470th Advisory Committee on Reactor Safeguards (ACRS) - March 2, 2000
UNITED STATES OF AMERICA
NUCLEAR REGULATORY COMMISSION
ADVISORY COMMITTEE ON REACTOR SAFEGUARDS
***
MEETING: 470TH ADVISORY COMMITTEE ON REACTOR SAFEGUARDS
(ACRS)
U.S. Nuclear Regulatory Commission
11545 Rockville Pike
Room T-2B3
White Flint Building 2
Rockville, Maryland
Thursday March 2, 2000
The above-entitled committee met, pursuant to
notice, at 1:02 p.m.
MEMBERS PRESENT:
DANA A. POWERS, ACRS Chairman
GEORGE APOSTOLAKIS, ACRS Vice-Chairman
THOMAS S. KRESS, ACRS Member
MARIO V. BONACA, ACRS Member
JOHN J. BARTON, ACRS Member
ROBERT E. UHRIG, ACRS Member
WILLIAM J. SHACK, ACRS Member
JOHN D. SIEBER, ACRS Member
ROBERT L. SEALE, ACRS Member
GRAHAM B. WALLIS, ACRS Member
P R O C E E D I N G S
[1:02 p.m.]
CHAIRMAN POWERS: The meeting will now come to
order. This is the second day of the 470th meeting of the
Advisory Committee on Reactor Safeguards.
During today's meeting, the Committee will
consider the follow: Technical components associated with
the revised reactor oversight process; nuclear power plant
license renewal application; proposed final amendment to 10
CFR 50.72 and 50.73; proposed final Revision 3 to Regulatory
Guide 1.160; assessing and managing risk before maintenance
activities at nuclear power plants. We will also discuss
proposed ACRS reports.
The Committee met with Commissioners between 9:30
and 12:00 noon today in the Commissioners Conference Room,
One White Flint North, and discussed items of mutual
interest.
The meeting is being conducted in accordance with
provisions of the Federal Advisory Committee Act.
Mr. Howard Larson 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.
Transcripts of portions of the meeting are begin
kept, and it is requested that the speakers use one of the
microphones, identify themselves, and speak with sufficient
clarity and volume so that they can be readily heard.
Before we initiate the discussions, do any members
have any comments that they want to make at the opening of
the meeting?
[No response.]
CHAIRMAN POWERS: Seeing none, I think we can
proceed then with our agenda. The first topic that we're
going to discuss is the technical components associated with
the revised reactor oversight process.
Mr. Barton, I believe you're going to direct our
process through this most interested topic.
MR. BARTON: Thank you, Mr. Chairman. The purpose
of today's session is to continue dialogue with the staff
regarding the revised oversight process, and I think,
specifically discuss preparedness for rolling out the
process for the initial implementation program, and also
some discussion on the significant determination process
which we didn't have time or weren't ready or something to
discuss the last time we met with the staff.
So at this point, I'll turn it over to the staff.
Who's got the lead? Frank, do you want to say anything?
MR. GILLESPIE: No, it's Bill's.
MR. BARTON: All right, Bill, you've got it.
MR. DEAN: Good afternoon, gentlemen. I'm Bill
Dean, the Inspection Program Branch Chief from NRR. And
with me today are Alan Madison and Doug Coe from my staff.
We're here to talk to you about exactly what Mr.
Barton addressed. Basically this is a continuation of our
February 3rd meeting where, basically, we were only able to
get through the performance indicator portion of the
discussion.
So we wanted to pick up where we left off and talk
to you about the significance determination process.
I would like to mention a few things that have
happened in the interim. Of course, we have developed and
submitted our Commission paper, SECY 0049, to the
Commission, which I believe you all have copies of, and
hopefully you've had a chance to start to peruse that
document.
That certainly provides what we believe the basis
is for why we feel that going forward with initial
implementation in the near term is the right thing to do.
CHAIRMAN POWERS: Why is that?
MR. DEAN: Well, there are a number of reasons.
Of course, we watch with interest, your presentation to the
Commission today, and some of the comments that the
Commissioners made in the closing remarks, I think are
pretty much in line with where we believe we're coming out,
based on the results of the pilot program.
And that is that the pilot process allowed us to
learn a number of issues regarding the efficacy of the
revised oversight process. It allowed us, during the course
of the pilot program and in the interim between the end of
the pilot program and now, to make appropriate changes and
modifications to the process and improvements that would
allow us to be able to enter into the next phase, which is
basically -- and I think Commissioner Merrifield kind of
described it best; that really it's an expansion of the
pilot process to 103 plants.
You know, we believe that we've learned enough
information that gives us a good comfort level that this
program is an improvement in all the areas that the
Commission directed us to improve in, and I think that we've
demonstrated that.
I think we have also demonstrated some areas that
we need to continue to monitor closely and gather additional
information in, and that after the course of the first year
in implementing this process at all 103 sites, it will give
us the added information that we need to do to better refine
this program and get it closer to the perfection that
Commissioner Merrifield noted; that this was not a perfect
process.
It was not expected to be a perfect process. It
is a much improved process, but, obviously, there is going
to be continued improvements that will be needed.
CHAIRMAN POWERS: You said 103 sites.
MR. DEAN: Plants.
CHAIRMAN POWERS: Is this being applied anywhere
besides nuclear power plants?
MR. DEAN: No, I meant plants.
CHAIRMAN POWERS: Okay.
MR. DEAN: Sorry. We do appreciate the
endorsement that we heard regarding your belief, universal
belief that this is an improved process.
But we also recognize that we may continue to
agree to disagree on certain aspects of the program, and
that perhaps more effort is needed on the part of the staff
to either continue to discuss certain issues or aspects of
the program with the Committee or individual members, and
certainly we're willing to do that.
Before we get started, I do want to note one thing
in terms of schedule. I know that you also have other parts
of this afternoon to listen to other presentations, but we
do have a briefing for the Chairman at 3:00 this afternoon,
so hopefully we can adhere pretty closely to the schedule.
CHAIRMAN POWERS: Oh, we've got him where we want
him now. Let me ask you a question.
MR. DEAN: Yes, sir.
CHAIRMAN POWERS: When you presented last time, a
document that had a series of questions posed about the
pilots, and then you got a grade from some people that did
some grading for you on that, in many cases you got an
incomplete.
And the answer was that I can't answer whether
this criterion had met; the thing didn't go on long enough.
Have you had a chance to get back to your graders and say
now we're going to go in to this second phase where we have
a pilot involving 103 plants, and ask them, how long does
this have to go on before you can give us something besides
an incomplete? Either pass us or fail us.
MR. DEAN: I believe -- I think the Commission
paper addresses that as part of the rationale for moving
forward into initial implementation, but also recognizing
the fact that after a year of initial implementation, we
need to do a thorough self-assessment, much like we've done
in the pilot program, and report back to the Commission
again.
And that would incorporate getting feedback from
all of our stakeholders, much as we did in the pilot
program, soliciting public feedback, industry feedback,
internal stakeholder feedback, on, you know, now that we've
experienced a year of this process, you know, what does that
tell us about, for example, some of the issues where, you
know, there is still some discomfort out there about the
capabilities of this process to do certain things that
people believe it should.
And, you know, it's having the chance to
experience this process over the course of the year. Does
that help in that regard? Has that helped to alleviate some
of the concerns in that area?
I think a lot of the discomfort or concerns on the
part of both internal and external stakeholders about this
process, a lot of it is based on just not having enough
experience with enough diverse plant performance issues to
be able to really feel fully comfortable with it.
And that's what we hope this initial
implementation phase will do; it will allow us to gather
additional insights from a wider spectrum of plants and
different performance levels and performance issues, so that
we can fully exercise all aspects of the process.
Okay, what we'd like to do with respect to the
agenda, is spend most of the time hopefully talking about
the significance of termination process, and Alan and Doug
will take the lead on that.
I do have some discussions, hopefully at the end,
on some future initiatives, and perhaps update you a little
bit. There were some questions, for example, today, on
performance indicator thresholds.
And one of the things we've done over the past few
weeks is take a look at the historical information that we
gathered from all plants from the submittal in late January.
And that has allowed us to gain some further insights about
some of those thresholds.
And we have made some adjustments or plan on
making some adjustments to some of those thresholds on a
going-forward basis. So, hopefully at the end, we'll have
some time to talk about that.
Otherwise, unless there is any other further
question, I'd like to turn it over to Alan and to Doug to
start talking about the significance of the termination
process.
MR. MADISON: Good afternoon. This is a brief
overview of the significance of the termination process.
And as has been mentioned before, it's really not just one
process; it's multiple processes.
And I'm sure we'll get to the details that are of
interest to you, based upon your questions.
But just to review, the principal objective of the
significance determination process was first in characterize
the significance of findings, to provide a relatively simple
tool to provide to inspectors so that they could make an
approximation within an order of magnitude of the
significance of inspection findings.
We realize that we've said before that it is more
difficult than the processes they've used in the past, from
their engineer expertise to determine what the significance
of characterizing a finding, but it's not quite as difficult
as doing a PRA analysis.
There are some shortcuts and we can discuss some
of those if you wish. But it uses similar risk metrics to
what were used to determine the thresholds the performance
indicators.
And therefore we have a way of correlating the
significance of inspection findings to crossing the
threshold in the performance indicators.
DR. WALLIS: I don't quite understand. What
metric are you using? The PI seems to me to be in different
plane from the usual risk metrics.
MR. MADISON: For the yellow, the white/yellow,
and the yellow/red thresholds on all the performance
indicators --
DR. WALLIS: There is a PRA.
MR. MADISON: -- are set at Delta CDF, the metric
for --
DR. WALLIS: The green/white?
MR. MADISON: The green/white threshold is set at,
as we've talked about in the past, to identify outliers.
However, we've done just a gross check to make sure that we
are within the vicinity of a threshold of 10 to the minus
six, and we're still pretty close there.
DR. WALLIS: Ten to the minus five in Appendix H.
It's not ten to the minus six?
MR. MADISON: Ten to the minus five is your
white/yellow.
DR. WALLIS: But that's what it says in Appendix
H.
DR. SHACK: It's a typo.
DR. WALLIS: It's a typo? Because I have been
puzzled by that/
MR. MADISON: It must be a typo if it actually
says that in Appendix H, because the intent was 10 to the
minus five for the white/yellow, and --
DR. WALLIS: It also says for white/green, which
really puzzled me, because it's the same number. Anyway --
MR. MADISON: It was meant to be 10 to the minus
six. Now, of course, that's not possible with some of the
non-reactor thresholds, because you don't have as clear a
correlation to risk as you do with the reactor safety.
DR. WALLIS: I think you really need to clarify
this typo, if it is a typo.
MR. MADISON: That should be clarified with the
new information that we have out on the significance
determination process. And it also will be incorporated
into the procedures that have been written to describe the
significance determination process.
CHAIRMAN POWERS: In your viewgraph, you say with
similar risk metrics. Does that mean that there is no
significance in the determination process associated with
findings in connection with security and safeguards?
MR. MADISON: I'm afraid I don't understand the
question. We have a significance determination process for
safeguards issues that uses relative risk, and then goes
into the reactor safety SDP to actually correlate it to
change in core damage frequency.
CHAIRMAN POWERS: But we don't have any --
MR. MADISON: But in the inspection finding arena,
we have what we think are relative significance in a
qualitative manner from one inspection finding to another.
If you have an inspection finding in the reactor safety
arena and a white inspection finding in the safeguards area,
they should have the same qualitative significance.
And we have tested that through doing feasibility
reviews on each of these where we have involved the staff,
as well as industry.
CHAIRMAN POWERS: But I have not seen something
that tells me here's how I think I got to the idea that this
white finding in the safeguards area is relatively the same
as this white finding in initiators.
MR. MADISON: And that's because we haven't
written about it yet. You haven't read that part, but we've
done that, in doing, as I mentioned, feasibility reviews on
each of the significance determination processes.
And the one on the safeguards significance
determination process was just recently completed, so that
report is not out.
But that was the objective, and actually that was
one of the clear criticisms that we received in the
lessons-learned meeting on the week of January 10th; is that
that wasn't transparent to industry or to the public, that
there was that correlation; that a white or red finding in
safeguards was the same in EP as it was in reactor safety.
And so we tried to make that correlation clear,
and by doing the feasibility reviews on each of those, we've
tried to validate that, that that is, indeed, the case.
CHAIRMAN POWERS: It remains obscure to me.
DR. SHACK: What is the basis for that? It's an
expert opinion thing? You get a bunch of industry people
and NRC people in?
MR. MADISON: With the exception of when you go
beyond white in the safeguards area, and when you go from
the fire protection. Those both feed into the reactor
safety SDP, and so there is a clear tie to each of those.
I didn't bring the diagram. I don't know if you
have the diagrams for the new, but they are in, I think
they're in the document, the new SDPs for both safeguards
and fire protection.
They clearly feed directly into the reactor safety
SDPs, so that if there is areas of concern or issues of
concern, the issue is characterized finally through the
reactor safety SDP. So you get the same tie, the same equal
tie there.
CHAIRMAN POWERS: I have a document that described
the SDP, and, in particular, for fire. Has that changed?
MR. DEAN: Yes. We're developing, as part of the
guidance documents that we're developing for implementing
this program, we're developing an inspection manual chapter
on the significance determination process which will provide
all the information associated with all of the various
processes that we use for determining significance.
And it will incorporate all of the lessons learned
and revisions that have been taking place over the last
several months as we've refined those based on lessons
learned.
And the fire protection one is one that we have
tested out, as a matter of fact, over the last several
months. We've had a couple of issues at several plants that
have allowed us to gain some insights, as well as in the
meeting we had February 15th and 16th with NRC and industry
to talk about fire protection.
So we're in the process of revising that.
MR. MADISON: I can tell you the major changes on
the fire protection SDP. We tried to clarify that that was
a feed into the reactor safety SDP.
The output of the fire protection SDP goes into
the reactor safety SDP. That was one change. I wasn't
clear. That was the intent all along, but I wasn't very
clear in the procedure.
And there -- what we also tried to do is show that
the input to that SDP should be the same as the input to any
other SDP. Whatever comes out of the Guidance in 0610* as
far as describing the threshold for findings.
CHAIRMAN POWERS: Let me exercise memory a little
bit on what that SDP process is. I have to go in and make
an assessment on whether the degradation in the fire
suppression capability, both manual and hardware-wise, has
been degraded significantly, a medium amount, or not very
much.
And from that I derive a parameter. Is there
something that tells me what a lot of degradation is versus
a medium amount of degradation, versus very little
degradation?
MR. MADISON: There are some concepts that are
incorporated in the training that the inspectors receive in
that area, yes.
And let me add this, too: That portion of the
procedures is actually to be used only during the triennial
inspection or by a fire protection safety engineer. The
screening portion of the tool is designed for the resident
staff and the normal inspector, Regional Inspector that
would go out to the site and identify small issues out at
the site.
So the expertise is available at the time when the
finding -- to come to that type of conclusion.
MR. DEAN: But I think to answer your question
more specifically in terms of criteria that say what is low,
medium, and high, that's one of the issues that we have
identified in using the significance determination process,
and that's one of the areas that we do have to improve in
terms of providing --
CHAIRMAN POWERS: It's totally capricious and
arbitrary right now.
MR. MADISON: It could be.
CHAIRMAN POWERS: And having done that, if I
succeed in doing that, I find I'm given a parameter. And I
take that number and I add it. It says to the frequency of
fires, but I think you really mean the logarithm to the
frequency of fires.
And where did that parameter come from?
MR. MADISON: From EPRI studies.
CHAIRMAN POWERS: EPRI studies? Okay, so this
comes out of five?
MR. MADISON: Yes.
CHAIRMAN POWERS: Ah, now I understand better,
thank you.
MR. MADISON: We had a long discussion over where
a lot of those numbers come from on the -- during the 15th
and 16th workshop with industry and the public.
And J.S. Hyslop was very good at describing that
and defending his terms to the point where industry was
accepting of the numbers that were in there, the relative
significance of those numbers, although they did express
concern about the age of those numbers, that some of those
numbers were quite old and that maybe new studies should be
done to update those numbers.
CHAIRMAN POWERS: You've got -- the industry funds
a research program attempting to better develop fire risk
assessment capabilities. Why don't you use that?
MR. MADISON: We took that as a point to look at.
There are a couple of phases. I guess part of what we
wanted to do was to try to describe, just basically, the
significance determination process as far as the phases of
the significance determination process.
And with that, I wanted to use the next slide. It
talks about Phase 1, 2, and 3 of the process.
Phase 1 is more of a screening device where the
issues that are identified by the inspector. And there are
some questions that the inspectors ask to clearly identify
or represent whether or not this is a very low
risk-significant finding, or does it have the potential be a
higher risk-significant finding?
If it doesn't have any potential to be a high risk
significance finding, then it is colored as green. It is
directed to the licensee's Corrective Action Program and
documented in the report. If it is, then it goes to the
Phase 2 screening, which is more complicated.
CHAIRMAN POWERS: Here's the step that I never
really could understand from the description of this
process. Suppose I have a finding that affects both the
containment barrier and the RCS barrier?
MR. MADISON: It automatically goes to a Phase 2
review. If it affects more than one cornerstone it
automatically goes to a Phase 2 review.
CHAIRMAN POWERS: Okay, so does it go through both
of these little flow paths here?
MR. MADISON: No, you go straight to the Phase 2
review or if it affects both the barrier -- we would look at
both of those, that's correct. We would look at all the
action scenarios and we would try to pick -- not try to, we
would pick the most conservative call.
CHAIRMAN POWERS: You might want to make that
clear in the documentation, because you make heavy use of
this kind of flow chart in the description of the
significance determination process. That is the one that
just hits you immediately is -- even some of your examples.
You even have an example in there, I think, where it affects
two or more cornerstones, and it doesn't tell me in the flow
chart what do I do.
MR. MADISON: You do both.
CHAIRMAN POWERS: You go through both?
MR. MADISON: You do both and you take the highest
call.
CHAIRMAN POWERS: I was pretty sure that you went
with the highest one, but it didn't say that.
DR. WALLIS: You say "we" -- who is "we" when you
say "We" do these things?
MR. MADISON: The inspector does this.
DR. WALLIS: The inspector does all of this?
MR. MADISON: The Phase 2 review is done by the
inspector. During the initial implementation phase there
will probably be necessary for the regional SRAs to help out
in some cases, although the inspectors have received
training on this.
DR. WALLIS: The inspector has enough knowledge to
run the PRA and make these --
MR. MADISON: Doesn't have to run a PRA --
DR. WALLIS: -- run the licensee's PRA?
MR. MADISON: The work sheets provide kind of a
quick method for him to estimate the risk --
CHAIRMAN POWERS: The prebuilt sheets are pretty
clear, I think.
