subjected to conditions different than the daily operation, if they were
     undergoing a transient.  That is if you had design basis event, they did
     not plan to do any testing or any calculation to determine that that
     valve would work.  They were focusing primarily on the day-to-day does
     the valve work today under these conditions.
         What I think Jack had mentioned earlier, and something I
     think you picked up on, was the fact that each plant is doing their own
     thing.  Some people -- in case I have to be a cheerleader for Palo
     Verde, I think that's how Jack described it in my early draft of my
     report -- they're doing what they think is the right thing, completely
     categorizing and understanding all the valves.
         On the other hand, you had the case of Turkey Point that
     wasn't going to do much more than what they had to, and they had people
     out there who hadn't even decided to do.  But it did have a wide range
     of it.  And essentially I can get into a lot of other things on
     maintenance which I don't think you are focusing on now, but I think the
     question is stated about capability.  People have the ability to use
     operating experience, calculational techniques which are being improved
     on, and test capabilities that exist if they decide to do it, and that's
     a mixed bag as to what's happening.    
         DR. POWERS:  I guess I want to understand a little bit.  You
     mentioned calculational capabilities.  I haven't seen any.  I just have
     to ask what it is.  I am familiar with some German work on valves which
     is extraordinary calculations on the finite element, more nodes than I
     care to describe, coupled with an experimental program with thousands
     and thousands of strain gauges and what-not on valves, trying to
     validate this model, and it's taken them years to do this.  Is that the
     kind of calculational capability you were talking about?
         MR. ORENSTEIN:  What EPRI was looking at was primarily some
     simple methodology to characterize or to determine what kind of margin
     you had on the valves.  They were not asking each plant to sit down with
     a very complex computerized system.  They were trying to come up with
     some simple formulae or something that could be simply used with the
     results of even static testing to get better understanding of the valve
     factors and certain features of the equipment.
         I am not exactly sure to what level INEL has gone or would
     be able to go, but I do know that as part of our program, two of the
     gentlemen who were very heavily involved on generating the calculational
     techniques and verification for the industry valve tests at Idaho were
     working with us, and in addition to that, the lead person from INEL who
     was working on the project, who visited all seven plants with me, Owen
     Rothberg, is in the room here, he is the person who wrote the original
     89-10.  So I mean I cannot tell you the degree or the depth of
     involvement that people are planning to do, but I know that they are
     trying to get some simple techniques that can be used at the plant in a
     very quick way to accurately determine if the valve would have the
     capability to work under the other conditions.
         DR. BONACA:  For some of the dynamic testing that you
     observed, okay, was it done under accident conditions, first?  And if
     yes, how successful was or did you identify problems?  I think that that
     is an issue, I mean --
         MR. ORENSTEIN:  I did not witness the test, but my
     understanding -- Owen, you can correct me if I'm wrong -- what I
     understand is that in the case of the tests that were done at Palo
     Verde, they simulated the conditions as best as they could, whatever
     they means, and they did find that the valves would not be capable of
     performing their safety function under the design conditions, and they
     did have to modify the valves.
         I believe Palisades, in doing similar type tests, also found
     there were conditions where the valves had to be changed.  I think it is
     also interesting to note that the static testing was very important, and
     we have a -- there was a Canadian study that was done jointly by the
     person who formed the -- who led the formation of the air-operated valve
     users group, he's a fellow by the name of Brian Ferguson from Ontario
     Hydro, he, in conjunction with Bill Fitzgerald from Fisher Control, who
     had used the Fisher flow scanner, did a study on the Bruce Station AOVs
     and they found essentially 45 percent of the air-operated valves as they
     were found in place for the first set of tests needed adjustment in
     order to be sure that they would be able to function properly.
         Subsequently, they found that each year when they were doing
     maintenance on them, the population of valves that had to be adjusted
     and changed on the set-up and bench set were less, but still
     significant.  
         MR. FLACK:  The question that was raised, though, was the
     kind of accidents that would occur.  I mean we talk about design basis
     accidents, some of these are very low probability events that would
     have, you know, need to occur to get the -- 
         DR. POWERS:  Let's set the ground rules very clear.  We are
     either in design basis space or we are in severe accident space.     
         MR. FLACK:  I understand.  I understand.     
         DR. POWERS:  Don't tell me that DBAs need to be discounted
     because of their low probability because then I'm going to take you over
     to the severe accident space, and you don't want to go there with this
     kind of information.    
         MR. FLACK:  No, I understand, and I'm not trying to argue
     that point.  We are trying to put things in perspective from a reduction
     issue as well.  If we are going to request licensees to perform tests on
     valves under certain conditions, we have to ask the question, what are
     the risk implications of those conditions?  Are they going to -- do they
     present a high risk to the public?  I mean those are the kinds of
     questions our branches are asking ourselves as we revisit the
     regulation.  So it's just in that light that we are asking that
     question.     
         DR. POWERS:  If you're going to have 45 percent of the
     valves don't work under DBA conditions, I presume that is 45 percent
     won't work under severe accident conditions.  I think you can take your
     risk achievement words to judge whether there is a significant issue
     here or not.  
         MR. FLACK:  That could be one way of demonstrating it, yes.
         MR. ORENSTEIN:  Okay, I don't want to be -- give you the
     wrong impression.  I'm not saying 45 percent of the valves would not
     perform the safety function during an event.  I said 45 percent of the
     valves had to be adjusted.   
         DR. POWERS:  I understand you've come down from my original
     coming in here, which was 100 percent, okay?
         MR. ORENSTEIN:  I didn't say that, did I?    
         DR. POWERS:  No, but that's what the generic issue is.
         DR. MILLER:  The testing program at Palo Verde said 45
     percent --
         MR. ORENSTEIN:  No.  Ontario Hydro at Bruce Station had 45
     percent of the AOVs had to be changed in their set-up and adjustment in
     order to make sure that they would travel properly from minimum to
     maximum pressure in that position.
         DR. MILLER:  How did they determine that?
         MR. ORENSTEIN:  By using the diagnostic equipment that was
     made available, is available to everyone today, from one of the
     manufacturers.  In fact, that's been a burgeoning industry.  It started
     with one company with equipment which was on the ragged edge on its
     capability, and now you have about six companies which are coming up
     with very sophisticated equipment which is better designed for AOVs than
     the original ones were, which were essentially an extension of the MOV
     testing equipment.  But there is a lot of equipment out there.
         In fact, I was in Germany back around 1992, and I think it
     was a Nickel-Westheim plant where I was shown by Siemens people and
     Herion people that they did have some very sophisticated valve
     diagnostic equipment that they were looking to add onto AOVs, and at the
     time I was there they had like 55 valves connected to their computerized
     system.  So rather than doing an intrusive test or doing a separate test
     later on, they had all the valves hooked up, waiting for a transient,
     and they were going to record all the data simultaneously.
         DR. MILLER:  Those are in situ type instruments, and they
     watch how they operate?
         MR. ORENSTEIN:  That's what they were doing over there back
     like eight years ago.  Now what -- or seven years ago, now.
         DR. MILLER:  You say now they have better techniques?
         MR. ORENSTEIN:  I don't know what they are doing today, but
     I know that we do not that here.  People here have concerns about the
     problem that the cabling may have associated with everything in the
     plant and our requirements, I guess, are a little bit different than
     what theirs are.
         DR. BONACA:  Well, one of the bases you presented for
     closing this issue was that the core damage frequency associated with
     this issue was marginal in justifying further action.  Provided that
     there are no further insights to show clearly some specific and unique
     deficiency that have to be addressed now.
         I have a couple of questions.  One, first of all, you seem
     to indicate that dynamic testing is done only in a scattered way, and
     when done, was not necessarily successful under design conditions.
         DR. BONACA:  I don't understand we -- I don't think I said
     that, did I?
     That's what I heard.
         DR. MILLER:  Well, you said at Palo Verde they did dynamic
     testing and they didn't work and had to adjust them.
         MR. ORENSTEIN:  No, they did dynamic testing.  The dynamic
     testing told them that something had to be done to the valve so that the
     valve would work properly under its design conditions that you had it
     made for.  The valve was not set up right.  The testing was good.  There
     was no problem with that.  I think the -- we may have some disagreement
     amongst the experts from INEL and the people at Palo Verde as to how
     much margin they have on the valve.  But they definitely were able to
     determine, as was the case in Bruce and the case in LaSalle and almost
     all the other cases, where they found that the diagnostic testing was
     considered to be reasonably correct, calculations that were done and
     tests that were done showed that leaving the valve as it was might not
     have given the valve the capability of -- would not have had the valve
     perform as you had determined that it should be working.  I don't think
     there was any lack of success.
         DR. BONACA:  Okay, I heard something else before.  Just a
     question, going back to the CDF contribution, what was the CDF
     contribution associated with the MOV issue, just to put it in
     perspective?
         MR. ORENSTEIN:  I don't know.  I am not sure. All I know is
     this.  The thing that was interesting about the MOVs was people looking
     at MOVs initially having failure rates on the order of one, two times 10
     to the minus three.  They did diagnostic testing and they found that the
     failure rates were eight 10 to the minus 2, and this was associated with
     torque switch setting and other things.
         In the case of AOVs, I don't think we have that type of a
     database that we have actually put together.  I do know that in some
     cases, for example Indian Point Unit 3, they did testing on -- the
     numbers escape me -- I think it is 20 valves, 20 air-operated valves,
     many of which were in important systems, and they found that half of
     them had to be adjusted and had to do things, change spring setting, et
     cetera, in order to make sure that they would work properly.
         This is not -- say 50 percent is bad, but what I am saying
     is they did find a fair number of valves that had been acting in a funny
     way under normal conditions, some of which would have had to go ahead
     and operate under more severe conditions, and they did the testing.  In
     that case it was static testing.  They just did not feel comfortable
     with what they were seeing, with what they thought they had margins, and
     then they made adjustments.
         They have not done dynamic testing there yet.  In their case
     they used an outside contractor and I think they used Crane MOVATS
     equipment, but there is a wide range of this type of thing.
         Now as far as the AOVs go, you talk about the study that was
     done back in July of '97.  There is a whole slew of variables in there
     and one of the things that I noticed as I was coming into the meeting
     today, in fact I read it yesterday, was the original writeup for the
     Generic Issue 158 used a generic failure rate that was obtained from an
     AEOD study from NPRDS data.  That study said that the general AOV
     failure rate for NPRDS data is .042 and the failure rate of AOVs in
     risk-important systems was .011.  Now the numbers that were used in the
     INEL-158 study that you have were taken to be I think something like
     .001 -- 10 to the minus 3 or two 10 to the minus 3 or one 10 to the
     minus 3.
         However, there is a part of the report that is very
     important that is sort of not very clear to the reader and that is the
     beta factor, which you are using to consider the common cause
     contribution even though they said certain numbers in the report, the
     actual numbers that were used in the calculations were extremely low and
     what we are doing now is we are looking at this more -- as Jack said, if
     you pick a wide enough range of failure rate and wide enough range of
     beta you are going to come up with a high CDF.
         The bottom line that we have gotten to now is that the
     report you have says that with all these variabilities that you put into
     the failure rates on the POVs, AOVs -- in particular, my concern -- you
     don't get much of a core damage frequency.  However, what some recent
     work that is correcting some errors and omissions there is saying is you
     shouldn't look at those numbers because those are probably going to be
     drastically changed because the beta factors that were used were not
     prototypic and we are trying to get new calculations to give you a
     better range.
         I mean I can't tell you what a CDF number is.  Again, each
     plant is different and the main concern as I see it, and I think most of
     the people in the Agency see it, is that it makes sense to identify the
     risk-important valves, not necessarily AOVs, and then go ahead and
     address them to confirm that they will work, and then do additional work
     to make sure that they will continue to work.
         That is the thrust of our report and I think that is the
     thrust of the whole Agency.  The question is under what umbrella, under
     whose label you have it, whether it is a generic safety issue area or
     whether it is a compliance issue or if it is an NRR item, whether it is
     a Generic Letter -- I don't know.  But the thing is I think we all
     recognize that what has to be done, rather than trying to chase around
     10 to the minus what it is, depending on the failure rate which is
     variable, and we ought to really address the issue, which I think has
     been stated by Dr. Powers earlier today.
         The other thing I want to mention is in the 158 study that
     you have, July of '97, it used the failure rates that were presented in
     the 44 IPEs and what we have observed in many cases, that some of those
     were extremely optimistic on the common cause or the beta factor, and to
     me it appears that the most important issue on air-operated valves and
     solenoid operated valves and I am not so sure about hydraulically
     operated valves -- it may be but there are less of them and they don't
     have them appearing in as many important areas -- the important thing is
     the commonality, the fact that if you go to Three Mile Island, as we
     did, and we sat down with the utility and they start to explain what
     they found on some of the valves, and what they found was a valve was
     acting in a funny way.
         They went back to get information on the design of that
     valve and they couldn't get anything.  Eventually they were able to
     extract from the manufacturer information that told them the valve was
     okay, but when they looked at the manufacturer's analysis they found
     they had a friction or valve factor of zero.
         As a result, TMI went back and asked them to please
     recalculate what the valves' margin had if they use present day
     technology using what we have learned from the MOV program and
     diagnostic testing, and lo and behold, they found out that the valve did
     not have any positive margin, and they did make changes to improve it,
     but this is something they have done on their own, and how many things
     like this occur?  I don't know.
         A similar valve at a sister plant, in particular Crystal
     River, made by I guess it was architect engineer was also Gilbert, they
     had problems with the same valve but it was in a different system, and
     they were trading horses on or trading information on explaining how
     they could go ahead and fix the problem at the other plant.
         MR. ROSENTHAL:  Can I?
         MR. ORENSTEIN:  Yes.
         MR. ROSENTHAL:  Hal is an expert on this, so a week ago I
     wanted to describe individual valve failures at length and let me just
     back up a little bit.
         Number one, we are trying to present a balanced presentation
     where I mean our starting out point, which I still think is the point is
     that no new regulatory requirements are necessary.  That is the basis
     for closing the GSI.
         We have tried to give you some balance on the risk side,
     saying what studies were done, what the operating experience is -- there
     are individual failures, what is going on in the field in order to
     provide some balance and not present a particularly rosy or particularly
     glum situation.
         The fact of the matter is that with respect to capability,
     we could look at -- we don't see that as a new requirement that
     demonstrating the capability is a compliance issue, so we would not
     advocate a new requirement.
         Let me note that two big things that are different from 1989
     of the MOV work and now is that we have got a maintenance rule on the
     books and there is diagnostic testing equipment out in the field that
     didn't exist 10 years ago.
         Okay.  Given our perception of the risk and plant-specific
     or system-specific valve-specific nature of the issue, and just the
     overall operating experience, we believe it would be appropriate to work
     with industry to promote, enhance good programs.  We see some evidence
     that that started -- there is a Joint Owners Group -- and so we believe
     it is appropriate to -- again, not to have a new requirement but to work
     with industry.
         DR. BONACA:  I have just one last question on this.  Now
     still it seems to me that because it is a significant issue you would
     still -- I mean this issue seems to need some leadership.  You are
     planning this June 3rd public meeting and it is not clear here from all
     we heard what is going to happen there.  Some people will do something. 
     Some people may not do something about it and the question I have is, is
     the timing of proposing a closure of GSI-158 the right timing right now?
         MR. CRAIG:  Well, Dave Terro is going to talk about where
     the responsibility and leadership for the issue lie.  Closing the GSI
     has no effect on what utilities have to do to demonstrate compliance. 
     What was hanging out there, if you will, was this potential for an
     additional requirement that would pass 50.109, the backfit criteria, and
     what we have concluded is, for the reasons that you have heard, we can't
     come up with any.
         There is nothing we can identify and as we looked at it we
     reflected back on the MOV activities and the basis for that was
     compliance and we don't see a logic or a rationale that would get us to
     an additional requirement as opposed to those kinds of interactions that
     we would have with industry to determine whether or not some compliance
     action would be appropriate.
         Go ahead, Dave.
         MR. TERRO:  This is David Terro again.  I just want to say
     that about a year ago Research first proposed to close out this GSI and
     asked NRR if we agreed with it, and about a year ago we said the same
     thing.  We said no, we think it is premature.  There is not enough
     information out there with respect to AOVs and how that issue is being
     resolved.
         In the past year quite a bit has happened, and let me just
     summarize that again.
         One, the AOV JOG has formed, and they are specifically
     taking the initiatives to address the AOV concerns.
         Two, DSI-13, industry initiatives, the Commission policy
     came down that the NRC should now rely more on industry initiatives to
     resolve many of these generic concerns.
         Three, the ASME is addressing AOV concerns through a
     risk-informed approach and is developing code cases and we are working
     with the ASME to incorporate diagnostic testing of AOVs into that code
     case.
         Four, the NRC has come a long way, the Staff has come a long
     way with risk-informed initiatives and specifically risk-informed
     inservice testing initiatives, and we have developed a Reg Guide 1.174
     and Reg Guide 1.175, which gives us a lot better guidelines and
     direction on how to approach risk-informed reviews and testing issues.
         Lastly, of course, we have the AEOD research study on AOVs
     and that is about ready to come out, so after all these initiatives,
     after we have taken a look at all these initiatives today, a year later,
     we said yes, we believe now is the proper time to close out the GSI
     because all of these other factors have kind of taken the ball and is
     now running with it --
         DR. BONACA:  Does NRR agree with the proposal by RES to
     close this GSI?
         MR. TERRO:  Yes.  Yes, that was my final statement -- yes,
     NRR does agree that we can close out the GSI.  It does not mean that the
     concerns with AOVs are totally resolved but that we intend to work with
     the industry in solving those concerns.
         DR. BONACA:  Are there any more questions for the presenters
     or comments from the members?
         [No response.]
         DR. BONACA:  With that, Mr. Chairman, I will give it back to
     you.
         DR. POWERS:  Okay.  John, you were going to close out with
     anything additional on 165 or have you pretty well covered it?
         MR. CRAIG:  I have asked Owen Gormley to come down, who is
     the lead engineer for that issue, and he will give you a thumbnail
     sketch and just so he doesn't confuse any of us, the resolution that you
     saw in the package is going to be the same.  What we need to do is we
     just needed a little more time to turn the crack and do the reviews to
     get a quality presentation to you.
         But having said that, let me ask Owen to briefly summarize
     what he would have said, and if you have any questions it is an
     opportunity to ask them.
         MR. GORMLEY:  I am Owen Gormley from Research.
         I would like to assure you that there are no reactor plants
     out there in an unsafe condition because of the small safety relief
     valves.
         I'm sure if you looked at the package you recall that we
     looked at the five major plant types and we winnowed or screened the
     systems and trains and valves down to one worst case valve.  We did a
     fairly rigorous analysis on it, and we found that it had an acceptable
     increase to CDF, if any increase is acceptable.  It certainly fell
     within prescribed limits.
         At that point we became concerned about hanging our hat on
     just one valve so we went and looked at all the other valves -- all the
     other valves in those five plant types.  Then people kept raising
     questions of LERs and so we went and searched the LER database and found
     that only the Shearon-Harris event which had precipitated the GSI had
     any relevance to this issue.
         At this point we asked ourselves how did this thing get to
     be classified high priority in the first place?  We went back and looked
     at the prioritization.  What we found in our analysis was that there are
     no valves in any of these plants that have the capability of failing
     their train.       There are a number of assumptions and concerns on the
     prioritization but the key assumption was that 10 percent of the 45 to
     55 or perhaps 60 valves in a plant would have the capability of failing
     their train and if you make that assumption you then come up with a
     relatively high core damage frequency, and if they don't fail their
     train you can't calculate a significant core damage frequency.
         So those things have not changed.  In addition, one of the
     other factors that caused the issue to be characterized or prioritized
     as high was that it looked like it would be fairly easy and economical
     for the utilities to do tests right on their plant sites of these
     valves, so we could pull them into a testing program like other valves
     in the plant and we have been wrapping up or tying up loose ends and
     tucking in strings for so long that this has happened without any action
     by NRC.
         I would like to assure you that there are no problems that
     we have seen with the Generic Safety Issue.  Probably if we had looked
     more closely at the beginning or if there had been more information
     available at the beginning it would not have even been raised as an
     issue.
         DR. POWERS:  When I looked at the package the first thing
     that struck me and the first thing you opened up your discussion with
     was we selected five plants and we have looked at their valves.
     And I said well, gee, five is 5 percent of the population.  You came to
     the conclusion that there was only one out of the -- one valve at one
     plant that was a real problem.  That's fine, except now I have to ask
     about the sampling, okay?  Clearly there is the possibility that 98
     plants out there still are at risk on this issue.  You selected five and
     you haven't looked at the others.  How do you know that the sampling
     that you took is appropriate to this study?
         MR. GORMLEY:  Perhaps I failed to say five major plant
     types.  We've got a --
         DR. POWERS:  No, I understood, and I understood the plants
     and I know the plants that you picked.  But I also know that three of
     those plants have had the benefit of rather extensive examination in
     connection with other issues, and so I say I also know that there are
     plants that have not had the benefit of those extensive examinations in
     connection with other issues.
         So my question comes back, it's really a theoretical
     question.  You may not be the right one to answer it here, but John is. 
     What is the strategy or the logic that's involved in your sampling?  I
     mean, you've done it several times.  You've done it on the previous
     study we just heard about.  And it's being used frequently.  How do I
     have confidence that the 98 plants you did not examine aren't all
     suffering the worst-case thing that I can possibly imagine?
         MR. GORMLEY:  Well --
         DR. POWERS:  That's really the question I'm asking.
         MR. GORMLEY:  Okay.  I'm glad to have that question this
     month instead of next month.
         DR. POWERS:  Yes.  You would definitely have got it, and
     that seems to be, when I look at your package, my personal examination
     of your package was that was the Achilles heel on the package.
         MR. GORMLEY:  Okay.
         MR. CHERNY:  Could I try and give a partial answer to that
     question today?
         DR. POWERS:  Sure.
         MR. CHERNY:  For that issue there was a representative
     number, types of plants chosen, all the different plant types were
     represented.  The important thing to remember is that the overpressure
     protection requirements that were used to size and protect all the
     systems and all the plants is the same as what was used on those five
     plants, and that's the ASME code requirements for overpressure
     protection.
         DR. POWERS:  Had you found no flaws, I'd say hey, pretty
     good answer.  But you found what?
         MR. CHERNY:  We found one that was sized bigger for -- I'd
     let him explain why it was big.  I don't remember why it was big.
         MR. GORMLEY:  There was a possibility that the charging
     pumps could through a valve misalignment --
         DR. POWERS:  And you explain that in the -- and what not,
     but it doesn't change my question.
         MR. GORMLEY:  Right.
         MR. CHERNY:  Again, I think it points out the fact though
     that you may have on a couple of plants a couple of outliers that the
     utilities would be responsible for taking some kind of special action on
     if there are any.  The so-called one valve that he found, he was able to
     show was not a real problem when he looked into it in some more depth.
         DR. POWERS:  And some sort of engineering judgment you
     based, you say yes, there may be a couple of them out there.  The
     question I'm asking you is how do you refute the individual that says
     no, it's not a couple, it's 98.
         MR. CRAIG:  We'll have a much better answer when we come
     back in June.
         DR. POWERS:  Thank you, John.  I guess you've already given
     it to me.
         [Laughter.]
         In that case, I'll ask do our Members have any additional
     questions they want to ask on this issue?
         John, as you can tell, the Committee is very interested in
     GSIs, not only individually but also globally in this area, and so we'll
     look forward when we come back and, quite frankly, we've enjoyed your
     presenters, especially your authority on valves.  He obviously knows
     more about valves than I will know if I stay up nights studying.  And I
     will take a recess until 25 after the hour.
         MR. CHERNY:  Thank you.
         [Recess.]
         DR. POWERS:  Let's come back into session.  We are going to
     have some change in the original plan of attack, but we're still going
     to spend some time discussing the fire protection functional inspection
     program and its fallout.  I have some opening comments, and I've
     provided the Members with background material here that I'd like to go
     through a little bit, maybe not as extensively as I had originally
     planned.
         When we get into this presentation, we're really dealing
     with fundamental issues of fire protection, what should the licensees do
     to assure adequate protection of the public from accidents initiated by
     fire or exacerbated by fire, and what does the NRC need to do to verify
     the licensees provide this assurance.
         There's some background on all this that the Members need to
     be aware of as we discuss these issues.  First and foremost, of course,
     is our fire protection regulations are indeed prescriptive, that despite
     the existence of the fire protection regulations, the IPEEEs apparently
     are showing that CDF from fire-initiated accidents to be significant,
     significant at least in comparison to CDF values that we derive from
     analyses of accidents initiated during normal operations.
         One of the questions that promptly comes up is in fact do we
     believe those results, that is, are methods that were used in the IPEEE
     process sufficiently reliable to come up with CDF values.  That's not
     going to be a part of this discussion, but it's a larger discussion that
     the Committee has.
         The real issue here is that if you do believe these results,
     then you have to remember the peculiar nature of our fire regulations. 
     They do not require the kinds of redundancy and diversity and safety
     class that we require for the protection systems during normal
     operations.  Yet associated with them are these relatively high CDF
     values.
         The fire protection and functional inspections were
     conducted on four pilot plants, and inspections were indeed costly to
     the industry, and I think it's fair to say that they were costly to the
     staff as well.  I think some of our speakers are well prepared to
     explain to you that their tongues were hanging out trying to do both the
     functional inspections and all the other work that came along with them.
         One of the questions we're going to have to understand,
     though, in thinking about the costliness of this is how much of that
     cost arose because the licensees were reestablishing the design basis
     information that should have been routinely maintained.  One of the
     conclusions that comes through in the report of the fire protection
     functional inspections has repeatedly said that its success lay in
     refocusing attention on the importance of fire protection at the plants.
         The other thing to bear in mind is that the licensees are
     comfortable with the existing prescription regulations and the existing
     inspection process.  What's going to be discussed in the fire protection
     functional inspection report that we have is that there are proposals to
     change the inspection process.
         When you think about change, then you have to think about
     all of these pilot programs that are going on now in connection with our
     changes in the way we inspect plants and assess plants, and the issue
     comes up if we do go about changing the fire protection inspections, do
     we want to inject them into the pilots that are now under way.  It's a
     challenge, because those inspections rely upon performance indicators,
     and we really don't have fire protection performance indicators now the
     way we do in many of the other performance areas.
         Finally I go into background for the Committee to always
     bear in mind is the fire protection is different than many reactor
     safety issues, in that it has a very high level of visibility and
     tangibility both to the public and the legislature.
         I've included in your background some points of contention
     that exist between proposals of the staff and responses from the
     industry.  I don't know that it's pertinent to go through these now,
     because there's going to be some changes in the staff position, but
     these are points of contention that we may want to bear in mind as we
     think and learn more about this issue.
         So at that point I guess I will turn to Steve.  Are you
     going to --
         MR. HANNON:  John Hannon, Assistant Branch Chief.  I'd like
     to make a few --
         DR. POWERS:  I'll turn to you and let you take over the
     discussion from that point on.
         MR. HANNON:  Thank you, Dr. Powers.  I appreciate the
     opportunity to come and meet with the ACRS to discuss our current status
     of our fire protection functional inspection program.  Steve and his
     staff have been working very hard and closely with the oversight task
     force that is responsible for integrating the fire protection inspection
     program into the oversight activities.
         As Dr. Powers pointed out, this is a controversial issue. 
     We have received at least two letters recently, one from NEI and one
     from Clearinghouse on Fire Protection commenting and giving us their
     concerns with the proposal.  And there seems to be an emphasis on
     timeliness and trying to go too fast here with this new program.  But
     hopefully you'll see that we have come up with a reasonable approach,
     and we think it's appropriate and necessary, and at this point then I'll
     turn over to Steve West to make the briefing.
         MR. WEST:  Thank you, John.
