Joint Subcommittees on Materials & Metallurgy and Plant Operations - July 10, 2001
UNITED STATES OF AMERICA
NUCLEAR REGULATORY COMMISSION
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ADVISORY COMMITTEE ON REACTOR SAFEGUARDS
(ACRS)
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JOINT MEETING OF MATERIALS & METALLURGY AND
PLANT OPERATIONS SUBCOMMITTEES
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TUESDAY,
JULY 10, 2001
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ROCKVILLE, MARYLAND
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The Subcommittees met at the Nuclear Regulatory
Commission, Two White Flint North, Room T2B3, 11545 Rockville Pike, at 8:30
a.m., F. Peter Ford, Chairman, presiding.
COMMITTEE MEMBERS:
F. PETER FORD Chairman
MARIO V. BONACA Member
THOMAS S. KRESS Member
GRAHAM M. LEITCH Member
STEPHEN ROSEN Member
WILLIAM J. SHACK (Recused)
JOHN D. SIEBER Member
ROBERT E. UHRIG Member
GRAHAM B. WALLIS Member
I-N-D-E-X
AGENDA ITEM PAGE
Introductory Remarks by Subcommittee Chair 3
Industry Perspectives, Larry Matthews, et al. 4
NRC Staff Presentation
Introduction, Jack Strosnider, NRR 154
Technical Discussion & Actions 157
Allen Hiser, NRR
Risk Perspective, Mark Reinhart, NRR 212
Staff Perspective Including Input From 227
"Independent Group of Experts,"
Ed Hackett, RES
Regulatory Process, Tad Marsh, NRR 249
Summary, Jack Strosnider, NRR 257
General Discussion and Adjournment 257
P-R-O-C-E-E-D-I-N-G-S
(8:32 a.m.)
CHAIRMAN FORD: The meeting will come to order. These
are Joint Subcommittees on Materials & Metallurgy and Plant Operations.
I am Peter Ford, the Vice Chairman of the Materials &
Metallurgy Subcommittee. ACRS Members in attendance are, or will be: Dr.
George Apostolakis; Dr. Mario Bonaca; Dr. Thomas Kress; Mr. Graham Leitch;
Mr. Stephen Rosen; Mr. John Sieber; Dr. Graham Wallis; and Dr. Robert Uhrig.
The purpose of this meeting is to discuss the controller rod
drive mechanism, CRDM, cracking issue and materials reliability program. This
is our first subcommittee meeting on this issue.
Ms. Maggalean W. Weston is the cognizant ACRS staff
engineer for this meeting. The rules for participation in today's meeting have
been announced as part of the notice of this meeting published in the Federal
Register on June 27, 2001. A transcript of the meeting is being kept and will be
made available, as stated in the Federal Register notice.
It is requested that speakers use one of the microphones,
identify themselves, and speak with sufficient clarity and volume so that they
can be readily heard.
We have received no written comments from members of the
public regarding today's meeting. A portion of this morning's session may be
closed pursuant to 5 U.S.C. 552b(c)(4) to discuss proprietary information.
Dr. William Shack will recuse himself from this subcommittee
meeting discussion because of a conflict of interest. Similarly, Mr. Stephen
Rosen will recuse himself from discussions specific to Duke Power Company
because of a conflict of interest.
We will now proceed with the meeting. Mr. Larry Matthews,
representing the Materials Reliability Program, will introduce the topic and the
presenters.
MR. MATTHEWS: Good morning. I am Larry Matthews with
Southern Nuclear Operating Company. I am the Chairman of the Alloy 600
Issues Task Group of the Materials and Liability Project. I will be doing most of
the presentation. I have a little back-up over here in case we get into things that
I clearly don't understand.
(Slide change)
MR. MATTHEWS: The MRP's purpose, being here -- Those
are our industry goals. In the near term, what we want to do is to assure the
structural integrity of our plants. In the longer term, we want to work toward
developing a program so that the utilities can effectively manage PWSCC in
their units.
We will be explaining the background. We have been asked
to go over the background of the head penetration issue, present our program,
and then we will get into what our recommendations for the industry are.