MR. MADISON: It's plug and chug in a lot of
cases.
CHAIRMAN POWERS: Well, I think that overstates
it. I don't think it is plug and chug.
MR. COE: We don't want it to be plug and chug.
We want it to be a thinking process that entails the
accumulation of risk insights. That is what we want the
inspector to gain as well as an answer.
MR. SIEBER: Are these work sheets plant-specific?
MR. MADISON: Yes, they are. We were going to
talk about that in a little bit.
MR. SIEBER: That's the work sheets you have been
sending to plants --
MR. MADISON: That's correct.
MR. SIEBER: -- for right now.
DR. APOSTOLAKIS: What is the logic of the sheets
being plant-specific and the thresholds not?
MR. COE: The logic is that we are trying to
assess an affected accident sequence, what the remaining
capability is if you take away -- if you assume
automatically some of the capability is already removed
because of the problem that you found, so we have to judge
for that particular plant how many other mitigation systems
are needed to get to core damage that will remain for that
sequence, and that is how we try to determine --
MR. MADISON: And the sheets are going to walk you
through that.
MR. COE: And again it's a rough, it's an
approximation within an order of magnitude so we are not
drawing a bright line. The thresholds are not -- as you
said, they are a fuzzy line. They are not a bright line.
DR. APOSTOLAKIS: Well, this analysis is
plant-specific.
MR. MADISON: Pardon?
DR. APOSTOLAKIS: This analysis will be
plant-specific?
MR. MADISON: Yes, based upon plant-specific
information and within the limitations of what is
represented on the work sheets.
DR. APOSTOLAKIS: All right.
CHAIRMAN POWERS: One of the things I didn't
understand about the work sheets, I got the impression if we
were to look, say, 10 years from now that it might well be
that work sheets were actually made by the inspector
himself, rather than supplied. Is that the case?
MR. MADISON: That is not the intent, no.
DR. APOSTOLAKIS: Now if you have a model of the
plant that maybe comes from the IPE with some improvements
and so on, on the Sapphire code would that be an appropriate
model to run to see this, the remaining protection?
MR. COE: It could be, and we would hope that if
the SDP indicated that there was a potentially
risk-significant situation that had been identified that if
there was any value in doing those further detailed studies
we would want to do that, and we have set aside --
MR. MADISON: It's likely going to fall though
into the Phase 3 review and not necessarily in the Phase 2
review. The Phase 2 review is more to identify with a
conservative call whether or not there is significant risk
characteristics with an inspection finding, to then increase
the dialogue if necessary with the licensee.
DR. APOSTOLAKIS: Now my understanding is that one
of the national laboratories is working under your
sponsorship, not "your" -- this particular group -- but the
Agency sponsorship to put on Sapphire all the IPEs that have
been submitted to the Agency, so now if I have a Sapphire
model of the IPE of the plant, why can't I completely bypass
these sheets and go there and --
MR. MADISON: There's some advantages to having
these work sheets rather than just having just a computer
model where you do really plug and chug. You plug a number
in and it spits out a number. Doug will be one of the first
ones to tell you this. It actually forces the inspector to
thing about what is important at his site, what are the
important characteristics of that train and what are the
important components I should be worried about in that
train. It makes them stop and think about that and maybe go
look at those more frequently because that's where he is
going to find the most significant issues.
A computer program doesn't necessarily do that for
him. It is almost a training tool as well as a
calculational tool.
DR. APOSTOLAKIS: I think there is great value to
that. There is no question about it. You don't want just
to push a button and get a number out, but I think you can
also get similar information maybe by minimal modification
of the existing software.
MR. DEAN: Yes. I mean that's a good point and we
have had that discussion almost from Day One about
computerizing the model. I think one of the things that we
feel is important about the significance determination
process is that in order to utilize it the inspector has to
make some assumptions about things.
This process clearly calls out what those
assumptions are, gets those out on the table, so that the
NRC and the licensee can discuss the appropriateness of
those assumptions and whether they really are applicable or
not, and that is the real strength of this process.
CHAIRMAN POWERS: That comes across very well on
your documentation.
DR. APOSTOLAKIS: I have no -- I don't object to
any of this. It's just that we have bad experience in other
situations where methods were developed for a quick and
convenient calculation and then they took a life on their
own. The precursor analysis -- there was a period of time
when it was advertised as being an alternative to PRA. I
don't think anybody in his right mind would say that now.
MR. MADISON: We have been very cautious. There
was an early attempt to utilize the SDP, by industry to
utilize the SDP to prioritize maintenance, and we said no,
stop doing that, that is not the intent, and we have said
and we have made it very clear to industry that its only
intent is as a tool for inspectors to characterize
inspection findings.
DR. APOSTOLAKIS: I think that if there is hope
that in the future, in the near future, these computerized
IPEs will play an increasing role in this, I think that will
be a good development.
MR. MADISON: I think they already are in some of
the other aspects of the program too. If you have read the
discussion about event response, we initially looked at
utilizing the SDP to characterize events. During our
feasibility review we came to the conclusion that that was
not appropriate, that there were better tools to do that
characterization and they were available to the SRAs, to the
regions, and they should use those tools, not the SDP.
The SDP was still the right tool to use for
characterizing inspection findings, but we thought using the
models, the Gem model, the Sapphire, were more appropriate
for characterizing events.
DR. WALLIS: Does Sapphire come in at Phase 3
here?
MR. MADISON: The Sapphire may come in in Phase 3.
DR. WALLIS: Phase 3 starts after "Yes" -- that's
not that clear from your --
MR. MADISON: I beg your pardon?
DR. WALLIS: Phase 3 starts --
MR. MADISON: Phase 3 is you have made a
determination out of the Phase 2 --
DR. WALLIS: It starts at "Yes."
MR. MADISON: Yes, that's correct. You have a
determination out of Phase 2 that you have a white, yellow
or a red finding, and then you go into the Phase 3. Now I
said that it increases the communication between the
licensee and the inspector, because all along during Phase 2
there should have been communication about what are my
assumptions, what are the things that I am considering, what
was the condition of this piece of equipment in your
estimation at the time of the evaluation.
One of the other objectives, major objectives, of
the tool is it's a communications tool. As Bill said, we
lay out on the work sheets and on the report what our
assumptions are, what are the considerations we are making
during the analysis of the issue.
That's all out in the open. That's all part of
the discussion with the licensee, and it is information the
public and other stakeholders have to evaluate our work
doing the SDP.
DR. SHACK: You take that you miss programmatic
failures. You know, if I have a valve failure because I
have a bad maintenance program, but the valve itself is not
very important, I am going to end up green. But the fact
that I have a problem with my valve maintenance program may
well be significant. Do I miss that with this process?
DR. BONACA: I had a question, in fact, that I
posed last time and I don't see a change here, so I was
wondering if you are considering it, which goes in the
direction, which is, do you have a repeat event that may not
make it to Phase 2, but may be significant in and of itself
because it indicates something? For example, say that you
have two events, or three events, they may something about
the maintenance program or something else that may be
significant just because -- not because you meet some kind
of risk criterion in and of itself, but the repeat event in
and of itself has a significance.
MR. DEAN: Yes. And what you are talking about,
and there was some discussion of this this morning with the
Commission and your presentation in terms of corrective
action programs, or what we have characterized as the
cross-cutting area of problem identification and resolution.
And one of the reasons why we have embedded into the
oversight process, to the baseline inspection program a
substantial element of looking at the licensee's problem
identification and resolution performance, and that
incorporates in each inspectable area some element of that
effort should be looking at licensee's efforts and problem
identification and resolution, as well what we have right
now, which is an annual inspection to look at problem
identification and resolution activities, with the annual
inspection probably focusing more on corrective action,
extent of condition type activities.
Whereas, in the inspectable areas, you are
probably looking more at, how well is the licensee doing
problem identification? Are they identifying issue in that
particular area and getting those in a corrective action
program.
DR. BONACA: You see, I think that this belongs
right here. You have a box with corrective action program
there. If your corrective action program cannot deal with
events that repeat themselves time and time again, this
reliance on the box becomes meaningless. I mean you have a
chart here. I would like to see inspection issue involved
in the condition, the first box. Does the issue clearly --
and you have a "yes" down. The next question is -- is this
a repeat finding?
MR. DEAN: Yes. And what I was going to get is
one of the elements of the annual inspection is to look at,
for example, what has been in the licensee's corrective
action program and in addition to what we have see through
our inspection findings over the course of the previous year
or so in terms of what sort of issues have emerged that have
been characterized with some significance. You know, green
issues are not good issues, they are issues of very low but
some risk significance.
Do we see any patterns or trends? That is one of
the purposes of doing that annual inspection is to look for
patterns and trends and to look at see what the licensee is
doing in terms of evaluating the body of information in
their corrective action program to see if they indeed
recognize if there is any patterns or trends.
DR. BONACA: But this is the Significance
Determination Process. Anything which is not identified in
the Significance Determination Process is, by definition,
not significant, it seems to me. I mean, to me, in a risk
analysis scenario, although it may not be quantifiable,
repeat events have significance. Okay.
We may not be able to quantify them. But the fact
that you have, you know, misalignment after misalignment
after misalignment is significant issue from a risk
standpoint.
MR. DEAN: And we would believe that if you have
misalignment after misalignment, then you are talking about
impacting things like safety system availability. You are
going to have unplanned availabilities.
DR. BONACA: Other systems.
MR. DEAN: And, so, a basic premise of this
program is that if you see programmatic breakdowns in areas
like valve maintenance or things like that, then they will
evince themselves in either issues that will be captured
through increasing trends in the performance indicators, or
we will come up with a number of inspection findings, some
of which may trip a risk significance threshold, or which
there may be an accumulation over time that would cause us
to identify a trend or pattern.
And, so, you know, this --
MR. MADISON: The finding is still identified as
green. It is still identified, it is documented in a report
and it is required to be addressed by the licensee's
corrective action program.
But I will say this, this is something we are
watching closely during initial implementation. We have a
working group set up to look at the problem identification
resolution, actually, all cross-cutting issues, but focus
first on problem identification resolution issues. And we
will be looking at this and making sure that the initial
assumptions we are making with the program, the premises of
the program, are valid.
DR. BONACA: Yes.
DR. SHACK: That is the majority conclusion that
that hasn't been tested yet.
MR. DEAN: That's correct.
DR. BONACA: Yes. And, again, I suggest you look
at this fact because this says, this is the safety
Significance Determination Process.
MR. DEAN: Yes.
DR. BONACA: And, so, I think you have to look at
all the aspects, because, by definition, since you have put
the definition here, that is -- you know, anything which is
not here is not being considered.
MR. DEAN: I guess not to be too much longer on,
you know, repeat issues, you know, in our enforcement
process, under the current oversight program, you know, that
is one of the things that we look at, but that is something
that we also struggle over. You know, what is the time
period between one issue occurring and another issue
occurring that that really is a repeat issue? And are there
different aspects about the issue that really it is a
different element that caused this issue to occur?
And, so, that is an issue that we struggle over a
lot in the current process in determining, you know, is this
really a repeat issue or not?
DR. POWERS: Did I get an answer to Dr. Shack's
question about, do you catch programmatic failures?
MR. DEAN: Well, I guess in kind of a long-winded
way. I think what we tried to get across was that we
believe that if there are programmatic issues that affect
equipment or activities of risk import, that you should see
that over time evince itself in thresholds being crossed.
Now, is this something that has been proven out?
It hasn't. I think it is something that we certainly
recognize in the Commission paper, that this is something
that, you know, time will really tell, and is one of the
motivators really for getting into initial implementation
and getting more plants involved so that we can hopefully
prove out the theorem that we believe that this process has
embedded in it, that we will see those programmatic issues
emerge and thresholds being crossed and significant issues.
MR. MADISON: But his question was, do you miss
the programmatic findings? No, you don't miss the
programmatic findings because the programmatic findings have
an impact. They can be measured through the SDP and if they
come -- they will come out at least green, if they get into
the SDP. And, again, they are documented, they are
identified and they are required to be corrected by the
licensee.
We are, as we mentioned earlier, the process
relies on the site -- the reactor safety process relies on
site-specific work sheets, and they are being developed for
each of the plants. As you mentioned, we will be mailing
them out to the sites.
We are planning on making visits out to each site,
and the SRAs from the Region will also be supporting Doug,
and others from headquarters will be going out to each site
and validating that the information is correct, because the
information originally was based on old IPE submittals and
there may have been some major changes. But it would have
to be a fairly significant change to the facility because of
the conservative and the fairly simple nature that the work
sheets do. So if they added a diesel generator that wasn't
incorporated into the program, then we will have to make a
change to the work sheet.
DR. POWERS: Yeah, that would change the work
sheet. Yes.
MR. MADISON: And we will do that. We actually
have learned some good insights in going out and doing this
during the pilot. We found out some non-conservative calls
we were making with regard to turbine-driven pumps versus
electrical driven and we made some changes to the program
based upon that review. So it has been a real good review.
DR. POWERS: If I was real nice, maybe didn't ask
any more questions, could I get the copy of the work sheets
for Davis-Besse.
MR. SIEBER: It is in ADAMS, I saw it.
MR. MADISON: It should be no problem.
DR. POWERS: That is the question I asked, I asked
could I get a copy of it.
[Laughter.]
MR. MADISON: Yes. You will get a copy. Anybody
else?
DR. UHRIG: Do you have training?
MR. MADISON: We do have a course for the
inspectors that we are training them on called G-200 that
talks about the entire process, but it focuses at least a
full day on the Significance Determination Process where
they do examples of both BWRs and PWRs, some actual examples
from the field.
DR. POWERS: I would think, having looked at your
example sheets, that if I were an inspector I would be
pretty enthusiastic about those sheets. Is that -- have you
got in --
MR. COE: Initially, there was some, you know,
kind of the initial shock of, oh, gosh, I have got to figure
out this whole new system. But we found I think that after
they do a few examples, they begin to see how it all comes
together, it becomes an interesting tool that really allows
them not only to get an answer but to see the relative
influence of the various assumptions that they make, and the
influence of changing those assumptions.
DR. POWERS: Yes, I think that certainly comes
across nicely in your documentation. That is one thing you
don't need to change in the documentation, just what you
say. Laying the assumptions down and seeing that they have
an influence on the answer you get was nicely done.
MR. COE: Right.
MR. MADISON: Again, I mentioned this earlier, I
just want to highlight it again, we have done -- we did a
feasibility review on the initial development of the SDP,
that was documented in 007A. But we have since done a
second feasibility review that was tied to the event
response on the reactor safety SDP, that is documented in
049 that you have before you.
We have done feasibility reviews on all of the
SDPs, which have involved our staff running through real
examples from the field, in some cases with, for example,
the safeguards SDP, as many as 30 or 40 examples that were
run concurrent with staff and industry to make sure that we
were coming out with a similar answer, at least understood
where our differences if we came out with difference
answers. We feel fairly comfortable that was a good test at
least at the beginning of the process for each of the SDPs.
Ongoing work, as I mentioned earlier, we need to
continue to do the site visits to make sure that we have
consistent application of the work sheets.
There we go. We expect to continue work on those
through May of this year to try and complete those. We are
getting them in a little slower than we had expected from
our contractor but we are mailing them out to the licensees
as soon as possible and then to our Staff so that they get
them right away and then we will follow up with site visits
and try to complete those.
We have developed a containment significance
determination process that we feel at least at first blush
after the first read looks pretty good. It is tied to a
change in LERF, delta LERF, and then ties back into the
reactor safety SDP, the existing one.
We expect to do a feasibility review of that with
the Staff at least the week of the 13th of March.
We have a shutdown screening tool that also seems
to show promise and we are going to try to do a feasibility
review of that the same week. We think both of those should
be ready to run some time early in April, to actually
implement into the new process and watch them closely again
as we are with this whole process, but those especially.
One of the lessons learned that came out of the
workshop, the January 10th workshop and actually before,
through the pilot program, was that external events weren't
well taken care of within the significance determination
process. As sort of a stopgap measure we're developing an
external events screening tool to look for where external
events may be a significant impact at individual sites and
to flag those sites then for extra effort by the SRAs and
Headquarters staff when issues are identified there to
ensure that external events didn't play a large part in that
issue.
CHAIRMAN POWERS: When you use the term "external
events" here, are you distinguishing them from fire events?
DR. BONACA: No.
MR. MADISON: No.
CHAIRMAN POWERS: So fire events are included?
MR. MADISON: Fire events are considered an
external event.
CHAIRMAN POWERS: Think they are a peculiarity to
a site?
MR. MADISON: Yes -- to the best of our knowledge
they are. Again, this is something we are looking at. We
are going to continue the process of developing corrections,
necessary corrections to all the SDPs to incorporate these
lessons of external events issues into all the SDPs but that
is going to be some time beyond April.
With that, we get into the changes that we have
made, if there aren't any other questions on the SDP.
CHAIRMAN POWERS: I would like to go back and have
a little better understanding of Phase 3.
MR. MADISON: Okay.
CHAIRMAN POWERS: My irreverent characterization
is that is where we find out why the industry thinks you're
wrong.
MR. MADISON: That's true. That's a good analogy.
DR. BONACA: You put the gloves on.
MR. MADISON: We told them, we laid it out for
them with the Phase 2. We put it in the inspection report
that this finding has, we think, a significance of white or
greater. These are the assumptions we have made. This is
why we think it is significant.
We offer the licensee the opportunity to either
send us information or come to a regulatory conference and
give us the information. In some cases we feel that there
may be a need that we'll request information because we
don't have enough information to make that final
determination and that will be part of the Phase 3.
Once we take that information in and understand
where their objections are, where their differences lie, we
make the final call on what we figure the significance of
the finding is, and again I revert back to what I said
earlier. It is not a bright line. It gets more into the
qualitative area of what do we think the significance is
based upon the best available information we have, including
that provided by the licensee.
MR. SIEBER: Now --
DR. SEALE: Go ahead.
MR. SIEBER: There is a subjective part that goes
into that by the regional administrator, the regional staff,
is that true or not?
MR. COE: That's true.
MR. SIEBER: What factors do they take into
account that would alter the quantitative outcome of all of
this?
MR. COE: I wouldn't necessarily say it's
subjective. I would say that this process does not obviate
the need for judgments to be made.
MR. SIEBER: That's better --
MR. COE: But what it does do, it forces the Staff
and it obligates the Staff to make those judgments clear so
their effect and influence is obvious as to how it did
influence the outcome.
If they were to deviate from the process, they
would have to document why they deviated from the process.
MR. SIEBER: Nonetheless they have the authority
to deviate from the process.
MR. MADISON: Certainly.
MR. COE: With justification.
MR. MADISON: With justification, but we also
during at least the initial part of, the first year of
implementation as we did during the pilot we have an
oversight group that includes Doug and myself and others
that we collect this information.