         I'm Steven West, the Chief of the Fire Protection
     Engineering, and now Special Projects Section also, since the
     reorganization.
         DR. POWERS:  Didn't have enough to do?
         MR. WEST:  I didn't.  Fire protection wasn't enough.
         So we're actually going to break the staff's presentation up
     into two parts today.  First I'm going to talk a little bit, give you an
     overview of the fire protection functional inspection pilot program,
     kind of the background.  I'll go through that quickly, because I think
     most of you are familiar with it -- but ask any questions -- and give
     you the status where we're at and what we have left to do.  And then
     we're going to have Pat Madden from the Plant Systems Branch and J. S.
     Hyslop from NRR's PRA branch discuss with you a method that we've
     developed for assessing the risk-significance of fire protection program
     deficiencies such as inspection findings, FPFI findings or any other
     inspection.  And they'll be able to talk to you some also about some of
     the specifics about the findings from the FPFIs and their risk or safety
     significance.
         Before I get started I just wanted to I guess apologize a
     little bit.  We thought we'd be further along when we got here to talk
     to you about the program.  We're a couple of weeks behind in getting our
     final report and our final Commission paper with our recommendations to
     the Commission.  And as you can imagine, because a couple of people have
     already mentioned it, it's not only a very important area, and we want
     to make sure that we do the right thing, but whatever we do obviously
     could have significant impacts on both the industry, the reactor
     licensees, and the staff.
         So we're trying to be very careful in coming up with our
     recommendation and doing the right thing based on the insights we got
     from this FPFI pilot program and other things that have happened over
     the past few years that give us some insights into the state of reactor
     fire safety.  And I'll discuss some of those as we go through the
     presentation here.
         As you'll recall, and Dr. Powers mentioned, one of our
     principal objectives of this FPFI program was to renew industry
     attention to reactor fire safety.  In light of the Thermo-Lag experience
     when we started looking into the state of fire protection and indeed
     looking at the staff's focus on reactor fire safety, we thought that it
     may have dropped below that which was in place at about the time when
     Appendix R was being implemented.  So actually probably what happened
     was, you know, the staff was very active in fire protection, in getting
     Appendix R implemented.
         Our activity in the area started tapering off, and of course
     the licensees follow suit.  So it's not really -- we're not trying to
     cast any aspersions on industry, but there was a concern that there was
     not being adequate attention paid to reactor fire safety.
         Along those lines we were interested in getting information
     as to whether licensees were in fact maintaining their licensing and
     design bases for their fire protection programs.
         DR. POWERS:  Let me ask you a question, Steve.
         MR. WEST:  Yes, sir.
         DR. POWERS:  I mean, as you know, I've had the privilege of
     attending these fire protection forums that the industry holds.  They're
     well attended.  I mean, I think the last one I was at there were 160
     people there.  That is not indicative to me of a lack of attention by
     the industry.  I mean, that seemed to be a very active bit of attention. 
     What led you to believe that there might -- that things may have fallen
     off?
         MR. WEST:  Well, they didn't have those forums before.
         [Laughter.]
         MR. WEST:  Before Thermo-Lag.
         DR. POWERS:  Not before Thermo-Lag, but --
         MR. WEST:  At least not at the scale they're at now.
         DR. POWERS:  I mean, they seem to be self-curing pretty
     quickly here then.
         MR. WEST:  I think there were a lot of changes that were
     brought about in response to the Thermo-Lag issue, and I think Fred
     Emerson or Dave Modeen's going to be talking to you later, and they may
     be better ones to ask about the industry response to some of these
     issues.
         But our perception was that after the Thermo-Lag issue, when
     we did a thorough self-assessment of the NRC's reactor fire protection
     program we did a couple pilot inspections for that and reviews of LERs
     and a bunch of other things, that it looked like the emphasis on fire
     protection both within the staff and with the industry had fallen,
     dropped, from the time of Appendix R.
         I believe NEI began conducting these forums initially to
     address Thermo-Lag issues because they were so pervasive and so many
     issues that had to be dealt with, and it made sense for industry to get
     together to talk about the issues and how to resolve them.  And then
     they grew from that.  They started getting more staff interaction
     through those forums and they have continued them, and they have been,
     as you mentioned, a very good indicator of industry's interest in
     reactor fire safety today.
         Okay.  Inspect design bases, inspect Thermo-Lag corrective
     actions, which was a commitment we had made to Congress, actually.  We
     had done a self-assessment of our fire protection program, as I
     mentioned, and we are kind of continuing that through the FPFI pilot
     program.  We wanted to see how effective our inspections had been in the
     past and today.  And so that was a part of it.
         And then, of course, falling out of the program, we should
     be able to make a determination on what the appropriate level of fire
     protection inspections would be for the future.  It could be anything
     from do nothing to continue to do full scope FPFIs or something in
     between.  So that was kind of the objectives we set up going into the
     program.
         Okay.  So what did we do?  And I think you know what we did. 
     You have mentioned most of it.  We developed an inspection procedure to
     conduct the FPFIs.  It is a very comprehensive inspection procedure,
     very thick.  It covers all aspects of reactor fire protection programs
     in quite a bit of detail.  It is an inspection procedure for fire
     protection like never existed before.
         We have gotten very good reviews on the inspection
     procedures.  We found them to be very effective in helping us plan and
     conduct our inspections.  And during our workshop with industry, we got
     some good feedback that they are good inspection procedures.
         So we used those inspection procedures to conduct four pilot
     inspections at River Bend, Susquehanna, St. Lucie and Prairie Island. 
     And Prairie Island was a little bit different because we were -- it was
     not a full scope FPFI but we were looking at the licensee's
     self-assessment that they had done using the FPFI procedure and lessons
     they had learned through the previous pilot inspections.  And one of the
     things we are trying to determine is could licensee self-assessments be
     an effective way for licensees to go and look at their programs and
     relieve some of the NRC inspection burden, if we had confidence that
     those self-assessments could achieve the same types of results that a
     FPFI would.
         We also, during the pilot period, we didn't actually conduct
     FPFIs, but we had two major inspections, team inspections, one at Quad
     Cities, actually, we went there a few times, and at Clinton.  And we
     used FPFI-like inspection techniques at those inspections also.  They
     were kind of that level, that scope, that level of detail, and that
     comprehensive.
         Now, one thing I want to point out is that we have, through
     the pilot program, tried to improve or increase our use of
     risk-information and risk insights to plan inspections and to assess
     inspection results.  And we actually, in the procedure, after I think
     the first or second FPFI, put an appendix into the procedure that
     provides the team leader and the inspectors guidance on how to
     risk-inform their inspection plan.
         And for the pilot inspections, the four pilots here, we used
     a risk analyst to help plan the inspection.  And, actually, I think for
     most of them, they came along on the inspection.  J.S., who is here
     today, helped us with those.  You probably have some questions in that
     area.  He may be a good one to ask about that.
         DR. POWERS:  Let me interrupt, Steve.
         MR. WEST:  Sure.
         DR. POWERS:  Just to remind members that we are planning to
     have a subcommittee meeting of the Fire Protection Subcommittee at
     Susquehanna in June and that would be an opportunity for the committee
     to get the inspectee's point of view on the FPFI.
         MR. WEST:  That would be a good one, a good thing to do
     while you are there.  Susquehanna did fairly well on their FPFI.  They
     had a fairly strong program.  We found strengths as well as weaknesses. 
     The licensee's engineering staff has been there a long time and they
     have been involved in their program, much more so than consultants, so
     they have good control over their program, understand it, were very good
     at answering the questions raised by the inspection team.  I would say
     overall they got very high marks at Susquehanna.
         We did have a one-day workshop attended by, I don't know,
     160 or so stakeholders, mostly licensees but also members of the public,
     vendor owners groups, NEI staff, our Region staff from here and
     headquarters.  We got some good insights from the workshop.
         And then one of the things that we had in mind that we
     needed to do before the workshop was to develop a method, kind of a
     systematic method that could be used to assess the risk significance of
     fire protection deficiencies.  And that was one of the topics of
     discussion at the workshop, and there was pretty much total agreement
     that that would be something that would be worthwhile to develop, both
     from industry saw the benefits of that as well as the staff.  So we have
     been developing a method and that is what J.S. and Pat are going to talk
     to you about later.
         We didn't have it in time, you know, during the inspections,
     to use it throughout the pilot inspection process, but we have gone back
     and looked at some of the inspection findings and run it through the --
     we call it the Hyslop maneuver, and assess some of the FPFI findings
     that way.
         Okay.  What are our kind of observations at this point,
     having got to the point where we are putting together the final -- in
     the final stages of our Commission paper and our final report?  We think
     there is renewed industry attention to reactor fire safety.  That has
     come out in forums such as the NEI Fire Protection Information forums,
     in our workshop on the FPFI program.
         In response to the FPFI pilot program, a number of licensees
     went out and on their initiative starting conducting self-assessments,
     even though they were not selected as pilot plants.  NEI has a program
     underway to develop self-assessment procedures that the licensees could
     use to conduct self-assessments.  So I think that objective was
     achieved.
         We did find, during the FPFIs, that a lot of the findings
     that we came up with during inspections had probably existed for quite a
     while and they were not revealed by our previous inspections.  And we
     think our NRC core inspection procedure, which is the procedure that is
     performed at each plant about once every three years, is weak and that
     it doesn't turn up some of the more risk significant findings.  It
     doesn't direct the inspector to look in the right areas.
         And, similarly, licensee QA audits, or in self-assessments
     that may have been based on the core inspection program, also had not
     found these types of problems.  We did find that the self-assessments
     that licensees were doing in preparation for an FPFI, like the one at
     Prairie Island and St. Lucie had also done one, where they looked in the
     right areas, at the right depth, were effective in finding problems with
     the programs.  So we concluded that self-assessments can be beneficial.
         I think if you just took our inspection reports and counted
     all the items where we said, you know, we found this noncompliance or
     deficiency or weakness, going back to the regulatory requirements, I
     think you would come up with a list of about 140 items.  Some of those
     were unresolved items and they have subsequently been resolved to our
     satisfaction.  And, of course, they were varied safety and risk
     significant.  Some would be, you know, very low and some are potentially
     high.
         With the exception of our inspection procedures themselves,
     or our inspection program, we didn't really find any significant
     problems with the reactor fire protection program.  And what I mean is
     if we looked at, you know, what the existing requirements and guidance
     are, we didn't see any big holes or items that we have missed where we
     should be paying attention to reactor fire safety and we have not.
         DR. POWERS:  Did you find or look for the opposite, that is,
     where the fire protection was excessive, unnecessary, redundant?
         MR. WEST:  I don't think -- no, I would have to say no, we
     didn't do that.  Now, I want to mention that, in this topical area, that
     we have actually briefed at least the subcommittee, I am not sure about
     the full committee, on an issue that we are working on on circuit
     analysis, and that problem came up independent of the FPFI program.  But
     it is an area where questions have been raised about the adequacy of our
     guidance on how you would do a circuit analysis.  So we are continuing
     to work through that.  There are some industry activities underway.
         DR. SEALE:  Steve, --
         DR. POWERS:  You must have surely found something else
     because you are doing a complete rewrite of the guidance.  I mean it is
     more than just fire induced circuit failure.
         MR. WEST:  You are talking about the comprehensive Reg.
     Guide.  Yeah, we are -- we do have the program to take all of the
     existing guidance that is scattered throughout many documents and try
     and consolidate them in one place.  It is really -- we are really not
     doing that to resolve any problems with the guidance.  We have found
     that there are some cases where there is --
         DR. POWERS:  Other than it is dispersed.  I mean that is a
     problem, it is dispersed.
         MR. WEST:  It is dispersed and there could be some
     conflicts.  You know, one thing may say hoses should be 100 feet long
     and another one way say they should be 75 feet long.  So there are some
     things like that.  I think the only -- in the comprehensive Reg. Guide
     right now, the only place where we think there may be a hole that we
     need to try and fill is on compensatory measures, providing some
     guidance on how you would establish what an appropriate compensatory
     measure could be for a particular fire protection program deficiency.
         DR. SEALE:  Steve, I have to chew on your ear a little bit
     here.
         MR. WEST:  Sure.
         DR. POWERS:  That is the gentlest thing that has happened to
     him in recent weeks.
         MR. WEST:  Yeah, it is usually much lower.
         DR. SEALE:  I find it incomprehensible that you could have a
     finding up there that said problems were found during the FPFIs, were
     not found by the NRC core inspection or licensee QA audits, and then
     come down and say that there were no significant problems found with the
     NRC fire protection program.  It seems to me that you need to have a
     sense of ownership for what the people in inspection and QA are doing on
     issues associated with your programmatic responsibilities.
         If they didn't have the kind of working information that the
     inspectors could use to maintain a high level of fire awareness in the
     inspection program, then it is your fault, at least partially.  You
     should have a sense of ownership for what they are using as the basis
     for the inspection program.
         MR. WEST:  And I agree with you.  That's what I said.  I
     said with the exception of inspection procedures, looking at the
     regulation itself and the guidance that's used to implement the
     regulation, we didn't find --
         DR. SEALE:  Well, that didn't come across very well.
         MR. WEST:  I thought I said that, but if not.
         DR. SEALE:  Okay.
         MR. WEST:  No, definitely, I think the, you know, the core
     inspection procedure is not adequate to find risk or safety significant
     fire protection problems, and there could be problems with the skill of
     the inspectors, there could be a number of reasons why --
         DR. SEALE:  Well, you know, there's even a cue or a hint
     here that might help you.  One of the things that the people in the
     training programs in the utilities found was that the training program
     process seemed to not exactly fit with the training requirements until
     the idea of ownership on the part of the users for the information base
     that was included in the training program was developed, and this was --
     then this was now an INPO kind of problem in terms of delivery of
     training and so on.  But the idea of ownership is an excellent way to
     articulate the relationship that ought to exist with a, if you will, a
     third party deliverer, which is what the inspection and QA people are
     relative to your technical area and the plant.  And if you can develop
     that concept --
         MR. WEST:  Right.
         DR. SEALE:  -- maybe it'll help define the things you need
     to do.
         MR. WEST:  Yes.  Okay.  I agree with you, and I think maybe
     it's not coming across in my slides or in my presentation, but in our
     Commission paper and our final report on the FPFI program, we do
     acknowledge that some of these problems exist because of our own
     inactivity --
         DR. SEALE:  Shyness.
         MR. WEST:  Right.  So, I mean, that's a valid point and it
     is one that -- as I mentioned, one of the reasons we did this whole
     program is we weren't sure how good or how thorough we had been, either,
     and we did implement this program to help us achieve a better
     understanding of that.
         Okay.  Also, we kind of have concluded that some level of
     NRC inspection is warranted, and probably some level of licensee
     self-assessment also is warranted.  I think we really think the licensee
     self-assessment or their -- ownership of their program, their pride of
     ownership, could be a big part of what we do in the future in a way of
     our oversight and inspection process, and presumably Fred or Dave will
     talk about that some more later because they do have some activities
     underway that should prove to be very beneficial.
         DR. SEALE:  There again in the training area,
     self-assessments are an integral part of the process.
         MR. WEST:  Right.  Right.
         So we are now developing, you know, I say some level, and we
     are now trying to put getting a recommendation to the Commission that
     would specify what that level of NRC inspection would be and how
     licensee self-assessments can play a role in what we do.
         We're trying to also be true to the objectives and concepts
     of the new reactor oversight and inspection process.  So whatever we're
     going to do should be incorporated into that.
         DR. APOSTOLAKIS:  You mean someone will talk about it later,
     how you do that?
         MR. WEST:  Excuse me?
         DR. APOSTOLAKIS:  You will talk about it later, how you do
     this?
         MR. WEST:  How we do what?
         DR. APOSTOLAKIS:  How do you coordinate it with the
     oversight program and the performance indicators they have and all that? 
     I mean, at which point are you going to get into the documents?
         MR. WEST:  I can talk a little bit about that.
         DR. APOSTOLAKIS:  You don't plan to cover this?
         MR. WEST:  Well, I --
         DR. POWERS:  These documents are defunct now.
         DR. APOSTOLAKIS:  Defunct?  We spent all this time reviewing
     them.
         DR. POWERS:  Thanks.
         MR. WEST:  We have developed a -- let me address that.  We
     in the Commission paper that went to the Commission in March on the new
     reactor oversight process recommended a fire protection inspection
     program that consisted of resident walkdowns, their normal duties, and a
     triennial fire protection team inspection.  That would not be a full
     FPFI; it would be a much reduced scope from an FPFI.  And we're now
     putting together a Commission paper specifically on the fire protection
     inspection programs, providing much more detail and is providing our
     bases for that recommendation.
         It was -- that paper was supposed to be finished before this
     meeting, and unfortunately, it's not.
         DR. APOSTOLAKIS:  I have here a draft --
         MR. SINGH:  Excuse me.  George, please don't discuss that. 
     That's pre-decisional, and that's the --
         DR. APOSTOLAKIS:  I can say from whom to whom.
         MR. SINGH:  Oh, sure.
         DR. APOSTOLAKIS:  I'm not going it read the whole thing.
         From Mr. Travers to the Commissioners, status of reactor
     fire protection projects and recommendations for reactor fire protection
     inspections.
         Is that obsolete now, or that doesn't tell you anything? 
     Yes what?  It doesn't --
         MR. SINGH:  Yes, it's obsolete because that is not good
     anymore.  They revised the whole thing.
         MR. WEST:  Wait, wait, wait, wait.  The paper may be
     revised, it may go like that.  It's pre-decisional right now.  We're
     working through the concurrence process.  It's up through the director
     of NRR and we're discussing comments with him.
         DR. APOSTOLAKIS:  So the comments I have are useless to you? 
     I mean, is it really dramatically different, what you plan to do?
         MR. WEST:  No, your comments are very useful if you have
     comments.
         DR. APOSTOLAKIS:  You don't know what they are.
         [Laughter.]
         DR. APOSTOLAKIS:  Tell me at which point, then, I should
     give you my comments.  Since you're not going to cover what is in here. 
     At the end of your presentation?  Or you don't want them at all?  I
     mean, I don't care.
         MR. WEST:  No, I think we would like to have your comments. 
     It's up to the committees when you want to provide comments.
         DR. APOSTOLAKIS:  I don't know.  If this is now completely
     rejected -- what do you think?
         DR. POWERS:  I think we're going to try to adhere closely to
     the schedule, which means I'm going to close this session at 11:45, and
     that means I need to complete the staff presentations no later than
     11:30.
         MR. WEST:  Okay.
         DR. POWERS:  Is that going to give you adequate time?  Good.
         MR. WEST:  So right now, the -- what's before the Commission
     would be a triennial fire protection inspection, you know, each three
     years, go to a plant and do some fire protection inspection with a
     three-person team.  That's kind of where we've settled in on, but until
     the paper actually gets signed out by the EDO --
         DR. APOSTOLAKIS:  Well, that's what you say here as well,
     don't you?
         MR. WEST:  Yes.
         DR. APOSTOLAKIS:  That there will be triennial meetings.  I
     mean, inspections.
         MR. WEST:  Right.
         DR. POWERS:  What I've never understood was three people,
     three -- every three years.  Why not four people every four years or one
     person every other month or -- I mean, how do you come up with that
     number?
         MR. WEST:  Do you want to answer that, Leon?
         MR. WHITNEY:  Leon Whitney, NRR.
         The three people refers to the fact that it's a synergistic
     integrated team of fire protection engineer, electrical engineer, and
     mechanical systems engineer, and we don't feel that -- unless you have
     that group of people working on it as far as a shutdown, that they can
     get below the surface and dig out the analysis and validate it.
         DR. POWERS:  You used more for the FPF --
         MR. WHITNEY:  Well, we used more people.  We used a regional
     representative, we had the risk representative with us.  We're not
     planning to, within the triennial draft, to have the risk representative
     actually travel to the site during the inspection, although he may come
     during the information gathering visit.  He's certainly going to be
     providing a major input into the inspection plan.  So he's part of the
     team; he's just not necessarily on site, and therefore, if you look at
     the way the inspection program, DIE, direct inspection effort, is
     calculated, he wouldn't show as a DIE, a direct inspection effort,
     because he's not on site during the actual one week of inspection.
         As for the duration, I don't know if you -- duration of one
     week.  It's adequate to certainly do a vertical slice of some aspect of
     post-fire safe shutdown and/or fire protection in the sense of
     sprinklers and detectors, et cetera, and barriers.  Triennial -- partly,
     that's driven by an intent to ensure and maintain adequate attention to
     the issue and to -- if we're going to have a one-week -- say a vertical
     slice, that means that various issues every three years at any given
     plant can be addressed, disparate issues, different vertical slices can
     be addressed, and over time, you get a good look at the entire program.
         DR. POWERS:  I think the real issue boils down to why these
     -- I can't call it big, but visible every-three-year inspections versus
     a regular inspection by the on-site inspectors and the regions?
         MR. WHITNEY:  Well, for traditional combustible control,
     ignition control, and status of sprinklers in terms of plant status
     looks, a single inspector who is adequately trained can do that.
         Now, when you get into the post-fire safe shutdown area and
     its interaction with fire area boundaries, barriers between equipment,
     electrical analysis in particular, and all this integrated look, you
     have to have the three people working together to adequately review the
     complex analysis and its implementation in the reactor plants.
         DR. SEALE:  Could I ask a related question?  How many fire
     protection specialists do you require in order to be able to support 30
     inspections a year?
         MR. WHITNEY:  Well --
         MR. WEST:  You would probably need one in each region.
         MR. WHITNEY:  And considering follow-up activity, you would
     be a very busy person, yeah.  However, it wouldn't be 30 a year.  If you
     look at -- generally, we go on a site basis, and we've worked out the
     math and it's six to eight per region per year, and then if you add in
     the fact of these, you know, 2,000 man hours and do all the
     calculations, he's a very busy person, especially with follow up.  Now,
     you also need other people to staff the electrical and mechanical.
         MR. WEST:  You know, there are a couple of other
     considerations.  One that we've mentioned a couple of times is the
     expectation that the licensees will be conducting self-assessments, and
     this gives them an opportunity to conduct them over a period of time
     looking at their whole program, probably over several years, could be
     two to three years, really.  And that way, when the inspectors go in,
     they can focus on the results of the self-assessment with some
     independent inspection, but they'll be able to take advantage of the
     work the licensees have done.
         The other aspect is that at the current time, there are no,
     as Dr. Powers mentioned, fire protection performance indicators.
         So that throws fire protection into an area, into an
     inspectable area, NEI is working on developing a set of fire protection
     performance indicators, and I think that'll be done in -- I think
     they're going to propose something to us sometime in the year 2000.  And
     one thing that we've said is that we would reconsider this baseline, say
     we went with a triannual inspection, we would reconsider that after we
     had conducted some triannual inspections, reviewed some licensee
     self-assessments, and determined that there were some performance
     indicators that could help reduce the amount of direct inspection that
     was required.
         DR. APOSTOLAKIS:  Now let me understand that a little bit. 
     What kinds of fire frequencies are we talking about here?  If I look at
     the performance indicators that the oversight program has developed,
     they have frequencies on initiating events, right?  And basically they
     are using unplanned scrams or scrams with loss of normal heat removal
     and so on.
         Now you're initiating event is the occurrence of a fire.
         MR. WEST:  Right.
         DR. APOSTOLAKIS:  What if I have a facility where in the
     auxiliary building for the last 15 years they really never had a fire? 
     Why shouldn't that be an indication that they are doing something right?
         MR. WEST:  That may be an indication that they're doing
     something right, but it can't be the only indication that we rely on to
     not conduct any inspections.
         DR. APOSTOLAKIS:  But you didn't say that.
         MR. WEST:  The fire frequencies are -- there should be an
     attachment to that draft paper you have, Attachment 1, that has all the
     data on fire risk and fire frequencies.
         DR. APOSTOLAKIS:  Yes.  But, I mean, we're not talking about
     events that appear once every thousand years.  I'm telling you, there
     was no fire at all.  Nothing.  Nothing.  Small, or anything.
         DR. WALLIS:  There can still be malfunctions of the fire
     protection system even without a fire, as we had out in Washington with
     the water hammer, which actually led to a significant event.
         DR. APOSTOLAKIS:  But the fact that you haven't had a fire
     should affect your inspection.  I mean, you may want to have additional
     performance indicators for other things.
         MR. WEST:  It may affect your inspection.  There may be
     information that you consider when you're planning your inspection,
     because the idea behind these inspections is to focus first on the risk
     and safety-significant areas, and that could be an input that the
     inspector uses to help develop his inspection plan, tells him where he's
     going to look, where he's going to do his inspection.
         DR. APOSTOLAKIS:  Which was something that I couldn't find
     in the big package that is now obsolete.  Was it there?
         MR. WEST:  That the inspections are going to be
     risk-informed, or that they're going to --
         DR. APOSTOLAKIS:  Focus on the -- or the critical locations. 
     Is it in there?
         MR. WEST:  I think it's in there.
         MR. WHITNEY:  Excuse me again.  Leon Whitney, NRR.
         The baseline inspection procedure talks in large measure
     about how the inspection plan is put together and calls upon the
     inspectors to take all risk and event information into account.
         MR. WEST:  They may not have that procedure.
         MR. WHITNEY:  I don't think you have that right now.
         MR. WEST:  It is in the paper, but --
         DR. APOSTOLAKIS:  Now when are we going to see these things? 
     Are we going to -- you're not going to discuss those when you go to
     Susquehanna, right?
         DR. POWERS:  No.
         DR. APOSTOLAKIS:  So there will be another presentation?
         DR. POWERS:  We'll have to deal with it when they're ready
     to deal with it.
         MR. WHITNEY:  We've developed the baseline; I believe it
     would be published and presented by the oversight program.
         DR. APOSTOLAKIS:  I mean, it seems to me that would be a
     good indicator of something.  It doesn't tell you much about the
     detection and suppression system.  You may want to do something there. 
     But the fact that they haven't had any fire should play a significant
     role.
         Now, let me go to the second one.  Another indicator or
     class of indicators that the oversight program is using is the
     mitigating systems, okay?  So they want safety system unavailabilities
     for 36 months, and they give you the numbers.  And the facility, you
     know, you have stated that you want to reach safe shutdown.  So if you
     go now to your critical locations, or any location, and identify what
     may be affected by the fire, why can't I have performance indicators on
     the staff that is independent of the fire, and then if I meet the goals,
     I'm happy.
         If there is a train that is not affected by a fire in this
     room, then I want a certain unavailability of that train, and if the
     utility demonstrates that they meet it, we don't inspect anything,
     because they met the goal.  I mean, that was the whole idea of the
     oversight program, that you have goals, and if you don't meet them, then
     something is triggered.
         MR. WEST:  Right.
         DR. APOSTOLAKIS:  Increased management attention.
         MR. WEST:  And that may be what comes out once the
     performance indicators are developed.
         DR. APOSTOLAKIS:  By NEI?  Or by you?
         MR. WEST:  Well, NEI has a program to develop them for
     industry with our -- I guess we'll have to review them and buy into them
     at some point.
         DR. APOSTOLAKIS:  But, I mean, if you are developing a
     functional fire protection program, you could use some insights like
     that without having the benefits of a major performance indicator
     development program.  It's kind of obvious.  You want to achieve safe
     shutdown, these are the trains that do it.  If you gentlemen convince me
     that the unavailability is less than 10 to the minus 2, that's fine. 
     I'm not going to do anything.  And in fact you can make that part of the
     maintenance rule, I guess.
         What's wrong with that kind of thinking?  Why do we need a
     research program to decide that?  I mean, we've been doing five PRAs for
     15 years now, 18 years.  Or that may very well be in the program.
         MR. HANNON:  This is John Hannon.  Let me point out one of
     the revisions to the paper you're looking at builds in a placeholder. 
     In the event that kind of performance indicator is demonstrated by the
     industry in the future, we would consider that and modify our inspection
     program accordingly.