I have a lot of slides. So in case we don't get to it, I am going
to put the conclusions up first.
(Slide change)
MR. MATTHEWS: Basically, we have been working on this
issue for a while, and Axial PWSCC -- that is, cracks in the axial direction in the
CRDMs, we feel, do not impact plant safety if they are only Axial cracks. They
are bounded by the previously submitted safety analyses back in the '93/'94
time frame.
We also feel there is reasonable assurance that other PWRs
do not have circumferential cracking that would exceed the structural margin.
This is based on Oconee-1 and ANO-1, which have had these cracks, being in
the highest grouping based on an effective time-at-temperature for their heads.
These leaks were discovered by careful visual examination of their
heads. Volumetric examination of other nozzles in those plants in Oconee have
found only some minor craze cracking, nothing of real significance.
The leaks were discovered when there was still plenty of
structural margin remaining, and several other plants that are in the highest
groupings have examined their heads and had no evidence of leakage at this
point.
CHAIRMAN FORD: Mr. Matthews, before you come off that
graph, could you put it back, please?
MR. MATTHEWS: Sure.
CHAIRMAN FORD: When you are talking about Oconee and
ANO being in the highest grouping, that is in the United States. Were you also
be doing a reference to other incidences abroad?
MR. MATTHEWS: We have not benchmarked what we have
done so far against the other foreign plants. There's a lot of differences
between the way the plants in the U.S. were made and the ones overseas, and
so we are not sure that putting them on the same graph is the right thing to do.
We will probably be taking a look at it, but we haven't done
that today.
(Slide change)
MR. MATTHEWS: We have other activities going on in the
MRP. We are working on a risk assessment of the overall problem. We've got
some probabilistic fracture mechanics work that is getting underway.
We will be assessing crack growth data and what data is
available and where there are needs to further establish crack growth data. We
will be working on NDE demonstrations, both designing a block and fabricating
the block for demonstrating NDE capabilities and also developing the
techniques and demonstrating what the techniques are capable of detecting.
We are putting together information and training package for
utilities to use for training of their people who will be doing the visual
examinations of the head, working on flaw evaluation guidelines and reviewing
repair and mitigation strategies.
CHAIRMAN FORD: Before you take that one off, I take it all
of these will be addressed as we go through. These are conclusions, and the
supporting data for all of these will be given later on?
MR. MATTHEWS: These are activities we have ongoing right
ow. There's not a lot of results to bring forth on these activities right here. They
are underway.
CHAIRMAN FORD: And what is your time scale, and what
do you hope to achieve in that time scale?
MR. MATTHEWS: As fast as possible. We have NDE. We
are hoping to have at least an initial block built to demonstrate the capabilities
before the fall outages. So a risk assessment is underway and should be
through fairly quickly, I would think.
CHAIRMAN FORD: So should you find more cracks in other
stations during the fall outages, you will have a sufficient amount of good quality
data -- for instance, crack growth data, etcetera -- to substantiate your safety
arguments?
MR. MATTHEWS: We think so. The crack growth team is
going to meet. First meeting is in August, and that is in here. But if there's
more data needed, it takes time to generate that data, and we'll just have to go
with what data is available and conservatisms, etcetera.
(Slide change)
MR. MATTHEWS: So we know what we are talking about,
this is a diagram of the vessel head. This particular one is in the B&W unit.
You have the head. Penetrations come through the head, and they are welded
-- you'll get a little more detail on the next slide -- with a J-grove weld on the ID.
The B&W units are -- or actually, only two units, the Oconee-1
and TMI have these thermocouple penetrations out on the very edge. This is
the insulation that -- Most of the B&W units have insulation above the head that
sits up above the head in a flat plane.
There's a shroud out here, and we'll get into some of the
details of what other people have done. Other units have differing
configurations on this insulation, and makes it harder for many of them to do a
good visual, but we'll get into some of that.
CHAIRMAN FORD: So when you said earlier on that you
couldn't take into account the French experience because of differences in
design, how are they markedly different?