The information comes in from the field on what
the Phase 2 review found, and we provide kind of that
consistency monitor to make sure they have applied the
process correctly and we would have come to a similar
determination based upon the assumptions they made.
MR. SIEBER: And that is done before the
imposition of civil penalty or whatever else?
MR. MADISON: Well, there is no civil penalty with
the new process on things that go through the SDP, but yes,
it is done before it is actually documented in the report.
DR. SEALE: In your first year of piloting,
adjusting, and so on, are you going to essentially do
sensitivity studies by toggling the yes/no determination at
the end of Phase 2?
MR. DEAN: Well, I'm not sure. One of the things
we did in during the pilot program is we did an independent
review of all the issues that were identified by the regions
that were classified as at least green by the significance
determination process and did an independent assessment with
risk analysts to ascertain whether they would have come to a
different judgment.
I believe in all cases they said that they made
the right call. I think they felt that one of the regions
might have been too aggressive in one case, that they
wouldn't have even classified the issue as green, but that
is the result of I forget how many issues, Doug, sixty or
seventy issues?
MR. COE: The pilot total was about 99 issues,
total, in the pilot.
DR. SEALE: Well, you'd expect about one out of
that, but that's a call within your flexibility as this
review group too, isn't it? I mean if you see one where you
would like to see what happens if you took it to Phase 3 you
could ask for that?
MR. MADISON: That's true.
MR. COE: Yes.
MR. MADISON: And these oversight panel reviews
are fairly challenging. The individual has to come fully
loaded to discuss the issue at the oversight panel. We have
tied that now to enforcement actions, to the enforcement
panel, so it directly flows from the oversight of the SDP
into what are the enforcement aspects of that.
CHAIRMAN POWERS: If I am a licensee and you guys
have got a finding that says I have a fault right down in my
security and safeguards area, okay? You have got your
little work sheets and you told me just how we came out, and
I said, no, you're wrong. I have run the conflict code on
this particular incident and I find out there's only a delta
risk of loss of material of 10 to the minus 6th here. What
do you do?
MR. MADISON: I don't understand what the conflict
code is --
CHAIRMAN POWERS: Oh, that's because you haven't
read the literature on safeguards and security.
MR. MADISON: Probably -- I don't have a high
enough security clearance, I guess, but we as the NRC, based
upon the -- you know, we will have to look at our procedures
to see if there is any fatal flaw based upon that
information, but we as the NRC retain the right to make the
final call. That is our job.
But I think the first question we have to ask is
what is the basis for this result out of this conflict code,
what are the modeling assumptions, and the assumptions we
have made in our model -- how do they compare to ours.
CHAIRMAN POWERS: I could point you to 16 papers
in the literature of facility defense that says the conflict
code validated, works well, boy, this is a great code.
MR. COE: But that doesn't answer the question. I
think it's going to be the burden of the licensee in a case
like that to come forward and say we understand how your SDP
arrived at your answer but our answer is different for the
following valid reasons, and item by item convince us that
there is an alternative perspective that should supersede
our own.
MR. MADISON: One of the other reasons for doing
the feasibility reviews besides to verify that we were on
the right path with the SDPs was to ensure that industry was
on the same path and was on the same page with us, and
industry has agreed that these are the right significance
determination processes, that they come up with answers that
they can agree to.
We have identified issues that have significance
and they have agreed to the significance if characterized
appropriately.
MR. GILLESPIE: Alan, something that we also have
to keep in mind: Independent of what this grades it as,
compliance is still required. If they're in deliberate
noncompliance because they don't think it's important, that
throws us into an whole other avenue.
And you're outside this system, and now you're in
wrongdoings space. So there are other boundary conditions
that are fixed. So the idea that someone can have a totally
generation of security, and have it be a red, would be -- I
think that would be actually difficult to occur, unless it
was connected with some weird kind of event that both killed
all the guards they need for compensatory measures and
destroyed all the barriers and detection systems.
I mean, I'm not being -- it's just, you know,
probably unrealistic to think we could actually have a red
in security, quite honestly, without having seen something
earlier.
MR. MADISON: A red in security, unless you can
show a change of core damage frequency through the reactor
safety SDP, the highest defining security is going to
achieve is white.
CHAIRMAN POWERS: I understand that.
MR. MADISON: As far as significance within --
CHAIRMAN POWERS: I took security as an example,
because I wanted to understand what happens if the licensee
comes into this Phase III with superior technology to what
you have.
MR. MADISON: Well, I can relate to the case of
the Sequoia findings. The licensee continued to try to
bring in additional information, additional analyses, and in
some cases, new analyses, to prove their case.
We still took the position that based upon the
information that we had at the time, that we were making the
right call through the SDP.
MR. COE: It would be their burden to demonstrate.
You made the comment that the premise was that they had
superior technology. And I guess what that means is, a more
refined view, a better basis, more detail, et cetera, that
sort of thing.
And it would be incumbent upon them to demonstrate
to us why that is and why we should utilize those
assumptions, versus our own assumptions.
We have to be careful to be clear that anytime the
licensee comes forward to bring us information that would
influence a regulatory decisionmaking process, it needs to
be docketed up front, on the table, publicly available, and
in some cases, when they're talking about sophisticated
analyses, reviewed to some level of detail by our own staff.
So in many cases, I think we're going to find that
it may be that the effort, both their's and ours, to resolve
the question of are we white or green, may be far beyond the
effort needed to fix and for us to verify whatever problem
it is.
MR. MADISON: Absolutely. That was the point we
were trying to make to Sequoia, that they probably spent
$100,000 responding to that issue that would have cost them
14 hours of inspection. And they had already fixed the
problem.
And the other aspect of that is, too -- and this
is why, again, we're not drawing a bright line -- we see no
difference in the significance determination process between
.9 and 1.1. It's the same number as far as we're concerned,
because it has the same relative significance.
MR. DEAN: I think that over time people will come
to appreciate the sensitivity. We have been trying to
promote the fact that a green issue is not a good issue, but
by the same token, a white issue is not the end of the
world.
And so I think that over time, as we get more of
these issues emerging, and these things play out, I think,
overall, both internally and externally, there will be a
greater understanding of what the various colors mean in
terms of risk import, and what it entails in terms of what
the NRC's reaction is going to be.
MR. MADISON: We do have some new information for
you. As we promised, we are going to look at the
performance indicator thresholds, based upon the historical
information submitted to us January 21st.
We have made some adjustments to some thresholds.
I don't know if you want to talk about that.
MR. DEAN: Yes. First of all, this is a result of
ongoing analysis. We took the opportunity with the
historical data submittal in January from all the licensees
to take a look at the validity, if you will, of some of the
thresholds that we had established on a going-forward basis
for the pilot.
I want to really emphasize the fact that if you go
back and look at SECY 99-007, where we talk about
performance indicator thresholds, we were very clear in that
document that these thresholds would be something that we
would be looking at through the pilot program, and we would
gather more information, and there would be some need to
refine these thresholds on a going-forward basis, and not
that we're going to, on an ongoing basis, every year, look
at these thresholds as industry improved performance and
continue to move the thresholds upward and upward.
Okay, but it is to establish at least on a
going-forward basis, for initial implementation of this
program, an adequate set of thresholds that do, indeed, meet
the stated goals, at least at the green/white threshold with
respect to identifying George's favorite issue, the 95
percentile deviation from nominal industry performance.
DR. WALLIS: Was the criterion for moving these,
the 95 percent or was it a risk-based criterion?
MR. MADISON: It was primarily an analysis done of
how many outliers we would have identified, dependent upon
the threshold set. In several cases, for example, the
scrams with loss of normal heat removal, had we left the
threshold at four, no licensee would have been identified
over a three-year period, to have crossed that threshold.
DR. WALLIS: So you wanted five out of 100.
MR. MADISON: A rough number of five. Again, you
know, seven is okay; three is also okay, some rough number
of five, an approximation of identifying the significant
outliers of performance, significant deviation from nominal.
DR. WALLIS: Well, it doesn't imply any kind of
risk evaluation whatever.
MR. MADISON: Again, we looked at that earlier,
and we felt that we were close with a 10 to the minus six,
and that was -- again provided significant safety margin.
DR. WALLIS: That was a small sample. The 10 to
the minus six was not everybody, so you may be really
unfairly treating some plant. We've said this before.
MR. MADISON: Yes, you said this before, but
again, we felt there is significant safety margin at the
green/white threshold that we have.
What we're trying to identify at the green/white
threshold are those licensees whose performance has slipped
to the point where we need to get more engaged. We felt
that was the right type of threshold, a set, of those
outliers, those folks that are deviating from nominal
performance. Those are the ones we want to focus our
attention on.
CHAIRMAN POWERS: A couple of questions come to
mind on this: Is there going to be at some time, a document
where I can go in and look at it and say, okay, here's the
database that they looked at and here's why they came up
with two. I mean, I could do the statistics myself or
something like that?
MR. MADISON: We've answered this question before,
because you have asked it before, and, yes. We have to
write that document. But, yes, that is in the plan to
document that during the coming year.
MR. DEAN: We will borrow, for example, from
Appendix H of SECY 9007 that goes into a lot of discussion
about.
CHAIRMAN POWERS: I hope you do it better than
they do, because I can't follow their logic in there. But I
see the numbers.
MR. MADISON: Maybe the same author, but we'll
make an attempt to do a better job with it.
CHAIRMAN POWERS: Let me ask one other question
about this: Everybody has concluded that somebody has
crossed the green/white threshold. And you say, okay, we've
got to get more engaged.
And so that means that you come to somebody and
say, okay, I need more resources and more manpower to go
look at Oconee, not more than we planned at the beginning of
the year.
And he says, guys, you can't do it; I've got my
money out, already done; you're going to have to wait till
next year, but we'll sure enough put it in the budget for
next yea and you're up.
MR. BARTON: That's not going to happen.
CHAIRMAN POWERS: The question is, are we
confident that the gear up to get more engaged, occurs
sufficiently quickly that what crossed the green/white
threshold will not have crossed the white/yellow threshold
by the time we get there?
MR. DEAN: That's a good question and let me take
a first crack at it, and then Alan or Doug can jump in.
I guess to real briefly talk about what the
supplemental inspection approach is for additional
inspection when a threshold is crossed -- and let's go
through a performance indicator. We get -- let's take --
we're going to get a report April 21st, okay?
The industry is going to give us their input from
the first quarter of 2000, and we'll get that April 21st.
It will take us about a week to get that so we can see what
it say.
We say, okay, we've got this plant here that's
crossed the threshold. Okay? Now, let's look at why is it
that they crossed the threshold?
Is it something simple like, well, gee, last
quarter, they had two additional scrams, okay? Well, that's
a pretty easy one.
Or you may have something that's a little bit
more, a safety system unavailability where you've got to
look at why was it unavailable?
But the purpose of supplemental inspection as you
cross from green to white is to allow the licensee to do
their root cause evaluation, root cause review, and then go
in and look and say does what you did make sense? Did it
appear that you did the appropriate extended conditions
reviews?
It's basically for us to go in there and follow in
behind them. So there may be some time period there from
the time that that PI cross the threshold, before it's the
appropriate time for us to do our followup inspection.
If you were to then cross a threshold from white
to yellow, the supplemental inspection there requires us to
be involved in more of an independent diagnostic approach.
So in that case, you would probably see us engage
a lot more quickly to capture information as to why was that
threshold crossed, and do more of an independent review of
why it is you are where you are in that stage.
So, do we have the case where we could shift
quickly from green to white to yellow over the course of a
couple months? I don't think so, unless you have a
situation where you have, for example, an important piece of
safety equipment that's out for a large period of time.
And that would have been something that would have
gotten our attention and the licensee's attention pretty
quickly anyway. So, Alan?
MR. MADISON: There are other aspects of the
program, too, that would respond to significant conditions
or events on an real-time basis.
But I think the strength of the program is that
you don't have to guess about what we're going to do; we're
telling you what we're going to do in the action matrix,
based upon inputs.
I think if the stakeholders, the public being the
one that we're driving that at, sees that we're not
following our processes, they're going to call us on that.
We have to justify why we've deviated from our processes.
CHAIRMAN POWERS: I think the take-home lesson I
get is that it's entirely possible that before you get more
heavily engaged, it could be for -- continued deterioration
of performance. But you don't think so? You think that
would be really unusual? I guess I'm content to think that
probably it would be.
MR. MADISON: I wanted to highlight some of the
other PI thresholds. The reasons why we changed them are
pretty much the same in doing the review.
But I wanted to mention that the safety system
unavailability performance indicators, we've reverted back
to what we initially proposed in SECY 99-007.
Now, we had initially changed those during the
pilot program to take into account, the two-week allowed
outage time on EAC that some licensees have. And that's why
we changed that from 2 to 3.8. That took into account and
allowed outage time considerations.
We'd also changed some of the other PIs to greater
than -- to being two, because of industry goals that had
been established by INPO and others being at that two level.
And the ones that we had initially proposed were tighter.
We ran -- we agreed to run those through the pilot
program and test it out. In looking at the pilot program
data, and looking at the January 21st historical data, we
find that the numbers that we had originally selected were
more accurate representations of what actual performance was
during that time period, and we have decided to go back to
those numbers and implement those for initial
implementation.
DR. APOSTOLAKIS: I have a question, Alan. The
number of scrams that you will use to enter the
determination process is over what period? What period of
time?
MR. MADISON: Which one, the normal scram? It's
for 7,000 critical hours. It's basically one year of
operation. This one is over a three-year period.
DR. APOSTOLAKIS: Over a three-year period, so are
you observing, say, three above the limit, the new limit?
MR. MADISON: Yes, greater than two scrams,
complicated scrams, loss of normal heat removal.
DR. APOSTOLAKIS: Right. Now, for the safety
system unavailability, how many tests am I supposed to look
at and calculate?
MR. MADISON: This is measuring the unavailability
of that equipment over a one-year period.
DR. APOSTOLAKIS: Over one year?
MR. MADISON: Four quarters.
MR. DEAN: It's a three-year rolling average.
MR. MADISON: But it's a three-year rolling
average over a four-quarter period.
DR. APOSTOLAKIS: What does that mean?
MR. COE: It's not demand failures.
MR. MADISON: Yes. It's not demand failures.
It's not a reliability indicator.
DR. APOSTOLAKIS: What is it?
MR. MADISON: It's an unavailability indicator.
It measures the time the piece of equipment was out of
service for maintenance, or because it was broken or was
intentionally taken out of service for other reasons.
DR. WALLIS: A three-year rolling average takes a
long time to change if it's been very good and then begins
to go down.
MR. MADISON: I don't think that's a three-year
rolling average.
MR. COE: That's a one-year number.
DR. APOSTOLAKIS: It is a three-year rolling
average. Why don't you say it isn't in unavailability?
MR. MADISON: It's not a reliability number.
DR. APOSTOLAKIS: It's not available.
MR. COE: It's a one-year number. It's a
four-quarter rolling average, but you can get, if you have
old information -- one of the things that we found -- it's a
one-year rolling average.
MR. MADISON: One of the things we found was that
you had with design issues, though, you can really flavor
that PI and stay with it for a long time. And we've tried
to make some accommodation for that in the guidance, that if
a design issue, as far as measuring the unavailability time,
to make sure that that doesn't happen, and if it does
happen, to be able to remove that biasing if the event has
been on for at least four quarters and if the event -- or if
the number has been in there for at least four quarters and
has been corrected by the licensee, we've reviewed it and
agreed to the correction is adequate, and we'll allow them
to pull that number out of the calculation.
MR. DEAN: Don, Don Hickman, is there any
clarification on the SSU?
MR. HICKMAN: The safety system unavailability
indicator is the ratio of the total hours the system was
unavailable during the past 12 quarters.
MR. MADISON: Twelve quarters, yes.
MR. HICKMAN: Divided by the total hours it was
required during the past 12 quarters.
MR. MADISON: So it is three years.
MR. HICKMAN: It is a three-year average.
MR. MADISON: I'm mistaken then. But the
reliability number that you were talking about, the measure
of when it fails, that's something we are working on with
research to try to develop that.
DR. APOSTOLAKIS: But it's not included here.
MR. MADISON: It's not included. That's why we
include fault exposure time in this performance indicator,
so if -- and that's why, again, a design issue would have a
large impact on this performance indicator, because we would
count the fault exposure time all the way back to the day
one.
And also if you have an error that you have
discovered in between surveillance, you would count half the
time back to the last time it was known to have worked. If
we had a reliability number, we'd have an indicator that --
an unavailability number, we wouldn't have to worry about
fault exposure numbers.
DR. APOSTOLAKIS: I remember, again, the former
AEOD. I don't know their new title. They presented a nice
table where they had the unavailabilities of all sorts of
safety systems across the 103 units.
How do these numbers compare to those
unavailabilities?
MR. MADISON: I don't know. Don?
MR. HICKMAN: You are referring, I guess, to the
system performance studies that AEOD did? That's a good
point.
We've not really checked these against that. And
we should do that. I guess by way of sort of validating
their results, they made a lot of assumptions when they did
those studies, obviously.
DR. APOSTOLAKIS: They tell us that this is the
real world. I mean, they are based on data.
MR. HICKMAN: That's right.
DR. APOSTOLAKIS: And that's why you have been
perplexed all this time, Garrett. Why don't you use the
plant-specific numbers. There is a table that has all that
stuff.
MR. MADISON: Don actually worked with some of
those issues.
MR. PARRY: If you've looked at those numbers,
actually we've done some checking, okay? The HIPSI results
and the RIPSI results are pretty much consistent with these
thresholds; they don't vary that much.
DR. APOSTOLAKIS: If you come here with one
viewgraph that will have these distributions, and you will
support the argument that you have, I will have no problem.
I will buy you a beer, a coffee, whatever.
But you're always giving me this argument as an
afterthought.
MR. PARRY: No, no.
DR. APOSTOLAKIS: Yes.
MR. PARRY: No, we're not. You have to be a
little -- you have to think back a little bit, too, of we're
getting the data from the industry. The industry has
presented us the data that went into the determination of
the thresholds.
That's what we start with. That's how the program
is going. The AEOD results were a look over an extended
period. But that's not going to be updated all the time,
and the numbers are, as Don said, calculated in a slightly
different way.
They're more focused on PRA-type information than
the data that we get from the licensees.
DR. APOSTOLAKIS: What counts eventually is the
PRA documentation.
MR. PARRY: I agree.
DR. APOSTOLAKIS: You want to know what -- you
don't care whether it was a rolling average or if it was --
is it going to start or not? And these data that those guys
showed us, address that issue. They actually go one step
beyond.
I think they tend to support your argument that
you don't need an individual number for each plant.
MR. PARRY: I think they do.