         DR. APOSTOLAKIS:  The inspection program as it is now does
     not do this.
         MR. HANNON:  It allows for that eventuality to take place,
     but it does not do it now.  That's right.
         DR. APOSTOLAKIS:  You state very clearly in this paper which
     is obsolete that -- in fact say simply stated the underlying purpose of
     the NRC fire protection program -- I cannot read one sentence?; come on,
     they've said it many times -- is to reasonably assure that one means of
     achieving and maintaining safe shutdown conditions will remain
     available.  Okay?
         That's not really your objective, Steve, is it?  You really
     don't want to see any fires, because the New York Times may publish
     something and people may get upset.  I mean, you said that in your
     opening remarks, that people are paying attention.  Because if I go to
     the rest of the document that is now obsolete and I have this as an
     objective, then a lot of the stuff that you require is not needed.  So
     clearly your objective was different.  You just don't want to see
     anything.  I mean, except maybe a wastebasket, but you don't care about
     that.
         So I would suggest in the new document you really state
     clearly what you want to achieve, which you know already.  I mean, it's
     not new to you.  And if you really don't want to see fires, then perhaps
     you should state what kinds of fires that cause what, because that's
     your objective.  I mean, from reading the rest of the report, it seems
     to me that's really one --
         DR. SEALE:  George, you just have to recognize that the
     program has to include both prevention and mitigation components.
         MR. WEST:  Yes, I think you have to read two sentences,
     because that is the underlying purpose of the regulation, and it's
     achieved through fire protection defense in depth, which includes as the
     first element preventing fires, which you cannot do in all cases.
         DR. APOSTOLAKIS:  That's not defense in depth.
         MR. WEST:  That is fire protection defense in depth.  We've
     had this discussion before.  If you look at the fire protection
     regulation, it's stated in there.
         DR. POWERS:  The fire protection regulation is the only one
     that defines defense in depth, and it defines it very explicitly, and
     the delightful thing about it for PRA types is it follows exactly what
     you do in a fire protection PRA.  I mean, the two are totally aligned.
         DR. APOSTOLAKIS:  The fact that you have defense in depth
     has to do with the uncertainties you have.
         DR. POWERS:  No.
         DR. APOSTOLAKIS:  Not necessarily with your objectives.
         DR. POWERS:  No.
         DR. APOSTOLAKIS:  If you had a perfect assessment method
     that would tell you where fires would occur and, you know, with all the
     detailed probabilities and so on, that's an ideal world, defense in
     depth would play a minimal to next-to-nothing role, because you wouldn't
     need it.
         DR. POWERS:  Not in this case, George.  This case I think
     defense in depth the way it's defined would exist even if I had the
     perfect analytic tool.
         DR. APOSTOLAKIS:  It is defined because at that time you
     didn't have the perfect analytic tool.  It's a vicious circle here.
         DR. POWERS:  Now you really --
         DR. APOSTOLAKIS:  Are you saying because we defined it that
     way and now I have the perfect tool, I'm in trouble?
         DR. POWERS:  There is no trouble here.  The fire protection
     should be able to absorb risk-based methods of analysis more easily than
     any other world that exists, because the way they define defense in
     depth is the way you do a risk analysis.  You start by preventing fires,
     then you find you can't prevent all fires, so you try to detect them and
     suppress them, and you can't suppress all fires, so you try to protect
     the equipment that they might damage.
         DR. KRESS:  There is nothing wrong with that definition,
     George.  It's in line with our definition pretty much.  The only problem
     with it is it doesn't seem to be a good way to set limits on how much --
         DR. APOSTOLAKIS:  My objective is safe shutdown, and I
     demonstrate that I can have a 10 to the minus 6 probability frequency of
     not achieving this, and at the same time I can have a fairly large
     number of fires.  I have met my objective, but Steve is unhappy, because
     he doesn't want to see many fires.
         So what I'm saying is that the purpose is more than just a
     shutdown.
         DR. POWERS:  I'm really going to have to intercede, just to
     maintain schedule, because I've been losing schedule for the last two
     days.  And since I only have two days left, I have to make up someplace. 
     So I'm going to have to insist that we stay on schedule here.
         MR. WHITNEY:  Sir, if I could just respond to that last --
         DR. POWERS:  No.
         MR. WHITNEY:  Okay.
         DR. POWERS:  Let's press on with the presentation and
     recognize I'm going to hold you to schedule.
         MR. HYSLOP:  Can everyone hear me?
         My name is J. S. Hyslop.  I'm in the PRA branch of NRR, and
     together with Pat Madden in the Fire Protection Section, we've developed
     a fire protection risk-significant screening methodology to be used to
     detect the risk significance of fire protection weaknesses.
         I'm going to talk about the methodology, and Pat Madden will
     be discussing the applications afterwards.
         DR. APOSTOLAKIS:  So we haven't seen any of this yet.
         DR. POWERS:  No.
         MR. HYSLOP:  We have some objectives of the screening
     methodology.  The first is to focus inspectors on risk-significant sets
     of inspection findings, and to screen out findings which have minimal or
     no risk significance.  In addition, this fits into the plant oversight
     assessment process.  Therefore, it produces a potential risk
     significance which is tied to a color which is tied to a recommended
     regulatory response.
         Now here are some of the characteristics of the model. 
     First of all, it's a screening methodology.  If a fire scenario can be
     developed, then the frequency of challenging fires is conservative,
     challenging fires are defined by those not extinguished by
     extinguishers, all equipment and cables in the room where the fire
     initiates has failed, the barrier is challenged, and it failed. 
     Equipment and cables in the adjacent room fail.  And the
     characterization of the degradations to defense in depth due to the
     inspection findings is conservative.  It's a screening method.
         It's qualitative.  The degradations in defense in depth are
     characterized by high, medium, and low.  The method looks at inspection
     findings collectively.  As you know, degradations in defense in depth
     have a synergistic impact on risk.  The model produces a change in
     risk -- this is in CDF -- utilizes a paradigm similar to that of the
     inspection finding risk characterization process as defined in its
     SECY --
         DR. APOSTOLAKIS:  Excuse me, J.S.
         MR. HYSLOP:  Yes.
         DR. APOSTOLAKIS:  How do you produce the change in risk when
     the whole thing is qualitative and very conservative?
         MR. HYSLOP:  I'm coming to that.
         DR. APOSTOLAKIS:  Okay.
         MR. HYSLOP:  Would you like me to answer it now or --
         DR. APOSTOLAKIS:  No.
         MR. HYSLOP:  Okay.  So the frequency in fire is integrated
     with the defense in depth mitigation capability, and we produce
     risk-significant categories consistent with the regulatory response
     thresholds used in the licensee performance assessment process.
         We have an underlying quantitative foundation for this
     method.  First of all, we consider ignition frequency, that is ignition
     frequency of fires, and this is divided into ranges, and the upper
     frequency of the band represents the entire range, and the range is over
     a factor of 10.
         DR. APOSTOLAKIS:  Again, I have to understand that.
         MR. HYSLOP:  Yes.
         DR. APOSTOLAKIS:  What do you mean by ignition frequency?
         MR. HYSLOP:  The frequency of fires.
         DR. APOSTOLAKIS:  You said you have a room.
         MR. HYSLOP:  Yes.
         DR. APOSTOLAKIS:  And if there is a fire, everything goes.
         MR. HYSLOP:  Right.
         DR. APOSTOLAKIS:  Is that what you said?
         MR. HYSLOP:  If you can define a fire that ignites and
     propagates, then everything in the room goes.  However, the ignition
     frequency has been developed by the AEOD database for the different
     rooms, for the cable spreading room, for the switchgear room, et cetera,
     and that is based on at least 10 years of data.
         DR. APOSTOLAKIS:  But these are not fires that are sizable
     enough or in the right place to do a lot of damage, right?
         MR. HYSLOP:  Well, there is an ignition frequency, and then
     we convert that to a challenging fire through something akin to a
     severity factor, and I will be showing that on the next slide.  So we
     don't say all fires produce challenging fires even if we say there is a
     part of those.
         DR. KRESS:  So you have a database for these frequencies for
     each particular room, it is a set.
         MR. HYSLOP:  Yes.
         DR. KRESS:  And then you take, for a given room, you are
     going to divide it up.
         DR. APOSTOLAKIS:  For each room?
         DR. KRESS:  You know, you are going to divide that up.  You
     are going to divide that up into bands and do something with each band.
         MR. HYSLOP:  Well, first of all, we look at one fire area at
     a time, okay.  And there is an ignition frequency for that fire area. 
     And if it is -- say it is 5 times to the minus 3, then that fits into
     the 10 to the minus 3, the 10 to the minus 2 band.
         DR. KRESS:  I see.
         MR. HYSLOP:  So we use 10 to the minus 2 to represent that
     ignition frequency, which is the set of fires.
         DR. KRESS:  I understand.
         DR. APOSTOLAKIS:  Well, but why didn't you put the
     challenging probability in your room?
         MR. HYSLOP:  Because all of those fires don't --
         DR. POWERS:  Let me interrupt and say I don't know how we
     are going to do this.  You have got five minutes.
         MR. HYSLOP:  Both of us have five minutes?
         DR. POWERS:  You have five minutes.  I think this is going
     into the detail that is appropriate for a subcommittee.
         MR. HYSLOP:  Okay.  What I will do is go quickly through the
     next couple of slides.  First of all, I have said we integrate
     defense-in-depth with the frequency.  There we get core damage
     frequency.  There are certain dependencies between automatic suppression
     and manual suppression modeled.
         Here we tried to illustrate the concept.  Auto-suppression
     controls fires.  Manual -- the fire brigade is necessary to go in and
     extinguish the fire.  So if we have a significant degradation in the
     fire brigade and a degradation in the automatic suppression, the credit
     for that combination is reduced.
         Likewise, there are common mode failures between
     auto-suppression and the fire brigade.  Both water systems have common
     valves, pumps, et cetera.
         I will put this up here.  I am just going to talk a little
     bit about these.  These are the values which underlie the model.  We
     have several degradations in the defense-in-depth element, low to extra
     high.  These are the defense-in-depth elements which are modeled, safe
     shutdown, we have a three hour, one hour barrier, automatic suppression,
     and here we have manual suppression.  It is different in the control
     room and outside the control room because the control room is constantly
     manned.
         The reason the fire brigade is up here is for degradation of
     the fire brigade, we credit these values for manual suppression.  Note,
     for the high degradation, we don't -- we do credit manual suppression a
     little bit because of fire extinguishers.
         Five minutes.  Okay.  Let's go on to the next slide.  These
     are exponents of 10.  Any particular questions about this?
         [No response.]
         MR. HYSLOP:  Okay.  Here in the quantitative value assigned
     to the dependencies.  I elected to negate the credit for automatic
     suppression when it has medium degradations and the fire brigade has a
     high degradation.  And then for a low degradation of automatic
     suppression, this credit is reduced but not eliminated.  And then for
     the low degradation of the auto-suppression and the fire brigade, a
     certain value is added.  This is essentially a common cause contribution
     of .005, it is an estimate, an extreme --
         DR. WALLIS:  I'm sorry.  Did these numbers come by guesswork
     or by analysis of data or something?
         MR. HYSLOP:  Okay.
         DR. WALLIS:  They look awfully round.
         MR. HYSLOP:  Well, they are round.  They are round because
     this is a screening method, that is the first thing, and it is an
     approximate method.  These values in the low degradation come from NRC
     studies, countless ones, industry studies.
         DR. WALLIS:  Okay.  So there is a basis of experience, they
     are not just pulled out of the air.
         MR. HYSLOP:  This is the basis for experience.  These values
     came about because I am not going to allow any credit for the high
     degradation.  These values came about because the are in between.  There
     is some data on these -- on this value.  And here, for safe shutdown, we
     are doing essentially the Morris method technique.  For no trains, zero
     credit.  For a manual recovery, 10 to the minus 1, for a full train, 10
     to the minus 2, and for two trains with common cause, 10 to the minus 3. 
     So there is a basis for these numbers.  I just didn't go into them
     because I have got five minutes.
         DR. SEALE:  You've got one now.
         MR. HYSLOP:  Well, I've finished.
         MR. MADDEN:  Good job, J.S. -- and I am not going to say
     anything.
         [Laughter.]
         DR. POWERS:  I think you have introduced this new screening
     methodology that I think the committee is very interested in, in truth,
     but I think we are so interested in it that it is one of these things
     that is better pursued in a subcommittee forum where we can go into the
     details and explore the numbers in some depth.  We will try to find a
     time to do that, when it is mutually convenient.
         MR. SHACK:  Let me ask one question.
         DR. POWERS:  Sure.
         MR. SHACK:  The high, medium, and low -- that's the judgment
     of the inspector?  He goes in and he says this is a high, medium, low
     degradation --
         DR. POWERS:  Right.
         MR. SHACK:  It's his qualitative judgment.
         DR. POWERS:  Right.
         MR. SHACK:  And then he comes back and he plugs it in. 
     Okay.
         MR. MADDEN:  That is where we are kind of marrying the two
     sciences together, looking at that qualitatively, and we are developing
     a guidance document for the inspector to make those judgments.  It is
     the degree of conservatism you can probably argue over but it will give
     us a starting point for a more detailed analysis.  It will allow the
     inspector or reviewed to make a judgment to either no, this isn't
     safety-significant or risk-significant or potentially risk-significant,
     or it is.
         What it is trying to do is look at fire protection in an
     integrated fashion, even though George doesn't believe we had
     defense-in-depth, but that is what this process is trying to do, okay?
         MR. SHACK:  You say --
         MR. MADDEN:  All right, well, you know, you say it is a
     perfect world but it is not a perfect world, George.
         DR. SHACK:  In the fire protection functional example --
     when you went back and you screened these through, the noncompliances,
     how did they bin?
         MR. MADDEN:  Oh, well, that is an interesting question.  I
     am kind of glad you brought it up.
         We went back and we looked at the findings from the fire
     protection functional inspection.  We looked at approximately 33 percent
     of the findings.  When we started the process with the fire protection
     functional inspection we didn't have this tool available to us, so the
     inspection wasn't really governed or geared to that, but yet some of the
     principles still held true.
         What we did is we came back, we looked at the findings, we
     binned them and we binned them based on areas that are associated with
     what I want to call the top risk players -- control room, cable
     spreading room, and aux feedwater pump room for example, charging pump
     room for example, and we found that some of the findings would have put
     you onto the borderline Red category if you were to look at them in a
     integrated approach under a certain set of scenarios.
         You have to develop the scenarios, and that is where there
     is a new burden put on the inspector, that he has to come up with what I
     want to call a scenario where you could have a fire, the trains could be
     either affected by the plume or the fire could be sufficient enough or
     the fuel sources could be sufficient enough to develop a high gas layer,
     so if you were to get into a room, for example, that had nothing but
     conduits and pumps in it, it would be hard for him to enter into this,
     other than having findings, and those findings would end up being turned
     over to the licensee to be put in their corrective action program to
     weight against the regulation or compliance with the regulation.
         So there is some what I want to call bringing the risk sense
     into the inspection and forcing the inspector not to just go get a
     rulebook but to think about the process and how it interacts.
         DR. POWERS:  Did you have any more questions on these
     presentations?
         Fred, did you want to say some words?
         MR. EMERSON:  I'd like to say a few words.
         DR. POWERS:  Now I have a presentation by Fred Emerson from
     NEI -- I think the committee is familiar with Fred.
         MR. EMERSON:  I would like to thank the ACRS for the
     opportunity to say a few words about industry views on fire protection,
     inspection and assessment.  I have four slides and I am going to go
     through them fairly quickly, and I think in many respects we go along
     with the Staff thinking that there are some areas that we don't, and the
     areas of agreement and the areas of disagreement I think will be
     apparent by the time I finish.
         In summary, we believe and the Staff has indicated that
     current fire protection inspection programs are to be subsumed into the
     new oversight process, and we also agree with the Staff that there needs
     to be a balance between NRC baseline inspections and industry
     self-assessments.
         In keeping with the spirit of the oversight program, both
     need to be risk-informed and we also agree with the Staff that the FPFI
     should be reserved for reactive inspections when poor performance has
     been indicated by the licensee.
         DR. POWERS:  I guess you have to elaborate on the square
     bullet a little bit.  I seem to have read a letter that would indicate
     to the contrary and maybe it's just the timing in which you want it
     subsumed into the oversight process.
         MR. EMERSON:  I'm sorry, you said it shouldn't be?
         DR. POWERS:  Well, what I read was not subsumed into the
     pilot.
         MR. EMERSON:  Oh, yes, I understand you point.  The FPFIs or
     whatever their successor are should be subsumed into the new oversight
     process.  Now we don't think the module, the inspection module that has
     been generated, should be evaluated in the oversight process.  I was
     going to get to that in just a few minutes.
         DR. POWERS:  Okay.
         MR. EMERSON:  Steve alluded earlier to what the industry is
     proposing.  He talked about performance indicators and he talked about a
     plant self-assessment program and we are proposing this basically as a
     two-step piece as to how the industry should engage itself in this
     oversight process.
         In the short-term, and by short-term I mean during
     approximately the next year or so, a voluntary plant self-assessment
     program should be in place to address NRC concerns about
     self-assessment, that they perhaps were not comprehensive enough or deep
     enough on a broad enough scale to assure that the necessary findings or
     the necessary depth is achieved to determine what the state of the
     programs really are.
         We need to establish a baseline for the long-term assessment
     process, bring licensees up to a certain level to get ready for that,
     and NEI is developing guidelines to maximize the cost effectiveness of
     that.  By that I mean rather than telling each licensee to go out and do
     a full-blown FPFI type self-assessment that there are ways to approach
     it to focus licensee resources in areas that really need attention
     without digging into every area in a great deal of depth, and that is
     the goal of our committee.
         In the longer term, we need to balance licensee
     self-assessment and NRC oversight.  We are developing performance
     indicators to do that.  We propose to work with NRC to assure that there
     is an adequate balance and that the appropriate level of self-assessment
     and inspection is achieved without it being unnecessarily burdensome. 
     There was always some burden associated with it, but we want to assure
     that it is not unnecessarily burdensome to the licensees or the Staff.
         DR. POWERS:  When you make these judgments --
         MR. EMERSON:  On burden?
         DR. POWERS:  On how much to credit the self-assessment
     versus independent inspection and when not?
         MR. EMERSON:  I don't know that I can answer that yet.  I
     think we are going to have to see to what degree we can develop
     performance indicators successfully.
         We need to see what shape the NRC's baseline module, how
     that works out, and I don't know that I can really characterize what
     that balance needs to be.
         I know the industry is very interested in moving it away
     from total reliance on the NRC baseline inspection program as it
     currently is reflected in the SECY-99-007A because we think that -- Dr.
     Seale talked about accountability and the licensees need to take some
     accountability for their own programs, and in some ways are the
     best-qualified to assess them, but obviously you need regulatory
     oversight of that process, and what the balance is I think is yet to be
     determined.
         DR. POWERS:  I just wondered if you look at this you see
     that there are certain obligations from the NRC, there are certain
     obligations from the licensee.  There is a certain public interest.  How
     does that public interest get factored in -- and fire definitely
     attracts public interest.
         MR. EMERSON:  Yes, it does.
         DR. POWERS:  It attracts interest from the legislature.
         MR. EMERSON:  The public is definitely interested in making
     sure that fires that have an effect on the public don't occur and that
     you reduce the danger to the public through adequate implementation of
     defense-in-depth, and the public would like to be sure that the
     regulator is taking an active enough interest in nuclear fire protection
     issues such that the licensees have to either through their own efforts
     or the NRC's achieve those goals.
         I believe some segments of the public don't have a high
     degree of confidence now that that is occurring, and we want to assist
     the NRC in achieving a higher degree of public confidence that it is.
         DR. POWERS:  I think you have answered my question.  You are
     aware of the issue.
         MR. EMERSON:  Yes.
         On my last slide, to address your question about the
     baseline inspection module that the staff has proposed for discussion in
     the pilots, we have sent a letter to the staff with our comments, and
     you probably have that letter in your documents at your disposal.  The
     basic premises or the basic conclusions -- our principal comments are
     summarized in the four bullets.  We think that the risk-information is
     only selectively used in this document.  The risk-information should be
     applied to a broader area than just selecting the areas to be inspected,
     and then doing a deterministic type inspection.  That was our principal
     comment there.
         We believe that there is an over-emphasis on safe shutdown. 
     We heard Mr. Whitney indicate earlier that they felt that the triennial
     inspections were necessary to look at the safe shutdown element.  We
     think that any inspection needs to address all of the elements of
     defense-in-depth with equal emphasis.
         DR. POWERS:  That was more striking to me than any other
     comment that was made in the letter.  I mean it struck me that, gee, if
     I was the NRC, that is exactly where I would put all my attention,
     because I have very great confidence that the licensee has a very
     deep-seated financial incentive to focus on prevention and detection
     suppression of fires and whatnot.  So I look at the back end of things,
     a shutdown -- get this plant shut down safely in the event of a fire, if
     I am regulator.
         I just have great confidence that the licensee is going to
     work on all the prevention and detection things.  It has got an
     insurance agent that wants him to do it.  He has a financial incentive
     to do it.  Let him work that problem and probably rely heavily on his
     self-assessments.  I mean why isn't that good logic?  What am I missing
     here?
         MR. EMERSON:  I don't have any problems with your logic.
         DR. SEALE:  Dana, if I may comment.
         DR. POWERS:  Sure.
         DR. SEALE:  One comment.  It is interesting logic.  There is
     a problem, though, and that is we want to be sure we don't throw the
     baby out with the bathwater.  And that is if we are going to somehow
     turn this into a risk assessment, I still need quantitative methods to
     handle the suppression and the front end of the problem in doing the
     risk assessment.
         DR. POWERS:  We never get those from inspection, we get
     those --
         DR. SEALE:  No, I agree with you.  I mean you still have to
     have the analysis part of the front end in order to get the risk number.
         MR. EMERSON:  A third of our more significant concerns with
     the module is that we think that the triennial inspections are not the
     best way to determine the health of the licensee program.  And if you
     send a team in once every three years, it would seem that it is much
     better to have more focus on more routine oversight of self-assessments
     and a more frequent look than just a visit once every three years to
     make that assessment of the health of the program.
         DR. POWERS:  Whereas the previous bullet was the most
     striking, this was the most intriguing.  I mean there is a certain
     attraction of what it says there, but it is an assertion.  And I
     listened to Mr. Whitney tell me, well, you can't do that.  I have got to
     have these specialists in here to look at things in a great deal of
     detail every once in a while.  Well, how do you respond to him on that?
         MR. EMERSON:  I wouldn't argue that --
         DR. POWERS:  I know what my response was.
         MR. EMERSON:  I wouldn't argue that reliance on specialists
     -- because there needs to be some reliance on specialists who know what
     they are looking for, and I would agree that in the safe shutdown area,
     that might be appropriate.  But there might be a way to do that on a
     more routine basis in assisting the residents in interpreting what they
     are seeing on a day-to-day basis at the plant than actually sending this
     team in every three years.
         DR. POWERS:  Well, I think I got the impression that he was
     going to do all those things that he could do on a routine basis, but he
     could get the kind of detail that he was looking for in the triennial
     from that routine basis, simply because the guy he is asking to do it
     has to do a lot of other things, too.  He can't take a vertical slice
     down through things and factor in all the things that he has to and
     still get all the other jobs he has to do done.
         MR. EMERSON:  If, in fact, there is to be an increased
     reliance on looking at the licensee's self-assessments.  The licensees I
     think know how to look at their programs, and they have people at their
     sites who are well versed in their own safe shutdown programs, and I
     would say that an increased reliance on the licensee's ability to assess
     himself in that area would alleviate a lot of that concern.
         The last areas, there is a concern that trying to evaluate
     this model -- it is question of timeliness.  You know, there has been
     some structured preparations for the oversight pilots, and to throw this
     in at the last minute, now, the pilot plants I think would be very
     nervous trying to accommodate this sudden influx of new information into
     their program that they have carefully evaluated and prepared for.  And
     we don't think that the speed with which this is being done is
     warranted.  There are perhaps other ways that this program can be
     piloted once more thought is given to what it should include and how it
     should be balanced against licensee self-assessments.
         DR. POWERS:  Events themselves may cure this problem.
         MR. EMERSON:  That may be.  That is all I have.
         DR. POWERS:  Do members have any other questions for Fred?
         [No response.]
         DR. POWERS:  Well, Fred, thank you very much.  I appreciate
     your comments whenever you come.  It is always useful to get your
     perspective on things.
         MR. EMERSON:  May I say one thing?  There was a discussion
     before about the NEI forums and what they were intended to do.  I need
     to point out that the predecessor to NEI, the Edison Electric Institute
     has been conducting forums long before Thermo-Lag and they continue to
     do that.  So the NEI forums were not -- were basically a successor to
     the EEI forums, not created just exclusively to focus on Thermo-Lag, but
     we continue to find them useful.
         DR. POWERS:  And as I do, and I would encourage members that
     any time they have an opportunity to attend one of those, they are
     really very, very useful to get some insights on what is hot in the
     field of fire protection.
         DR. SEALE:  When is the next forum?
         MR. EMERSON:  October 18 to 20.
         DR. POWERS:  It is just up the road a ways.
         MR. EMERSON:  In St. Pete, Florida.
         DR. POWERS:  Down the road a ways.  Okay.  I am going to
     recess until 12:45.
         [Whereupon, at 11:48 a.m., the meeting was recessed, to
     reconvene at 12:48 p.m., this same day.].                   A F T E R N O O N  S E S S I O N
                                                     [12:48 p.m.]
         DR. POWERS:  Let's come back into session.
         Paul, could you -- Bonaca's in the -- okay.  We'll hold for
     about 2 minutes.  I'll apologize for the sluggishness in the start.  We
     just had a valued employee who's leaving us, and so there's, it's been a
     little slow to get started after lunch here, Tom.
         DR. KRESS:  The subject of this particular part of the
     meeting is some proposed modifications to the core damage assessment
     methodology and the post-accident sampling system that's required in
     plants.  Our severe Accident Management Subcommittee met on April 30 to
     hear about proposals from the Westinghouse Owner's Group to modify the
     system.  The guidance for the requirements can be found in a couple of
     documents -- NUREG-0737 and Reg Guide 1.97.
         The general purpose of these things, which were instituted
     as part of the TMI requirements were to have timely information on the
     extent of core damage or release of fission products in hydrogen for
     purposes of aiding decisions on emergency response and perhaps on
     accident management of recovery.
         The current requirements that are found in these documents
     have been around for awhile, since, I think, about 1984.  And they
     relied primarily on sampling from the RCS and sampling from the
     containment.  And these samples then or others subjected to analysis,
     chemical or otherwise, radiological -- to determine things like fission
     product content, a very specific range of fission products;
     hydrogen;dissolved gasses; boron.
         The licensees have exercised these systems and tests in
     emergency drills, and their experience has been that this sampling, to
     determine things like fission product content, has a real delay in it. 
     It's hard to deal with, analyze a sample that's radioactive and stuff
     like that -- you know, to take a sample and remove it and take to a lab
     takes a lot of time.
         It's their experience that the information that you get
     these comes in, actually, too late to be of real substantial benefit in
     making their emergency response decisions.  So instead of making those
     decisions on the basis of those samples, they've relied on what were
     secondary indicators -- things like core exit thermocouples and
     radiation monitors in containment, and even water level in the vessel,
     to actually infer, what I would call core damage states, rather than
     fission products.
         Core damage states being things like clad damage or
     substantial melt or onset of real hydrogen production and things like
     that.  So, since they couldn't use these samples very well in practice,
     they've proposed modifications to the requirements that would -- it
     would basically put into place the way the actually do it now.