MR. MATTHEWS: Not necessarily designed, but as much the
material processing. How you process the alloy-600 makes a big difference,
and we believe they process their tubes considerably differently. I believe they
actually even have counter bores on the ID that none of the U.S. plants have,
and things like that.
CHAIRMAN FORD: I'm just concerned that we are throwing
out a whole lot of data, an awful lot of data.
MR. MATTHEWS: We are not throwing it out. It's certainly
going to be taken into account. Right now, what we are trying to do, though, is
just rank the U.S. plants and figure out what we need to do in the immediate
near term for the U.S. plants. All of that information is going to be folded into
the program, for sure.
DR. WALLIS: Well, the plants with the access holes get
inspection without much trouble, presumably.
MR. MATTHEWS: Some of the B&W units have cut access
holes right here that are large holes, that are like nine-inch or maybe even 12-
inch holes. I'm not exactly sure of the size. They can open those doors and
quite easily look --
DR. WALLIS: They can see right in there.
MR. MATTHEWS: -- and see all of this. The B&W units that
have not cut the access holes have what they call mouse holes, which are small
holes down at the bottom of the shroud that they can put video probes or other
techniques for getting under there.
DR. WALLIS: So you don't need to take the insulation off and
all that sort of thing.
MR. MATTHEWS: No, not for these plants.
DR. WALLIS: But for all plants, you've got some sort of hole
you can snake something in.
MR. MATTHEWS: That's not true, and I'll show you some of
that.
CHAIRMAN FORD: Is that the only detection technique you
use?
MR. MATTHEWS: Right now, that was the one we were
recommending. We have other NDE that we are looking at and evaluating.
None of it has been qualified.
We had qualified techniques for detecting a different type of
flaw, the ID initiated flaw that the French had seen, and we had qualified
techniques for doing that, and actually, plants were on a schedule to do
inspections of the lead plants anyway, of their penetrations for the ID initiated
flaw.
These flaws are different. It takes different techniques to
detect them, and the way that we've seen first it shows up is through leakage.
That's the quickest way to verify whether or not you've got leakage. It doesn't
tell you whether they are through a crack, and we understand that.
DR. WALLIS: Well, this is a box. If it's boxed in, you would
think that a leakage would simply increase the partial pressure of steam in there
to the point where you would be able to detect it somehow.
MR. MATTHEWS: I'll show you some pictures. This is not a
pressure chamber.
DR. WALLIS: No, you detect water vapor in there.
DR. MATTHEWS: It's very, very low leakage, very low
leakage.
DR. WALLIS: It's got nowhere to go. So it stays in there.
CHAIRMAN FORD: We will be coming back to discussing
later on in this presentation the whole question of NDE and its accuracy and
where we are expected to be in the fall?
MR. MATTHEWS: We'll get to some of that, what we are
trying to do anyway.
(Slide change)
MR. MATTHEWS: This is a simplified diagram of the head
penetration. It shows the J-groove weld where the tube itself is welded to the
ID of the head, and the angle of incidence here depends on where it is on the
spherical head.
This is again a B&W design. They have -- Their CRDMs are
flanged on. The Westinghouse and other units are different. They are screwed
on and sealed with a canopy seal weld, not as easy to remove even the CRDM.
(Slide change)
MR. MATTHEWS: Speaking of the French --
DR. WALLIS: This weld is what retains the tube or is it
retained some other way?
MR. MATTHEWS: Yes. That's the retention of the tub, is that
J-groove weld on the ID of the head.
DR. WALLIS: So if the weld fell completely, the tube comes
out?
MR. MATTHEWS: If it fails in a circumferential direction right
at the interface with the tube, it would. But most of the flaws tend to be radial,
in which case it will not eject under that situation at all.
Bugey found their first crack, we believe in '91, an ID initiated,
through-wall crack. By the way, there's a lot of background here. If I'm boring
any of you or you're already familiar with it, then I can skip through some of this.
Later on, a lack of fusion was detected in the attachment
weld, a small lack of fusion at Ringhals-2 in '92.
DR. WALLIS: These are both outside the United States?