DR. APOSTOLAKIS: But you have to do it right.
MR. HICKMAN: One thing to keep in mind is the
AEOD studies were done primarily with data from 1987 to
1993. A few went to '95, but most of them were to '93, and
we're looking at more recent data.
We should see some consistency, though, I guess,
some sort of relationship.
MR. MADISON: We'll take the criticism and we will
document the look in our rewrite of this.
DR. APOSTOLAKIS: Good. I will really appreciate
that. If you have picked up those reports, and you will see
that you will get a lot of support for what you are doing,
plus one member here will tend to be more quiet.
[Discussion off the record.]
MR. PARRY: Can I just add a comment here? I
think we'd also get support for these thresholds by looking
at the typical numbers that you find quoted in IPEs for
unavailabilities. They are not very far off these
unavailabilities.
DR. APOSTOLAKIS: The argument you're giving me
makes perfect sense to me.
MR. PARRY: Good.
DR. APOSTOLAKIS: It's just that I have to ask you
to get them. I don't understand that.
MR. MADISON: I want to also note the occupational
exposure control threshold. It's actually the measure also
changed. We had originally proposed a two-tiered type of PI
that would measure a three-year number and a one-year
number.
During the initial discussion with industry and
our folks, the feeling was that it was too complicated to do
it that way, and let's choose one. They chose the
three-year to test during the pilot. It wasn't very
satisfactory during the pilot, so we're using the one-year
going forward.
And that changes the threshold then from five and
three to two and one.
DR. APOSTOLAKIS: Right.
MR. MADISON: We have increased a couple of the
thresholds, relaxed a couple of thresholds.
If you look at unplanned power changes, safety
system functional failures for BWRs -- pardon me; I'm sorry
-- safety system functional failures and security equipment
performance index, we have actually loosened those.
That is, again, based upon going back and looking
at the actual data that we got in. We realized, for
example, in security equipment performance index, we did
capture a few more than we had intended.
The safety system functional failures captured
significantly more plants that we had intended to capture
with that threshold, so we have loosened those thresholds up
to, again, identify the real outliers, the folks that are
really deviating from nominal performance.
MR. DEAN: Okay, good. The last topic we wanted
to talk about is some of the things that we see. We talked
about the need for further refinements and improvements, and
this page here, this slide here talks about some of the
major things that we're going to be working on over the
course of the next year or so.
The first item there is develop additional
performance indicators, and this last discussion we had on
safety system unavailability, and the fact that we don't
have a reliability indicator, we feel that it would enhance
the program to have a reliability indicator.
It's one area that we identified quite some time
ago. We have engaged with the Office of Research to look at
developing a reliability indicator.
Another area here, the example I have here is
containment performance. We really don't have --
MR. BARTON: You eliminated that one, didn't you?
MR. MADISON: We eliminated the one that was
proposed.
MR. DEAN: Containment leakage.
MR. MADISON: It looked a --
MR. DEAN: Well, I'm sorry, that's true. The
containment leakage we have. The containment leakage
performance indicator was one that we deleted because it was
just fraught with issues that just made it very difficult to
get at consistent figure across the board.
CHAIRMAN POWERS: One of the people that I have to
report to reminded me that there is a third component to all
of this process, and he drew my attention to the corrective
action program.
Are you going to have performance indicators on
the corrective action program?
MR. MADISON: That's a good question. We do have
a working group looking at what we can do better in the
corrective action program, or if there is necessary
improvements we can make to the process based upon that.
We have advertised all along from the beginning
that that was an important component of this program. We
said that was a major portion of the baseline inspection.
Ten to 15 percent of all inspection activity out
at the site is done in the corrective action program. There
is a major inspection done on an annual basis at each site
that looks at the corrective action program on a rollup type
basis.
So we've always advertised that as a major
portion, a major component. We have relaxed our
documentation requirements to allow inspectors to make
qualitative judgments about the effectiveness of a
corrective action program, barring significant findings.
Even if they don't have significant findings, they
can make a qualitative judgment of the effectiveness of
corrective action programs during that annual review in the
report.
And we've also included consideration of that and
other cross-cutting issues in the assessment part of the
program where the assessment report on an annual basis, as
well, as the mid-cycle report, semiannually can look at
these issues and make qualitative judgments about the
effectiveness of the program in those areas.
CHAIRMAN POWERS: I'm surprised at your emphasis
on the qualitative nature. It seems to me, since I was in
the business of looking at DOE facilities, that one of the
first things we asked them was, you know, what was the
backlog in their equivalent of a corrective action program,
and how long was the average lifetime of an item in their
equivalent of a corrective action program?
It seems to me we have an intuitive feel for some
quantitative numbers here.
MR. DEAN: Yes, to build on where you're coming
from, Dr. Powers, is that one of the things that we
attempted to do early in this process was engage industry in
some discussion over what would be the criteria that we
would use to judge the effectiveness of a corrective action
program? And it dealt with things exactly like what you're
talking about: Size of backlog, timeliness of correcting
issues.
And so industry took that onboard, and actually
INPO volunteered to look at developing some criteria.
MR. BARTON: In fact, INPO has a standard out now
or a guide for self-assessment in corrective action
programs.
MR. DEAN: Right. That's a fairly high level
principle document.
MR. BARTON: It just came out.
MR. DEAN: Right. And that resulted, I think, a
lot from our discussions early on about what can we do to
establish criteria? As Alan mentions, that looks at
self-assessment/corrective action, but probably at a higher
threshold than to get after, perhaps, what an inspector
would be more interested in, in looking at the actual
effectiveness in dealing with some of those quantitative
type issues.
So, what we plan on doing is looking at taking on
this issue ourselves, and trying t establish some more
standardized criteria by which we can judge the
effectiveness of a corrective action program, and being able
to look at things like that.
As you mentioned, a number of licensees trend that
type of stuff already as a measure of their effectiveness.
So what we'll do is look at that and then work
with industry to try to come to some consensus as to what we
all agree are good criteria. Hopefully we can use that on a
going-forward basis, but that will take us some time, I
think, to develop that, but we do have a group in place
that's starting to look at that issue.
MR. MADISON: And if you want to talk about some
of those individual PIs with me, I used some of the same
type of indicators doing diagnostic evaluations as well.
But that's more down at a lower level in some cases than we
want inspectors to look at.
CHAIRMAN POWERS: You could guys could get on my
good side today because you would have saved me from getting
a lecture from my boss for performance indicators on this
corrective action thing. Then I would have remembered that
it's a key -- I wouldn't have been chastised and been in a
much better mood.
MR. MADISON: I'm sorry. It's been in the written
material from the beginning.
[Laughter.]
MR. GILLESPIE: Let me emphasize that we had a
meeting actually with INPO and NEI, Ralph Beedle and Mark
Pfeiffer from INPO who came up, who has now moved up the
chain at INPO a little bit.
Besides that document, that higher level document,
they actually have the next tier down. They call them
how-to's, where they're looking at a whole process where
they would go out and do periodic evaluations.
The licensee would do annual evaluations that
they's share with us. In fact, at the meeting we had, we
shared the thought about is there something to be learned
from how we deal with the training program that we might
learn from this?
If they're going to do periodic evaluations, could
we go and observe four or five or six of them a year? Plus,
have the inspectors then getting an annual report which is a
self-assessment.
And the industry has taken this seriously enough
that what Mark said was, for only the third time in history,
they have asked every utility in the country to report back
to them on how their programs match up against that
higher-level program as a starting point.
So, the idea that the cross-cutting issue is
corrective -- problem identification, corrective action
programs, has really taken hold.
I'll say we're tiptoeing a little bit because
we're on that threshold of regulation versus excellence.
Their focus is to try to make sure that their facilities
have the wherewithal, procedures, and the ability to
identity problems to keep us out, quite honestly, to keep
their performance in that band.
I think that's going to be a big plus for safety,
if we can be a catalyst to see that happen. So that process
has started.
The working group that Bill mentioned will be
interfacing with them, and INPO said that probably their
process will gel enough that they can really talk to us
about something, probably towards the end of April or so.
So, there are a lot of people working it, and a
lot of high level attention is now getting paid to it,
problem identification and corrective action. So, it's not
just that one document. There is a whole bunch of stuff
that's going on underneath it.
DR. SEALE: Mr. Chairman, do you think there would
be something of interest in that product of around the end
of April that the Committee might be interested in?
CHAIRMAN POWERS: I am willing to bet money that
there is, but I'm also willing to bet money that they're not
ready to come talk to us about it.
DR. SEALE: Well, whenever.
CHAIRMAN POWERS: But in May.
MR. GILLESPIE: Yes, they were kind of viewing it
as that kind of timeframe, because they're trying to get
this report in from everybody, and then get their thoughts
together. For instance, how often would INPO go out, like
parallel to the training accreditation visits. And then
licensees would do something annually, so they have actually
put some real thought into how this whole thing links
together.
And we would then observe this whole process kind
of as an integral. We just have to see how that comes off
in the next year.
MR. COE: I'm not sure a working group would be
prepared to come to you at that point.
CHAIRMAN POWERS: Okay.
DR. UHRIG: There was a recent report I saw where
Dr. Vesely of the Fussel Vesely fame, commented that only
about ten out of the 2,000 or 3,000 items in the backlog
corrective action list were really important to safety, and
that these should be addressed first.
Would that, if implemented by the utilities, have
an impact upon the kind of evaluation of that program that
you're considering?
MR. GILLESPIE: Absolutely. Bill was working for
a couple of utilities, but we also put some seed money into
that same project. And it was a kind of neat frequency
distribution, sorted by important sequence with systems
versus flaw, which allowed you to get that kind of focus.
We would expect that anything that comes out of
this would have to take consideration of exactly that point,
because we really want to focus on that top two or three
percent being worked.
So that would be kind of a performance
characteristic we'd see being factored into a good
corrective action program.
MR. COE: We have actually done a couple of
exploratory types of inspections along those lines to see if
there is a way to develop a tool or whether it's worth
pursuing. At about the time we completed those inspections,
Vesely came out with his thoughts and ideas.
And we have had an ongoing dialogue with Research
as to the viability and the possibilities of such a tool.
MR. MADISON: We see it right now, what's been
developed, as very time consuming and resource-intensive.
And we need to develop something that is going to be much
more simple and much more less impact on our resources.
DR. UHRIG: One other thing that I ran across
recently was a NEI publication that characterized this
process as four levels of the green, white, yellow, and red
levels, and the green was satisfactory, the white was
characterized as being deserving of a utility attention; the
yellow was characterized as deserving of NRC attention, and
the red is unsatisfactory.
Is this a fair characterization?
MR. DEAN: No. I'm not sure -- I don't know
exactly what document that is that you're referring to.
DR. UHRIG: It was one of the NEI leaflets. I may
be paraphrasing this.
MR. DEAN: One of the issues that we're concerned
about a little bit is that people take -- and this may be a
criticism of the process that we need to look at -- is that
people take, you know, the green, white, yellow, and red
characterizations of performance indicator results or
inspection findings, and then try and translate that to an
assessment of the licensee performance.
And really what you to go to is, you have to go to
our action matrix. The PIs and the inspection findings
serve as an input to that. And then there are various
categories in there, depending on the impact on various
cornerstones and how many cornerstones are affected and to
what level.
And that defines what action we take. So that's
something where people fall into that trap a little bit, of,
you know, they're a white-performer or a yellow-performer,
and we have to be careful that we don't make that
connotation.
So you might be referring to something that might
have been sent out early, because our own document, 1649,
NUREG 1649, kind of mischaracterized that approach early on
when we were first developing the pilot program.
DR. UHRIG: This was headlined something like
proven evaluation process being implemented, as I recall the
headline.
MR. DEAN: We'll have to ask NEI to see if we can
get a copy of that.
MR. BARTON: Are you through with this slide?
MR. DEAN: Yes. Well, we're about 2:30.
MR. BARTON: I was just wondering if you had any
more and if there were any questions. NEI was going to make
a presentation, but I don't think NEI is with us this
afternoon. That's why I allowed the staff to go another 15
minutes.
If the staff is finished with their presentation,
are there any other questions of the staff? I think this
was an enlightening further discussion on where you're
going.
I think it will make a lot of good improvements in
the program in getting it ready to roll out.
Any other questions?
[No response.]
MR. BARTON: Thank you very much.
MR. DEAN: You're quite welcome.
MR. MADISON: Thank you.
MR. BARTON: Mr. Chairman, I send it back to you.
CHAIRMAN POWERS: I thank the staff also for this
presentation. I hold you in great admiration. It's
unbelievable, all you've been able to do.
MR. DEAN: Thank you.
CHAIRMAN POWERS: I think we're excited about it,
and it's very evident to us that the Commission is very
excited about this program. So while we interrogate you
closely, it's just because we want to learn all we can about
it.
MR. DEAN: We appreciate that. Like I said, you
know, the offer, if any individual members feel like they'd
like to have some discussions with us, certainly any time
you want us to come back and talk to you, certainly as we go
through the pilot process, you're going to want updates.
CHAIRMAN POWERS: I think we'll need fairly
frequent updates, but we don't want to do it till you're
ready to come update us. Thank you very much.
DR. SHACK: If you can quiet George, I'll buy you
a beer.
[Laughter.]
CHAIRMAN POWERS: I'll recess us for 15 minutes
till quarter of.
[Recess.]
CHAIRMAN POWERS: We'll come back into session.
The next item on our agenda is to discuss license renewal at
Oconee, but before we get started, I'll recognize Jack
Sieber.
MR. SIEBER: Thank you, Mr. Chairman. I need to
put on the record that I will recuse myself from voting on
the Oconee matter, due to a conflict of interest in owning
Duke Capital stock.
CHAIRMAN POWERS: Okay, we'll pay no attention to
you whatsoever then.
[Laughter.]
CHAIRMAN POWERS: Oh, you mean just for this item.
I'm sorry.
Dr. Bonaca, do you want to lead us through this
set of presentations?
DR. BONACA: Yes, Mr. Chairman. As you know, last
week we met at the Oconee facility. We had an open
Subcommittee meeting that most of the Committee members
attended.
We reviewed the closure of open items in the SER
and the final SER provided for Oconee. We had
representation on the part of the licensee, and also on the
part of the NRC staff.
We had a number of issues. We asked both of them
to come and to present to the Committee. Specifically for
Duke Power, we asked to talk about the scoping methodology,
cables and connections, reactor vessel internals, and also
one-time inspection, their philosophy of application, as
well as buried piping, and how inspections from Oconee apply
to the Keowee facility.
We also asked the staff to address the same issues
in their presentation to us for the SER.
I would like to remind both presenters that we
have only one hour and 15 minutes scheduled for our agenda,
so we will try to be pretty quick through those
presentations and to leave a few minutes for us for
discussions.
With that, I'll introduce the Duke personnel.
MR. ROBINSON: Thank you, Dr. Bonaca. My name is
Greg Robinson, and it's nice to be with so many of you who
were with us at Oconee last week.
I'd like to introduce with me today, Jim Fisicaro
from Duke Energy, and also Jeff Gilbreath who will be
presenting our reactor internals information. Jim?
MR. GILBREATH: I just wanted to say a few words
of thanks. Mike Tuckman wasn't able to be here today. He
had a death in his family earlier this week, so actually the
license renewal folks actually work for me, and on behalf of
Duke Energy, I just want to thank Dr. Bonaca and his team
for last week's effort.
I think that was a very good interchange amongst
both sides. I think we both learned some things, and do
appreciate the support that the ACRS has given this. We
appreciate the NRC staff for their review.
We are meeting schedules, and I think everybody
knows that this is a very important piece to Duke Power
Company, so we appreciate your efforts. So thank you very
much.
MR. ROBINSON: And with that, thank you, Jeff.
These are the five issues that you just laid out, and I'll
move quickly into the first one:
We have spoken briefly about the scoping
methodology last year when we had a chance to meet, and we
did spend a good bit of time at Oconee going through the
details of the scoping process, including the engineering
records that captured the scoping results.
The SER open item was associated with a definition
or struggling with the definition of design basis events and
the timeframe that that definition was used at Oconee.
There was a concern or the issue was whether the
set of events that we did identify associated with the
scoping of the plant, was sufficient for scoping for license
renewal.
We went through a number of meetings and a number
of discussions with the staff on this issue, and in order to
resolve it, we conducted a case study and looked at ten
additional events, and the licensing basis aspects at Oconee
for those ten addition events.
And we were able to conclude from that study that
there were no additional systems, structures, and components
identified by those ten events that were not already within
the scope of license renewal.
And we felt very good about the validation efforts
of that study.
DR. BONACA: Just a question: Seven of those
events, you conceded; the other three you did not find them
in your design basis. The question I have is, do you
consider those seven additional events part of your current
licensing basis?
MR. ROBINSON: The seven additional events, in
some aspects, part of our current licensing basis at Oconee.
They are not, however, part of our design basis events set
of materials.
Again, to change that definition would require
significant changes to other aspects of the plant. But as
far as finding them, we did find aspects of those seven
events that you've spoken of in the current licensing basis
of Oconee.
DR. BONACA: Okay. I appreciate the fact that you
covered them and addressed them. I just was left with that
question in my mind as to whether or not you would consider
that part of your current licensing basis.
CHAIRMAN POWERS: I wonder if the process of
identifying these ten additional events has any translation
to whether -- this particular -- restricted to Oconee.
MR. ROBINSON: I don't know that I'm qualified to
speak about others' designs, but I imagine that things that
were designed in the time period when the definitions of
terms such as design basis events were being put forth,
you're going to find uniqueness in the late 60s designs in
the United States.
CHAIRMAN POWERS: That's why I'm interested in the
process and not necessarily the details.
DR. BONACA: I would expect that when we come to
the staff we'll ask that question, and we'll hear that it
would be, in my judgment -- that's why I asked the question
about current licensing basis, because that's what I
believed happened there, although I recognize that it wasn't
part of your original design. But you were asked by the
staff for a number of issues that came like TMI action items
and so on, to address additional issues. Although they were
not part of the original design basis, they are part of your
current licensing basis.
MR. ROBINSON: Yes.
DR. BONACA: Okay, thank you.
MR. ROBINSON: I will move on and summarize the
second issue on our list now, which was the insulated cables
and connectors issue.
A little background on this issue: When we
originally did the reviews, aging management reviews for
license renewal at Oconee, we found several instances from
field walkdwn work where we had cables and connectors that
were in locations that were in high temperature areas or
high radiation areas.
And in a number of instances, we were able to
relocate those cables, to move them out of those areas.
Using that thought that we perhaps could make modifications
to the plant and not end up with any cabling in a very, very
aggressive environment, we went with the idea that we would
really not need an aging management program if we modified
the plant to the extent where the hardware was not being
exposed to these environments.