         There are, in my mind, maybe two or three issues that we
     need to think about when we hear this proposal.  One of these would be
     -- since they're not actually looking for fission products anymore, but
     rely on a calculational methodology to go from temperature readings, for
     example, to information that they can use for emergency response.
         One issue I would ask you to think about, is this
     calculational methodology sufficiently good or sufficiently accurate.
         Another one is, will the proposed modifications result in
     sufficient information, even with those calculational tools on to base
     emergency response decisions and recovery actions, and even worker
     protection.
         And, the third issue -- which may sound a little funny, but
     it's one that I'd like for you to think about -- is there a better way
     than either current rule or the modification to this?  Is there an
     option that hasn't been considered?
         We do plan to have a letter on this, so I'd like for you tho
     think about these things carefully and help me make up my mind on what
     will be in the letter.  You do have a draft that I've developed, and for
     the benefit of those here that aren't familiar with the ACRS process,
     generally the Subcommittee starts the process by gathering information
     and is charged with developing a preliminary position.  I want to
     emphasize that word "preliminary" -- it's a position.  It's for
     consideration by the full committee.
         When we arrive at these preliminary positions in the
     Subcommittee, we try our best to communicate these to all stakeholder;
     that's including the full committee and it's including the licensee or
     the Owners Group, and it includes the staff who are a part of this, so
     that they can think about what our issues are and maybe be prepared to
     address them in the full Committee.
         I want it known that such a preliminary position gets
     debated and discussed -- I would say ad infinitum in the full Committee
     meeting.  And quite often, these preliminary positions get changed, and
     they're going to get changed as the result of a full meeting of the
     minds in their discussion.  But sometimes they don't, also.
         With that as an introduction, I will turn it over to, I
     think, Bob Brian of Westinghouse Owners Group.  He's going to start us
     out.
         MR. BRYAN:  Good afternoon, Mr. Chairman, members of the
     committee.  My name is Bob Bryan, I am from TVA, and I am representing
     the Westinghouse Owners Group as we discuss our proposals on core damage
     assessment methodology and post-accident sampling system.
         There were a couple of key points that I felt like it was
     important to make up front, and one is that the methods that we have
     right now are ones that were developed shortly after TMI, and there has
     been a lot of research, and lot of work, and a lot of discussions about
     what happened in TMI, and we have a better knowledge today of how severe
     accidents progress and what kind of information is available, and our
     new methodology takes advantage of that.  And we feel like that it is
     important to update our methodology to today's standard.  There are
     things in the current methodology that are basically not correct
     phenomenologically.
         Second, the revised methodology meets all the regulatory
     requirements, and by that I mean the specific requirements in 10 CFR. 
     As a consequence of these changes, there will be no request for
     exemptions, there will be no request for rule changes.  We will have to
     revise licensee commitments related to guidance documents, i.e., NUREG
     0737 and Reg. Guide 1.97.
         Most importantly, we think that what we are proposing better
     supports our post-accident needs.  We have been doing a lot of severe
     accident training, we do drills regularly, and I think we have a better
     understanding today of what our needs are and what the timing for those
     needs are as compared to what we had when the methodologies were
     originally developed.
         And last, the method we are proposing is accurate for making
     the kinds of decisions that we need to make.  We need basically order of
     magnitude kind of projections of where the plan is with respect to core
     damage.  It is not critical for us to know whether it is 37 percent of
     the fuel is melted or 47 percent of the fuel is melted.  We need to know
     in broad senses where the plant is.  And so our proposed methodology has
     that accuracy built into it.
         DR. WALLIS:  Have you actually formally written down or
     analyzed just what it is you do need?
         MR. BRYAN:  Yes.
         DR. WALLIS:  So you can compare this formally with what you
     are going to get?
         MR. BRYAN:  Yes.  And I think I will address that in a
     minute.
         Our outcomes, I just wanted to show you that what we propose
     provides the protection of the plant and the public that we would like
     to have.  We also hope to show that what we are proposing does meet the
     needs for looking at emergency based decisions.  And in terms of the
     future things we need to do, we still have a couple of issues that are
     open between the Owners Group and the staff to be resolved.
         I wanted to try to give you some flavor of how the core
     damage methodology and PASS enters into our emergency planning
     processes.  If you have an event, there are a couple of things that
     happen.  As you are trying to decide emergency action levels, i.e.,
     whether you are in an unusual event, a site emergency or a general
     emergency?  These things are made based on indications directly from the
     plant.
         They are made off of the status of systems.  Are your ECCS
     pumps running?  There are direct requirements out of our emergency
     operating procedures that say if core exit thermocouples are at certain
     levels, that is an indication of the status of plant systems.  They are
     made off of high radiation monitors.  If you are above a certain level
     on the containment radiation monitors.  If you are above a certain level
     on the containment radiation monitors, you enter particular steps in the
     emergency action levels.
         The core damage assessment feeds somewhat indirectly this
     process.  There is not a direct feed from the core damage methodology
     into any specific emergency action level.  What it does feed is a
     general knowledge for the emergency director and that team to help make
     decisions relative to emergency action levels that he may want to take
     based on his judgment of where he thinks the accident may be going, as
     opposed to specific things that are going on right at that minute.
         DR. WALLIS:  Can I ask about CDA?  Is that something that
     someone has to sit down and compute or is there some algorithm which
     takes these instrument indication and gives a direct printout or some
     picture of the status of the core?
         MR. BRYAN:  Okay.  Okay.  This is basically an action that
     is done offline.  It could be done in the Technical Support Center or,
     in the case of my utility, it is done in a Central Emergency Center.  We
     do have a computer program that is in there that we feed information
     from the plants into that we do routine updates to.  We also have
     basically a set of hand charts that we can work our way through in case
     the computers weren't available or something like that.  But this is a
     pretty simplistic look at things, and I will talk about that a little
     more in just a minute.  But it basically says you are at one of three
     pretty high level points in terms of where the plant is.
         Similarly, in terms of protective action recommendations,
     those things, once again, are made principally off things that are
     actually happening.  What is the status of the plant as determined back
     here through your EOPs or direct instrumentation readings, through
     measurements of off-site dose by your field teams, or by measured
     releases?
         You can, also, if you are looking at projecting protective
     action recommendations, the core damage assessment may be used as a
     feeder into off-site dose projections to help in making these, but the
     protective action recommendations generally, you try to make those off
     of measured data, not sampling, but actual releases that are out there,
     or a specific plant state.
         These things are all pretty short-term activities.  We see
     these in terms of minutes and hours, and in the middle of an event,
     things are happening pretty fast.  Where we see a real need for PASS is
     in terms of longer-term recovery strategies, and in these things you
     will have many hours or perhaps days to sit down and make decisions
     about what actually happened, where the plant really is, and what are
     the best ways to set up a long-term recovery plan.
     The core damage methodology is basically a way for us to simplistically
     quantify the state of the plant, and we basically look at it for three
     things.  Is our clad intact?  Are we in a situation where we might have
     clad rupture?  And in this case you'd be getting your noble gases and
     some volatiles out.  And then finally, is the fuel in an overheated
     state where you would be getting a lot of nonvolatiles out.  And as I
     talked about before, we use this as providing guidance to the emergency
     team to help them in making decisions.
         DR. WALLIS:  This fuel temperature isn't directly measured. 
     It's measured by something else.  You don't actually measure the
     temperature of the fuel.
         MR. BRYAN:  That's correct.  That is correct.
         DR. WALLIS:  It doesn't just look for those states.  Doesn't
     it look for how much damage is done?
         MR. BRYAN:  No, sir.
         DR. WALLIS:  It says yes or no, there is a rupture?
         MR. BRYAN:  That's correct.
         DR. WALLIS:  So there must be some level of sensitivity
     where it decides rupture or no rupture then.  That's all been worked out
     presumably.
         MR. BRYAN:  Yes.  I mean basically what we look for is if
     the core exit thermocouples are under about 750 degrees and we don't
     have -- and our high-radiation monitors are at fairly low levels
     basically consistent with what you would have for normal coolant
     activity, we say the clad's intact.  If the core exit thermocouples are
     in the 1,200-degree range and you're seeing elevated levels in the --
     elevated levels of radiation in the containment, we make an assumption
     for the core damage assessment that you're in a clad-rupture scenario. 
     If you see very high temperatures on the core exit thermocouples or you
     see very, very high levels on your containment high-radiation monitors,
     you make an assumption that you had fuel overheating and basically the
     whole source term's available in some form that you have to deal with as
     released under the RCS and potentially into the containment.
         DR. WALLIS:  The core exit thermocouple's a pretty indirect
     measure.  I mean, it depends on the flow rates of the steam and how much
     is uncovered and all sorts of things.  It's not a direct measurement of
     what you want to find out.
         MR. BRYAN:  That's true, but you can make broad assumptions
     about and conservative assumptions about where you are.  I think we
     picked end points for these things that if you make decisions off of
     them, they are acceptable for making prudent decisions relative to the
     state of the core, and once again keep in mind, to step back to the
     emergency action levels, if I have an indication that I have as an
     example 1,200 degrees on the core exit thermocouples, I assume that I
     have essentially failed my ECCS systems.  That requires me by my EALs,
     independent of whatever I think the core damage may be, to take certain
     steps relative to declaring either a site or a general emergency.
         So while you may say the things are indirect, they are the
     ones that we use independent of the core damage methodology for making
     the key decisions about how we manage the accident and how we ultimately
     decide on protective action recommendations.
         DR. SHACK:  I thought in the report you were making
     estimates of the amount of core damage simply by how many thermocouples
     were showing high temperatures.
         MR. BRYAN:  You can, but what we really care about, though,
     is really just broad --
         DR. SHACK:  A go, no go.
         MR. BRYAN:  A broad sweep on the thing.
         When we went back --
         DR. WALLIS:  I guess that's what we're going to have to be
     satisfied with, that the broad sweep gives you enough information, that
     maybe it needs to be less broad.
         MR. BRYAN:  Well, first, we felt like if we were going back
     and looking at this thing, we felt we needed to revise it, what were
     things that we wanted to make sure that we dealt with.  Number 1 is the
     timeliness issue.  Even with online sampling, there are time delays that
     are built into that.  You have to send people down there.  They have to
     purge lines.  They have to take samples.  They have to analyze them in
     the sample facility.  And those things lag what's going on in the plant,
     particularly if you have a transient that's moving with any speed at
     all.  Your core exit thermocouples, your online equipment, responds much
     more quickly to that.
         DR. WALLIS:  I was very surprised about that.  I mean surely
     there's sophisticated instrumentation which is almost immediate, which
     will tell you -- give you indications of what you're looking for.  You
     don't have to use some antique chemical sampling method.
         MR. BRYAN:  You may be able to go in and put in a plant new
     instrumentation that nobody has right now that does much of this thing,
     but the issue is, you know, one is we have to deal with what's in our
     plants today and decide if that's appropriate.  Number 2 is keep in mind
     that the equipment that we have in now is believed to be and we
     certainly believe it to be consistent with every regulatory requirement
     that's out there and so from that standpoint was adequate.  What we feel
     like is what we're proposing here provides a scheme that provides better
     information, more timely information, than what we have currently, and
     so the net effect is an improvement in the way we deal with the
     situation.
         We talked about accuracy.  It needs to be representative of
     actual plant conditions, but the question is, you know, what's the
     degree of precision we need to know it.  And the answer is for making
     decisions about -- we make our protective action decisions at fairly
     high levels, so we don't need a great deal of precision in our numbers. 
     So the fact that I know precisely how much iodine or any fission product
     is in a sample stream is really immaterial to our decision making
     process.
         We're going to make conservative decisions relative to what
     the potential releases or actual releases are based on broad-sweep
     things.  If we think we have early indications of potential core damage,
     we're going to do the evacuations that are consistent with that that are
     conservative with respect to that.  And so we try to keep the plant
     looking ahead from a safe standpoint.  Sometime later we can come back
     and take samples and send them off to a laboratory, and we'll talk about
     this and get a very detailed picture of what's transpired.  But for
     making our decisions in the minutes and hours after an event, we don't
     need that degree of precision.
         In terms of the availability of information, we feel like
     the in-plant information -- the in-plant instrumentation provides that
     information in a much more timely manner, and it's more effective in our
     overall emergency planning because, as I said, you have to tie up
     personnel to take samples, and if you're really in a severe accident,
     any trip into the auxiliary building represents a radiation hazard to
     the people that are doing it.  And we feel like those operators are more
     valuable to us to be able to be available to do recovery actions that we
     may need to mitigate the event than taking samples for us.  And we may
     have to take, if we didn't have in-plant instrumentation, we would be
     having to take those at fairly frequent intervals.
         From our standpoint in terms of the way people actually do
     this, the decisions right now are largely made on in-plant
     instrumentation.  We use sampling only as basically a means of last
     resort.  We have the capability, but largely because of these
     considerations, this last consideration, that's not something we like to
     do if we feel like the other information is adequate.
         DR. WALLIS:  Now at TMI there was lots of information which
     was misunderstood, so confirmation of information is sometimes useful.
         MR. BRYAN:  That's true, and I think there are a couple of
     things though relative to TMI.  One is that was a huge lesson learned,
     and I think we never need to lose that attitude of questioning that
     should have developed after TMI.  But we have put in a lot of things
     specifically to look -- to fill information voids that we found existed
     in TMI -- core exit thermocouples are a prime example of that.  We've
     gone to a whole different set of procedures now in terms of being
     symptom-based as opposed to saying yes, this is my event, I'm going to
     go down this path.  There are a lot more places in the process that
     bring you back to questions am I doing the right things, am I getting
     the right information.  And so I think we feel like overall we've
     covered a lot of those voids that didn't exist prior to TMI.  That's not
     to say that when the next event happens, we're going to know it all.
         The next couple of slide I am going to put up basically are
     for information and I don't intend to go through point by point, but
     this is basically a comparison of the existing core damage assessment
     methodology with our new methodology.
         It obviously uses in-plant instrumentation and we have tried
     to account for physical processes that were not in the original core
     damage assessment methodology.
         DR. KRESS:  Let me ask you about that, Bob.
         MR. BRYAN:  Okay.
         DR. KRESS:  Number one, you just said you really didn't need
     fission products for your core damage assessment.
         MR. BRYAN:  Specific.
         DR. KRESS:  But you would get them anyway, you say, for some
     reason or other.
         MR. BRYAN:  Okay.
         DR. KRESS:  You are going to project those based on the
     calculation I presume using MAAP.
         MR. BRYAN:  We do a couple of things.
         Relative to fission product deposition we have looked at
     NUREG-1465, we have looked at MAAP, we have looked at -- there have been
     comparisons with MELCOR work that that give us some feel for how things,
     where things may be.
         DR. KRESS:  So these would be sort of general for low
     pressure accidents and high pressure accidents or ATWS events --
         MR. BRYAN:  That's right.
         DR. KRESS:  You would have some indication of the effect of
     the temperature transient on fission product release based on all this
     knowledge and some guidance on how much it has held up in the RCS and
     how much gets released, and then what happens if you have a containment
     spray zone in accounting for what happens in containment.
         MR. BRYAN:  Yes, that's the idea.  Just to use some
     examples, if we have low RCS pressure we will assume we have a large
     release in progress and the assumption for the core damage assessment
     methodology is the fission product release would be anywhere from 50
     percent to essentially 98 percent, very broad band.
         For small accidents or small break accidents where the RCS
     is at high pressure, we have a different set of criteria that cover a
     band going from 2 percent to 50 percent, and basically what we do is
     these bands are broad enough that even if I miss it, if the actual
     release was 10 percent or 25 percent, it is not going to make any
     difference in terms of the kind of information I am giving people and
     saying it is basically we have a high pressure event, we have got a fair
     amount of holdup in the RCS, and here's what we would project to be
     going on in terms of release.
         If you had a small event that actually had more than 50
     percent, you are going to take actions as if all of this stuff was out
     in the containment, which is still a conservative action relative to
     making protective action recommendations.
         DR. KRESS:  I am not quite sure I understand that. You have
     something, an event, going on and you want to tell your people down in
     the emergency room we have got this event going on and in the next 10-15
     minutes or so you could expect to see either somewhere between 2 percent
     and 50 percent of the fission products in containment?  I am not quite
     sure what you are telling them.
         MR. BRYAN:  Okay.  What we would do is what we would tell
     them is that we had a -- if we were getting between 2 and 50 percent,
     what we would tell them is we have had cladding rupture.  It looks like
     we have a small break in the RCS, and we would provide some information
     to the offsite dose team where they could calculate, if you wanted to
     postulate a containment release or if you had one in progress you could
     make a projection about what might be going on.
         At that point they would basically assume that they had clad
     rupture.  There is an event tree, but let's assume that we are not in an
     overheat situation.  We just had clad rupture.  They would make some
     assumptions relative to what the fission product mix in containment is,
     and they are going to tend to err somewhat on the high side of that
     relative to deciding what is the potential release offsite.
         DR. KRESS:  Might someone decide to evacuate on the basis of
     this information, or do they decide to evacuate on the basis of some
     other?
         MR. BRYAN:  Well, most of the time it is decided on other
     factors.  The Emergency Director always has the authority to declare
     essentially a general emergency or a protective action that is greater
     than that, make that recommendation to the state.
         DR. KRESS:  This is based on this information and other
     information?
         MR. BARTON:  Do you have a PAR diagram or something with you
     that could explain this to Dr. Kress, a logic diagram, fault tree you go
     through with all the inputs that you use to make your protective action
     recommendations?
         MR. BRYAN:  I don't have a slide like that.
         DR. KRESS:  That's all right.  I have seen those.  I am
     familiar with it.
         MR. BRYAN:  To go back to this one, this is independent of
     this block.  The decisions are largely made off of specific set points
     and instrument readings, equipment status or the Site Emergency
     Director's judgment.
         DR. KRESS:  These are in the emergency operating procedures?
         MR. BRYAN:  Either in the emergency operating procedures or
     in the emergency plan procedures.
         DR. WALLIS:  Well, I guess it goes back to that question I
     asked some time ago, and I knew exactly what you need to know at this
     EAL stage in order to make a decision, then we could perhaps tell
     whether your proposal meets those requirements or not.
         You are sort of doing it from the other end.  You are saying
     I can measure all these things but I still don't quite know what you are
     going to do with it.
         MR. BRYAN:  But what I am saying is I basically do not use
     this --
         DR. WALLIS:  But at the EAL stage somebody there needs
     information.  What does that person need?  How are you going to give it
     to him?  That is all I am asking.
         MR. BRYAN:  Okay --
         DR. WALLIS:  Will you be able to answer all the questions
     these folks have by your instrument?
         MR. BARTON:  He will be able to answer enough to be able to
     make a conservative --
         DR. WALLIS:  I don't know yet because no one has told me
     what those questions are.
         MR. BRYAN:  The questions I have -- I can enter this from a
     lot of ways, but when I get far enough into the event I basically get
     down to what is the status of my three fission product barriers.
         DR. WALLIS:  I don't need --
         MR. BRYAN:  And --
         DR. WALLIS:  I just need to know that you have gone through
     this process.
         I don't need all the details, but if you haven't, then I
     can't evaluate it.
         MR. BRYAN:  And these I think both we, the NRC, and state
     emergency people all believe that there's sufficient information in our
     plans to make these decisions independent of this.
         MR. BARTON:  Graham, there is a table in the emergency
     procedures that gives you certain symptoms in the plant which will get
     you into this EAL listing and be able to -- you will be able to classify
     what level emergency you are at based on the symptoms, and you get those
     from the instrumentation and plant indications.
         There are procedures in place and there are methods
     available to get the information, to get you the EAL box without --
         MR. BRYAN:  That's right.
         DR. WALLIS:  Essentially what do you have to show, and you
     think you have shown in presumably, and the Staff -- I don't know what
     they think -- what you are proposing will give the information.  That is
     all you have to show.
         DR. KRESS:  And they are not proposing anything that affects
     that top line --
         MR. BRYAN:  That's right, we are not changing the top line
     at all.
         DR. KRESS:  The top line is fixed --
         DR. WALLIS:  Well, then I am unaware.
         DR. KRESS:  -- and it is not being changed.  It just these
     three areas down below --
         DR. WALLIS:  So it is the other line.  My questions apply to
     that.
         DR. KRESS:  And what he is saying is that the top line is
     basically independent of these three others.
         DR. WALLIS:  Okay, I'm sorry.  I was confused.
         Anyway, the questions still apply but to the other line.
         DR. KRESS:  Yes, it applies, but that is another issue. 
     That is another question.
         MR. BRYAN:  This goes over, just very quickly, what our
     existing methodology -- how it looked at things, what was and wasn't
     considered and how they were considered, and what we are proposing in
     our new methodology.  Basically all we are saying is there were a lot of
     things that weren't considered basically because we didn't know about
     them and they weren't well understood, and the new methodology is an
     attempt to take advantage of that, so we get a better look at it than we
     had before.
         DR. POWERS:  Bob, one of the things I didn't understand --
     there are quite a few things I don't understand, but one of them is what
     you meant by a bounding aerosol model.  Is that one that overpredicts
     aerosol deposition or underpredicts aerosol deposition?
         MR. BRYAN:  Well, our intent in this is to underpredict what
     the retention in the RCS would be, i.e., that there would be more
     released --
         MR. LUTZ:  Opposite.
         MR. BRYAN:  We want to overpredict what is --
         MR. LUTZ:  Yes.
         MR. BRYAN:  -- in the RCS?
         MR. LUTZ:  Yes.
         MR. BRYAN:  Okay.
         MR. LUTZ:  Underpredict release to containment.
         DR. POWERS:  It seems to me to be the way and it is just how
     you pick it, and so you did go with the bound such that you underpredict
     the amount that would excite the instrumentation?
         MR. BRYAN:  That's correct -- from his standpoint.  That's
     right. What we did was we looked at it so that we assumed it was held
     up, it would be in there so that a smaller number in containment would
     drive us to a higher assumption on what the actual state of damage was.
         DR. POWERS:  You know, who came along and said okay, I have
     looked at these aerosol physics models and by doing something I made
     that bounding?
         MR. BRYAN:  Bob?
         MR. LUTZ:  This is Bob Lutz from Westinghouse.  What we did
     is we looked at a lot of analyses with the MAAP code, the MELCOR code,
     and also looked --
         DR. POWERS:  Let me cut to the chase and ask you which one
     of those models that you looked at considered the Coulombic interaction
     between aerosol particles due to charging by radioactivity?
         MR. ROSENTHAL:  None of them.  We also looked at the
     research that currently is coming out of Europe from the FEBIS
     experiments and others in Europe and concluded -- and when we look at
     everything in total we believe that the predictions of the MAAP code
     tend to predict more retention in the primary coolant system, in the
     reactor coolant system, and less airborne radioactivity in the
     containment.
         Now the reason we did this is because we are basing in part
     our estimate of core damage on the containment high area radiation
     monitor, so if we set as our standard for coming up with core damage
     estimate a low level of radioactivity in the containment, in an actual
     event if there is less deposition in the reactor coolant system, less
     deposition in the containment, then we tend to overpredict the amount of
     core damage using this methodology, which is on I believe the safe side
     rather than underpredicting.
         DR. POWERS:  I guess that is my question.  What you want to
     do is exactly what you tried to do.  That is, I have got a signal in my
     containment indicating the amount of radioactivity or something that I
     have and I don't want to underestimate the amount of core damage that I
     have based on that, and we use an aerosol model.
         Okay.  Those aerosol models have been based on aerosols that
     are not radioactive, but aerosols are radioactive in this case and when
     they are radioactive have a Coulombic interaction.
     And I personally don't know what that makes them do, whether that makes
     them deposit more or deposit less, so how do I know that I'm bounding
     for the real case?
         MR. LUTZ:  Well, what we're saying is based on what we
     understand today, what the current knowledge is, we're making our best
     estimate at things.  We know the existing core damage assessment out
     there is not accurate because it doesn't consider anything, so we're
     trying to develop the best tool that we know how today.
         Now, even if you go to samples of containment atmosphere
     rather than relying on the containment monitor, you still have to go
     through this process of what does containment radiation represent in
     terms of the core.  So this is not unique to the proposal necessarily to
     use fixed in-plant instrumentation; it's a generic problem that we have
     if we're going to use any radioactivity measurements to make an estimate
     of core damage.
         So how do we infer core damage, whether it's -- whatever
     process we use, it is an inference of core damage and not a direct
     measurement.
         DR. KRESS:  How does that next line, the revaporization in
     the RCS, fit into that bounding logic?  Because that removes other
     things.  I mean, that takes things back into containment, it takes you
     the other way.
         MR. LUTZ:  That's correct, and we've looked at it in I'll
     say two ways.  One is what we're trying to do with core damage
     assessment is within the first minutes or hours, to try to follow what's
     going on in the core so that it can be part of the information that the
     TSC has.  And in that time frame, based on what we know about aerosol
     physics and what's happening, the revaporization does not drive what's
     in containment.
         Now, to account for things that go on during the event, we
     base the estimate on the current RCS pressure.  So in other words, if
     you're going along for an hour and then suddenly open -- intentionally
     open the PORVs, we say you're going to dump a lot of that out because of
     revaporization, you're going to dump a lot of what was retained in the
     RCS at that time, you're going to dump it to containment.  So the
     methodology does consider it from that standpoint.
         DR. WALLIS:  I would think you would want to know
     independently the core damage and how much is in the containment, rather
     than trying to infer one from the -- they're independent variables.  You
     can get more -- you know, lots of core damage with less in the
     containment understand certain circumstances.
         MR. LUTZ:  Yes.  And to understand, instead of the old
     methodology where we based it on samples of radioactivity, we are now
     using three indicators --
         MR. BRYAN:  Let me see if I can bring this back for just a
     minute.
         One thing to not lose sight of in here is that what we're
     talking about is what we deal with in one feet of the decision process. 
     You know, we're not -- we're really not -- in our minds, we're not
     taking away information that we were using to make these decisions with
     anyway.  The main line of how we decided what actions we were going to
     take and what protective actions we were going to take were done sort of
     independent of this model.  This was a second order feed into that
     decision process.  So we think getting that better provides -- helps our
     process, but I don't think it really changes what the know or don't know
     as we progress through this per se.
         DR. FONTANA:  Isn't the decision you're going to make
     whether to implement evacuation, for example.  Okay.  Now, in that case,
     aren't you really just interested in what the activity that would be
     released to the environment is, and you don't care too much about how
     much core damage you've got unless an estimate of how much core damage
     you've got goes into some predictive model that will tell you at some
     time in the future, some bad thing is going to happen.  Now, which one
     of those?
         MR. BRYAN:  Well, okay, we do -- the short answer is sort of
     both.  I mean, what we do is, when you get to the point that you decide
     that you have either lost or you're coming close to losing all three
     fission product barriers, you take an immediate protective action right
     then.
         DR. FONTANA:  Okay.
         MR. BRYAN:  Okay.  And then you take additional protective
     actions, preferably on actual readings of what is happening either out
     in the field or at the plant from a radiation standpoint.  You're
     reading what's being released or what you're measuring by your field
     team.
         DR. FONTANA:  Okay.  If you're doing that, then why do you
     care what the extent of core damage is, because you already have a
     measurement?
         MR. BRYAN:  We don't.  And in those cases, we don't at all
     in terms of deciding protective actions.  None at all.
         DR. FONTANA:  I see.
         MR. BRYAN:  Now, what we also do, though, is we do use this
     process to help feed a predictive thing.
         DR. FONTANA:  Okay.
         MR. BRYAN:  We sit there and say, well, gee, the emergency
     director might ask you, well, if I were to -- if I'm down on one train
     of RHR and my electric grid, you know, my buses right then seem real
     shaky, you may say, well, tell me what happens if I'm going to lose RHR
     in the next ten minutes.  And so you would make an assessment of, you
     know, when you think the core might overheat and then what a release
     would be, and he may make some -- he may make a recommendation to the
     state that says, gee, I think it would be a good idea to do this at this
     point.