MR. MATTHEWS: Yes. Industry safety assessments for the
U.S. were prepared in the early Nineties for those types of cracking, and
concluded it was not an immediate safety issue.
Additional European PWRs over the years have discovered
their cracks -- axial penetration cracks in their penetrations, and they have
initiated head replacements at many units. In 1991 DC Cook --
DR. WALLIS: Initiated head replacements? They have
actually done that?
MR. MATTHEWS: Oh, yes. They have replaced many
heads.
DR. WALLIS: So it's not just initiated? They have gone
ahead --
MR. MATTHEWS: Well, they haven't finished. There are
some heads that have not been replaced.
DR. WALLIS: It takes a long time, yes.
MR. MATTHEWS: You can't order one and have it tomorrow.
In '94 Cook 2 found one penetration that had axial cracks in
it, and that penetration was repaired, and the owners groups over the years
have been working with models, etcetera, trying to help the utilities manage the
issue.
DR. WALLIS: Have the -- During this time period, were the
NRC involved at all? When you say an industry program --
(Slide change)
MR. MATTHEWS: Yes. The NRC was involved. In 1997
they issued Generic Letter 97-01, requested quite a bit of information. The
owners group -- all the owners groups wound up putting together generic
responses, and those were coordinated between the owners groups through an
NEI task force.
We wound up with a way to rank the plants in the U.S. based
on this type of ID initiated flaw. That was a histogram, and there were a couple
of models, and this way that we have normalized everything that Cook 2
allowed us to rank the plans on the same scale, even though they were using
different models.
CHAIRMAN FORD: On the basis of one data point?
MR. MATTHEWS: That was the normalization for ranking
them. The models predicted various times of degradation, and then --
CHAIRMAN FORD: This, I guess, will be coming on later. So
am I being superfluous to ask you what the basis for these prediction models
were back in that time period? Are you going to cover that later on?
MR. MATTHEWS: Well, no, this is about all I was going to
say about those models, except that they are probably still pretty good for what
they were set up to do on the initiated flaws, and that they were using time and
temperature. They were using material properties and stresses that were
calculated, operating in residual stresses for predicting the initiation and the
crack growth rate, based on the material properties, etcetera.
CHAIRMAN FORD: You've given only one data point. That's
the only thing against which the model was --
MR. MATTHEWS: I think the French data was actually used
in some of these, and there were other data points, if you will. The lack of
cracks was also a data point that could be used in some.
CHAIRMAN FORD: Just something greater than a certain
time period?
MR. MATTHEWS: Yes.
DR. WALLIS: Did the NRC do independent modeling?
MR. MATTHEWS: You have to ask the NRC. I don't believe
they did, no.
MR. BAMFORD: Let me say something briefly about the
model. I'm Warren Bamford from Westinghouse.
We were involved in setting up a number of different models,
starting around 1992 or thereabouts. We began by benchmarking with
European experience, which was Ringhals plant where it was the first non-
French plant that had cracked, and it -- Cracking was found there in '92 or
thereabouts, I think.
So the first model benchmark with the Ringhals experience.
As time went on, we found a flaw at the DC Cook plant in the U.S., and we
revised the model to be consistent with experience up to that date, and
benchmarked everything in comparison with the DC Cook plant.
The reason for that was that that's the American experience,
and we thought that that would be more relevant to the plants in the U.S.
So the modeling has gone on and has been continually
upgraded with time, but it wasn't until this past fall that we got involved with --
or that we saw cracks in other locations, originating in other locations other than
the inside surface of the tube.
We are not aware of cracking anywhere else in the world
that's originated at any other location other than the inside of the tube except for
the plants that we are going to be talking with you about here. So that's another
reason why we try to stay with the U.S. plants in our modeling right now.
Now you could also argue that plants outside the U.S. haven't
found any cracks other than the inside area of the tube because they haven't
looked. That's not entirely true, but you have to -- I guess we have to admit that
not everyone has looked as completely in the outside of the tube and at the
weld region as we are doing now.
So I think that's the reason why the model has been changed.