However, because a number of the cables had not
been moved out of their aggressive environments, and may not
be moved due to budget restrictions or other things, there
was a feeling during the inspections that it may be better
to go ahead and plan for an aging management program for
those cables.
We can still relocate them, still modify the
plant, which would eliminate the problem. But for those
areas that we did not eliminate the exposure to the
aggressive environment, we wanted to go ahead and put a
programmatic action in place. We called that the insulated
cable aging management program.
We did work with the staff to develop the aspects
of that, so there was a good understanding. In particular,
a number of members of the staff and Duke were involved in
IEEE efforts on aging effects, and they applied their
knowledge to this program.
The focus of the program is on the cables and
connectors, and the adverse localized environments,
including radiation, temperature and moisture environments,
in particular, conduits.
And we did have an opportunity when we were at
Oconee to see some of the areas that we had gathered
information from, a number of the cable banks that were
there in the buildings, and they will be the types of areas
that this program will be focused on.
DR. BONACA: In containment, you had also some
areas where you had synergistic thermal/radiation effects.
MR. ROBINSON: Yes, we did, in containment. One
of the things we did do as a part of license renewal efforts
to gather information in containment is, we instrumented the
inside of several of our containments to gather thermal
data, so we could do thermal mapping and profiling to begin
to understand what kind of thresholds we were actually
exposing the hardware to.
We used that as insights to us in noticing the
aggressiveness of the environment. Along with the thermal
monitoring, we did some radiation monitoring, and that's
where the idea of the synergistic effect did come in.
DR. BONACA: Thank you.
MR. ROBINSON: So that is a summary of the
insulated cables item that we dealt with.
DR. BONACA: The program, however, that you
presented, is broader than just thermal/radiation. You have
the moisture concern, and issues being addressed also for
buried cables and in-tray cables, right?
MR. ROBINSON: Yes, they are, especially the
cables in the conduits. I'll make note that we've spent
some time -- we are in our third inspection at Oconee, our
Regional inspection this week, and one of the items in the
electrical area was to go back in the plant and reinforce
the aspects of this program versus the physical layout of
the plant, in particular, conduits in areas that may be
exposed to moisture or maybe could collect moisture, which
would also be a part of this program.
CHAIRMAN POWERS: Do you have an idea of what the
chemistry is that causes a coupling between the moisture and
the thermal processes?
MR. ROBINSON: No, sir, I don't.
CHAIRMAN POWERS: I could imagine why the
radiation would couple with the moisture, just because you
build up a little peroxide and some free radicals in there.
MR. ROBINSON: To my knowledge, the areas that
could be exposed to moisture are typically in the lower
parts of the building and away from bigger, hotter,
equipment, so there is probably less of the synergistic
effect there, if there is any.
CHAIRMAN POWERS: What you say is there is this
coupling of thermal and moisture, not radiation and
moisture, as far as I can remember in your documentation.
MR. ROBINSON: Okay. The next area is the one
that Jeff Gilbreath will cover, and this is where we're
moving into our reactor vessel internals area.
MR. GILBREATH: The reactor vessel internals had
six open items that we had to address. Those six open items
basically captured all of the aging mechanisms that we
identified in our topical report, and also how those aging
mechanisms may affect or potentially affect the reactor
vessel internals.
Specifically, those were -- they are listed:
dimensional changes due to void swelling; cracking of
internals -- this was primarily looking at radiation stress
cracking; thermal embrittlement of the plates and formers,
non-cast items.
Then we evaluated the cracking of baffle bolts due
to ISCC. Also we were to evaluate embrittlement of cast
components and reactor vessel internals; thermal
embrittlement of the vent valve, and reduction of fracture
toughness.
Just to point out some of the components that
we're addressing, our internals basically are two
components: the plenum, which is upper internals area,
which houses your control rod drive mechanism. In that
mechanism, there is actually ten spacers or guide cards, and
those ten spacers are made of cast and also made of CASS
austinated stainless steel.
Then there is your core support area, which is
actually three components bolted together. Your core
support shield on the very top actually has the vent valves,
eight vent valves in it, and also on Oconee Unit III, you
have a CASS austinated stainless outlet nozzle.
Then our primary focus is actually in the core
barrel region where the radiation is the highest. You have
your baffle bolts, your plates, your former and baffle
plates, and also your core barrel region.
And then your lower internals have an in-core
guide tube which has a spotter assembly made of CASS
austinated stainless. So those were the components that
have been identified as needing further studies.
DR. SHACK: Just out of curiosity, why are the
baffling plates perforated?
MR. GILBREATH: I have a better drawing of those.
[Pause.]
The baffle plates actually form the geometry of
the core, support your assemblies but at the same time these
particular plates have a pressure relief holes in those for
interaction of water from the bypass region and also the
normal core region. There are some slots in the plates,
actually in the center of the plates in this area that also
allow some cooling interchange.
With this particular design, the Oconee, it's an
upflow design, bypass flow design, and they have tried to
maintain pretty much a zero differential pressure on one
side of the plates versus the other. Some designs are
different.
DR. SHACK: Have you estimated your gamma heating
then in there?
MR. GILBREATH: We have a program to actually do
that. Some utilities have -- EDF has done some studies in
that area like the gamma heating effect there could go as
far as an additional 50 degrees but that is something that
as part of our program we will be doing over the next three,
four years.
Initially our approach that we took to reactor
vessel internals, we have developed an aging management
program. That program really was a focus on the process --
what we need to do, what we need to learn to manage the
potential effects of all these different aging mechanisms,
since most of these particular effects may have never been
seen before in the industry.
In doing that, once we have completed our
analysis, our studies in the industry as far as testing
certain surveillance materials, we would put together
whatever inspection programs would be needed to manage the
effects to the internals.
The NRC in reviewing our proposal, I think their
concern was that a lot of these aging mechanisms may not
show up until late in life and if you are developing your
program now, they weren't sure that there was a real
commitment I guess to doing inspection in that period that
the aging mechanism may show up, so they suggested that we
assume that these effects do exist and commit to an
inspection program and in doing that, if, for instance, once
we do our analysis and our evaluations we can prove that
that will not affect the function of the internals at that
time we can make that submittal.
They will evaluate it and we can maybe change the
elements of the inspection program. That was acceptable to
us, so basically what we did, we submitted an inspection
program. We rolled in all the different process that we're
already working on in the inspection program to help develop
the different elements.
Basically there we have 12 elements in the
inspection program and things such as acceptance criteria,
the inspection method, corrective actions, different things,
we still have to develop, and so the commitments we made
with the inspection program -- one, we would inspect all
three internals and we would do this in a time when we
wouldn't just do it all in the early part of the license
renewal period but we would do one in the early part, one in
the middle and one in the latter, not being the last year of
the renewed term.
We also committed to work with the industry,
particular the B&W Owners Group, Reactor Vessel Internal
Aging Management Program. They have quite a number of tasks
that are really supporting us in doing the evaluation and
performing the analysis we need, not only the BWOG but also
EPRI has a program called Materials Reliability Program,
which they have an issues task group on reactor vessel
internals and that task group is managing or trying to
coordinate all the different activities in the U.S. on
reactor vessel internals aging effects.
Also, they have another group called the Joint
Baffle Bolts Task Team or the JOBB you may have heard, and
that particular group said look, who's the leaders
internationally? Who is actually doing the work out there
in the world on reactor vessel internals that we might could
participate with, learn from what they have done and also
incorporate some of our materials? We formed the JOBB and
actually found that EDF has done quite a bit of work in this
area.
So we have taken materials from both the Oconee
internals and also materials -- well, the Westinghouse
groups have done the same -- and we have sent those to EDF
and asked -- they have already set up contracts and all to
irradiate their materials at different places -- and we have
asked if we could irradiate ours and do some studies in that
way. We are working with them -- as a matter of fact, we
have a meeting with them in April to go over some of the
findings in the initial irradiations.
There's a lot of industry participation going on
that we have committed to. Lastly, we have committed to
give reports to the NRC on a routine basis, the first report
being within one year of receiving a renewed license and
then later reports over the next 10 years, and the final
report being about at the end of the present license but
within two years prior to our first inspection, laying out
the basis for our inspection program and developing our
aging management program at that point.
I guess the last bullet we have already covered.
Obviously modifications of this program are going to exist
as we learn more.
The inspection as it exists today, our inspection
program, really consists of three items. One is the baffle
bolt inspection which we plan to do some type of volumetric
inspection on the baffle bolts. That is one area that we
have actually seen some cracking in the industry. I know
the EDF has had cracking and there's been a few baffle bolts
found cracked in the U.S.
In that program there's been quite a bit of work
in the industry already, developing inspection methods for
that, so there is not a lot of work to do in that area
except to say that we are doing analysis to see how many --
there's different internals for different designs but like
the Oconee design there's approximately 1400 baffle bolts or
baffle former bolts. What we want to know is how many of
those baffle bolts we need to maintain the function of the
internals and we are doing analysis to determine that today.
Also, the CASS austinated stainless steel, you
know, the real concern there, we knew that there was a
thermal embrittlement effect and we knew that there's an
irradiation effect, but never really have seen any kind of
synergistic effect of the two and so we are trying to
develop now or we are developing a program today not only to
do an inspection but to do an analysis to determine a
critical crack size so we can figure out what type of
inspection we will have to do to detect a crack in that
particular component. Most of our CASS austinated
components are in a compressive state.
Also we have pretty much the other components that
capture the rest of the internals, concerns with our core
barrel and shield bolting is X750 material. You could have
a stress corrosion cracking issue there that we need to
monitor, and we have a program today that we do an
inspection of those bolts.
Also on the plates, former plates and baffle
plates, I guess a concern has come up through this
evaluation -- what is swelling, is there a potential for
swelling, and how might it affect the reactor vessel
internals, and so we really try to focus in on where the
gamma heating effect may be the highest, because where your
highest temperatures are and your highest irradiation, that
is probably going to be your limiting area as far as
swelling or the first place you would see swelling and so we
are developing a program to perform an inspection for
swelling also.
That's kind of where our focuses are today. As we
said, this program may evolve. You may see that group that
says "other components" become two or three bullets, two or
three different types of inspections, depending on what
mechanism or what effect we are looking for.
It could be volumetric if we are looking for
cracking, if we are looking for dimensional changes -- it
could be quite a few things and those we are going to still
have to work out.
CHAIRMAN POWERS: It isn't obvious to me that the
plant's temperature region would be the region of maximum
swelling.
MR. GILBREATH: The direction we have been given
in studies that we have looked at, I guess we have utilized
some of Frank Gardner's studies and contracted him to help
us -- he seems to believe and has shown with the results he
has had I guess in the vessels he has looked at where the
maximum temperature is and fluence, a combination of the
two, are really your two drivers for swelling.
If the temperature drops a little, you may not
have any effects, so where that threshold is, it's still
really unknown with PWRs.
CHAIRMAN POWERS: I would assume that the
temperature effect can't be linear. It has got to go
through some maximum glib to get it high enough. I will
anneal out -- if I get it hot enough. I don't know what hot
enough is though.
DR. SHACK: Yes, but he is on the other end of the
curve.
CHAIRMAN POWERS: Okay.
MR. GILBREATH: Yes, it seems that higher
temperatures in this case are not good.
CHAIRMAN POWERS: Yes, you are going upslope.
MR. GILBREATH: Yes -- which is actually good for
PWRs since we do not operate at the temperatures that the
swelling has been seen in the past.
MR. ROBISON: Thank you. I appreciate Jeff going
through that. We had quite a lengthy discussion at Oconee
last week on the very same subject.
It is a very broad subject, and in fact that is
the area, as several of us have discussed, that we believe
is sort of the new area that license renewal has moved into,
is reactor internals and the maturation of this program from
when we started in 1996 until today is pretty amazing. You
see how far we have come and then the timelines and plans
that have been laid out. It speaks well for the hard work
Jeff and others have done.
The last two items on our agenda today would be
the one-time inspections and then the buried piping
overviews.
I just have one slide on the one-time inspections,
calling out that we make sure we know what we are talking
about when we are talking about one-time inspections. They
are aimed at verifying the aging effects are not occurring.
This is the check to make sure that things are not
happening. We could not absolutely say something was not
going to be an effect that would cause a problem over a
longer period of time, so we said what we really need to do
is go look.
We have almost 30 years of operating experience
now. Somewhere between here and 2013 we had planned to do,
before the end of the initial 40-year period, we would have
had 30, 35 perhaps even closer to 40 years of operating
experience or exposure of this set of components to the
environment, and something that was going to reveal itself
should be revealing itself somewhere in that timeframe.
What I have listed here, and I won't read through
them, you can read through them, but these are the nine
topical areas for the one-time inspections. You can see
they range from carbon steel type components to stainless
steel type components to things that are exposed to oil and
air and moisture, to systems that are exposed to very clean
chemistry, chemically controlled items, but we just could
not quite make judgments that they were going to be fine so
we are going to go look.
CHAIRMAN POWERS: Your reactor coolant pump motor
oil collection tank inspection, that's because you are
afraid you may get acids in this motor oil that gets
collected?
MR. ROBISON: It's even simpler than that. When
we dump the oil in it, there's a chance that when we spray
down in the reactor building you are getting water in this
tank.
It's a carbon steel tank inside. We don't know
what is going on.
We assume there is a coating of oil inside that
will remain even when you drain the tank out. You will keep
a film in there.
We don't know, and what we would like to do is go
take the manway off and go in there and take a look just to
convince ourselves that that coating of oil is protecting it
and we are not inadvertently spraying down the building,
getting moisture in this tank and having the tank perhaps in
a degraded condition so it couldn't catch the oil in the
case of needing it in a fire event.
It just seemed like a good, common sense way
rather than trying to analyze our way out or guess our way
out we would go into the plant and take a look.
DR. UHRIG: Some of the inspections have to do
with specific pieces of equipment and others are materials.
Take the first couple -- cast iron selective leaching
inspection. Is there any particular place that you will do
this or is there a sampling of places?
MR. ROBISON: There were a number of pump bodies
in treated water systems and raw water systems that we felt
like could have a progressive leaching effect occur if it
were going to occur. We do disassemble those pumps for
maintenance periodically and what we hope to do here is plan
some intrusive type inspection while maintenance is in there
doing work on the pump for other reasons.
DR. UHRIG: On the galvanic susceptibility
inspection, does that have to do with buried pipe, or is
that in addition to the buried pipe?
MR. ROBISON: That is in addition to the buried
pipe. From my past experiences, we have put bronze and
stainless and carbon sort of intermixed as replacement
items. We certainly did that for corrosion or erosion
issues and I am not certain of the long-term effects of
welding all of that together.
I asked my metallurgist here and he gives me some
insights and some I understand, some I don't. I am going to
go look and make sure that we are not creating a situation
in the plant -- I don't think we are.
DR. UHRIG: How about the condensers? Are you
using different materials in the condensers or you have all
the same?
MR. ROBISON: Up to now we have had the same. I
don't if we have retubed any of Oconee's condensers. I
can't remember off the top of my head. I know we have done
some work at some other plants, other of the Duke plants.
DR. UHRIG: I remember having four sections with
four different materials one time at Turkey Point.
MR. ROBISON: Oh, boy.
CHAIRMAN POWERS: If your metallurgist is like my
metallurgist, he'd probably give you the galvanic corrosion
potential good up to a sign.
MR. ROBISON: Yes.
CHAIRMAN POWERS: And these complicated system --
MR. ROBISON: They handed me the book and said you
can figure it out. Find your metals on the thing and just
be careful with which ones you pick, so it seemed more
practical to go take a look, so we are going to go do that.
DR. BONACA: Assuming you have corrosion on the
oil collection tank, you have a leak from that, they'll look
at it from inside the containment, right?
MR. ROBISON: Yes.
DR. BONACA: And so you will have really a
spillover on the floor?
MR. ROBISON: Yes, sir. Yes, and that certainly
is a concern, and that is why it seemed more prudent to go
look than to try to make an assumption that we dump the oil
frequently enough to keep a sheen in the tank itself.
CHAIRMAN POWERS: I would think that the worry
about water, that's a good one. I hadn't thought about that
one, but I would also worry about, you know, you put those
hydrocarbons in there and they are nice good hydrocarbons in
theory but as they age and get older you can get carboxylic
groups in there and they become acidic and they can do some
corrosion, even when you don't -- it's oil and old oil is
not always very protective.
MR. SIEBER: There is boric acid there too.
MR. ROBISON: Right, yes. I think the Staff will
speak more to the one times.
The last subject area I will overview for us is
the buried piping area. We had some discussions on it. I
thought I would begin with a graphical illustration. I'm
told that I am supposed to start with graphics and then go
to words, but I did it opposite today. My wife is a
schoolteacher. She told us that.
The 132 inch diameter piping represents the
condenser circulating water system at Oconee, which is
actually a large cave underground. The 18 inch line is
meant to represent or illustrate the largest size line
anywhere else on site that is buried or at Keowee. One of
the discussions topics that came up was how do we make it an
equivalency between Keowee buried lines and Oconee buried
lines when in fact the entire site was disturbed together at
the same time and all the lines were installed together with
a similar technique, and I have illustrated that here.
Surface preparation of coating and wrapping the
lines was the same, the standard specification of how we
prepared the piping when we put it in the ground. The
interesting thing about the 132 inch line is we actually go
in that line and inspect from the inside, so every few years
we are able to dewater one of the units' lines -- there's
two lines coming into each unit -- and go through the lines
and inspect internally for areas where the coatings and
wrappings may have had a holiday in them, creating a
galvanic cell with the soil and you would end up with a hole
in the line.
We have three that we were able to find in the
operating literature, operating history of the plant.
Typically when you find it, you will UT around the area.
You will go in and make some type of repair on the spot.
Interestingly though, to lose function of that
line would require many, many, many holes. In our situation
here, finding many, many, many holes would tell us the
behavior of the piping material and the whole system, the
soil, the piping, the coatings and all had progressed to the
point where something needed to be done. That is the
indication that we are after, not the one hole or the other
hole but the general behavior of the setup.
You can see if you look at the square footage that
we are reviewing here, it is roughly the area of 10 football
fields that we are surveying, and that is quite a lot of
surveillance data.
CHAIRMAN POWERS: That's a pretty good sampling.
[Laughter.]
MR. ROBISON: That is a pretty good sample.
MR. BARTON: Are you surveying by internal -- UT
from internally?
MR. ROBISON: We are visually looking internal,
internal to the lines, for areas where the coatings may not
be doing their job, because typically what will happen is a
galvanic cell will establish itself between the soil and the
carbon steel piping and it will lead to a whole in the line.
This was meant to introduce you. I don't know if
you have any other particular questions here, but it was a
solution. I would even look closely at our other nuclear
units to see if this type of technique will work, but I do
know that we feel very good about the technique we have
here.