         So you can use it for projections, and we do use it for
     projections.
         DR. FONTANA:  Okay.  Thanks.
         MR. BRYAN:  We feel like that our new methodology makes a
     fairly direct indication of the level of core damage in the sense that
     it's consistent with the same decisions that our operators are making
     and other people in the emergency planning group are making relative to
     the indications they use for making their actions.  It's done primarily
     on core exit thermocouples in combination with radiation levels.  But we
     have other instrumentation -- hydrogen, source monitors, water level --
     that can be used to help validate these things, and those are all built
     into the methodology.
         Once again, we think compared to what we have out there
     right now, that this is an improvement.  It is more reflective of the
     actual situation than what we currently have.
         DR. WALLIS:  Is it not possible to have core damage without
     radiation going into the containment?
         MR. BRYAN:  It may be.  It's --
         MR. BARTON:  It is if your RCS is --
         MR. BRYAN:  Is completely intact.
         DR. WALLIS:  That's right.  That's right.
         MR. BRYAN:  But --
         DR. WALLIS:  So you're using some very indirect measurement
     --
         MR. BRYAN:  But core exit thermocouple --
         DR. WALLIS:  Yes, that's more direct perhaps, but then
     you've got to have models to figure out what they mean.  Thermocouple
     doesn't tell you you've actually got damage.  You have to --
         MR. BRYAN:  That's true.  We infer levels of damage from the
     thermocouples.  That's --
         DR. WALLIS:  Really, you want to measure radiation in the
     RCS.
         MR. BRYAN:  That's a very difficult thing to do on line.
         MR. BARTON:  You'll see it in your containment area
     radiation monitor.
         DR. WALLIS:  If it gets out.
         MR. BARTON:  No, you'll see it if it's in the RCS.     MR.
     BRYAN:  I mean, that's --
         DR. POWERS:  Yes, you would.  You would.  You've got core
     damage, it's in the -- it's going to get in the RCS.  You're going to
     see it in the containment radiation monitor guaranteed.
         MR. BARTON:  Yes.  You definitely would.
         DR. POWERS:  It would be pretty low, but -- but the fact is
     the RCSes aren't tight, and the noble gases are going to get you no
     matter what you do.
         MR. BARTON:  So then you worry about potential containment
     failure, imminent containment failure, as part of your decisionmaking.
         DR. WALLIS:  So you're saying that because the RCS is never
     really tight, you're always going to get something out?
         MR. BARTON:  Well, you've got packing, you've got mechanical
     seals, you've got all that kind of stuff, and you're going to have some
     leakage, small as it may be, but you're still going to get --
         DR. WALLIS:  It may be minimal.
         MR. BARTON:  Yes, but you're still going to get fission
     product in containment.  You're going to get stuff in containment,
     guaranteed.
         DR. WALLIS:  Well, then you have to discuss sensitivity and
     so on, it's diluted in the containment.  I guess you're assuring me it's
     all right.  I'm just skeptical.
         DR. POWERS:  The other thing to recognize is that the -- at
     least the plants that I'm familiar with, is the radiation monitors are
     set to detect things that are pretty small, and then they -- when you
     get this amount in there, they go crazy.
         MR. BARTON:  You'll see it in the monitor.
         DR. POWERS:  I mean, there's no such thing as ten times
     crazy.  It's just --
         MR. BARTON:  That's right.
         MR. HARRISON:  I'm sorry.  I just wanted to also note that
     you will get --
         DR. POWERS:  Please identify yourself.
         MR. HARRISON:  I'm sorry.  I'm Wayne Harrison from South
     Texas Project and the Licensing Subcommittee chairman.
         I just wanted to comment, you would also get indications in
     your fuel monitor and in your chemical and volume control system.  So
     you would know if you had some sort of fuel failure during -- without
     escaping the containment.
         DR. POWERS:  I will hasten to also note that everything that
     was on the previous slide was also available at TMI, and not only at the
     time, but for months afterwards, they denied that there was fuel damage,
     okay?  But I think his last point --
         DR. WALLIS:  So you're assuming we know more now. You're
     telling us that won't happen again.
         DR. POWERS:  Yes.  That's the -- I mean, that's the
     assurance, is that we know more now.
         DR. MILLER:  They didn't understand what they were seeing.
         DR. POWERS:  No.  I mean, they had radiation monitors that
     pegged on them, they had core exit thermocouples that fried on them,
     they -- every single thing he mentioned up there -- hydrogen indications
     -- they were all available, and on top of that, we were getting, about
     every four hours, some samples coming out that were hotter than a
     pistol, and still people said there could not possibly be any fuel
     melting in the system.  And that persisted clear up to the time that
     they opened up the RCS.  But maybe we're smarter now.
         MR. BRYAN:  Maybe.  We hope.
         In conclusion, we believe that our proposal gives us more
     accurate and more timely information, and by more accurate, I mean it is
     more reflective of the condition that exists at the time we need the
     information than we get out of a sampling system.  We believe that this
     offers many advantages with respect to the availability of our
     personnel.  It reduces exposures that they have and frees them up to do
     what we believe are more critical activities relative to accident
     mitigation.
         MR. BRYAN:  and overall, since we are looking at it, we
     believe more realistically, than we do with the existing methodology,
     the effectiveness of our emergency planning is improved.  Also, having
     people available to do critical actions makes your emergency planning
     more effective.
     DR. APOSTOLAKIS:  I'm curious. How many people get involved in all this
     -- collecting information, transmitting information, making decisions? 
     Where are these people?
         MR. BRYAN:  Well, there are quite a few.  There's -- you
     have your technical support center that is located at the site, in close
     proximity to the control room, that has a specific staffing requirement
     for it.  I would guess that there are approximately 30 to 50 people in
     there for TBA.
     In addition, any time we get to the alert level, we staff our central
     office emergency center, which has another roughly 50 to 60 people in it
     --
     DR. APOSTOLAKIS:  And what is this?
         MR. BRYAN:  Well, for us, it's in Chattanooga.  It's a
     central site.  And it's activated -- if we get into an emergency
     exercise -- at any site.  Okay.  When we declare an emergency at any
     site, that center is also staffed.  And just like the TSC, it has
     procedures, it has a staffing hierarchy, and there's, there is a --
     people are basically on call all the time to staff that, 24 hours a day.
     DR. KRESS:  George, was your question aimed at how many people were
     involved in the sampling?
     DR. APOSTOLAKIS:  The overall process of collecting the information and
     making decisions regarding, you know, this is what's happening?
     DR. KRESS:  Okay, then --
     DR. APOSTOLAKIS:  Who are these people and where are they?  In other
     words --
     DR. KRESS:  But that won't change by this modification.  The only thing
     that'll change is the one involved in the paths.
     DR. APOSTOLAKIS:  Well -- say that again.
     DR. KRESS:  The only thing that will change with this modification is
     the ones that are involved in the sampling process.
     DR. APOSTOLAKIS:  I understand that, but I was -- yes, go ahead.
         MR. BRYAN:  Well, in terms of people, there are probably,
     roughly, about 10 to 20 that would be directly involved in using the
     information from the kinds of things that we're talking about, and
     feeding information directly to the site director.
     DR. APOSTOLAKIS:  Who is the ultimate decision-making, maker here?
         MR. BRYAN:  Well, I'm gonna give you two answers.  In terms
     of the plant, it's the site emergency director; he's the one that's in
     charge of it.  He can only make a recommendation, though.  The state is
     the one -- he makes decisions relative to protective action levels.  The
     state makes the ultimate decision in what action they're going to take
     relative to protecting the public.  We can make a recommendation to
     evacuate; the state has to actually issue the order and concur.
     DR. APOSTOLAKIS:  And with respect to core damage assessment, and all
     the other decisions that need to be made, somebody has done an analysis
     to understand what possible failures of communication there might be, or
     mis-coordination and all that?  In other words, are we focusing too much
     on the technical aspects here, and forgetting again the human?
         MR. BRYAN:  In this particular instance, we --
     DR. APOSTOLAKIS:  I know -- that's out of the scope.
     DR. KRESS:  Yes.
     DR. APOSTOLAKIS:  I mean, I'm just curious.  Have people done this?
     DR. KRESS:  Well, we have, yes.
         MR. BRYAN:  Yes, we have.
     DR. KRESS:  Yes, we spend a lot --
         MR. BRYAN:  Five times a year by most sites --
     DR. APOSTOLAKIS:  Have done what?
         MR. BRYAN:  Go through this whole scenario --
     DR. KRESS:  That's a lot of, that's a lot of
         MR. BRYAN:  They --
     DR. KRESS:  That's a lot of what the emergency drills --
         MR. BRYAN:  That's exactly what they are, and it exercises
     our interfaces with the state, our interfaces with the NRC.
     DR. APOSTOLAKIS:  That's not quite an analysis; it's a drill.  You see
     the difference.
         MR. BRYAN:  No, but inside those drills, the core damage
     assessment teams are exercised.  The those teams are exercised.
     DR. POWERS:  Explain to me, isn't it better to do a drill than an
     analysis?
     DR. APOSTOLAKIS:  Oh, yeah, but.
     DR. POWERS:  I'm confused.
     DR. APOSTOLAKIS:  Well, there may be some rare occurrence that you don't
     catch with a drill.
     DR. WALLIS:  Well, this is a different part of the whole picture.  I
     mean, you're proposing to give different signals then you did in the
     past, and it's important to know if you'll respond properly,.
         MR. BRYAN:  I don't think so.
     DR. WALLIS:  No?
         MR. BRYAN:  No.  You give the same signal.  Not to put this
     -- let's not get this out of perspective.  All I think we're hearing
     here is, instead of -- as soon as I get some symptoms that I've got
     something going wrong, I may have some fuel damage, or whatever, instead
     of running down to the PASS sample room and grabbing a sample and
     analyzing that and using that to make a decision, where I've seen enough
     stuff going on in the plant, I know I'm in a general emergency, now I've
     got 15 minutes, by the regulations, to make a recommendation to the
     state.  Meantime, there's some poor chemist trying to get a sample and
     analyze it.
     I can't use that data because it's not timely.  So, instead of relying
     on that, which -- the regulations now say you should get a PASS sample. 
     Instead of relying on it as part of the decision process, use the PASS
     information for stuff after the initial emergency, use it for recovery
     -- that's all that's being proposed here.
     DR. WALLIS:  You're being very helpful.  I mean, you're telling me what
     I've been asking all along.  What does the person who has to make the
     decision --
         MR. BRYAN:  No -- I've been that person.  I have never made
     a recommendation to the state on a PASS sample.
     DR. WALLIS:  I think that's the key thing, is whether this person is
     satisfied with this information.  That's the key thing.
     DR. POWERS:  John, let me ask you the ground rules.  There is no
     chemical analysis that I've seen mentioned that can't be done in an
     extremely fast manner, if you were to use what's available now in the
     market place.  And I presume that means that there is -- is there a
     ground rule that says, we can only use the technology that we have now
     available at the plants?
         MR. BRYAN:  No.  I guess we can spend more money and really
     put the latest technology in and all that stuff.  The question is, do
     you really need to do that to be able to make these decisions?  That's
     the real issue. Or, use the existing technology and take that
     information and use it where it best can be used in this overall process
     of assessing the damage and recovery -- they're not giving everything
     up.  they're still saying they would take certain samples within a
     certain amount of time, which is appropriate.  But, to take the sample
     and analyze all the things that was originally intended in the design of
     the PASS system and use that for decision making, I don't think is
     necessary, or is it timely.
     DR. KRESS:  Let me ask a little more about that, John.
     Suppose you decided you don't really need all that stuff, because
     apparently you don't.  It's in the original.  But it would be maybe very
     useful if you had a direct monitor that just give you the gamma for
     krypton and the gamma for cesium.  You could infer an awful lot from
     those two measurements alone, along with your total radiation.  That
     doesn't require you to take a sample and go analyze it by the chemical
     processes.
     That doesn't sound like too big a deal to me.  What would be wrong with
     something like that, as a replacement for a chemical analysis?
         MR. BRYAN:  It's another system; it's another modification;
     it's something else that I have to add to the plant.  And, do I really
     -- is it going to affect the decision that I make?
     I'm not so sure it will because I still have other indicators that are
     going to tell me what is the state of my core, and it's going to tell me
     what's the potential for losing other systems, what's the potential for
     losing containment, what kind of release do I have?  I don't think I
     need that information to do that.  It'd be nice to have, but it's not --
     DR. KRESS:  Well, it's information that --
         MR. BRYAN:  Pardon?
     DR. KRESS:  It's information that would allow you to not have to rely on
     these bounding calculations for aerosol deposition in the RCS and
     containment.  It would give you the information directly; you wouldn't
     have to rely on it.
         MR. BRYAN:  We did do a little looking into this to see what
     people had.  Very few plants have that.  There are a couple of plants
     that, that do have such monitors.  It turns out that they're not
     particularly simple.
     You have to dilute the samples considerably because the meters saturate,
     the detectors saturate.  So, you're into dilution.
     The other thing is, they're pretty exotic.  They require a liquid
     nitrogen cooling system on them.  So, in terms of something that you're
     going to put into a plant, they're a pretty complicated thing that would
     require a lot of maintenance and upkeep.
     DR. MILLER:  Just to see -- what'd you say?  Cesium --
     DR. KRESS:  Krypton.
         MR. BRYAN:  Cesium and krypton.
         DR. MILLER:  I think it would be pretty simple system.
         MR. BRYAN:  And a couple plants --
     DR. KRESS:  No, you don't have to have --
     DR. KRESS:  It's for cesium and krypton.
         DR. MILLER:  You don't need all that stuff.  Get a teleron
     detector and that's be it.
         MR. BRYAN:  Well, a couple of plants have had them and these
     are the systems that they have to do that, and they're --
         DR. MILLER:  That's because they're using uranium, and you
     don't need it for just seeing two isotopes.
     I had a question on -- you chose not to use your exit core nuclear
     instrumentation.
         MR. BRYAN:  It's used as a verification.  It's not -- it's
     not used as a part of the quantitative, to actually do quantification of
     where you are, but it is used to help you verify where you are.
         DR. MILLER:  It seems to me that it's used -- you said
     didn't use it, partly, because you had to go into the instrument panel
     to read it out.
         MR. BRYAN:  Some of them may, but it's a -- I know, at least
     at our plant, we do look at exit cores.
         DR. MILLER:  Because it would give you added information
     over and above the thermal core thermocouple.
         MR. BRYAN:  But it's not part of the formal methodology. 
     It's the verification of where you are, as opposed to one of the trees
     that we go through to say, this is the state you're at.
         DR. MILLER:  Is there a reason you've chosen not to use it
     as part of that, or you just didn't think you'd needed it?
         MR. BRYAN:  We felt like the others were easier to get and
     more direct.
     DR. POWERS:  It seems to me I've seen work in Germany, where they used
     that exit core instrumentation to get -- and they built a little box,
     and it really gave them some magic results on the state of the core as a
     function of time.
         DR. MILLER:  Yeah.  You had the same thing; you had a TMI,
     plus you have your wide ranges, wide range chambers.  You have some
     more.  I think with a little bit of innovation, you can get a lot of
     information.
     Plus, I would say I go along with Dr. Kress:  for an in-core monitor for
     something cesium, it would be a very simple detection system; not an
     exotic uranium system with liquid nitrogen.
     DR. BONACA:  For one, I don't believe that PASS was ever intended to
     perform emergency action level calls in the first half an hour of an
     accident, of course.  I think that what happened is that, when emergency
     action level or the emergency plan were modified after TMI, then I since
     PASS was available, it was incorporated as a means of getting
     information.
     So, the result of it was that it just never could perform the function. 
     I believe the driver of that was, if you remember, the debate on, you
     know, what was interactive vessel versus the sample TMI.  And the fact
     that one could not make any call regarding non-condensibles or anything
     of that kind.
     That, I think, was the requirement for the PASS system.  I'm only saying
     that, I don't think it ever should have been in the emergency action
     levels anyway, to start with.  And, I don't know what changes you can
     make to PASS system to do that.
         DR. MILLER:  Of course the only comment I have is, I'm
     surprised we're so late coming with this kind of proposal because we're
     not coming in with anything we didn't know two years after TMI, or less.
     You know, all the information -- as Dr. Powers pointed out -- was there,
     if you read the TMI instrumentation.  It's just that no one understood
     what they were looking at.  And very quickly, we understood what we were
     looking at.
         I am surprised here it is 1999, it is 20 years later.
         DR. BONACA:  This MAAP and MELCOR, whatever was unavailable
     then to make his proposal, that was to make those kind of correlations.
         DR. MILLER:  That's true, but what they are doing is fairly
     -- as he points out, you don't need much sensitivity.  You don't need
     MAAP to tell you what is going on from your core exit thermocouples, it
     is all there.  Except you have wider range thermocouples today than you
     had in TMI.  That was part of Reg. Guide 1.97.
         DR. KRESS:  I think we had better move on.  We have
     additional presentations.  The staff is supposed to make a presentation,
     too.
         MR. BRYAN:  At this point, if there are no further
     questions, I would like to turn it over to Wayne Harrison to talk a
     little bit about PASS.
         MR. HARRISON:  I appreciate the intro, Bob.
         Good afternoon, my name is Wayne Harrison.  I am the
     Chairman of the Licensing Subcommittee of the Westinghouse Owners Group. 
     And I think this last discussion is a good lead-in to a discussion on
     the post-accident sampling system.
         [Pause.]
         MR. HARRISON:  Bear with a moment.
         [Pause.]
         MR. HARRISON:  He didn't stack them the way I stack them.
         [Laughter.]
         MR. HARRISON:  There is a difference between Tennessee and
     Texas.  I want to go quickly to summary of the regulatory basis for the
     Westinghouse Owners Group post-accident sampling.  I think we talked a
     little bit earlier in the presentation that we think this is properly
     focused on the public health and safety and what is really required for
     accident management needs.
         The proposed PASS changes are in compliance with the
     regulations.  We are really not looking to require any exemptions per
     50.12 to the regulations.  What we are looking for, actually, is to
     revise compliance with NUREG-0737 commitments, and I really should have
     put up there Reg. Guide 1.97 as well, that is another set of commitments
     that the changes would affect.
         As we have been discussing, the current accident management
     activities -- well, the current accident management activities have been
     reviewed and approved by the Nuclear Regulatory Commission.  I think we
     talked a little bit about how we do severe accident management or how we
     identify emergency action levels and so forth, which has typically been
     reviewed and approved as far as the emergency planning at nuclear power
     plants.
         And as we have talked earlier, the current accident
     management activities have no reliance on the post-accident sampling
     system for short-term activities such as emergency operating procedures,
     identifying emergency action levels or severe accident management
     guidance.  And the accident management activities have only a minimal
     reliance on the PASS for medium and long-term activities, and I will
     talk a little bit more about that as I go through.
         You probably recognize that the post-accident sampling
     system typically takes samples from three areas in the reactor
     containment.  Number one is from the reactor coolant system.  At South
     Texas, the post-accident sampling system takes samples from the reactor
     coolant system hotlegs and the residual heat removal system.  I think
     the part about taking samples off the reactor coolant system hotlegs is
     typical of the residual heat removal system may be unique to South Texas
     projects since all of our RHR is inside the containment.
         The other sample point for the reactor containment
     atmosphere, it is typically taken at a number of places within the
     reactor containment.  South Texas takes it at the top of the dome, above
     the steam generator cubicle, inside the steam generator cubicle and
     inside the bioshield wall.  And that is probably kind of representative
     of where most plants take it, and there may be some variation from plant
     to plant, and with --
         DR. WALLIS:  Excuse me.  How does it take a sample?  Is
     there a hole and something is --
         MR. HARRISON:  We have some -- I can't give you a very good
     description of the system.  I'm sorry.  But, basically, we have some
     tubing and sampling where we can open some valves and draw samples into
     our post-accident sampling panel.
         DR. WALLIS:  But that could be presumably be automated.  You
     don't have to have someone go and do it, the way it has been presented
     before.
         MR. HARRISON:  What we do is, if it turns out we need to go
     take a sample, the post-accident sampling system panel has a number of
     automated functions associated with it.  But if you have an event inside
     the containment, it will isolate -- the containment will normally
     automatically isolate.
         If you had a significant event, you are going to have
     operators going through a number of activities in their emergency
     operating procedures as their first and number one priority.  To get a
     sample from the post-accident sampling system, operations would have to
     go un-isolate the system such that the chemical and radiation protection
     people can take their required sample.
         DR. WALLIS:  This surprises me because it seems to me that
     you would -- on some signal, such as high exit temperature, thermocouple
     measurements, you could automatically open some valve, let some fluid
     out and so some certainly radiation measurements immediately.  You don't
     have to have anybody go do anything.  Why is there this sort of delay,
     the operators have to do something?  I don't see why.
         MR. HARRISON:  Well, that is because we have really -- we
     don't depend on the post-accident sampling system to drive any emergency
     operating procedures.
         DR. WALLIS:  It seems you are sort of deliberately making it
     awkward to use so that you can say you don't want to use it.
         MR. HARRISON:  Well, hardly.  I think the first focus of the
     operations -- of the operators in the emergency operation facility, or
     emergency operations procedures is to mitigate the event.
         DR. WALLIS:  No, I am saying they shouldn't have to do
     anything with PASS, it should just happen.  It should be a passive PASS.
         MR. HARRISON:  And at the time the requirements are that you
     need to be able to take a sample within three hours, and those were our
     regulatory requirements.  So the system is designed to comply with that
     and to enable to take the sample within the required time, which
     supports what we need for accident management, if we were -- or what was
     perceived to be needed at the time for accident management.
         But, again, as far as characterization of the event,
     determination of what the emergency action levels are, and, ultimately,
     the protective action recommendations, is really seen on the picture
     that we showed where it depended upon implant instrumentation to get the
     most responsive action on the part of the emergency team.
         I am going to briefly go through, as I mentioned, where the
     samples were taken.  I want to just briefly just go -- have some tables
     that show the reactor coolant system, the reactor containment atmosphere
     and the reactor containment sump.
         This is the changes that are proposed in the Westinghouse
     Owners Group for what we do in the reactor coolant system.  The primary
     change, the most -- that we are going on -- excuse me.  Where we would
     retain the post-accident sampling is on reactor coolant system boron. 
     We would propose to relax the requirement for time from three hours to
     eight hours and the accuracy from 5 percent to 10 percent, which is more
     reflective of the current instrumentation capability.
         The remainder of the Reg. Guide 1.97 and NUREG-0737
     requirements with regard to timing and accuracy, we are proposing to
     have no requirement on time and the accuracy would be as defined by the
     procedure.  Now, the subcommittee asked, when we gave this first
     presentation, we originally said there would be no requirement on
     accuracy, and that is really not true.  The accuracy will be defined by
     the procedure, it will be defined by the type of equipment that you
     would use for taking that sample, and the methodology employed at your
     facility.  So that is what I mean by plant application specific on
     procedure, and you will see that note on all of the slides.
         It also may be dependent upon, what does the accident -- or
     the Technical Support Center or the Emergency Operations Facility need
     if you were going to take that sample?
         With regard to these particular items, none of these are
     required by emergency operating procedures, severe accident management
     guidelines.  For any response, we may use such -- this information for
     long-term accident management, so we would propose to be able to
     continue to take a sample, but we don't feel like that -- we feel like
     that should be controlled within our own licensee guidance.
         DR. KRESS:  The time you have up there, eight hours.
         MR. HARRISON:  Yes.
         DR. KRESS:  That is eight hours from when?
         MR. HARRISON:  That is eight hours from attaining a stable
     plant condition.  One thing that I would like to point out, and in
     talking to the South Texas project chemistry people, is that the
     post-accident sampling system really needs a stable plant condition
     before it is effective.  If your plant is rapidly changing, or the
     conditions are rapidly changing, number one, you won't get useful
     results because it will only tell you what happened, and what is water
     the bridge, essentially.
         And, second, the post-accident sampling itself doesn't work
     as well under conditions where you have rapidly changing plant
     conditions.
         So we feel like for when you would really need this reactor
     coolant system boron, eight hours is appropriate.  And the other factor
     on reactor coolant system boron, what we are really looking for is to
     make sure we have shutdown margin and the emergency operating procedure
     that calls for that is the one for natural circulation cooldown, so we
     are really looking a little ways down the road, and that was the
     justification for the eight hours.
         DR. WALLIS:  It seems to me that quite apart from
     regulations, you might have requirements to know some things about how
     accidents develop.  If you did, very unfortunately, have an accident
     like this, then down the road you might have to justify, to someone like
     you, your actions.  You might have legal suits, all kinds of liability
     problems.  And the more information you can draw on to show that things
     were done properly, the better.
         MR. HARRISON:  And I think if you at the way we would
     propose to implement the post-accident sampling system, we would
     probably still have access to that kind of information.  If we were to
     look at it from the purposes of doing accident management strategy, if
     we took the samples, we would have the data available to us for
     comparison to the decision making.
         DR. WALLIS:  I was wondering why -- I would think you might
     be more nervous about those issues than just meeting some regulatory
     requirements, if you actually thought through the worst case scenarios.
         MR. HARRISON:  We didn't really build this looking
     specifically at the liability issues, but it would -- I think it would
     give us some information.
         DR. WALLIS:  What would happen if somebody misunderstood
     this and so on?  Look at the worst case and how you might save yourself
     from that.
         MR. HARRISON:  Yes, sir.
         DR. POWERS:  Now, on this slide, you indicate that you are
     going to still measure boron, you are not going to try to get it --
     derive it from just a mass balance?
         MR. HARRISON:  That's correct.
     With regard to the reactor containment atmosphere samples, the main
     quantity or quantification we need from the reactor containment
     atmosphere is for hydrogen.  There was a requirement or there is a
     requirement to be able to get that from the postaccident sampling
     system, and in discussions with the staff and in looking at what we
     really have in the plant, the right way to do that and the most
     effective way to do that is actually with the containment hydrogen
     online monitor.
         It's a safety-grade redundant system in the containment, and
     it's better for determining hydrogen concentrations than is the
     postaccident sampling system, so we're simply proposing that we're going
     to eliminate from the postaccident sampling system that particular
     function.
         DR. POWERS:  Is your online monitor environmentally
     qualified --
         MR. HARRISON:  Yes.
         DR. POWERS:  For severe accident conditions.
         MR. HARRISON:  Yes.
         Which by the way makes it a better monitor than most
     postaccident sampling systems, because if you are aware, the PASS itself
     is not required to be a safety-related system.
         With regard to the other containment sampling requirements,
     they're again not required by the emergency operating procedures or
     other guidance documents or diagnostic documents, and there is also
     concern as we mentioned earlier on the timeliness and the accuracy of
     the postaccident sampling system to really support what our needs are
     for that type of information.
         And the third and last area that was subject to sampling is
     the containment sump.  The Westinghouse Owners' Group proposes to retain
     a requirement for containment sump samples for plants that meet all
     three of these conditions:  that the plant has brackish water cooling,
     with a single barrier between that brackish water system and the
     containment, and has no passive pH control for the sump.
         With regard to the remainder of the Reg Guide 197, I think
     these are pretty much governed by Reg Guide 197 instead of the NUREG,
     but with regard to the remainder of the other sump sampling again
     they're not required by the EOPs or the SAMGs or needed for the short or
     long-term response.
         Again, to go back to questions that we had, it may be useful
     on a plant-specific basis to have a capability to sample what's in the
     sump for long-term accident recovery planning.  That might be very
     useful information to us.
         DR. POWERS:  Maybe I don't understand.  If I don't have
     brackish water, then I come down to sump pH all others?  Or do I have to
     not have brackish water and have passive pH control, whatever that is.
         MR. HARRISON:  You would need to have sump pH or, excuse me,
     sump sampling capability.  If you have a brackish water cooling system,
     and if that brackish water cooling system has only a single barrier
     between itself and the containment, and that's -- primarily the concern
     there is chlorides and having a potentially infinite source of water
     into the containment, or high-chloride water to the containment.
         DR. KRESS:  And if it's not pH controlled.  Three areas.
         MR. HARRISON:  Three areas.  Each one -- all three have --
     criteria have to be met.  You have to have --
         DR. POWERS:  Oh, okay.
         MR. HARRISON:  It has to have no passive pH, a single
     barrier, and be a brackish-water plant.  All three.
         DR. UHRIG:  Otherwise it's not required.
         MR. HARRISON:  Otherwise it's not required.  That's right.
         DR. POWERS:  So I'm not at all interested in sump pH if I
     have a double barrier.
         MR. HARRISON:  Right.
         DR. POWERS:  I mean, I can't imagine why I'm not interested
     in pH just because I have a double barrier, but that's the requirement.
         MR. HARRISON:  For instance, I'd use South Texas as an
     example, South Texas has a double-barrier system.  We use containment --
     component cooling water.  We know what the pH of the component cooling
     water is.  It's a chemically controlled system.  And if we were somehow
     have a leakage from the component cooling water system to the
     containment, we would be able to quantify that and have an idea of
     what's in there.
         DR. POWERS:  Yes, but I'm worried about what's the pH in the
     sump water.  Why don't I care just because I have a double barrier?
         MR. HARRISON:  Well, you care what the pH of the sump water
     is, but the way we look at this is that you will know based on the fact
     that you have a passive pH, for instance, trisodium phosphate baskets in
     the containment or in the case of an ice condenser the chemical contents
     of the ice, so you'll know the quantity of that component, you'll know
     what you put in from the refueling water storage tank, you'll know what
     you already have from the reactor coolant system, and if you introduce
     water from some other source, you would be able to quantify that water
     that you had introduced from the other source.  So we think we have a
     way to get a very good idea on what the pH is, and the passive pH is --
         DR. KRESS:  I think he's interested in cases where there's
     no passive pH.
         DR. POWERS:  Well, let's go ahead and let him have passive
     pH.
         Let me ask that question.  I'm in the middle of a severe
     accident.  I'm dumping junk into this water, serious first-order junk. 
     A lot of these junks are metals, metal ions.  And they look at this
     trisodium phosphate and they ignore it.  They sit there and say gee,
     there's this nice lovely anion that I just love to complex with and form
     a precipitate out of, but because this is a severe accident, I'm going
     to ignore this, and because these guys need it for sump pH.
         MR. HARRISON:  I think you need to look and see why am I
     putting that water in the sump in the first place.  If I'm in a severe
     accident, it means I've lost -- I've used up all my refueling water
     storage tank or for some reason I don't have it available, and I'm
     really in a bind trying to find another source of water for keeping my
     core cool or providing cooling.
         My first priority is going to be to get that water in there. 
     The next thing I'm going to have to look at is well, okay, long term
     what's that going to mean to me.  And then I can get an idea of what --
     I can calculate my pH or determine what my pH is.  But again it comes
     back to being for --
         DR. POWERS:  Let me come back to this.  You can calculate
     your pH.  Okay.  You've got so much water with so much trisodium
     phosphate in it, and x kilomols of an unspecified cation.  Now,
     calculate the pH.
         I do this for a living.  I can't do it with that problem.
         My point is that you're putting stuff into this water that
     has an affinity for your buffering material.  It chemically interacts
     with it.  It removes it from the buffering equation.  But a priori you
     don't know how much you put in there.  A priori you don't know how much
     of -- how far the equilibria go.  So it makes it extremely difficult to
     calculate what the pH is.
         MR. HARRISON:  Well, I think you do know how much you put in
     there.
         DR. POWERS:  How much of the reactor fuel's in there?  How
     much of the metal ions have vaporized out of the core and come there? 
     How much of the concrete has leached into the sump?
         MR. HARRISON:  Well, that's -- you're right.  Obviously you
     don't -- when you asked how much you put in, I was thinking in terms of
     the quantity of water in the various sources.
         DR. POWERS:  You know how much that is, but you don't know
     all this other stuff that's coming in there.  Which is why I would think
     that you would want a measurement to say what is my pH and what is my
     buffering capacity.
         MR. HARRISON:  Right.  And I think that would go back to the
     design basis on the pH.
         Do you have anything you can offer on that, Bob?
         MR. LUTZ:  Bob Lutz from Westinghouse.
         The only thing that I'd like to add is that we're not doing
     away with capability to measure pH of the sump water.  For all of these
     things that we're talking about removing regulatory requirements, and I
     use that in quotes, the capability to obtain a sample from the sump and
     to do whatever chemical analysis the TSC deems would be desirable is
     maintained.  What we're saying is that it's not required for the
     short-term response to regain control of the plant, it's more a recovery
     function than it is a mitigative function.
         MR. HARRISON:  Right.  Thank you, Bob.
         DR. POWERS:  Well, I think in mapping this thing out that
     you have neglected a major area.  Now whether it dilutes your point,
     your essential point, which is in the short time I don't need this
     information, I only need it in the longer term, I think you're probably
     right there.
         But in the longer term, when you've thought about things, I
     think you've left out major considerations.  And those major
     considerations are that under accident conditions you're going to dump a
     bunch of junk into this water that interacts with it chemically, and it
     interacts with it in ways we probably have a hard time predicting,
     because we don't know how much comes in, we don't know how much leaching
     there is, and things like that.  And it's going to change things.
         And the only way you're going to be able to have confidence
     in where you think you are is not on a mass balance calculation, how
     much I put in, but rather on getting a sample out and saying what is the
     pH and what is the buffer capacity, and how many hours do I have before
     I have some serious iodine partitioning coming out here.
         MR. HARRISON:  And I think as far as if you have iodines
     coming out of solution, I think we may have some additional indication
     of that from radiation levels.
         DR. POWERS:  I kind of doubt it.  I think your radiation
     monitors are going to be pinned and tinned.
         DR. KRESS:  Well, they'd never pick up iodine anyway.  They
     don't have a good gamma.
         DR. POWERS:  Iodine doesn't have a good enough gamma to
     hit --
         DR. KRESS:  You won't see the iodine.
         MR. HARRISON:  Any other questions on the tables?
         A summary of the basis is just a rehash of what I just went
     through in tabular form.  We don't need the post-accident sampling
     system for an immediate response.  Where there was sort of an immediate
     response was with regard to containment hydrogen, but the containment
     hydrogen is really more appropriately measured or handled by the
     containment online hydrogen monitor.
         We do use the PASS potentially for assurance of a long-term
     stable state.  We talked about having boron for shutdown margin within
     eight hours of the stable state, and we just had the discussion of sump
     pH for brackish water plants.
         You obviously can use the post-accident sampling system for
     planning recovery.  We don't think there is a record response required. 
         
         One of the important things we wanted to point out is that
     the technical support center engineers, the emergency operations
     facility engineering staff will identify roles for post-accident
     sampling system based on the individual accident scenario.  It's going
     to be plant-specific and it won't be something that we can necessarily
     predetermine in a set of requirements.
         Knowing that they still have this capability, this is where
     that expertise and where we would rely on determining what we would need
     for the long-term sampling requirements.
         Basically, just looking overall, we don't believe that the
     post-accident sampling system is critical to the public health and
     safety based primarily on the long-term aspects of the system.
         Our conclusions -- we believe the revised post-accident
     sampling system that the Westinghouse Owners Group has proposed is
     technically sound, that it meets the regulatory requirements for
     sampling, and that the proposed changes will improve the effectiveness
     of our emergency planning and that it will support the ability to
     maintain the safe, stable plant following an accident.
         DR. KRESS:  Thank you.  Dana, we are pretty far behind, but
     we still have to hear Staff's side of the story.
         DR. POWERS:  My schedule is such a disaster this meeting
     that one more delay or what-not will have a minimal impact on it.
         DR. KRESS:  I would ask the Staff to try to be brief, if we
     allow them to.
         DR. POWERS:  Brief but thorough.
         We have one of the outstanding speakers from the Staff here
     with us anyway.
         DR. KRESS:  Yes, that's right.
         DR. POWERS:  Not known to be brief sometimes.
         MR. HARRISON:  Oh -- I'd hate to have you guys hear me snore
     over here.
         DR. POWERS:  No, we were waiting for the comments out in the
     hall.
         [Laughter.]
         MR. HARRISON:  Now that you mention it, I was thinking of
     one of the "Airport" movies but I won't go into that one.
         [Laughter.]
         DR. POWERS:  What you need is to persuade us of your point
     of view.
         DR. KRESS:  This is important so we don't want to
     short-change it.
         DR. POWERS:  We are fixin' to write so you want us to write
     things that are correct.
         MR. PALLA:  My name is Bob Palla.  I am with the
     Probabilistic Safety Assessment Branch, NRR, the lead reviewer on the
     core damage assessment methodology, which is one of two topicals.
         I want to just show the graphic here that we prepared.  It
     was prepared with an attempt to clarify and I hope it doesn't have the
     reverse effect.
         I wanted to point out that the post-accident sampling is
     basically from the sump, from the RCS, from the containment atmosphere. 
     We are looking at dissolved gases, hydrogen, oxygen, conductivity, pH,
     chlorides, boron.  We are looking for radionuclide from the sump, from
     the containment atmosphere.
         The scope of these samples is really the issue of WCAP
     14-986.  What I want to talk about here is basically how the
     radionuclides are used.  You can have two uses for the information, the
     radionuclide information from PASS.  It could be for core damage
     assessment, in which case you would derive estimates of core damage from
     that information, or you can use it for source term assessment where you
     would use that information as assumptions to dose assessment
     calculations and from that you could go to protective action
     recommendations and let me say in the longer term because it is really a
     question of when is the information available, and we have got the three
     hour time delay that is a factor there.
         Now this is pretty much the situation today, that the core
     damage assessment methodology that is in place now relies on PASS.  We
     don't get the sample upfront, and as a result we don't have a core
     damage estimate upfront, early, so therefore we don't feed that kind of
     information into the decision-making process.  I have kind of shown it
     separate there, but if one could make this information more timely, it
     would be an additional piece of information that could enter into the
     decision-making process potentially for the EALs and for protective
     action recommendations.
         What I am going to focus on here is just the WCAP 14-6-96
     scope, which is essentially how do you come up with a core damage
     estimate from in this case without the use of PASS, so we are currently
     driving it with PASS.  This proposed methodology eliminates that
     reliance.
         Now looking back at the regulatory basis for the core damage
     assessment methodology, interestingly enough there isn't really a clear
     statement about the need for a procedure or a method to translate
     radionuclide information into core damage assessment.  If one goes back,
     looks at the record, this is really all that you'll find -- TMI, 0737,
     item 2.B.3, Criterion 2.  The licensee is essentially required to
     provide the PASS system.
         Now the way that the Staff has interpreted it and really the
     only source of any guidance on core damage assessment methodology is
     provided in what was called the Post-Accident Sampling Guide for
     preparation of a procedure to estimate core damage.  This document was
     prepared in 1982.  It was disseminated to utilities as part of the
     Staff's review of the PASS systems.
         Now this document, if you look at it, lays out some
     expectations on the part of the Staff as to what this procedure should
     do, and it was referred to as a procedure at that time.
         Basically it says the primary purpose of this procedure is
     to provide a realistic estimate of core damage and the primary interest
     is to be able to differentiate between four categories of core damage,
     namely no core damage, cladding damage, some fuel overheating, and core
     melt.  Now they called out those four categories.
         They went further and they tried to define degrees of damage
     within each of those categories.  The result was they have like ten, the
     expectation being that you would be really finely dividing the state of
     the core into 10 different categories.
         Now what they did not do is talk about and state in any way
     how this information from the procedure would be used, so I think what
     has happened, and maybe this is part of the problem, is we basically set
     out a requirement for a system as part of our licensing reviews.  We
     required licensees to provide a procedure, and I don't think we gave
     serious consideration to how the results of that procedure actually
     entered into emergency response, so I think there's been a decoupling
     there.
         The procedure exists.  It is used.  It is tested in drills. 
     But it doesn't have a clear tie to decision-makings.
         DR. WALLIS:  Can you clarify something?  I thought Mr. Bryan
     told us that there was no need to change requirements by what they were
     proposing and it looks as if you would have to change this requirement,
     but it does call for a -- well, it says regulatory requirement.
         MR. PALLA:  I put it in quotes.  It is a TMI requirement.  I
     don't know --
         DR. WALLIS:  I am not quite clear what is requirement, what
     is not a requirement.
         MR. PALLA:  It's not a regulation.
         DR. KRESS:  It's not a reg.
         MR. PALLA:  I think he was saying there is no regulation.
         DR. POWERS:  What has happened is that licensees have made
     commitments to follow this document and to them that looks as much like
     a requirement -- in fact, you can't even cite against it, can you?
         MR. BRYAN:  This is Bob Bryan.  That is exactly correct. 
     What I was speaking to is what we would call a regulatory requirement is
     something that is a piece of the law, whereas a NUREG and a Reg Guide
     represents a guidance document where we may have to make a licensing
     submittal to but we would not have to request an exemption to the law or
     make a change to the law.
         MR. PALLA:  I will proceed here.  The way that the, quote,
     "regulation" -- the requirement for procedure, the core damage
     assessment procedure was met was in the case of the Westinghouse plants,
     the Westinghouse Owners Group prepared at generic document.  It was
     called the post-accident core damage assessment methodology that was
     subsequently used by individual licensees as the basis for meeting the
     TMI requirement.
         This was approved in 1984 on the basis that it met -- there
     wasn't any thorough review of this process.  It was basically reviewed
     and the bottom line assumption is that it met the requirement even
     though the requirement is not really explicitly there, so that is easy
     to meet.
         [Laughter.]
         DR. POWERS:  Or impossible to meet -- one or the other.
         MR. PALLA:  The methodology essentially, and I don't need to
     dwell on this very much, but its primary thrust was looking at the PASS
     results, radionuclide results, but there was some indication in the
     secondary sense to look at things like core exit thermocouples, hydrogen
     concentration, reactor vessel level instrumentation, as a means of
     confirming this, but the result of having primary reliance on
     post-accident sample meant that you really didn't end up with an
     estimate coming out of this until the three-hour criteria sampled and
     analyzed it.
         DR. WALLIS:  Many industries faced with this question of
     having a delay would say okay, it's a technical problem.  If there's too
     much delay we'll fix it.
         It is interesting that in this industry the approach is not
     to fix it technically but to go and try to change the requirement.
         MR. PALLA:  Okay.  I think you have heard from a couple
     speakers already that the delays in this information has led to a lack
     of use --
         DR. WALLIS:  Well, delays are inherent.  It is just that no
     one has tried to shorten them, as far as I can see.
         DR. POWERS:  On the other hand, the other way to look at it,
     in fairness, is if we are perfectly capable of making these decisions
     without getting this information, why get it?
         MR. BARTON:  You don't need to make the decision.
         DR. WALLIS:  I understand that too.  It's just the attitude. 
     Many people would say here is a chance to do something technically.  We
     will fix it and it will go away.  We don't need to involve the NRC and
     ACRS at all.
         MR. PALLA:  And I think that the methodology that you have
     in front of your is really an alternative to do it but do it by
     different and less direct means than samples.
         Just a quick statement about how did we review this.  Since
     there wasn't very much guidance on what this entity should be, we
     basically looked initially at what is the rationale for the WOG
     proposing to change this in the first place and obviously it is a
     twofold thing.
         There is an interest in elimination of the post-accident
     sample system, and there is also a recognition that the current process
     is not timely and could stand some improvement.
         MR. PALLA:  So we looked at the rationale for why is this
     thing being proposed, and is it okay to eliminate the reliance on Pass.
         We looked at the scope of the indications that were -- that
     are being relied on in the revised guideline, and it's called a core
     damage assessment guideline.  Let me just clarify this.  There's a
     topical report that discusses core damage assessment methodology or
     guidance.  Within that document, in the back is the actual guideline,
     and then as attachments to that are appendices that discuss how an
     individual utility would establish setpoint values for their plant.  So
     what I'm talking about here is really the guideline itself and the
     supporting appendices.
         We looked at, you know, basically what's the scope of the
     information that's being looked at, how is the information -- the
     readings themselves translated into core damage estimates and how are
     those estimates reconciled with each other, and then in the more
     specific sense, did the setpoint values that are either inherent in the
     methodology or determined by the utilities based on recommendations
     given in the appendices, do those appear to be reasonable.  I think that
     you all realize that it's a -- generally, it's a simplified approach. 
     As previous speakers have indicated, it's an order of magnitude kind of
     an answer, and as our initial regulatory guidance indicated, the
     post-accident sampling guidance document, you're trying to categorize
     things into four broad categories of damage fundamentally.
         DR. POWERS:  And I guess I'm sitting here thinking a little
     bit about what's the regulatory interest here?  It seems to me the
     regulatory interest is that you want to have a sound basis for making
     these emergency action decisions.
         MR. PALLA:  Yes.
         DR. POWERS:  And that beyond that, you really don't care.
         DR. KRESS:  Well, I think there may be some public health
     and safety and worker protection issues associated with recovery
     actions.
         DR. POWERS:  Well, --
         MR. BARTON:  But that's down the road, Tom.
         DR. KRESS:  I understand.
         DR. POWERS:  I was putting that -- I agree with you --
         MR. BARTON:  I agree with you, too.
         DR. POWERS:  -- that recovery is an important thing, but I
     put it, rather than on a second line, I would put it after the PR box on
     the first speaker's presentation, and you want a sound basis for making
     each one of the decisions in those blocks, and you really don't care
     what that basis is as long as it's sound.
         MR. PALLA:  Yes, I think what we --
         DR. POWERS:  I mean, am I characterizing --
         MR. PALLA:  I think what we see is that there are problems
     let existing situation, okay?  There's problems with how representative
     is the sample that we draw today.  If you haven't factored in --
         DR. POWERS:  Are there problems with the existing situation?
         MR. PALLA:  There's confusion as to how -- if you drew a
     sample and you tried it analyze it using the current methodology, it
     does not account for the fact that you could have retained a significant
     amount of fission products in the vessel itself and you might have hold
     up just because the RCS is at high pressure.  So you're going to pull a
     sample and try to -- and actually, you've got problems with the
     deposition in the sample line itself.  The sample that you obtain may
     not be representative, and that's where --
         DR. POWERS:  But I'm still able to make decisions despite
     that.  What I've got is --
         MR. PALLA:  Absolutely.
         DR. POWERS:  -- I've got an extra --
         MR. PALLA:  The top line of the first speaker's slide --
     you've already got fixed instrumentation, it's currently being used to
     drive EALs and to make, you know, PAR decisions.  So that process is
     already in place.
         MR. BARTON:  It's another data point that doesn't really
     help make a decision but it could confuse the decisionmaking process. 
     That's the way I look at it.
         DR. POWERS:  On the other hand, I think you're saying -- you
     know, there's one thing that I know about people in the middle of
     accidents, is that they do a really bad job of estimating how bad the
     accident is.  I'm reminded of the Chernobyl incident there, you know,
     they kind of blew up the reactor and they called up Moscow to say, well,
     we've blown up the reactor, except they didn't say that, they said we
     have an incident.  The guys in Moscow said, well, how bad is it?  He
     says, it doesn't look too bad, we should be on line in the morning, you
     know?
         [Laughter.]
         DR. POWERS:  Well, they missed that estimate just a tad.
         MR. PALLA:  He was talking about the other unit.
         [Laughter.]
         DR. POWERS:  He must have been, because he certainly wasn't
     talking -- but I think you can go through and find anybody in the middle
     of an accident -- they do a really bad job of estimating.
         MR. PALLA:  I think that's a good argument for trying to
     keep things simple, and we have learned more.  And what this methodology
     does, it is pretty straightforward, it's got built into it these
     assumptions about fission product retention.  As the one speaker has
     indicated, there's assumptions if you're at high pressure, a certain
     amount of hold up; if you're at low pressure, a different amount of hold
     up.  That's built in.  And what a utility would do when they implement
     this is develop plant-specific curves that have that assumption implicit
     in them, so they'll be expecting, you know, some -- only a residual
     amount of the fission products to actually get out, and if they saw two
     percent out there in a high pressure sequence, they might think they've
     got a full-blow core melt.
         Now, in the current way of thinking, if you saw that, you
     would say, no, I don't have any damage -- not too much.  This didn't
     account for the fact that a lot of the fission product is left behind in
     the RSCS.
         So from what we see, the changes to the methodology are
     warranted.  There's good cases made with regard to timing and the
     availability of the information.  It could probably improve the
     accuracy.  I'm not going to make any claims that this is a highly
     accurate measurement, though.  But what they do in this -- I've got
     another slide, but there is a cross comparison of various indicators to
     come up with an estimate.  So there's some degree of robustness to it.
         DR. POWERS:  How would you as an intellectual exercise gone
     through the methodology and said, you know, if I'm sitting at TMI, would
     I have drawn different conclusions than were drawn for the next three
     years after TMI?
         MR. PALLA:  You're asking me if we used this methodology --
         DR. POWERS:  Yes, if you did that exercise.
         MR. PALLA:  I would think that if the information we're
     dealing with truly was available, then, if you had this method, it would
     be telling you you have a full-blown release of the fission products.  I
     think it would be pretty clear from the method that that --
         DR. POWERS:  We had all of that information that they're
     getting now.
         MR. PALLA:  We didn't have the procedure for using it.
         DR. POWERS:  Yes, we didn't have -- and so it's really the
     procedure that's --
         DR. MILLER:  And we didn't understand what -- the people
     there didn't understand what it meant.
         MR. PALLA:  This is a number of things you're trying to --
     from each piece of information, rad monitors, core exit temperatures,
     hydrogen concentration -- you individual look at those, you individual
     try to come up with an estimate percent.  The speaker said we didn't
     quantify.  Actually, the methodology does quantify these things and then
     cross-compare them and expect not a high degree of agreement, but some
     degree of agreement between them, and you're kind of pulling this
     information together.  So there's some structure here in some, you know,
     systematic use of the information that you had at TMI, but maybe 2 and 2
     didn't equal 4 back then.
         DR. SEALE:  The problem with TMI was not a shortage of
     wiggly needles.
         DR. FONTANA:  That's right.  Maybe a couple of them that
     were bouncing off the paper.
         DR. SEALE:  That's right, but it wasn't the shortage of
     wiggly needles that was the problem.
         DR. POWERS:  Denial.
         DR. FONTANA:  People refused or didn't understand or denial,
     exactly.  As soon as I heard about --
         DR. SEALE:  Same thing at Chernobyl.
         MR. PALLA:  This will give you another piece of data to
     deny, then.
         DR. WALLIS:  When there's another accident and it turns out
     that they misdiagnosed it, which would allow them not to do something
     with the power system, there's going to be a lot of questions about why
     did the NRC allow them not to use -- to disregard these past
     requirements?
         MR. PALLA:  Well --
         DR. WALLIS:  Didn't this cause them to do what they did and
     so on and so forth?  That's the worst scenario.  MR. PALLA:  What
     we're trying to do here is fulfill the basic needs for response but not
     give away the ability to sample, and in fact, Jim O'Brien will speak
     about this as soon as I finish here.  One of the things that we're
     looking at and wrestling with the best way to do it is to assure that
     the capability to do a sample is still retained.  So we're relaxing the
     time requirement but not eliminating the need for the system.
         DR. WALLIS:  So who takes the risk?  If the NRC relaxes this
     pass requirement and, in retrospect, after an accident, this turns out
     to play a role in the severity of the accident, do the NRC people get
     fined or go to jail or punished in some way?
         MR. BARTON:  The licensee goes to jail for making the wrong
     recommendation.
         DR. WALLIS:  That's the way it is.
         MR. PALLA:  I would say this would improve the risk
     situation because you will now have -- you'll have two things.  Early on
     in the event, when we all could probably agree that pass wouldn't even
     be there, so you -- whether you have it or not is probably not relevant. 
     But early on in the event, with this methodology, you would have some
     additional information on the state of the core that could be fed into
     protective action decisionmaking.  So that's an improvement.
         In the long term, we would hope to retain the capability to
     sample still.  We would not have an explicit timing requirement, but we
     would still have the capability to sample.  So I would argue that we
     weren't really giving that up, that the sampling makes sense late in an
     event when you've got -- the core is stable.  It's something that you
     could -- the situation won't change between zero and three hours, for
     the most part, the sample with mean something then.  If you took the
     sample in the first hour, the plant is still going through a transient,
     that information is nice, but it's three hours old and you've got a
     different situation in the plant right now.
         So I'm thinking that this proposal is not really a
     relaxation or an increase in risk.  I think that this is an improvement
     on the -- insofar as the decisionmaking goes, and there would still be a
     capability to sample in the long term when sampling actually would seem
     to make more sense.
         DR. WALLIS:  You're presenting some very nice arguments, and
     I am happy to see you have the courage to do so because the -- the
     regulator who is only interested in protecting himself would say, I'm
     just not going to let them do anything because I'm going to be blamed if
     anything happened.  So he wouldn't be recommending what you're
     recommending.
         MR. PALLA:  Well, I think it makes a lot more sense to try
     to improve the decisionmaking process if we know there's a problem there
     now.
         Okay.  So the first point is that we think the methodology
     in fact does represent an improvement.  It's --in a very approximate
     way, it tries to account for some of the processes that we know plague
     the situation, the fission product retention, the hold up issues. 
     There's some treatment of those issues implicit within the structure of
     the revised guidance.
         With regard to the fixed plant instrumentation that's being
     used, essentially it has primary reliance on the containment high
     radiation monitors and the core exit thermocouples.  Hydrogen is also
     looked at.  These three indicators are compared with each other for
     agreement.  Within the guidance there are different discussions about
     what could contribute to differences in those readings.
         And then beyond that, there is the use of reactor vessel
     level instrumentation.  The RTDs in hotleg and the source range monitors
     are used not in so much -- you don't calculate a percent core damage
     with those, but you would, for example, with source range monitors, they
     look for a decade increase in count rate to confirm uncovery.  Now, I
     think you could probably try to use that information to look for core
     relocation, but that is not part of this, it is really used for
     confirming the core uncovery.
         And, similarly, with reactor vessel level instrumentation,
     there are some predetermined levels and what the method does is look at
     where is the core.  You know, what have we put the core through?  Have
     we uncovered it below the level at which we would have expected to have
     core damage?  So, you are looking to correlate this information.
         We think that the instrumentation that is being proposed
     here is the right set of instrumentation.  It is obvious there is not a
     lot more information that you could use.  I think they are making pretty
     good use of the instruments that give you the most relevant information. 
     And the manner -- the hierarchy that is placed on it, the fact that it
     is cross-compared with each other to try to add some robustness to the
     estimate, we think is strength.  So we think that it is a pretty
     reasonable approach.
         With regard to the set point values, we took a look at these
     assumptions that -- I focused a good bit on the fission product holdup
     assumptions and the retention issues.  And we asked Westinghouse for
     some additional information to provide the basis for these numbers, and
     they provided us a table of MAAP calculations that supported these
     numbers and we separately looked at what information was available using
     the MELCOR calculations.  Went back, looked at the source term fission
     product expert elicitation for 1150 just to kind of see, and we actually
     have a couple of committee members that were experts on that committee,
     the expert committee for 1150.
         The agreement is -- obviously, the fission product holdup
     and retention, this is sequence-specific, and you can run various size
     LOCAs that would all be low pressure, and you will see a fair health
     degree of variation among -- from sequence to sequence.  But I think, in
     general, what has been done here is a pretty reasonable attempt to
     select a value that is characteristic of the types of events that you
     would be looking at.  If you are looking at high pressure events, the
     fission product holdup assumptions look reasonable.  Low pressure, it
     looks pretty looks.