When we have had those several leaks and we've
UT'd large areas around those holes, they have been very
specific, location-specific, and the remainder of the piping
is at or above the mil spec that it was purchased at, so we
have good belief in the quality of what's there, the
behavior of what's there.
DR. UHRIG: Do you do any repair from the outside?
MR. ROBISON: If we can dig to it. The last hole
we had was 35 feet underground, and it would have been
difficult to dig down because we were out on the discharge
end. We would have to have gone and dug down from the upper
parking lot down to the line, so that is the reason we have
developed, tried to develop more focused internal
inspections, because of the locations of these lines.
You said the soil is pretty much identical between
the Keowee facility -- because one of the issues was that
you are inspecting the Oconee piping then inferring the
condition of the Keowee piping from the Oconee inspection.
MR. ROBISON: Yes, and I was unable to bring the
photograph but I did find a photograph in an old book that
we had onsite where the entire site had been disturbed. The
soil on the entire site had been disturbed literally from
the riverbed -- for you gentlemen who are able to go to
Keowee -- from the riverbed where the hydro plant is located
all the way over to the nuclear station in its location.
All of that was disturbed, so the piping at the Keowee
facility was put into the same moved soil and moved earth
that the big lines at Oconee were, so we would have a good
feel that all of that soil had been mixed and moved around
and should be similar in characteristics.
CHAIRMAN POWERS: There is nothing, given your
location, you don't have any problems where the Keowee could
be saltier than the Oconee soil?
MR. ROBISON: To our knowledge, no. When we went
and looked back through our records and talked to our
engineering folks, our civil engineering folks, they could
see no reason why there should be any behavior different
between the two. They are in the river valley.
CHAIRMAN POWERS: The classic one is that we've
got a parking lot that gets deiced with salt and that
affects the soil around it, and of course 50 yards away
there is no salt.
MR. ROBISON: I understand.
DR. BONACA: Now you said this piping is wrapped
on the outside, so there is some level of protect. Could
you describe that?
MR. ROBISON: It's epoxy or coal tar type --
MR. BARTON: Bitumastic tape?
MR. ROBISON: Yes, yes -- and then a wrapping, a
careful prep -- and I made sure I checked with our civil
engineers. I said you didn't just backfill it with gravel
and knock holes in your coating and wrapping? -- and they
said no, we even had specifications on the soil and how we
put the soil back in around the coatings and wrappings to
make sure that we left it in a good as-prepared condition.
I think that has been evident in the very few
leaks that we have seen over time.
DR. BONACA: Any other questions?
CHAIRMAN POWERS: I guess we did go and check the
cited reference on the effects of soil and found that soils
do have an effect on the galvanic corrosion -- five orders
of magnitude is the corrosion potential --
[Laughter.]
CHAIRMAN POWERS: The point is if they are all the
same then it's the same.
DR. BONACA: Plus again I mean your inspections to
date have not revealed any general widespread defects. You
found isolated, localized effects that are indicative of
cells rather than -- you know.
CHAIRMAN POWERS: And it would take a pretty
heroic type failure to cause a problem.
DR. BONACA: I think so too. Yes.
CHAIRMAN POWERS: You could probably see the
ground washing away before you --
MR. ROBISON: Yes.
DR. BONACA: Yes. With those type of pipes, yes.
MR. ROBISON: I had one other item. I wanted to
bring word from our Region II inspection for you. You knew
it was going on this week.
DR. BONACA: Yes.
MR. ROBISON: We concluded the inspection items
last evening and checked all the checklist items and I think
there are going to be some general plant tours and some
regional management onsite today, but I wanted to let you
know that we did finish those. We do not believe, Duke does
not believe there are any open items remaining. We were
able to close them all.
CHAIRMAN POWERS: So you got a good close-out?
MR. ROBISON: Got a good close-out and we have a
formal public exit tomorrow morning.
CHAIRMAN POWERS: Okay.a
DR. BONACA: Okay. I have just one more question,
which is in October when you had still an open item on
GSI-190, you offered to the Staff to have -- to meeting
either the plant-specific approach or to commit to a generic
closure of GSI-190. Later, in November I believe, the NRC
presented a resolution on GSI-190 and set the requirements.
You have committed to a plant-specific resolution
of GSI-190. Am I correct?
MR. ROBISON: Yes, sir, we did commit to it.
DR. BONACA: You already have defined the program
and the NRC has recognized that in the SER at this stage, so
it is not anymore an option which way you are going to go.
I just want to make sure of that.
MR. ROBISON: Yes.
DR. BONACA: That I understood it correctly.
MR. ROBISON: Yes. It would be our intent to
follow the outline of what has been laid out in the SER,
follow another approved process if the Staff finds one, or
use the latest technology and thought processes that were
available in industry as people continue to develop the math
models associated with environmentally-assisted fatigue.x
DR. BONACA: But if I understand, you took one of
the NUREGs in which there were six locations which were
specifically inspected and you chose the six locations for
your inspections.
MR. ROBISON: Yes, we did.
DR. BONACA: And you are still committing to
those?
MR. ROBISON: Yes, sir, we are.
DR. BONACA: Thank you.
MR. ROBISON: Thank you.
DR. BONACA: Any other questions? No questions.
Thank you for the presentations.
MR. SEBROSKY: I am Joe Sebrosky. I am the
Project Manager for the safety review for the Oconee license
renewal application. I would just like the other members of
the staff to introduce themselves.
MS. COFFIN: Stephanie Coffin. I am a Tech
Reviewer, Division of Engineering.
MR. DAVIS: Jim Davis, a Tech Reviewer in the
Division of Engineering.
MR. GRIMES: And I am Chris Grimes. I am the
Chief of the License Renewal and Standardization Branch. We
are here to talk about these four things -- the resolution
of the open and confirmatory items in the SER; reliance on
the current licensing basis and the regulatory process; our
perspectives on one-time inspection; and also buried piping.
MR. SEBROSKY: If you look at the next slides,
Slides 3, 4 and 5, they simply list the open items and just
a brief one-line description of what the open items were,
and the purpose of listing them was to make sure that the
ACRS members didn't have any questions or comments that the
Staff could respond to.
DR. BONACA: Actually, isn't it the same open
times that you have in the SER and that you closed there,
that you presented last week? Correct?
MR. SEBROSKY: The answer to the first question is
it is almost the same as the list of the open items that
were in the SER in the June version. As Duke pointed out,
one of the open items that we added after the SER in June
was issued was the electrical insulated cables, so we added
that open item. We also added some discussion on ECCS
piping. We added some additional information because Duke
updated their license renewal application, so the SER
changed not only because of the closure of open items and
confirmatory items but for those other reasons.
The answer to your second question is, is this the
same information that we presented to the subcommittee, the
answer is yes. So unless there aren't any questions from
Slide 3, 4 or 5, I guess I would like to move on to Slide 6
and turn it over to my boss, Mr. Grimes.
MR. GRIMES: I propose that because of the nature
of this question and also the dialogue that you had a moment
ago regarding the definition of design basis event and what
it means relative to the licensing basis, I wanted to just
go back to the fundamental philosophy of license renewal.
We had an original attempt in 1991 to establish a
review scope for license renewal that would attempt to try
and identify unique aspects of the licensing basis, but even
at that time there was a vision that the renewal review
process would use the current licensing basis, and continue
it, and that we weren't going to attempt to try and
modernize plants, but we discovered in that effort that
isn't anything unique about aging effects, that Mother
Nature does not subscribe to the 40-year life principle --
[Laughter.]
MR. GRIMES: -- that was established in the Atomic
Energy Act, so in 1995 the rule was amended and it extracted
a definition that is contemporary in its explanation about
how a licensing basis is established. It refers to design
basis events, and by inference to 50.49. It describes it in
terms using design basis event as a term, but as we learned
at Oconee and as I expect we will find as we add
clarifications to the guidance, for some plants to say
design basis event means an analyzed design basis event, but
our purpose in license renewal was also to get systems,
structures and components that are relied upon to perform
functions associated with the licensing basis that might not
be an analyzed design basis event -- capital "D" -- capital
"B" -- capital "E" but like earthquakes, like loss of decay
heat removal, like high energy line breaks.
To the extent the design has evolved over time,
there are implied capabilities to cope with events and so we
overcame our linguistic problem by talking about using
scoping events and we explored 10 events as Duke described
in order to identify structures and components that were
relied upon to prevent or mitigate those events without
calling them design basis events or anything else -- there
is a capability in the plant design and we needed to make
sure that the structures and components that are going to be
subjected to an aging management review fit in that box.
We found, as Duke pointed out, that everything was
subjected to an aging management review that needed to be,
and I expect that we will run into that again in the future
but from a broader perspective I will also say that
maintaining the integrity of the current licensing basis and
carrying it forward is a fundamental principle of license
renewal.
After reflecting on it philosophically, whether or
not for example other nonsafety capabilities like the
cooling loop for the spent fuel pool or some of the other
things that the plant design does not live up to a
contemporary plant, we are still comfortable that the
process has its built-in protections so as the licensing
basis evolves in the future we will continue to have
programs that manage aging effects for those things that are
relied upon and we look into risk space as well to test that
theory, and I am very comfortable that that underlying
philosophy is still a sound one.
DR. BONACA: I just asked that question before
however because at some point I believe when you come to the
SRP definition or somewhere you will want to capture a
process that has some definition in current regulatory space
rather than having to say, well we look to the other -- let
me just give you an example.
When Oconee was designed and licensed it had one
auxiliary feedwater pump per plant and they were
interconnected. Right now the plant has three auxiliary
feedwater pumps per unit. In addition to that, because of
TMI action item I imagine, there was automatic initiation of
auxiliary feedwater in the plant -- I imagine as seen in the
other plant.
I assume that those requirements which were
imposed for whatever reasons by the NRC and were installed
are part now of what we call the licensing basis for the
plant, so that if Oconee will come with the original SAR,
Chapter 15, with only one pump starting at a given time and
not automatically but by operator action, you would contend
that the current licensing basis incorporates a different
design which captures three pumps and an automatic start.
That is what I meant by -- am I correct? I am
trying to understand if I am correct or not in calling that
current licensing basis. I am trying to learn.
MR. GRIMES: Well, the simplest answer that I can
give you is throughout this process we raised questions
about why is the plant licensed the way it is licensed and
when we get into circumstances like that and we ask the
question and we can't find the answer, it goes back to we
will put that into the space of determining whether or not
the current licensing basis needs to be changed.
Now I am trying to draw back on the SEP
experience. There are plants that don't have certain
capabilities and if that is the way the licensing basis is,
then that is the way that we will evaluate it for --
DR. BONACA: I understand that, but I think there
is a fundamental difference between the SEP, which was a way
of reconciling certain lacks of components, with new
requirements imposed. I imagine those three auxiliary
feedwater pumps per plant at Oconee all fall under the
Appendix B program.
I don't think that only the original one is on the
Appendix B and the other two are not.
MR. GRIMES: And that is where I'll hesitate
because I wouldn't make that presumption. The way that we
went through the scoping events is we said the ground rules
for evaluating the current licensing basis are you go find a
statement in the FSAR that describes a reliance on a
particular component or a statement in the regulations, but
some of the TMI action plan stuff got resolved on a
plant-specific basis and then through the inspection process
we looked to see whether or not the FSAR captured those
things that were relied upon to resolve those issues.
So we still rely on the process ultimately to have
identified changes in the licensing basis, and that is the
way that we screen the events. I don't know the specific
answer to your question and the Systems folks who we didn't
bring today could -- might be able to answer that.
MR. MATTHEWS: I might be able to --
DR. BONACA: I think for Duke we are satisfied
that the scope --
MR. MATTHEWS: I was just going to provide a
clarification that, in answer to your first question, I
think the answer is yes. It would be in the licensing basis
of the plant, but they wouldn't necessarily be scoped as
design basis events in the traditional terminology.
DR. BONACA: You know, I don't want to belabor the
issue with Oconee. I think we have seen it enough and the
fact that they have verified this and no additional
components were identified is comforting.
MR. MATTHEWS: And I do think, as I mentioned, we
will probably have to go through a similar exercise against
future applications and we have even talked about the fact
that as a result we may have to come to a rule change
eventually to address this, to remove this confusion that
exists with regard to the terminology used.
DR. BONACA: It is confusing. The point I am
making is more for the preparation of the SRP, which should
provide some clarification and hopefully will in this
particular area because it is confusing.
MR. MATTHEWS: Yes.
DR. BONACA: Okay, thank you.
MR. SEBROSKY: That was David Matthews, by the
way.
DR. SEALE: You still are.
MR. MATTHEWS: Still am.
[Laughter.]
MR. SEBROSKY: Moving on to the next slide, Duke
made a presentation about one-time inspections and this
slide basically reiterates and has one additional thought.
Duke has nine one-time inspections and as Duke, as
Greg Robison mentioned, the purpose of the one-time
inspection is to verify that aging effects are not occurring
such that an aging management program would be required.
The last bullet is just the basis for the Staff's
acceptance. If you go to our SER, you will find that we
found it acceptable because at present the aging effects are
expected to be slow-acting and can be resolved by the
established corrective action process.
That is our basis for acceptability.
The last issue that we were going to discuss today
was buried piping and if you to Duke's application, the
aging is actually managed by two preventative maintenance
activities. Greg mentioned one, the condenser circulating
water system internal coating inspection.
There is also another one. As you know, there is
a standby shutdown facility that has a buried diesel fuel
oil tank and there is also an internal inspection associated
with that.
If you go again to our SER and the basis for the
acceptability we mentioned the condenser circulating water
system, 11 foot diameter pipe, accounts for 80 percent of
the surface area of the buried pipe.
So that is all we have for presentation today.
Were there any questions?
DR. BONACA: Any other questions from the members
CHAIRMAN POWERS: Pretty straightforward. No.
DR. BONACA: Thank you for the presentations.
I would like to go around the table and see if
there are any additional comments from members regarding all
we have seen. Most members were at Oconee last week. Not
all of them, so any questions you have we should discuss
here.
CHAIRMAN POWERS: I see no particular questions.
I think we learned something from going and looking at
Oconee. It is a plant from an older era and I think we need
to give some thought to what we have learned from their
example on how it might be applicable to other plants. I
think they did a particularly impressive job.
I think it might be worthwhile to look and see if
there are areas that we can profitably curtail based on the
experience there, areas and methods that we could profitably
highlight.
DR. UHRIG: Some of that might be related to the
results of the inspection but they may not be done in time.
CHAIRMAN POWERS: Okay, thank you very much.
DR. BONACA: Any additional questions from the
members?
[No response.]
DR. BONACA: Well, thank you very much. I turn it
back to you, Mr. Chairman.
CHAIRMAN POWERS: I have a problem. I am unable
to start the sessions on 50.72 until 4:15, so we will recess
until 4:15.
[Recess.]
DR. APOSTOLAKIS: We are back in session.
DR. SEALE: We've got a quorum at the forum, eh?
DR. APOSTOLAKIS: Yes. The next item is proposed
final amendment to 10 CFR 50.72 and 50.73. The cognizant
member is Dr. Bonaca. I will turn it over to him.
DR. BONACA: Okay. During the February 3 to 5,
2000 ACRS meeting the Staff presented its proposed final
amendment to 10 CFR 50.72 and 50.73. At that meeting the
Nuclear Energy Institute stated that the proposed amendment
would be beneficial for licensees and should be issued as
soon as possible with the exception of the following new
reporting requirement -- any event or condition that
required corrective action for a single cause or condition
in order to ensure the ability of more than one train or
channel to perform its specified function.
The Staff and the industry met on February 25th,
2000 to discuss this requirement. The Staff agrees that
there are problems with the requirement. The Staff plans to
meet on Monday, March 6, 2000 to decide on a course of
action and they plan to brief the ACRS on the resolution of
this matter on April 5-7, 2000 ACRS meeting.
I believe we have representatives of the Staff
here that can explain to us what the issue is and what you
expect to see as a closure and if also you believe that by
the April meeting we will be able to hear a report and write
a letter. Thank you.
MR. BARTON: You have got to come up front so we
can take a shot at you.
MR. ALLISON: My name is Dennis Allison. The
issues that arise with this criterion, which were really
unexpected to the Staff -- but assume you have a routine
monitoring program for heat exchangers to check for fouling
and you find that they are fouled, they are operable, but
there has been some fouling and you decide to clean two heat
exchangers.
That could be considered to fall under this
definition. It wasn't what was intended but it could be
considered a corrective action to ensure operability, so it
needs to be clarified and I would expect we'll clarify it
one way or the other.
I think at the meeting the licensees showed us
lots of things that we didn't want to be reported that would
be, so one could list a long list of exceptions. That is
not --
DR. BONACA: Could you give us an example of what
you would like to be reported and then an example of what
the industry is concerned that you agree that should not be
reported?
MR. ALLISON: Yes, sir. The kind of thing we
would like to be reported would be, say, you find a valve
stem that is cracked nearly through, so that 75 percent -- I
think there is an example in the package to that effect.
DR. BONACA: Yes. I remember that.
MR. ALLISON: Because you used the wrong material
in a plant modification, so it is corroding rapidly. You
decide that you need to replace the valve stem in the other
train as well, even though it might not be so bad yet, but
you are going to replace them with new material.
The reason we would like to see something like
that is that there is a little lesson there. Now in this
particular case that probably wouldn't end up in a bulletin,
but there is a lesson there. That is, if you use this
material you get rapid corrosion in this situation. Maybe
it is something we don't know about. So that is what we
would like.
I don't think there's a problem with that. That
is, I don't think the industry really objects to reporting
that situation.
Something that we wouldn't want to hear about is
the example I just gave of routine maintenance. You clean
two heat exchangers -- it could be considered.
A suggestion that licensees throughout the last
minute at the meeting and it seemed like it would work would
be to say something like the following -- an event or
condition that as a result of a single cause or condition
could have prevented fulfillment of the safety function of
two trains.
That is kind of a hybrid between two existing
requirements that they know how to interpret. They know how
to interpret the term "could have prevented fulfillment of
the safety function" and they know how to interpret the term
"as a result of a single cause or condition." So that is
another possibility.
DR. BONACA: But they agree that there is a
category of issues that should be reported?
MR. ALLISON: Well --
DR. BONACA: At least they are willing to
entertain that?
MR. ALLISON: Yes. I think industry is mostly
concerned with clarity and clarity can be interpreted to
mean unintended consequences, like a whole lot of situations
that shouldn't be reported.
They are also concerned about the process. They
don't want to have to review every deviation report,
thousands of things, all the maintenance things they do in
the plant for reportability. They would like something that
is a little easier to recognize and is clear.
DR. BONACA: Although it seems to me that I mean
for an event like the cracked stem you would have, you know,
a root cause evaluation most likely and that would end up in
the corrective action program with a pretty high level.