         There is going to be sequences -- I wouldn't argue that it
     is bounding.  We looked across the board at -- you know, not that many
     MELCOR calculations.  We did not go and run more calculations for this,
     but looked at what few we had and looked at the MAAP things.  I would
     not go so far as to say it is bounding, but I would say it is pretty
     representative and it appears to be conservative from the point of view
     that what you would see in the atmosphere -- I will probably get it
     crossed up, but let me just leave it at fact it is conservative.
         You would probably -- you would over-predict the degree of
     core damage is what would happen because you are going to be -- your
     monitors are focused on the airborne part of that.
         Insofar as sprays, there is like a DF of 100 that is
     assigned to sprays, and I don't know that that would be bounding either,
     but --
         DR. POWERS:  I don't know how you assign a DF to sprays,
     since they keep operating.
         MR. PALLA:  Well, what is done is if sprays are operating,
     there is a factor of a hundred reduction in the inventory.  So the
     utility, in pre-establishing these curves assumes a certain inventory. 
     So you would run a calculation, you know what your inventory is for
     starters.  Then you would say, for high pressure, I am going to hold up
     a certain amount.  So you only carry that much into the development of
     the plant-specific curves for high pressure.  And for low pressure, you
     similarly make an assumption about how much is held up.  You run that
     curve out.  If you have sprays, then you reduce it further by two
     orders, and you run that calculation out.
         What you would do in an actual event is figure out if you
     have got cladding damage or whether you have got over-temperature
     damage.  You would then branch into different steps.  There is a step A
     and a step B that covers clad damage and over-temperature damage.  And
     you would look at it further and you would be comparing it, you would
     compare the actual reading from the rad monitor, you know, in the plant,
     which took into consideration the development of the curves, where the
     rad monitors are and what part of the containment they are looking at. 
     But you would compare your reading against the reading that would
     correspond to 100 percent release, you know, all of the core, as
     modified by these assumptions, and then derive an estimate of -- you
     know, a fraction of the core that is over-temperature failures.
         And, again, that is cross-compared to the hydrogen.  It is
     cross-compared to the core exit temperature readings, with the hope that
     you have got some range, probably a reasonable range of where you think
     the core damage is.
         I just want to mention very briefly, we had a few issues. 
     We had some concern that the -- we had a basic question, should you
     retain the elements of existing methodology with the expectation that
     latent event -- yeah, maybe it didn't make sense to do a PASS sample
     early, but in the long-term, if you are going to have the capability and
     you are going to go and use it, -- would it make sense to try to have a
     piece of the methodology there still?  So that you can convert your
     radionuclide information from PASS into a core damage assessment --
     estimate.  Confirm core damage.
         We concluded that that probably doesn't make much sense,
     that you might tend to confuse the situation.  And at that point all the
     decisions have already been made anyway insofar as ones that would be
     based on core damage assessment.  So we don't see the need to have, you
     know, elements of the existing methodology, you know, that would relate
     core damage -- or radionuclides to core damage.  We don't see the need
     to drag them into the existing -- into the revised methodology.
         We had some question about the clad damage criteria that was
     proposed.  And essentially, what the original version of the methodology
     did was it sets up a pressure limit.  If you are above that that
     pressure, you use one temperature as an indication of clad damage having
     occurred.  If you are below that pressure, you would use a different
     temperature value.  We questioned, well, where do these numbers come
     from?
         And, as a result, Westinghouse went back, did some
     additional looks at that, some additional calculations and revisited --
     they looked at high burnup fuel effects, too.  Actually, that wasn't
     part of the original determination of the recommended set points, so
     upon looking at the broader range of fuel burnup, they modified the
     recommended set points.  So that looked like -- again, this is still --
     has uncertainty in all these numbers, but it did look like it was a
     reasonable value selected for the high pressure and the low pressure
     situation.
         The final item, the effect of additional fission product
     removal mechanisms beyond those considered in the guideline.  What the
     guideline made -- they made assumptions regarding how much fission
     product is retained in the reactor coolant system and said anything not
     retained goes into the containment and that is -- if it isn't removed by
     sprays, and that is what the monitors see.  And I guess the question we
     had is, what about natural processes in the containment, and would that
     have much of an effect or not?
         And we -- again, in this area, we asked and Westinghouse
     provided some additional information that showed the partitioning
     between -- of the fission products that are in the containment, how much
     of them are airborne, how much of them are deposited in pools?  And the
     airborne ones would be the ones that you would be looking at -- the
     monitors would be the seeing the airborne, but not the ones in the
     pools.
         DR. WALLIS:  Can I go back to the temperature pressure that
     you were just talking about?  There is some sort of analysis that is
     done about how to interpret these temperatures at various pressures.  Is
     this a special analysis derived just for this application?
         MR. PALLA:  No.  There are existing models for --
         DR. WALLIS:  This builds on something which is --
         MR. PALLA:  This is like clad ballooning, clad balloon
     models and strain models that predict --
         DR. WALLIS:  It has a history of being reviewed and
     scrutinized by people who know enough to -- if it is right or wrong?
         MR. PALLA:  Well, there are -- yeah, there are models that
     are approved in the licensing space.  Now, the models that were used
     here were MAAP renditions of those models, so we did not --
         DR. POWERS:  Yeah, the database is old.  There is some
     additional work going on with respect to high burnup fuels.  The
     database is old, but it was thorough, shall we say.
         DR. KRESS:  Except it didn't really account for hydrogen
     embrittlement very well.
         DR. POWERS:  No, it was all lower burnup stuff where you
     don't get any hydrogen precipitation.
         DR. KRESS:  But other than that, it is pretty good.
         DR. POWERS:  It is a pretty impressive database.
         MR. PALLA:  Well, just getting back to the last item there,
     we took a look at that, the effect of natural processes, and this effect
     is within the range of uncertainty of sequence to sequence variation. 
     Really, it kind of bounds what you would see the natural processes
     contribution, so we figured what is out there -- what is assumed to be
     out there is still not a bad estimate, even though it didn't account for
     natural processes.
         Just the bottom line, preliminary conclusions.  Preliminary
     until our SERs clears internal review.
         The revised guideline provides core damage information with
     a sufficient level of accuracy to support decision making.  It's
     simpler.  It's faster.  It could potentially be a risk benefit.  Now it
     potentially may not make any difference at all, because if a utility
     modifies this, it still doesn't factor it into decision making, you
     haven't really changed anything, although you will reduce exposures on
     taking samples and so on.  But we think that if this information is made
     more timely, it's right for being used as an additional piece of
     information in decision making.
         The method accounts in an approximate way for the effects of
     fission product holdup, hydrogen deposition and holdup -- well, hydrogen
     holdup, high-pressure sequences in particular is what I'm talking about
     there.  You could have produced a lot of hydrogen, but in fact you may
     not see it in your sample measurement.  Your online monitor may not
     detect it because it's bottled up in the RCS still.  It's taken into
     account by looking at high-pressure and low-pressure sequences,
     specifically when you look at hydrogen.  And we think that the earlier
     availability of this information could improve the decision making.
         So the bottom line is we think it's a worthwhile change to
     what's out there today, and meets, if you go back to the original
     expectations of trying to categorize core damage into broad categories,
     this seems to be an acceptable alternative to using PASS.
         DR. POWERS:  I just keep thinking maybe you're being too
     timid here.  I keep coming back to the fact the decision gets made
     without all this information, and that satisfies the regulatory
     requirement.  That's a fact.  Why would we want to go on?  Why not
     just --
         MR. PALLA:  Why even have this at all?
         DR. POWERS:  You know, if the licensee wants to do it,
     great, but why do I as a regulator care?
         MR. PALLA:  Well, I think to some degree there's always
     question about whether -- how are licensees doing this.  There's one
     utility may already be doing it without this information, and another
     utility -- I wouldn't want to vouch for a utility being out there that
     actually is relying on it.  So I think it still makes sense to try to
     make these assessments.  I wasn't ready to walk away from the --
         MR. BARTON:  Also I think you walk away from it, utilities
     may -- some utilities may walk away from it also and then wish they
     hadn't, because it does provide some good data for recovery and later on
     in the accident.
         MR. PALLA:  I think it would enhance your accident
     management -- your assessment of where's the core, you know, how much --
         DR. POWERS:  Accident management's a responsibility of the
     licensees.  We don't really regulate accident management.
         MR. PALLA:  That's right.  And this would be part of their
     tools that they would use.
         DR. POWERS:  And if they want to use that, if they want to
     use a ouija board, I mean, it's kind of up to them.
         MR. PALLA:  Maybe I'm being too timid.
         DR. POWERS:  Good
         MR. PALLA:  Anything more?
         DR. WALLIS:  Well, as I said before, you're more courageous
     than the self-protecting regulator would be.
         DR. SEALE:  Well, maybe they want to have --
         DR. POWERS:  No one has ever accused Bob of being timid.
         DR. KRESS:  Before you leave, Bob, would you say there are
     any defense-in-depth implications of this?  You know, emergency response
     is quite often viewed as a defense-in-depth measure.
         MR. PALLA:  The point of not having PASS samples early to
     drive the core damage assessment.
         DR. KRESS:  Yes.
         MR. PALLA:  I guess that one might be balanced by the fact
     that the chemistry issues and the question about how good is the result
     that you get from PASS, if it is in fact skewed because --
         DR. KRESS:  If it doesn't reduce your uncertainties, then
     it's not good defense in depth in the first place.
         MR. PALLA:  It may increase them, I think.  If one doesn't
     go back and actually revisit the way it's done today, it seems like you
     might take it off the shelf today, you might kind of point in the
     opposite direction, not the right direction.
         DR. APOSTOLAKIS:  And wasn't this the first time that we had
     a staff member be brave enough to admit that he was timid?
         DR. POWERS:  Yes, but I know that he's not timid.
         Tom, this is the discussion that seems to have taken on a
     life of its own.  Would you object terribly if I took a break?
         DR. KRESS:  I wouldn't.  I think we could --
         DR. POWERS:  And before I declare a break, can you give me a
     hint on what it is we're to learn from this next presentation?
         DR. KRESS:  Just a second.  Or maybe we ask Jim to tell us.
         DR. POWERS:  If we're going to do that, I'm going to go
     ahead and take a break.  He can tell us when we come back.
         MR. O'BRIEN:  Well, I can tell you this real quickly, that
     there's -- we could approve core damage assessment methodology changes
     without addressing this other topic at all.
         DR. POWERS:  We'll come back -- we'll take a 15-minute
     break.  We will come back, and you're going to be limited to 10 minutes,
     okay, because I have another presentation scheduled pretty firmly at
     3:30.
         We'll break for 15 minutes.
         [Recess.]
              DR. POWERS:  We will come back to into session.
         Mr. Brien, I'm putting enormous pressure on you; you will do
     us an enormous favor if you avoid putting up the viewgraphs that say,
     either boron or chloride can be estimated from the knowledge of the
     sources of the water addition.
         Or, you can provide me a demonstration of how you can do a
     calculation that I am unable to do with some of the most sophisticated
     aqueous chemistry modals in the world.
              MR. O'BRIEN:  With that challenge --
              [Laughter.]
              MR. O'BRIEN:  In view of the limited time, I've cut my
     presentation down to one slide.
              [Laughter.]
              DR. POWERS:  You can't cut it any further than that.
              MR. O'BRIEN:  My names's Jim O'Brien.  I'm in the
     Emergency Preparedness and Health Physics at NOR.  And, I did not review
     this on my own; I had some help from Chris Parczewski, Lumbrose Lois and
     Bob Powell in doing the review.
              I wanted to, just briefly, discuss one very important
     issue, I think.  The change in the core damage assessment -- that's what
     you guys have just discussed and reviewed -- is a paper change.  There's
     no change to plant capabilities or anything like that.  It's a change in
     the way you do an analysis.  We think is better from the timeliness
     perspective, and perhaps from an accuracy perspective also, in assisting
     you in emergency response.  But it's a paper change; it doesn't change
     anything as far as plant capabilities.
              The issue we're looking at is this WCAP; it's
     something that could potentially affect plant equipment and capabilities
     in the plant, as far as personnel training and so forth.
              The close action sampling system, as you have already
     heard, is from NUREG-0737 requirement, and Reg Guide 1.97.  It covered a
     number of samples that were required -- and I use the word "required"
     as, not in the regulatory sense, but -- the title of NUREG was
     requirements.  The samples were from radionucleides and dissolved
     gasses; pH; boron.
              I think if I characterize it into three groups, I'd
     say that you had radionuclides, you had boron -- four groups --
     dissolved gasses, and the last one being boron.  Did I say boron?
         MR. BRYAN:  Yep.  You covered it.
              MR. O'BRIEN:  Okay, pH, then.  pH is what I missed.
              DR. KRESS:  Chlorides and stress corrosion, cracking
     concerns, and also the radionucleide.  In brief, we looked at each one
     of those areas and we made a determination on what is really being
     requested is a change in capabilities.  So we assessed what would be the
     change in the capability to obtain and analyze these samples?
              For the oxygen -- I'm sorry.  For the dissolved
     gasses, I'll start over here on the left and move to the right. 
     Dissolved gasses, which are used as indications of the potential for
     loss of, creation of voids in the vessel dome -- we considered the
     director vessel level instrumentation system.  And the ability to vent
     the vessel is adequate that we no longer need to sample for the
     dissolved gasses.
              Moving on.  Hydrogen is the same thing.  It's one of
     the dissolved gasses and oxygen also -- well, excuse me.  Oxygen is for
     stress corrosion cracking.
              The next issue that we're going to talk about is
     oxygen conductivity, pH and chloride.  And focusing in on the RCS
     aspects of those samples, Westinghouse is requesting that those samples
     be deleted for the plant, that the capabilities be maintained for
     long-term monitoring but not within the licensing basis.  From our
     evaluation, we considered that this is acceptable, because we have
     information enough to evaluate the potential for stress corrosion
     cracking.  In a nutshell, that's it.
              DR. SHACK:  My core is melting... stress corrosion
     cracking.
         [Laughter.]
              DR. SHACK:  The technical basis of the review just
     really distresses me because, why would I worry about chloride in water
     in the course of a severe accident?  I guarantee you, it's not stress
     corrosion cracking.
              Now, I might worry about it because I changed the
     iodine chemistry completely.  I certainly have something in there,
     gathering the things that will drive iodine down to a high oxidation
     state so it's not volatile.  That strikes me as something as something I
     would worry about.
              I see lots of things in here that say, gee, I can
     calculate how much of x is in the sump because I know how much is coming
     in.  And yet, I have tremendous amounts of chemical processes taking
     place in these sumps and other -- and even in the vessel, during a
     severe accident, that are resulting in things becoming complex, becoming
     hydrolyzed, becoming precipitates.  These are challenging things to
     figure out, but it does not at least show in the write-up that I've seen
     that that's been recognized either by the applicant or by the review.
              MR. KANE:  Chris Parczewski is with the chemical
     engineering branch --
              DR. SHACK:  One or both?
              DR. POWERS:  Both, Bill.
              DR. SHACK:  Both.
              DR. POWERS:  Both.  Because I am definitely beginning
     to hydrolyze both ziconia and Uo2 in hot water in these situations, and
     I get some very interesting chemistries going on in there.
              DR. KRESS:  And your interest in this chemistry is for
     what reason?
              DR. POWERS:  Because it sucks things out of the water,
     and I lose buffering capacity or I inject protons and I suddenly drop
     the pH down.
              DR. KRESS:  Well, your interest in that is concern
     over fission products -- trying to get this out --
              DR. POWERS:  In the end, my biggest concerns are going
     to be in a partition of iodine.
              DR. KRESS:  Yeah, iodine fission in particular.  And
     if one had ways of measuring fission products directly, you wouldn't
     worry about all that crap.
              DR. POWERS:  Well, if I measure the pH directly and I
     measured the buffering capacity directly --
              DR. SHACK:  It's going to be interesting.
              DR. POWERS:  -- I could probably do lots of things
     with the liquid fission product.
              DR. KRESS:  Lots of things with that, before you ever
     get to the need to measure a fission --
              DR. POWERS:  That's it.
              MR. O'BRIEN:  Okay.  I think we're understanding your
     point there, that it needs to be something that's considered in our
     review, and also, I take it, in the topic itself -- we need to consider
     it.  And I think we need to consider it in the context of its use during
     an event.
              DR. POWERS:  There are other things to consider, as
     well as, where does the regulatory need end and the licensee's
     responsibilities pick up?  I mean, he is responsible for accident
     management.  I think we have to bear that in mind as well.
              MR. O'BRIEN:  The next sample is the boron in the RCS. 
     That was considered for the potential for criticality and post-accident. 
     Westinghouse would like to have that relaxed eight hours after
     state-table state is reached.  And our review -- we have concluded
     preliminarily, and these are all preliminary conclusion -- is that it
     should be obtained and analyzed eight hours from the time of initiation
     of the accident.
              DR. KRESS:  If you sampled and the boron was too low,
     what would you do?
              MR. O'BRIEN:  From the business perspective, I would
     certainly look to put in -- it depends on what systems you were looking
     to put in if you were going to try to take action --
              DR. KRESS:  If you were going to try to add boron in.
              MR. O'BRIEN:  -- before you maybe started something up
     or whatever.
              MR. LOIS:  This is Lumbrose Lois in the Ecosystems
     Branch.  You add some more boron, if you needed to.
              DR. KRESS:  It wouldn't just be an indicator that
     there's likely possibility of criticality; you'd just go ahead and add
     more boron?
              MR. O'BRIEN:  And I'd be sitting over here, and it
     would be the licensee that would be making those determinations.
              DR. KRESS:  Would you add that boron whether you had
     the measurement or not?
              MR. LOIS:  What?
              DR. KRESS:  Would you add that boron whether you had
     the measurement or not, to see what the boron was?
              MR. LOIS:  You have to consider the scenario in which
     you are at.  You assume that you are in the primary boron at time of
     cycle, and also whether or not you initiated separation from the water
     storage tank.
              DR BONACA:  Reactor storage tank.
              MR. LOIS:  Water storage tank, which of course does
     have a design circulation in there.  But in addition to that, all plants
     do have the capability to add boron in the RCS.
              DR. BONACA:  Although you would be probably more in
     circulation more right now, you would be feeling from sump.
              MR. LOIS:  Yes, that's what I was trying to suggest --
     area that you have define what point in the scenario and be able to
     listen to scenario you're at.
              In the extreme, assuming that you have significant
     core damage, the requirements for boron are much, much lower because you
     lost geometry, and therefore you lost capability.  Therefore, you need
     to find out where you are at.
              MR. O'BRIEN:  Okay, the last piece of the categories
     of information is the radionucleides, which you get from the RCS, the
     sump and from the containment atmosphere.  Our review of that -- the
     request is to remove that sample from the licensing basis.
              In a review of it -- we're still looking at that. 
     We're looking at it closely, and I'll give you the reasons why.  We're
     considering its use in emergency preparedness, in feeding it the source
     term assessments and then subsequently into protective action
     recommendations.
              When we discuss that, we're not talking about the
     initial protective action recommendations, which are done on plant
     conditions.  You reach the general emergency conditions.  There's some
     default PARs that are implemented automatically and the evacuations, if
     necessary, take place.
         It's after that initial PAR, what licensees are required to
     do is continue to assess the conditions of the plant, including any
     releases or potential releases, to determine if those protective actions
     are adequate or maybe need to be expanded.
         What we are considering on that is the fact that these PASS
     samples are three hours in arrears of the timing to make a decision to
     do it, to take the samples, and we are looking at the indicators that
     may be available to provide the same type of information, and the type
     of information we are looking at is the isotopic concentration of what
     may be released to the environment, and we are looking at how other
     information could be used, including core damage assessment information,
     field team monitoring information, and so forth, in trying to determine
     how much we are losing if we accept the Westinghouse proposal to do
     this.
         DR. KRESS:  In what timeframe would you need that kind of
     information?
         MR. O'BRIEN:  The requirement for obtaining these samples
     within three hours really defined a capability, what you needed in the
     plant to be able to do that.
         The time you take the sample is up to the decision of the
     decision-maker in an emergency organization.  He can decide to take it
     right away.  He could decide to take it a day later, depending on when
     he thinks that information is needed, but the idea is when he decides he
     wants that information it would be available in three hours and
     therefore the equipment in the plant would be there to support that
     analysis, so when you would need it depends specifically on the accident
     that is in progress.
         DR. KRESS:  Okay.
         DR. APOSTOLAKIS:  Okay.
         MR. O'BRIEN:  I lied.  I'll go to one extra slide and then
     that will be it and I'll look for any questions.
         There's three outstanding issues in our analysis right now. 
     One is related to the timing of the boron analysis where there is a
     disagreement between whether it is eight hours after achieving a safe
     and stable state, or eight hours after the accident initiation, and that
     still needs to be resolved.  I don't think that is going to be a major
     issue but it needs to be resolved.
         The other one we have to address in the Westinghouse Owners
     Group document they talk about removing the PASS requirements from the
     licensing basis but maintaining the capabilities, and we are concerned
     as to what actually will be in the FSAR and so forth, and we need to
     work that out to make sure we understand what our conclusions are
     related to.
         The last one, which is the one I just discussed, is the
     radionuclide samples, and whether or not we feel that removing the time
     to be able to obtain and analyze the sample within three hours is a
     prudent thing to do, given what pieces of information you may be losing.
         So just in trying to make my presentation as brief as
     possible, I apologize if it is not as organized as I had planned.
         DR. KRESS:  I would say it was very good.
         DR. POWERS:  I thought that was good.  We should have you
     down more often.  You did fine.  Are there any other questions?
         DR. KRESS:  Seeing none -- I guess we turn the meeting back
     to you, Dana.
         DR. POWERS:  Okay, thank you.  We have an issue that has
     come up with respect to the maintenance rule that we discussed last
     year --
         MR. BARTON:  Last month.
         DR. POWERS:  It seemed like a year ago -- last month, where
     there's some revisions and differences in particular language with
     respect to how one goes about classifying systems as being either
     risk-significant, highly risk-significant and of low risk significance,
     and so we have an ad hoc discussion of that language and the controversy
     surrounding it.
         I am informed that a letter from the ACRS is anxiously
     awaited by the Commission on this.
         DR. SHACK:  Gee, our last one was so definitive.
         DR. POWERS:  Yes, and they didn't seem to get the message
     and so -- gentlemen, I hope that we can cover this topic in 30 minutes.
         MR. KANE:  We are prepared to do so.  Let me introduce --
         DR. POWERS:  I think you are secure in knowing that we know
     all of these gentlemen.
         [Laughter.]
         MR. BARTON:  The usual suspects.
         MR. KANE:  My name is Bill Kane.  I am the Associate
     Director for Inspections and Programs with NRR, and actually it's been a
     long time since I have been before ACRS.
         I would like to just make a few preliminary remarks to set
     this meeting in context and then we have a brief presentation to give
     you.
         We were asked by the Commission to go before them yesterday
     to give a brief, not necessarily brief but a progress report on the
     revisions to 50.65, the maintenance rule.  In that discussion we
     notified them of a recent change by the Staff that occurred after our
     discussions with CRGR and ACRS for the need to provide some rule
     language to clarify that the assessments that would be required would be
     limited at least within the bounds of -- to not necessarily include
     everything in the rule.
         This was really precipitated by some public comments that
     we'd received.  It actually was always the intent and in fact I believe
     the discussions that we had with you, that was the case, but we felt
     that some anchoring language needed to be provided in the rule to make
     this clear as opposed to just the statements of consideration and
     regulatory guidance.
         We advised them that the change was not discussed with the
     ACRS formally and that we had preliminary discussions or at least
     informal discussions to see if that was an issue and we got the
     impression that we needed to discuss it further, so that was made clear
     to them. Now the context of this is that they are expecting us to
     provide them something on the 17th of May, which is the final version,
     and I think they certainly want to have us talk to you about the change
     and why we feel it is necessary and then a schedule of where we are
     going, so we have for you -- that is the context of why we are here, and
     then we have a brief presentation that we'll give you that Richard
     Correia will go through.  Also with me today is Frank Gillespie.  Okay,
     Rich?
         MR. CORREIA:  Thank you again for taking time to listen to
     us again.  We briefed you less than a month ago on what we believed at
     that time was the final A(4) language for the maintenance rule.  That is
     why I titled this slide, "Modification to the Revision of A(4)."
         [Laughter.]
         DR. POWERS:  And of course everything else is on A(4) but
     the title is A(3), right?
         MR. CORREIA:  It is currently.  It should be A(4).  Thank
     you.
         This is the version of the rule that we shared with you last
     month and actually in February also, which stated that all SSCs in scope
     of the maintenance rule should be subject to a pre-maintenance
     assessment.
         We did explain though that we recognized that there is a
     certain subset of systems in scope of the rule that contribute very
     little or nothing to plant risk when taking out of service and we
     proposed in our Draft Regulatory Guide a process to do assessments to
     recognize these low and nonrisk SSCs and that a license could, once they
     were recognized, not have to do another assessment, and that really the
     scope of their assessments would be reduced to something that we
     considered the most important structures, systems and components.
         MR. BARTON:  And at that time that all made sense to us --
     those words plus your proposed revision to Reg Guide 1.160 meshed very
     nicely.
         MR. CORREIA:  Right, and we still believe that.
         MR. BARTON:  I like to hear that.k
         MR. CORREIA:  The difference is the current modified
     language is that we are making a statement that a licensee may limit the
     scope of SSCs that would require this pre-maintenance assessment to
     those that do a risk-informed evaluation process, having been shown to
     be significant to public health and safety.
         DR. APOSTOLAKIS:  Isn't the word "significant" a relative
     one?  In other words, shouldn't you complete the sentence there by
     saying "significant to public health and safety for the plant
     configuration in which these activities take place."
         MR. CORREIA:  That is the intent of this.  This would have
     to be.
         DR. APOSTOLAKIS:  But why don't you say it?  Would that
     satisfy you, John?
         MR. BARTON:  That might help, as long as the words in Reg
     Guide 1.160 stay as proposed and don't get changed, because the meat of
     this whole thing is the Reg Guide, not in the rule.
         MR. CORREIA:  Right.
         MR. BARTON:  Because the Reg Guide really says what you need
     to do to do the maintenance.
         DR. APOSTOLAKIS:  What is the page?
         MR. BARTON:  And it is page 3 in Draft Reg Guide DG-1082.
         DR. APOSTOLAKIS:  Do you have the paragraph?
         MR. BARTON:  Starts out with the scope of SSCs?
         DR. APOSTOLAKIS:  Yes.
         MR. BARTON:  The key here is about half way into the
     paragraph there is a sentence that says, "The focus on the assessment
     should be on the SSCs modelled in licensed PRA in addition to all SSCs
     considered to be risk-significant by licensee's maintenance rule expert
     panel.  The assessment should also consider combinations of low safety
     risk significant SSCs for planned maintenance that could result in high
     safety risk significant situations."
         That was also what we stated in our letter.
         "To reduce the burden, the licensee may perform a one-time
     assessment to identify low risk-significant SSCs in maintenance
     activities" -- et cetera, et cetera, et cetera.
         As long as those words don't change, these words are okay,
     but if those words are what is intended to be used by licensees to
     implement the rule, why doesn't the rule say that?
         MR. CORREIA:  We started writing different language in the
     rule but what we found ourselves doing was taking the Reg Guidance words
     and putting it in the rule and it became very lengthy, so we thought
     rather than do that, this would acknowledge the fact that the scope
     could be limited and just let this language serve as a bridge to the
     Regulatory Guide, which would explain this process.
         DR. APOSTOLAKIS:  But would you change the Regulatory Guide? 
     Mr. Barton is happy with the way it is now.
         MR. BARTON:  Yes.  What assurance do we have the Reg Guide
     won't change between now and the time it gets issued?
         MR. CORREIA:  Oh, that's not a problem.  If I can skip to my
     last slide --
         DR. APOSTOLAKIS:  Would you do that?
         MR. CORREIA:  -- I guess there was never a doubt in my mind
     that we would have to come back to the committee to discuss what we
     believe is a closer version to the final version of the Regulatory Guide
     and reflecting on the letter that you sent us April 14th recommending
     workshops, we have incorporated this in our proposed schedule.
         As you can see here, we would obviously need to modify the
     Reg Guide to incorporate this language to make sure that it was
     consistent, change that, come back to the committee, reconcile any
     comments, issue for public comments, and have a workshop to make sure
     that we have stakeholder feedback in this whole process.
         As we told you in April, in my mind it is very important
     that both the industry and our inspectors understand what this language
     means and how it is to be implemented and inspected.
         DR. APOSTOLAKIS:  It seems to me that this paragraph has to
     be revised anyway.  I don't like words like "combinations of low
     risk-significant SSCs that could result in high risk significant
     situations."  Then automatically they are not low safety significant
     anymore.
         MR. CORREIA:  Let me explain --
         DR. APOSTOLAKIS:  You mean "low risk-significant as
     specified by the PRA at power."
         MR. GILLESPIE:  Well, let me pull in some of the other work,
     and you hit it exactly, George, and this got us into a discussion
     yesterday in front of the Commission of the list of systems.  The list
     is not the point.  Condition is the point.
         DR. APOSTOLAKIS:  Exactly.  Exactly.
         MR. GILLESPIE:  So what we need to do is look at these kind
     of words and get away from this plant has this list and this plant has
     that list and by god, it's The List.   It is the condition, and I
     would key -- I have got circled in mine, because it gets in the back, we
     have to work on what does significant effect really mean, because if you
     look in the back it talks about CDF.  Well, CDF is continuous through
     the year and what are we talking about on a daily basis?
     Because the Commission has some goals that we won't have at 10 to the
     minus 3 condition, it's in our strategic plan, and if I take 10 to the
     minus 5 and say 100 days, suddenly I'm in a 10 to the minus 3 condition,
     which our strategic plan says we won't allow.
         So there's some real places in here we have to do some work. 
     What's the daily limit in precursor kind of space, CCDF?  And what's the
     CDF limit, which is kind of a cumulative thing over a year?  So we've
     got some real clarification we have to work on this.  And I think this
     schedule recognizes that kind of aspect that we've got to bring into it.
         DR. APOSTOLAKIS:  I still don't understand, I mean, to make
     it very, very clear, why don't you add those words or something to that
     effect that I mentioned earlier here so there will be no
     misunderstanding what you're talking about.  That has shown to be
     significant, and because most people automatically think of the PRA at
     power, then you have all sorts of problems for the configuration during
     which you have when you perform these activities.  Then the regulatory
     guide will really be constrained.  They will have to address that.
         DR. BONACA:  I have just one more question at least
     fundamentally.  I don't know why we're here.  Why is this last statement
     being added?  I would like to understand that.  To me the licensee has a
     burden to demonstrate himself that as he pulls out components or systems
     out of service he can manage that safety of that configuration.  Period. 
     And there is ample guidance within existing guidelines and management
     rule and so on and so forth to limit that scope if there is a basis for
     it.  Why are we introducing this table?  That's what I'd like to know. 
     Where is it coming from.
         MR. KANE:  Well, I can answer that.  Again, it's as you say,
     we made it very clear in the statement of considerations and in the
     regulatory guidance that this is the approach that we were using.  But I
     personally believe, and I think we all believe, that some anchoring
     language needs to be clear in the rule because after all it is the rule
     that is the piece of paper that prevails, that there ought to be some
     anchoring language in there that expresses as best we can.  And I
     appreciate, you know, the point that you made, to make clear that this
     is the foundation for the development of the regulatory guidance as we
     go forward, recognizing that we'll get many, many views, we got many
     yesterday, we'll probably get many more on actually what are the precise
     words that show up in this regulatory guidance.
         That's why we developed, it will go out for public comment,
     it will come back, public comments will be addressed, and it will be
     reviewed again before it in fact goes final.  And this is one of the
     situations here with this rule that the rule comes first, the guidance
     comes later, the implementation of the rule of course will wait the
     guidance.  But again, if you could go to that slide.  So the answer to
     your question is that as best as I can make it clear, is that some
     foundation needs to be included in the rule we believe to express where
     we're going and build the regulatory guide.
         DR. BONACA:  And the reason why I asked that question, this
     is a definition of limitation.  And, you know, on a generic basis I'm
     somewhat uncomfortable about placing limitations to the responsibility
     of individuals who are taking a system out of service on what they can
     take out of service.  I mean, they're responsible for assuring the
     process provides a safe outcome.  And so that was my simple objection. 
     I mean, when I see the statement that's a statement of limitation.  It
     may be accurate.  It may support the process that is proper.  But I
     don't know.  I'm not sure.
         DR. APOSTOLAKIS:  So what you're saying, Mario, is that the
     requirement that the licensee shall assess and manage the increase in
     risk is good enough?
         DR. BONACA:  Yes.  I mean, that's the way it was.  Right?
         MR. BARTON:  No, it wasn't that way, I don't think.
         MR. CORREIA:  The only change was that we added this last
     sentence.
         DR. SHACK:  We took the structures and components within the
     scope out.
         MR. CORREIA:  I'm sorry, yes, we moved the total scope of
     the rule out, yes, saying that it may be limited.
         But again, the process would define how that limited --
         DR. BONACA:  For me it's very hard to make a judgment
     whether or not this limitation is implied limitation in the top
     statement, okay, it's going to be in all cases, you know, provide a
     sufficient protection.  And that's why I said I would have liked to
     leave it more general, because there are plenty of provisions within the
     regulation to limit the scope based on assessments and so on and so
     forth.
         You know, when I see this statement, that to me says oh,
     there's limitations, you can do less than.
         I had just one comment, and some level of, you know,
     question mark in my mind.
         MR. BARTON:  No, some people think that all you need to look
     at is what's modeled in the PRA and what you'd list as a high safety
     significant component or system.  And that's a problem.
         DR. BONACA:  Yes.
         DR. SHACK:  With George's additions, you know, for the
     configuration of interest it would solve that, wouldn't I?
         DR. BONACA:  And that's good.
         DR. APOSTOLAKIS:  There are actually two things, because,
     see, that's a problem with concepts that are relative, like risk
     significant.  And I think John's concern touches on that, although he
     does not express it that way.
         Let's say you are at shutdown, and you do your risk
     achievement worth calculations and Fussel-Vesley, categorize it.  Now
     typically I believe what we do there is do the components and structures
     and systems one at a time.  What Mr. Barton's concern is that even for
     shutdown, so if you interpret the configuration at shutdown, when you
     take out one system, then the risk significance of other systems may
     change.
         Is that correct, John?
         MR. BARTON:  Absolutely.
         DR. APOSTOLAKIS:  So he wants to see risk achievement worth
     for perhaps combinations of components that may be taken out of service. 
     That's really the concern here, that even by taking out one component,
     you have changed the configuration.
         DR. SHACK:  Yes, for the result of the configuration.
         DR. APOSTOLAKIS:  We typically don't do this, though. 
     Typically in a PRA we don't do this.  We don't take two at a time, three
     at a time, and say these are out, or if I set a probability of failure
     equal to 1, this is the risk achievement worth.
         DR. BONACA:  And in fact the experience as the licensees
     developed methods they were able to do that.  There were a lot of
     surprises out there.
         DR. POWERS:  That's right.
         DR. BONACA:  A lot of surprises.  You know, some innocuous
     system suddenly was becoming important because he has removed a couple
     of lines of defense and now you are relying on that system for the
     point.  So --
         DR. APOSTOLAKIS:  Bill had a -- Bill, you wanted to state it
     in a different way?
         DR. SHACK:  I just said for the resulting configuration.
         DR. APOSTOLAKIS:  Yes, that's exactly what it is.
         MR. CORREIA:  And we don't disagree with that position.  As
     Bill said, we thought anchoring, limiting scope language in the rule
     would be a way for us to express that view, that not everything in the
     scope of the rule is equally important.  And there may be some that
     don't.
         DR. APOSTOLAKIS:  Let me come back to Dr. Bonaca's point. 
     There may be -- although originally I was not really disturbed too much
     until you sensitized me to it, Mario, by this sentence.  It sort of
     implies that you can -- well, it says maybe, of course, but the
     significance with respect to risk is a way to do it.
         We heard earlier from the fire protection people that what
     they want is to make sure that they will have a path that will guarantee
     shutdown given a fire.  This is a very different way of approaching it. 
     You don't care anymore about the risk significance of anything.  You
     don't care anymore about combinations, at least at this level of
     components being out of service, because you say I want this path to be
     available, or I want these two paths to be available.  So you get away
     completely from the risk significance of SSCs.  Right?  Because now
     you're talking about paths.
         And that may in fact be a better way of doing it, because
     now I don't have to worry about taking two at a time, three at a time,
     out and calculating their relative risk worth.  And maybe by putting
     this sentence there you're leading people to do a certain analysis in a
     certain way.
         DR. BONACA:  Yes.
         DR. APOSTOLAKIS:  In the regulatory guide you may elaborate
     on these things if you wish.
         MR. CORREIA:  And obviously the regulatory guide would have
     to reflect methods --
         DR. APOSTOLAKIS:  Yes.
         MR. CORREIA:  That would allow different options.
         DR. APOSTOLAKIS:  But I think the tendency has been in the
     last couple of years to really base just about everything on risk
     significance, and we forgot the original idea of accident sequences or
     success paths.
         MR. BARTON:  Go ahead.
         DR. BONACA:  No, you go ahead.
         MR. BARTON:  I'm going to change the subject.
         DR. BONACA:  To me that statement, the scope of the
     assessment, two structures, a risk-informed evaluation process as shown
     to be significant.  It doesn't say two at a time or three at a time, it
     says one at a time.  You have performed somewhere an assessment that has
     ranked the systems.  And I've never seen any ranking of systems done by
     random choosing ones that you pull out.  There is no way to do so.  So
     you're going to rank them by looking at them, achievement worth, by
     pulling them out one by one.
         Now when you say that, then it's like a license to say okay,
     with the ranking now if I take out some system or component that is not
     in the ranking or high in the ranking, I can do it without performing an
     evaluation that sums up all the components out of service.  That's what
     I read in that.
         MR. CORREIA:  We state in the regulatory guide we're
     concerned with the individual or combination of SSCs that are shown to
     be risk significant.  The combinations obviously is the stated purpose
     of this regulation.  The need to understand, assess, and manage the risk
     due to that combination.  Absolutely.
         Licensees have already ranked individual systems regarding
     their contribution to safety of risk, and that's what Mr. Barton was
     referring to.  That is one subset.  But again that was done on an
     individual basis, and we agree, it's the combination that needs to be
     assessed and understood and properly managed.  And obviously the
     regulatory guide will have to be robust enough to reflect various
     options of doing that.
         DR. APOSTOLAKIS:  I think you need in the regulatory guide a
     very short tutorial as to what risk significance means, because if you
     take it for granted now that it means a specific thing, and when you get
     into this you have to revise your thinking.  Maybe a paragraph or two.
         MR. CORREIA:  I understand.
         MR. BARTON:  Rich, what's the reason for the reference to
     CRMP?
         MR. CORREIA:  There is no reference.
         MR. BARTON:  It's on this modified package we got, modified
     A4 provisions, new wording, Commission briefing paper.
         MR. CORREIA:  Oh, yesterday.
         MR. BARTON:  One of the bullets on there is the CRMP. 
     What's the intent of --
         MR. CORREIA:  What we thought was CRMP already for technical
     specification purposes, RE has a methodology for evaluating --
         MR. BARTON:  But its scope is limited.
         MR. CORREIA:  Its scope is limited.
         MR. BARTON:  Very limited.
         MR. CORREIA:  Right.  And we recognize that.
         MR. BARTON:  Okay.
         MR. CORREIA:  And it may not be -- I think the issue comes
     back to what is modeled in the PRA and is that the right modeling.  We
     understand that.  And obviously -- and I think we have some language in
     our draft guide that refers to the adequacy of the PRA model to make
     sure that it captures all the right SSCs.
         DR. APOSTOLAKIS:  Now I mentioned earlier the success paths. 
     Don't pay too much attention to it.  Because there would be many of
     them.  I mean, you really worry about the increase in risk.  So if the
     core damage frequency goes to 10 to the minus 3 or 2, you still have
     success paths, I hope.
         [Laughter.]
         MR. GILLESPIE:  To have it not be 1, you need at least one
     success path.
         DR. APOSTOLAKIS:  So I'm not sure that that's -- that's
     going to be much more analytical work than working with --
         MR. GILLESPIE:  It sounds like one of the hang-ups we have
     here is the words has kind of a past tense to it, "has been shown," I
     think, or that's what you were bringing up, that the analysis may have
     not yet been done, and therefore it has been shown.  I hadn't thought
     about the tense that we used in it, but --
         DR. APOSTOLAKIS:  How about if you say the scope "is shown"?
         DR. SEALE:  Shows.
         MR. GILLESPIE:  And I'm sitting here staring at it, and the
     tense of the verb --
         DR. APOSTOLAKIS:  Oh, shows.  Yes.  Yes.
         MR. GILLESPIE:  Leads to the problem you're talking about, I
     think.
         DR. BONACA:  But still, you know, the scope of the
     assessment may be limited.  This just implies that what you're putting
     in in the evaluation still is limited.
         MR. BARTON:  Or you can interpret that to say the scope of
     this assessment you only have to do to those systems, structures, that
     have risk significant evaluations significant to public health and
     safety, so you only have to look at high risk significant stuff.  Right. 
     Could I interpret it that way?  And I've got a problem with that.
         DR. POWERS:  And demonstrably unjustified.
         DR. APOSTOLAKIS:  I didn't follow that.  That what?
         MR. BARTON:  You can interpret that to only have to look at
     high-risk-significant stuff.
         DR. BONACA:  Yes, that's what it says.  And you can change
     the --
         MR. BARTON:  And then I've got a problem, because now I'm
     back, the only thing that's saving me is what's in the reg guide that
     says I've got to do more than that.
         DR. POWERS:  And the reg guide can change.
         MR. BARTON:  And the reg guide can change.
         DR. APOSTOLAKIS:  But for the resulting configuration they
     will not be significant any more.  I mean, that's your concern, that
     they may become risk significant.
         DR. SHACK:  Right, but I mean if you added for the resulting
     configuration to that sentence.
         DR. APOSTOLAKIS:  Yes, that's what I'm saying, if you add --
         MR. CORREIA:  Again, the assessment is of the proposed
     maintenance activity, 1, 2, 3, whatever it is they're removing from
     service and understanding what that configuration does to plant risk.
         DR. BONACA:  But again the evaluation has to look at all of
     them in the aggregate.
         MR. CORREIA:  Initially, well, without stating it, it
     implies that the whole scope of the rule has to be considered, or any
     system in the scope of the rule.
         Then there is a possibility of some further evaluation. 
     Some may be eliminated from further assessment.  That was the intent.
         DR. BONACA:  As you see, I mean that would be the biggest
     disservice to the operator.  He doesn't know what people are pulling
     out, I mean if he approves it.  But the fact is, he doesn't get any
     insights that, in fact, he shouldn't allow for some system to be out of
     service.
         DR. POWERS:  I think that is a singularly important point to
     make.  This is a disservice to the operator.  He really does get
     inundated with people wanting to pull things out and he has to make a
     decision on the fly, limited amounts of -- I mean it is guided by
     intuition and judgment.
         MR. CORREIA:  But it does have to be as shown because I
     could well imagine that people will have a set of configurations that
     are of interest to them and they will do the PRA once and for all, and
     for those configurations, they will have an assessment.
         SPEAKER:  And the existing guide allows that one time
     approach.
         MR. CORREIA:  Right.  Just when we were talking about shows
     versus as shown up here.
         DR. POWERS:  But I think it is okay, Bill, and it still -- I
     think it is all right to have a set of configurations that you have
     evaluated because you know you get into it every single outage that you
     have.
         MR. BARTON:  That is a reasonable thing to do.
         DR. POWERS:  And still -- and that still shows that this is
     of modest risk significance.  So I think shows still works here.
         Do you have more you are going to tell us?
         MR. CORREIA:  No, I have already shown you the schedule. 
     Obviously, we will be back here with the Reg. Guide at least twice more. 
     We would hope that we could have some of your staff's involvement during
     the workshops, that is very important, too.  But we appreciate the
     opportunity again.
         DR. POWERS:  Well, we thank you for taking the time to come
     down here on our emergency mission here.
         MR. CORREIA:  Thank you.
         MR. GILLESPIE:  We appreciate you having the emergency
     mission.
         MR. KANE:  We hope this helps and I appreciate the comments.
         MR. GILLESPIE:  The feedback, that was very helpful.
         DR. POWERS:  Thank you.  Gentlemen, I am going to take --
         MR. SINGH:  NEI also has a presentation.
         DR. POWERS:  We also have -- Tony has disrupted his
     schedule, which I am assured is very, very busy, and come down to help
     us with our emergency mission here.  So, Tony, the floor is yours.
         MR. PIETRANGELO:  Thank you for the opportunity to come down
     and chat with you about this.  You have seen the letters we have sent
     the NRC.  We were proponents of reflecting in the rule the actual intent
     of the staff and the Reg. Guide to focus on the most SSCs when they do
     configuration assessment.
         I wanted to ask a couple of questions of the ACRS, though,
     because I think some people don't know what the full scope of the
     Maintenance Rule is.  Would I do an assessment when my emergency
     lighting comes down, if I have to replace a light bulb on that system? 
     Would I do it on a gaetronics box in the plant?
         MR. BARTON:  You are giving me a list of what, low risk or
     non-risk significant components?
         MR. PIETRANGELO:  Well, my point is that the scope of the
     Maintenance Rule is quite broad, and given that broad scope, licensees
     undertook a risk significance evaluation in the implementation of the
     rule to try to focus on the safety significant SSCs.  I think in a
     perfect world, everybody wants to consider every combination that would
     be potentially risk significant in the plant, but at some point you have
     got to say, there are some things I need to focus on that are the most
     important.
         DR. BONACA:  Can I just say one thing?  But the rule allows
     you, in fact, the flexibility to have a superficial evaluation that has
     to be done, if in fact you have a lighting system.  I know you have to
     do -- say, not only to do it anymore.  I mean that is as flexible as the
     rule is, so I would like precise that.
         MR. PIETRANGELO:  Well, in discussions with the staff, I
     mean it is not readily apparent that it is as easy as that, Dr. Bonaca,
     either, in terms of documentation, in terms of combinations.
         DR. POWERS:  I thought it was very explicit.  There is no
     documentation on those things.
         MR. PIETRANGELO:  No, that is not explicit.  That is not
     explicit.
         DR. POWERS:  It was my reading that -- in fact, when we
     asked him about that explicitly -- do they have to write something down,
     even in the log book on that?  And the answer was no.
         DR. BONACA:  It was an answer from the staff to a question
     that said there is no documentation requirement.  In fact, I had a
     concern with that, but we left it that way.
         MR. PIETRANGELO:  Okay.  Well, I am getting new information
     now, too, because we did have an interaction with the staff last summer
     as we were trying to revise the guidance.
         MR. BARTON:  We were concerned about that, too.  You brought
     up some examples, all right, of issues that you wouldn't look at as part
     of your overall maintenance.
         MR. PIETRANGELO:  Right.
         MR. BARTON:  Because they had -- they are no-never-mind,
     they are not risk significant.  We asked the staff, would you have to
     document that?  Well, the answer we got was, no, we would be looking for
     -- since it is a performance-based rule, we would be looking for the
     licensee's program, procedures or how they are going to implement this. 
     Right.
         MR. PIETRANGELO:  Right.
         MR. BARTON:  We wouldn't be looking down in the grass. 
     Because the problem I have got is when you look at -- and you gave some
     examples of non-risk or low risk significant components.  But each
     licensee has got these things broken down different.  There is different
     systems classified that way.  And some licensees have got some pretty
     significant systems that are in direct support of ECCS and other safety
     systems that they classify as low risk.
         And if you say if I don't have to look at those in
     combination with, quote, the other systems, that is when I think I start
     having a problem.  When you say reactor water cleanup, intermediate
     range, all neutron monitoring systems, rod position indicating systems,
     source range monitor and feedwater control, there is one plant that all
     stuff is non-risk significant.  Are you telling me I don't have to look
     at any of that because I am taking out a RHR train or something?
         I got to look at it.  So I just can't look at the high risk
     significant.  That is the issue that we are struggling with.
         MR. PIETRANGELO:  And what we are saying is that you have to
     look at the whole process that has occurred here.  First of all, you
     have got tech specs as backstop in place.  Those are not going away. 
     Okay.  Secondly, you have got what was done in establishing the high
     safety significant within the Maintenance Rule, it was put through an
     expert panel.
         I think a lot of the considerations that you just mentioned
     were taken by those experts panels when they got down to the scope. 
     Okay.  What we are concerned about is having to justify kind of finding
     the needle in the haystack of low safety significant things that -- I
     mean I could go through and find and put together a combination probably
     that would result in something significant.  It is not saying that what
     has been done thus far precludes that from happening.  But I think this
     perfection for looking for any combination of low safety significant is
     in the way of the good, which is being done in the field.
         The regulatory analysis that was done to support this rule,
     I don't know if that was looked as part of the ACRS review, doesn't
     incorporate any additional licensee activity because voluntary programs
     are already in place for this activity.
         And so what is the incremental benefit of going -- I mean
     there is safety -- a safety standpoint, and what is the cost of going
     that extra -- looking for these low safety significant combinations?  I
     am just saying that work has not been done.  And we know -- and there is
     a history associated with the Maintenance Rule that kind of colors some
     of the discussions we have had.  And when you say the staff won't
     question what -- they just want to look at your process and procedures,
     well, during the baselines, they did question and wrote violations
     against what the scope was.
         MR. BARTON:  I know they did.  I understand that.
         MR. PIETRANGELO:  So to say that can't happen and won't
     happen, and given that the rule is performance-based and somewhat vague,
     you have to hang your hat on what is in that regulatory guidance and
     what is interpreted.  So we are not starting from a clean sheet of paper
     here either.
         I think our objectives are the same, though, in that no one
     wants to put the plant in unmanaged or unassessed configuration.  We
     believe the rule should require awareness and should require action
     appropriate with that.
         And one of Dr. Bonaca's remarks, I think -- you said
     something that struck home with me.  In the original proposed words by
     the staff, it was before performing maintenance activities on
     structures, systems and components within the scope of the rule.  You
     could take out, I guess, mention of SSCs.  I mean we have been focused
     almost with blinders on on scope maybe for too long, instead of looking
     at what the configuration is.  The concern is that you place the plant
     in an unassessed configuration and the focus has been on -- am I looking
     at this big scope, or am I looking at a smaller scope that I know will
     have significant impacts on plant risk?
         So, I mean just the fact that we had to get to a scope
     argument in this provision, I think that is the first time I heard it
     said that way, and it makes me think longer about it.
         But the other point I would like to make is that -- and I
     think George noted that it was in the Commission slides yesterday, that
     the staff has approved configuration risk management programs for
     risk-informed allowed outage time extensions.  And in that Reg. Guide it
     says it was the intent of those programs to meet this particular portion
     of the Maintenance Rule.  And the scope of that CRMP is --
         MR. BARTON:  Is limited.
         MR. PIETRANGELO:  -- the high safety significant SSCs
     identified under the Maintenance Rule, as well as what is modeled in the
     PRA.
         Now, I don't know --
         MR. BARTON:  Of these 50 systems of low safety significance,
     how many are modeled on the PRA?
         MR. PIETRANGELO:  I think -- our understanding is probably
     20 to 30 percent of the plant systems.
         MR. BARTON:  Six.  Now that doesn't tell me there is a heck
     of a lot of scope that I would have to look at if I was following a
     CRMP.
         MR. PIETRANGELO:  But I would also ask you to put some
     combinations together and tell me what would be the significant impact
     of those.  Okay.
         MR. BARTON:  There are some.
         DR. BONACA:  Well, I have seen some spiking, okay.  We have
     done it for years and I know that it wasn't very time-consuming once we
     had a way to do it.  And, second, that you got startling increases and
     all you had to do was to shift an activity by eight hours and it was
     plenty acceptable to the maintenance department and then the whole risk
     profile was getting flat through time.  Okay.  That is what managing
     risk seems to me.  And I would like to see some success there before we
     have all these provisos, because, also, I mean there has also been
     experience in some plants where there were full trains taken out of
     service and do maintenance on, so there has been the other excess, you
     recognize that.
         MR. PIETRANGELO:  I understand.
         DR. BONACA:  So, you know, I don't think these plants were
     designed for online maintenance.  I think we want to get there, and the
     way to do it is to do it right.  And today we have the tools to do it. 
     But -- and the bigger issue, as we pointed out before, is you are doing
     a disservice to an operator if you are convincing him, and he can't have
     eyes all over the place, that you can take out of service three, four,
     five components or systems and he says, okay.  Yeah, he looks at his
     charts, and he looks at everything and it looks okay.  And now you are
     putting him in a condition where he gets into trouble and maybe we could
     have told him that he shouldn't have done that, because there was a way
     to do it.
         MR. PIETRANGELO:  Yeah, but on the same token, I also don't
     want to distract the operator to perform a required assessment under a
     regulation on something that isn't going to matter.  I mean that doesn't
     help the operator either.
         MR. BARTON:  That's true.
         MR. PIETRANGELO:  So there is a balancing there.  And,
     again, the objective and intent is the same here, is to do it right,
     okay, and to get people to focus on the right things.  But we don't --
     and from a licensee's implementation perspective, we want, I think as a
     principle of going into this, a bounded scope.  And I think that is
     fundamentally different from what I hear you all saying.  And that is
     unfortunate, I think.  But we think you can bound what you need to look
     at in these assessments such that you don't distract operators
     unnecessarily, yet appropriately consider and manage the risk of doing
     online maintenance.
         DR. BONACA:  You see, for example, however, let me just say,
     if you read 50.59, you have support systems that are not safety
     significant.  And yet, if you make a change there, you have got to
     perform a safety evaluation.  There is a burden that is much larger than
     assessing the significance of taking that component out of service for
     maintenance, where it is much more important than, in my book, than just
     going through the 50.59 process.
         MR. PIETRANGELO:  Right.
         DR. BONACA:  So all I am trying to say is that we are trying
     to limit so much the scope and, you know, the point that John made, that
     Mr. Barton made about the list and only six of them being -- that list
     of the systems that are so-called non-safety significant.  I mean it is
     an issue.
         MR. PIETRANGELO:  Well, again, we know there is one thing
     that the staff has approved that says -- meets this intent.  What we are
     looking at is whether -- what licensees have already done to establish
     the high safety significant SSCs, how that matches up with what is
     modeled in the PRA.
         I think the staff would tell you from their experience in
     the baseline, they are pretty satisfied with people using the tools that
     are out there today, the risk monitors, even the matrices.  Okay.  They
     have limitations.  You still need to have some judgment associated with
     that.  But all we are trying to do is get a rule that allows us to use
     the tools that we have, not that we don't have.  Okay.  And if they want
     it to go beyond that, then that ought to be assessed for the incremental
     safety benefit in the regulatory analysis, as well as the additional
     cost of implementation of that.  That is our only point.
         DR. POWERS:  Are they are any more questions for Mr.
     Pietrangelo?
         [No response.]
         MR. PIETRANGELO:  Thank you for the time.
         DR. POWERS:  Thank you.  Well, we now come the dilemma we
     face, I think we are complete with transcription.
         [Whereupon, at 4:20 p.m., the open portion of the meeting
     was concluded.]
	 
	 	 
Page Last Reviewed/Updated Wednesday, February 12, 2014