MR. ALLISON: I would think so, yes.
Now one of the things -- a technical point. I am
not sure that you want to get into it, but a technical point
is when we drafted that guidance we said that this applies
only to significant conditions adverse to quality as
discussed in Criterion 16, but in turns out there's a lot of
variability in QA programs and at one plant they have a
specific definition of that in their program that would be
about right and so by its terms this criterion would be
about right for that plant, but at another plant everything
they do to correct the problem is just a corrective action.
They don't make that distinction.
DR. BONACA: Do you believe that you will be able
to resolve this issue by the April meeting?
MR. ALLISON: Yes, sir. I have recommended that
we take a little more time -- I don't know if that will be
approved -- to try to make sure we get a criterion that does
not have unintended consequences and if that is approved I
will have it resolved by the April meeting. If it is not,
then it will be resolved sooner.
DR. BONACA: Okay. We are not going to write
anything until this issue is resolved.
DR. SEALE: Not until we have something to comment
on.
DR. BONACA: Because I mean we already commented
favorably regarding the changes that you were proposing to
make to 10 CFR 50.72 and 73 and the only issue of
significance to come up was this one, and so we will wait
until we hear from you. Okay?
MR. ALLISON: Now I guess there is a possibility
that we would decide to proceed rapidly by some means like
using this or deleting it or something and go ahead. There
is that possibility but it doesn't seem like a realistic one
to me.
DR. BONACA: Okay.
MR. SIEBER: Would this be one of those issues
that one would call a process issue as opposed to a
technical issue?
CHAIRMAN POWERS: I don't know.
MR. SIEBER: If it's really truly a process issue,
then they can go ahead without us.
DR. BONACA: Well, yes -- you mean without our
review?
MR. SIEBER: Yes.
MR. DUDLEY: The technical issue involved with
this is that they did delete the requirement to report
conditions outside the design basis and there is a subset of
events that would have been reported that's trying to be
captured by this new criterion which are those events that
could lead to an inoperability, more than a train, looking
for a common cause failure.
It would be of interest to the rest of the
industry.
MR. SIEBER: So we have to see it before they can
go beyond that?
MR. DUDLEY: That's correct.
MR. SIEBER: In your opinion.
MR. DUDLEY: In my opinion it is how they finally
resolve the issue and the wording that is used because the
industry was saying with this reading every time they went
in to calibrate a piece of equipment, they would be
undertaking a corrective action due to instrument drift on
several instruments --
MR. SIEBER: That's true.
MR. DUDLEY: -- and would have to report it, and
taking it a little bit further, they were concerned that
every corrective action that they took within the plant
would need a root cause analysis to determine whether it
could result --
MR. BARTON: Reportable.
MR. DUDLEY: Whether it was reportable, and the
industry felt comfortable if they were already doing a root
cause analysis that they would already have that information
and that was probably an appropriate level to report.
MR. SIEBER: Thank you.
DR. BONACA: For our part I mean we need to have a
final resolution before we can make a judgment on other
resolutions so we will wait until we hear and we will not
write a letter now.
MR. ALLISON: Okay. Is there anything else?
DR. BONACA: Any other comments regarding this
issue or questions?
MR. BARTON: No questions, no comments. Thank
you.
DR. APOSTOLAKIS: Okay. I understand the Staff is
here for the next item.
MR. BARTON: But can you start before the posted
time?
DR. APOSTOLAKIS: A Federal employee told me I
could.
MR. BARTON: A Federal employee told you? Did you
believe him?
[Laughter.]
DR. APOSTOLAKIS: The next item is proposed Final
Revision 3 to Regulatory Guide 1.160, Assessing and Managing
Risk Before Maintenance Activities at Nuclear Power Plants.
The cognizant member is Mr. Barton, so he is in
charge.
MR. BARTON: Thank you, Mr. Chairman.
The last time we met with the Staff on this issue
was in November and at that time the committee recommended
that the proposed Rev. 3 to Reg Guide 1.160 be issued for
public comment.
We did have an additional comment though, and we
requested that our issue or definition of "unavailability"
be addressed.
During the comment period and resolution of the
comments. The comment period is over, the staff and
industry have I think reconciled the minor differences they
had on this Reg. Guide and the staff is here to present to
us how the guide has finally been resolved and to, I guess,
talk about the definition of unavailability, which will
close out this issue for the Committee.
DR. APOSTOLAKIS: This issue again?
MR. BARTON: Well, George.
DR. APOSTOLAKIS: This is one of the simplest
concepts, reliability.
MR. SCOTT: Okay. Good evening, I guess, almost.
MR. BARTON: Just about.
MR. SCOTT: Mr. Chairman and ACRS.
DR. POWERS: It hasn't even gotten good and
started yet.
MR. SCOTT: My name is Wayne Scott, I have been
acting since Rich Correia, who you all known and love, moved
on to NRR Projects back in November. As you said, Mr.
Barton, we have been through all these steps along the way.
We hope we have satisfactory resolution for your ears today,
and maybe this is our last time.
I want to point out one thing, by the way, that we
have said all along we were terms of Revision 3 to Reg.
Guide 1.160 and what we have really decided to do instead to
issue what the Reg. Guide people call a companion guide. At
this point in time the guide is called 1.XXX. It will have
a number different from 1.160. It will specifically address
the change in the rule and will endorse NEI's Section 11 of
their NUMARC 93-01 document.
So, rather than putting out a whole new Reg. Guide
and opening all the Pandora's box there and having them do
the similar thing with 93-01, they are issuing Chapter 11
uniquely, as well as a couple of pages to their appendices
that we will talk about, and we are endorsing it through a
separate Reg. Guide that is called the Companion Reg. Guide.
Our assumption is that shortly, you might say
maybe within a year or so, we will issue Revision 3 of Reg.
Guide 1.160 which will fold in more clarifications from the
baseline inspections and from inspections and changes in
oversight policy, program, all that sort of stuff, as well
as the issues with respect to the new (a)(4) into -- that
will be into Revision 3 of Reg. Guide 1.160 at a later date.
So, with that, I would like to turn over the
program to Dr. See-Meng Wong. Dr. Wong was the author, the
principal author of the NRC's initial Regulatory Guide in
this area before NEI decided to participate, so I think it
is appropriate that he take the floor.
MR. WONG: Good evening. I am See-Meng Wong from
the PSA branch and --
MR. BARTON: Welcome back.
MR. WONG: Thank you. Since we have been
scheduled for this last presentation for today, I thought it
was appropriate, this may be the end of the road for us.
But --
MR. BARTON: We can't afford to burn out any more
engineers, that is for sure.
MR. WONG: Right. I just want to briefly bring up
to date the Committee on what has transpired since the last
briefing to you on November the 4th. Essentially, on
November the 10th we provided a briefing to the Commission
on the status and the development of the Reg. Guide and
informed the Commission on the objectives. Our objective
was to endorse acceptable industry practices and also to
define an optional scoping criteria.
As a result of that briefing, we provided the
guidance package to the Commission for information on
November the 30th and sometime in December, we issued it for
public comment in the Federal Register. As of January 10th,
we have completed our 30 day public comment period on the
draft guidance.
The next slide, essentially, is probably where
most of the discussion is today, is on the public comments
that we received. We received comments from seven
utilities; from one state agency, which is the Illinois
Department of Nuclear Safety; Winston & Strawn, which is a
legal firm representing several utilities; and NEI.
The specific comments that we have gotten from all
these organizations essentially was to request an extension
of the 120 day implementation period. The requests varied
from 240 days to about a year. And, in fact, the request
from the utility that wanted a one year extension was so
that they could go and try to upgrade their program.
In fact, they provided a very detailed timeline of
what they have to do to scope, you know, the SSCs that they
need to be part of the (a)(4) assessments, the procedures,
the training and the testing of the program, and also a
self-assessment to make sure that they have got a good
program in place before the inspectors show up.
The second specific comment, this came about
actually from NEI, and it is really an industry proposal to
try to define a clear boundary between where the 50.65(a)(4)
and 50.59 interface. And in the package that we have
submitted to you, this will be on page 3, on Item 6, and
also on page 17 on Section 11.3.8.
The industry proposal is that they want to make
sure that for competency measures that address degraded
conditions prior to the performance of maintenance be
subject or be under the purview of the 10 CFR 50.59. And if
the competency measures is being used as part of risk
management action during the maintenance activity, they want
it to be subject to the (a)(4) assessment. What they are
trying to do is they want to avoid two assessments for
probably the same change in the conditions.
So, subsequent to the package that they have
provided to you, and I want to show you the language that
they have added which is not in your package, just for
discussion purposes. This is not in your transparency. On
page 3, in Section 11.3.2, they have added a note which says
that "If, during power operation conditions, the temporary
alteration associated with maintenance is expected to be in
effect for greater than 90 days, the temporary alteration
should be screen, and, if necessary, evaluated under 10 CFR
50.59 prior to implementation."
And in Section 11.3.8, at the end, very end of the
second paragraph they have added the sentence, or the
statement after the last sentence which said, "Since the
competency measures are associated with maintenance
activities, no review is required under 10 50.59 unless the
measures are expected to be in effect during power operation
for greater than 90 days."
This issue was discussed and presented to the
Commission by the people -- that are involved in the
development of the 50.59 regulatory guidance. Questions
were asked, why did you take 90 days? And the answer that
was given was it was arbitrary, they chose it at this time
without any good basis. Yes?
DR. APOSTOLAKIS: I have just a question a
clarification.
MR. WONG: Yes.
DR. APOSTOLAKIS: Could I take Regulatory Guide
1.177 which deals with outage times, --
MR. WONG: Yes.
DR. APOSTOLAKIS: -- and have some bounds on the
probability, the incremental probability of core damage and
so on?
MR. WONG: Yes.
DR. APOSTOLAKIS: Could I take that one and come
to you and argue that, you know, for 90 days or 100 days,
the incremental probability is below the limit, so I
shouldn't have to do this? Am I allowed by all this to do
this?
MR. WONG: Okay.
DR. APOSTOLAKIS: I mean this is a temporary
configuration, right?
MR. WONG: Right. The temporary configuration
they are talking about are these like scaffoldings that they
have in place.
DR. APOSTOLAKIS: So they are below the PRA
consideration.
MR. WONG: Below, right. It is probably not
modeled in the PRA.
DR. APOSTOLAKIS: Or maybe not at all.
MR. WONG: That is correct.
DR. APOSTOLAKIS: So why 90 days, why not a year?
MR. WONG: Well, if it is a year it is too long,
and -- well.
MR. BARTON: He said it is arbitrary, I don't know
why the 90.
MR. WONG: Right. Right.
MR. BARTON: But there is a requirement now, if
you gave a temporary modification, you have to do a 50.50.
Now, all of a sudden we are saying if it is only for 90
days, I don't want to do a 50.59. Is this what this is
saying?
DR. APOSTOLAKIS: Yes.
MR. WONG: Yes. Yes. This is what --
MR. SCOTT: If it is specifically --
DR. POWERS: For the maintenance.
MR. SCOTT: -- related to and required by the
maintenance activity. Basically, they are getting a little
bone here. And what we are talking about is, as See-Meng
mentioned, if they have to put up some scaffolding, if they
put some shielding in perhaps.
We even talking about tearing down maybe a little
wall or opening a door that normally is not open. If they
have to do that in order to perform the maintenance, then
the concept is they do, perform the maintenance, and then
put it back like-for-like, like it was, and if they can get
all done within arbitrarily chosen 90 days, and so far that
seems to be flying all right, because Gary Holahan basically
was one of the principal players in the decision to come up
with that 90 days. And he assures us that what we are
really talking about here is stuff that is not covered by
tech specs, it is not in a PRA, it is really of relatively
very low safety significance. So --
MR. BARTON: It is a temporary modification to the
plant.
MR. SCOTT: Well, --
MR. BARTON: Yeah, it is. Right?
MR. SCOTT: Yeah, except we had -- listening
yesterday at the Commission -- was it yesterday?
MR. WONG: Two days ago.
MR. SCOTT: Two days ago at the Commission
meeting, Harold Ray from San Onofre took exception with Tony
Pietrangelo talking about temporary alterations, temporary
mods, temporary changes, and what he really said, basically,
is if it is for maintenance and you it back like-for-like,
it is not a change, it is not an alteration, it is not a
mod. I don't know what the right word is, but it is a
temporary -- I looked through the thesaurus today in my word
processing system trying to find a better word to put into
this last piece of the Reg. Guide that is up there. But it
is a temporary --
DR. APOSTOLAKIS: But expected perhaps.
MR. SCOTT: Yeah.
DR. APOSTOLAKIS: Temporary expected activity.
MR. BARTON: To me it is a temporary, whatever you
want, if I put scaffolding up in the plant, I have got to a
safety evaluation of scaffolding. So all of a sudden I can
do all this stuff in 90 days and don't have to do it. I am
with you.
MR. SIEBER: A temporary mod could be a hose, a
hose or a jumper or a lifted lead.
MR. SCOTT: The idea is that --
DR. APOSTOLAKIS: Are you saying, John, that they
should do it?
MR. SCOTT: Yeah. As part of --
MR. BARTON: I am saying I don't understand why
all of a sudden the same thing I would do if I didn't do
maintenance, but put scaffolding up for a mod I am going to
do later, or some change I am going to do to the plant, I
have got to do an evaluation because it is a temporary
modification, I am going to have it in there for a while.
MR. SCOTT: The evaluation does not disappear, the
evaluation, however, is done under the aegis of the (a)(4)
safety assessment and management of the risk as opposed to
through the process of 50.59. That is really the change.
The assessment we expect, the NRC's expectation is the
evaluation of whatever they evaluate when they put up
scaffolding, that evaluation will nonetheless take place, an
engineering evaluation of hanging lead shielding on a pipe
or whatever they do with that sort of stuff. Those kinds of
things will still have to be done, but they won't have to go
through the formal 50.59 process, they will be handled
through the maintenance risk assessment and risk management
process.
DR. APOSTOLAKIS: So Mr. Ray disagreed with the 90
day?
MR. WONG: No, no, he didn't.
MR. SCOTT: No, he didn't. No, he just said,
basically, it is not a temporary alteration if it is
something you are going to do for maintenance and then put
it back in place. A temporary alteration is something of
long-term that is actually altered like the lifted leads.
DR. BONACA: Or like lead shielding. I mean I
know of some cases in the past where I have seen that the
safety evaluation helped identify some significant issue
that maintenance people totally missed.
MR. SCOTT: Sure.
MR. WONG: Sure.
DR. BONACA: And so it was useful in that sense
because it focused the evaluation on some significant issues
you had to consider. So I am not as comfortable as other
people seem to feel, but --
MR. WONG: Well, given the slight discomfort, this
is what we attempted to put some clarification statements in
our Reg. Guide in the implementation section, and this is
what we have crafted, that the assessment does not relieve
the licensee from obligations to his license or the
regulations, and the exemption requirements in 10 CFR 50.90
remain effect, and the intent here is to eliminate
overlapping requirements for assessments which could be
considered to exist under 10 CFR 50.65(a)(4) and 10 CFR
50.59. This clarification applies to temporary alterations
directly related to and required to support a specific
maintenance activity being assessed.
DR. BONACA: Okay.
MR. WONG: There is also the thought that we will
see how it is being implemented. If there is going to be an
abuse, we may just make a revision and maybe shorten the
time or rescind this.
DR. SEALE: What are you guys going to do if the
scaffolding suddenly shows up two weeks after it has been
taken down after being up for 90 days?
MR. SIEBER: A violation.
MR. SCOTT: Well, we thought about that, and one
of the issues in that area, we think that what is going on
in the industry these days is a real stretch for
profitability, and we have discussed that specific issue.
What if they take a door out and then -- for 89 days and
then they put it back in and take it back.
We don't really expect to see that for the simple
reason that it costs money to take that scaffolding down and
put the scaffolding back up. So it would seem to us to be a
lot simpler process, if they are going to leave that
scaffolding up and they want it up for a longer time, that
they should go right to the 50.59 in the beginning, or at
least as soon as they recognize that they are going to pass
the 90 day barrier.
And it is our opinion, I think that the cheaper
method is to do the 50.59 than to go through all the
rigmarole of tearing down the scaffolding and putting it
back up.
MR. SIEBER: That's true. I guess one way to look
at it, though, is if you are going to do a temporary mod
inside the boundary of the equipment you are working on,
let's say you are going to overhaul a pump, okay, and your
mod puts scaffolding around the pump, you know, you could
put that right into 50.65(a)(4) without any problem at all.
But if your modification affects some other
independent piece of safety-related equipment, it seems to
me to be more pertinent to do a 50.59 because now you can
take two trains out, where you can take two alternate pieces
of equipment out if the modification is incorrect or it
fails.
MR. SCOTT: Well, that should be, in my opinion,
that should be part of the overall assessment that the
licensee makes.
MR. SIEBER: Under (a)(4).
MR. SCOTT: Under (a)(4), integrating all those
aspects of the activity.
DR. POWERS: It sounds to me like they are making
a first step toward a risk-informed 50.59 here in this one
narrow area.
MR. SIEBER: That's true. In some plants, though,
it is maintenance people that do the (a)(4) evaluation
versus engineering and operations that do 50.59, so it is
two different levels of expertise and I am not sure they are
equivalent.
MR. SCOTT: Well, we expect that is going to have
to change, other people getting involved.
DR. POWERS: You suspect it is going to have to
change because of the language of 50.65(a)(4)?
MR. SCOTT: Sure.
MR. SIEBER: All right.
MR. WONG: Okay? Our other comments are
essentially very, very minor comments. In response to Mr.
Barton's questions, there were comments on unavailability,
but I think we have essentially beaten that to death, and
the definition that is provided in your package has been
agreed to by all the organizations that we know of except
WANO.
And when it was first proposed I really Professor
Apostolakis wanted to burn away that definition, but we made
an attempt to try to come up with the best that we could
have, and to try to clean it up so that it addresses
specifically the practical aspects of what we are trying to
use the definition for, which is to track the unavailability
of the equipment for the purposes of maintenance. So other
comments essentially are just choice of words, adjectives
and we have had a meeting with NEI to come to agreement with
what the words should be so that it provides clarity in the
guidance. Okay.
DR. APOSTOLAKIS: Now, let me understand this
definition in Appendix B.
MR. WONG: Okay.
DR. APOSTOLAKIS: When you say planned unavailable
hours plus planned -- unplanned unavailable hours divided by
the required operational hours, what exactly does
unavailable mean? I mean this is a definition of
unavailability. Does it include -- is it only the time that
you took it out to do something to the equipment?
MR. SCOTT: In Maintenance Rule space something is
not available if it is unable to perform the function that
got the SSC in the Maintenance Rule in the first place.
DR. APOSTOLAKIS: So this is only for maintenance,
this definition? The fact that it may be available in this
sense, but fail during the demand is not included here.
MR. SCOTT: I reckon that is true.
DR. APOSTOLAKIS: And that is --
MR. SCOTT: We are really looking at treatment of
systems in the Maintenance rule where, you know, the rule is
monitoring the effectiveness of the maintenance. And, so,
as you pointed out in your letter, it depends on whether it
is a standby piece of equipment or continually running, and
that sort of thing.
DR. APOSTOLAKIS: You actually read it. Good.
MR. SCOTT: A couple of months ago I had it
memorized, sir.
[Laughter.]
MR. SCOTT: We have, on this subject of
availability, we have had -- gracious, we probably have our
own TAC number for unavailability. And we have had people
going to national conferences and international conferences.
This is not just something that we just made up, you know.
DR. APOSTOLAKIS: No, I realize that.
MR. SCOTT: Right.
DR. APOSTOLAKIS: But I would be much happier if
you explained that this is a definition that applies, you
know, to these issues. I mean I guess it is understood
because you continue and talk about -- I mean you go on and
talk about maintenance activities and testing and so on.
MR. SCOTT: It also is involved very much in the
new performance indicators. I assume you have been involved
in all that.
DR. APOSTOLAKIS: Yes, and I have the same problem
there.
[Laughter.]
DR. APOSTOLAKIS: Let's see, what are we doing
here, Mr. Barton? Are we going to approve this?
MR. BARTON: Well, that was the intent, yes.
DR. SHACK: Now, what is the status of that
language? I mean that is -- the staff is now proposing to
approve the NEI document with that language added to the
sections and you are going to add that language to your Reg.
Guide and that is now staff approved and you are asking us
to approve that?
MR. SCOTT: We are at the point right now where we
have a Regulatory Guide -- oh, you are talking about this?
DR. SHACK: Yeah.
MR. SCOTT: Yes.
DR. SHACK: The Regulatory Guide plus that
language and the NEI guide that we have in our hand, plus
that language.
MR. SCOTT: Exactly right. That is the package.
DR. SHACK: You have approved that and now the
question is, are we going to approve it?
MR. BARTON: That is the question.
MR. SCOTT: Right. Exactly right.
DR. APOSTOLAKIS: Is it possible to add three
words here somewhere, or is it too late? Unavailability due
to maintenance operations is defined as follows. That is
correct, if you put those words "due to maintenance
problems."
MR. SCOTT: I am sure when you ask that question
you really don't have a good feel for what it would take to
make the change, not just in our Reg. Guide, that is not the
issue, the issue is -- is Don Dickman here? No. Throughout
all the apparati that collect unavailability data, that have
been set up, the data systems, the performance indicators,
the agreements with INPO and -- truly, I haven't been to
those meetings, so I don't know how all those other people
are, but to make a modification like that would be, for our
purpose, for this purpose, would be correct, but no easy
thing to do, sir.
MR. GILLESPIE: George, let me make sure I
understand, because we collectively may not be
communicating. The unavailability here is the same as
oversight, it is not just unavailability from maintenance.
If you have a demand failure and you find something
inoperable, that downtown also counts on the unavailability.
It is exactly the same unavailability that we talked about a
little earlier when the oversight group was here.
DR. APOSTOLAKIS: Yes, but, again, that is a
little different.
MR. GILLESPIE: It is not the reliability, it is
not the demand failure, but if you demand it and then find
out it is inoperable, --
DR. APOSTOLAKIS: Yes.
MR. GILLESPIE: -- that time of inoperability then
starts accumulating as part of the numerator of the
fraction. So it is not the same as what you just so.
DR. APOSTOLAKIS: No, I understand that.
MR. GILLESPIE: Okay.
DR. APOSTOLAKIS: Let's say you are testing
something every first of the month, for example.
MR. GILLESPIE: Right.
DR. APOSTOLAKIS: And you find out that the first
of February -- first of January was okay, first of February
was not. And then somehow you find out that it had been
failed for six days.
MR. GILLESPIE: Yeah.
DR. APOSTOLAKIS: So that, those six days will be
part of the unplanned unavailable hours.
MR. GILLESPIE: Yes.
DR. APOSTOLAKIS: Okay. But that still does not
account for the fact that it may have been available for all
this period, but it failed due to something that happened
during the demand.
DR. SEALE: Yes.
DR. APOSTOLAKIS: That part is not here. And all
I am saying is, if you say that this is due to -- I mean we
have to find the words. You are right, it is not just
maintenance.
MR. GILLESPIE: Yeah, and this is why we are
groping now in working with Research to try to find the
corresponding reliability or demand measure that goes with
this as a set, and we are just not there.
DR. APOSTOLAKIS: If we could put an asterisk
there, put at the end something that this is not the
unavailability that we are talking about in PRAs, this is
not the unavailability we are talking about in reliability,
this is not the unavailability that you will find defined in
a book. This is not it. There is nothing wrong this.
MR. GILLESPIE: You're right.
DR. APOSTOLAKIS: As long as you make it clear
that you are talking about this particular thing. You are
saying, administratively, that is not easy.
MR. WONG: Well, we can suggest it to NEI, because
that is there document.
DR. APOSTOLAKIS: Well, they know what it is,
right.
MR. WONG: Yes.
DR. APOSTOLAKIS: Yes.
MR. WONG: I think we can try to do that. Okay.
MR. BARTON: Let's go back to the definition of
the -- I am tired of unavailability, the other one, the
50.59 issue.
MR. WONG: Okay.
MR. BARTON: I need to see the words again. Let
me ask you something.
MR. SINGH: I will get a copy.
MR. BARTON: I am going to do a refueling outage,
I am going to do 489 maintenance items, and I am going to
erect scaffolding all of the place, take doors down, put
shielding all over the place.
MR. SCOTT: There is a caveat that says this is
issue is an at power issue.
MR. BARTON: It is a what?
MR. SCOTT: At power.
MR. WONG: At power.
MR. SCOTT: We are not trying to change the
licensee's outage.
MR. BARTON: That is why I wanted to see this
again, because I have got a lot of concerns if I just want
to do 50.59, I can do all kinds of modifications, and put
all kinds of stuff in the plant and leave it there for 90
days.
DR. BONACA: But even at power, 90 days, now they
were doing, they are making changes every day pretty much,
taking out some systems, components, putting them back in.
So now you have all the scaffolding and you are not
evaluating the impact of the scaffolding on -- are you
evaluating the impact every day as you do it?
MR. SCOTT: Every time there s a change. That is
the issue with the (a)(4), when there is a change in the
configuration of the plant, then there should be a
reassessment.
DR. BONACA: A reassessment, and that reassessment
will include the temporary modifications that are in place?
MR. SCOTT: That is the intent, yes. That is the
Commission's expectation.
MR. BARTON: That will now require that be done.
MR. SCOTT: Right. Essentially, what had been
being done before under 50.59 in this area would move over
under the responsibility --
MR. BARTON: 50.65(a)(4).
DR. BONACA: So you would have to perform it under
your PRA evaluation or whatever, Maintenance Rule.
MR. BARTON: Under (a)(4).
DR. BONACA: And that temporary addition or
whatever, alteration, will have to be considered.
MR. SCOTT: Yes.
DR. BONACA: For all the 90 days, on every change
you may.
MR. SIEBER: That's okay.
DR. BONACA: Oh, yeah, in principle it is okay. I
am trying to figure out all the thousand possible ways it
can fail.
MR. SCOTT: Yes, me, too. This issue arose when
somebody --
DR. BONACA: They always talk about, you know,
everything is perfect out there. Why is an organization
with other people -- and things always, this kind of stuff
always falls into crack. Oh, we didn't consider -- oh, we
didn't consider -- oh, we missed that, you know. I mean,
have you heard that before?
DR. POWERS: Never, Mario.
MR. SIEBER: I haven't either.
DR. POWERS: At his utilities, nothing will ever
fall in the crack.
MR. SIEBER: But things fall through the crack
whether it is 50.59 or 50.65(a)(4), you know, same crack.
MR. SCOTT: The issue as raised to us, that we
said, oh, gosh, let's think about that, was the issue of a
licensee having, say, valves in the overhead that needed to
be testing once a year. And so they put up -- they open a
maintenance activity, they put up the scaffolding, they test
the valves, and they leave the scaffolding up and they don't
close the maintenance activity.
MR. SIEBER: Right.
MR. SCOTT: And any time anybody would point out
at it, the issue, oh, well, we are still doing maintenance.
So the scaffolding stays up forever because every year they
walk up it and test the valves. So we said that is out of
the question, we don't want that to happen. We want people
-- our expectation is that they will do these things,
perform the maintenance, and then put them back the way they
were.
And if we find the licensees taking advantage of
this issue, then we are going to revisit it.
DR. BONACA: I guess the concern is already we
attempted to address within the Maintenance Rule the issue
of multiple configurations and complex configurations,
including multiple components. Now, we are addressing the
issue of adding to that.
MR. SCOTT: Temporary alteration.
DR. BONACA: Temporary alterations that would be
there in place overlapping for periods of time which would
make the configurations even more complicated.
MR. SCOTT: That certainly is true. But the risk
-- the assumption in all this issue is that the risk of this
activity is so low, it is not covered by tech specs, it is
not covered by any regulation beyond the 50.59 sort of
thing.
MR. SIEBER: Let me ask a simple question. It was
our practice back when I worked in power plants to specify
in a lot of maintenance procedures what temporary mods like
jumpers and lifted leads or what-have-you, where they were
to be installed and all that, and then when the procedure
was approved, a 50.59 evaluation was done on that procedure.
MR. SCOTT: Right.
MR. SIEBER: Does that make you redo 50.65(a)(4)
for all those changes that were already approved in the
procedure, temporary mods?
MR. SCOTT: I have to say yes because (a)(4) is an
integration of the status of the plant at any particular
time.
MR. SIEBER: Right.
MR. SCOTT: And if a new activity, maintenance
activity comes along, then that activity and its associated
pieces have to be assessed.
MR. SIEBER: So the burden goes up then for the
licensee, because he ends up doing it twice.
MR. GILLESPIE: Yeah, I think one of -- what
brought this to the fore was (a)(4) and the requirements of
(a)(4) exist no matter what.
MR. SIEBER: Right.
MR. GILLESPIE: So then the question was, do I
have to do 50.59 in addition, or is what I did for (a)(4)
good enough to fill both slots? So this doesn't change the
requirements under (a)(4), it is just that we hadn't thought
that part of the risk to the plant is heavy loads, it is
staging, it is putting those jumpers in. But, in fact, the
way (a)(4) was worded, it did already encompass this. And
when people visualize that, they said, okey, now we have to
do it under (a)(4), and, oh, shoot, now we have to do it
under 50.59. So now we are doing the same assessment twice
for everything, and this was an attempt to say, no, one
assessment is okay.
DR. POWERS: This is really not the same
assessment because the standard --
MR. GILLESPIE: Different. Different. Okay.
This is probably considered less onerous than the 50.59.
DR. POWERS: You have got more freedom under 65
than you do under 59.
MR. GILLESPIE: Yeah, you do. Yes.
DR. POWERS: Because one of them is a minimal
increase and the other one is a change in risk.
MR. GILLESPIE: Yeah, absolutely.
DR. POWERS: It is really just a risk management.
MR. GILLESPIE: It says manage and assess, right.
DR. POWERS: That's right.
MR. GILLESPIE: So you need enough information to
manage and assess. So it was kind of a double jeopardy.
The utilities were going to be stuck with both requirements,
and then what was the proper interface? So, and that is how
this really came about. But it doesn't really change
(a)(4), it just caused us to focus on what (a)(4)
encompassed.
MR. SIEBER: Thank you.
DR. BONACA: I guess just one last thing. My only
concern I am thinking about how people operate, and if you
are exercising a PRA, you are able to address multiple
changes there. I am not sure that you are going to reflect
the scaffolding in the PRA. You are simply going to perform
an evaluation and say, does it impact this area?
Now, I am trying to think how the PRA analyst
which doesn't live inside the plant with the maintenance
people is going to evaluate this consideration of all these
added components which are not in the PRA, to his PRA
evaluation.
MR. GILLESPIE: Yeah, this is much easier guidance
to say it looks good than it is to implement. This is going
to be a challenge because it is a different animal.
DR. BONACA: Oh, sure.
MR. GILLESPIE: And we are going to be looking at
things like the PRA analyst match of the maintenance guy,
where the maintenance guy has to figure -- think about
single failure-proof cranes, heavy loads over pumps. And so
you have got this spatial distribution that the PRA guy is
normally not interested in, but now he has to be interested
in it.
So it is a different kind of analysis. It is
going to be interesting to see how the industry implements
this, because their traditional organizations are really not
set up right now to step right into this. They have all the
right people, they are just not necessarily in the right
work units to integrate this together. Yeah.
DR. BONACA: That is exactly why I was asking
myself the question. I was trying to figure out from memory
how they work out, and they don't converge oftentimes.
MR. GILLESPIE: Which I think may lead to the
other side that they had, that 120 days may not actually be
enough time to implement what has come out of all the
discussions on this, if this represents kind of the end
point. And many of the people who commented said, we didn't
-- we are going to need more time now.
MR. WONG: Okay. The last slide is, where do we
go from here? Our target date to provide the final guidance
package to Commission for review and approval is March the
31st and the Commission can decide, given the comments that
we received, whether they will extend the 120 days, that is
their prerogative. That is all we have.
DR. APOSTOLAKIS: So the Committee action is a
letter?
MR. WONG: Yes.
MR. SCOTT: Yes.
DR. POWERS: Could you just sketch out for me one
more time about this business on a companion guide?
MR. SCOTT: It is a separate Regulatory Guide. It
will endorse the revised Section 11 of NUMARC 93-01, and has
words in it that states it works, essentially, in concert
with 1.160. So it focuses completely on (a)(4) as does the
Section 11.
DR. POWERS: Really, all I am interested in, is
there anything that is going to come back to us on this?
MR. SINGH: No.
MR. BARTON: This is it.
DR. POWERS: This is it?
MR. WONG: This is it. Yes.
DR. POWERS: It was a scheduling concern.
MR. BARTON: No, it is not Rev. 3 to Reg. Guide
161. The title of this thing is going to be what?
MR. SCOTT: Companion Guide 1.XXX.
DR. SEALE: Well, right now it is Reg. Guide 1.XXX
and Research won't assign a number to it until after the
Commission approves it and it heads over there for --
MR. BARTON: Is it still Rev. 3? Is it still Rev.
3?
MR. SCOTT: No.
MR. BARTON: It is just Reg. Guide 1.XXX?
MR. SCOTT: It is an independent Reg. Guide, yes,
sir.
MR. SIEBER: It doesn't have a Rev. yet.
MR. BARTON: And it is called Assessing and
Managing Risk Before Maintenance Activities at Nuclear Power
Plants?
MR. SCOTT: Right.
MR. WONG: Yes.
MR. BARTON: Okay. Any other questions of the
staff? Does the Committee feel comfortable when I write
this letter that we endorse proceeding for industry use with
what we heard?
DR. SEALE: I take it there is no one from
industry here?
MR. SCOTT: Biff Bradley was going to be present.
I talked to him this afternoon, he said that he feels
comfortable not being here, that they are in complete
agreement with what we are up to and so we end here.
DR. APOSTOLAKIS: I might add an additional
comment, I don't think it is worth the Committee's time to
argue about availability, but I think, for the record, it
should be there.
DR. POWERS: George, we can include in the meeting
minutes a protracted discussion with references, citations
and equations.
DR. APOSTOLAKIS: Oh, no, no, no. It is not worth
it. It is not worth it.
DR. POWERS: Oh.
DR. APOSTOLAKIS: It is a simple definition.
DR. POWERS: Mr. Barton, are we through with this
subject?
MR. BARTON: Yes, I think so. I'll turn it back
to you.
DR. APOSTOLAKIS: Are you happy with this?
MR. BARTON: I am not sure.
DR. APOSTOLAKIS: Oh.
DR. POWERS: I think we need to talk just a little
bit about this, but, on the other hand, what I see, my
personal view on this is that you are carving out a little
space to begin the construction of a 50.59 that is
risk-based. Okay. And this is a good thing.
DR. APOSTOLAKIS: Then I support it.
[Laughter.]
MR. GILLESPIE: Okay. Take down what George says.
DR. POWERS: If -- if and when you can get your
availability definition.
[Laughter.]
MR. GILLESPIE: I will say, you have really seen
-- this is the -- I think when we look, as we are
approaching a risk-informed regime, of something more
risk-informed, this is the first place where we have seen
potentially actually an organizational impact on utilities
in how they perform a function.
DR. POWERS: That's right.
MR. GILLESPIE: So I think what you are seeing is,
in direct application of really what is the first kind of
manage and assess your risk, that we are going to see an
evolution that the traditional organizations are going to
have to adapt to to get the technical talents together that
need to do these things. So I think that is an interesting
note that is coming out of this, a revelation that
scaffolding and stuff is part of risk. Not quantifiable,
but, you know. It is different, it is different.
DR. POWERS: The rule does not require them to
quantify it, it only says manage --
MR. GILLESPIE: Manage and assess. So you have to
cognizant of it and be able to recognize its potential
impacts. Yes.
MR. BARTON: What I am struggling with, is it
really going to be easier for them to add this to their
assessment of maintenance, or is it going to be answer six
questions on a pre-screening, on a preliminary evaluation to
a safety evaluation? And I don't know why I wouldn't think
the six questions and check them all off and be done with
it. But, anyhow.
DR. POWERS: Because you can't. Because you
can't. Still, not matter you have done, you are blocked
with 65(a)-4. It says you have got to manage and assess.
MR. SIEBER: You are blocked by the rule, and it
will be an extra burden, and in some cases it will be a
double burden. That's the way it is.
DR. BONACA: Well, organizationally, it is going
to be a challenge, because 50.59 today is as incompatible
with PRA as it was before.
DR. POWERS: That's right.
DR. BONACA: You are going to have a lot of, you
know, by having been there and knowing what it is, you don't
want to have PRA people doing 50.59s because you get in
trouble with the NRC.
DR. POWERS: Well, and that is what they are
trying to do, is avoid having a bunch of 50.59 folks
intruding into the risk managing and assessing process.
Thank you, gentlemen very much.
MR. SCOTT: Thank you.
DR. SEALE: Thank you.
DR. POWERS: Let's see. Sherry, are we ready. I
don't have the tools of my trade here. I need my black
things. I think we can dispense with the recording at this
point.
[Whereupon, at 5:13 p.m., the meeting was
recessed, to reconvene at 8:30 a.m., Friday, March 3, 2000.]
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Page Last Reviewed/Updated Tuesday, July 12, 2016