The other thing that happened was the cracking that we see now since last fall
doesn't appear to be focused on the outer rings of the head where the stresses
are the highest from an operational point of view, and that's why we changed
out model to just be time and temperature.
So I hope that helps a little bit, because he's going to get in
a little bit more. That's a little more background.
CHAIRMAN FORD: Just to follow on from your comment, you
know, as I understand it from one of your earlier reports, MRP reports, in the
table there you were showing several thousand inspections --
MR. MATTHEWS: Yes.
CHAIRMAN FORD: -- in France, from which --
MR. BAMFORD: Worldwide.
MR. MATTHEWS: It's worldwide.
CHAIRMAN FORD: Oh, yes, I recognize that, but I'm just
thinking of one country and, therefore, procedure. So you've got a lot of
experience there, and you're saying for some reason you were not able to use
that data to calibrate your prediction model that you had at that time?
MR. BAMFORD: We have not done that at the present time.
CHAIRMAN FORD: Is there a technical reason for not doing
that?
MR. BAMFORD: Well, the French have not seen cracking on
the OD and at the --
MR. MATTHEWS; No, he's talking about the old model, the
97-01 model. And the data was -- I guess the data and the materials and stuff
was all part of the models that were built back in the Nineties.
MR. HUNT: Larry, this is Steve Hunt with Dominion
Engineering. I worked on some of the models for EPRI.
We did inspections at a number of plants in the Untied States,
including Oconee, Oconee-2. We inspected all the nozzles back in the early
1990s. Some nozzles had some very shallow cracks, and they were
reinspected several times to try to track that.
We also performed inspections at Ginna and Millstone and
Point Beach, and we didn't find the same extent of cracking as was being found
in France. As a result, we were benchmarking the models to U.S. plant
experience, which was about five or six plants of data that we had, and the
models then were adjusted for differences in stress and that type of thing. But
they were all focused on the inside surface where all the cracking had been
worldwide up until this point.
So it wasn't just one plant, one data point at DC Cook. It was,
in fact, five plants that were used, including repeat inspections at one of the
units.
CHAIRMAN FORD: The reason why I keep hammering away
at this is that these are in your conclusions. I suspect you're going to come to
some argument, that we might not expect cracks for a certain time period. That
is presumably based on some data and a model, and this is why I keep asking
this question. What is your basis, technical basis, factual basis, for saying this?
That's why I keep asking this question.
MR. MATTHEWS: All right.
DR. WALLIS: Are we going to see what these models are or
is there some way that --
MR. MATTHEWS: It's pretty simple, the one we are using
right now to rank the plants.
DR. WALLIS: Is it just a sort of a curve fitted through a point
or does it have some more sophistication?
MR. MATTHEWS: What we've done is calculated the
effective time at temperature, and I'll get into the details here, of the heads.
DR. WALLIS: I don't know we need to get into it, but we could
get into details if we wanted to. There's a record.
MR. MATTHEWS: Yes. Of the model? There was a pretty
good description of the -- Calling it a model might not even be appropriate at
this point for what we are doing for the OD initiated cracking that we've seen
recently.
CHAIRMAN FORD: So it's essentially -- You mentioned
inputs to the model would be temperature -- that was one of the prime ones.
MR. MATTHEWS: Yes. Temperature and effective --
CHAIRMAN FORD: And material and fabrication.
MR. MATTHEWS: No, not now. Just a simple Arrhenius
model, time and temperature. That's all we are using right now to rank the
plants, time and temperature, because the models we had before didn't predict
this kind of cracking that we are seeing. They weren't set up to normalize and
use --
CHAIRMAN FORD: So the temperature using a given
activation enthalpy is the -- That's it?
MR. MATTHEWS: Yes, the head temperature and the time
that the plant has operated.
CHAIRMAN FORD: But we know -- Maybe I'm jumping the
gun here. If I'm jumping the gun, tell me to stop, and you'll get to it later on.
MR. MATTHEWS: I'll get to some of this, but go ahead.
CHAIRMAN FORD: But we know that there are heats and
material that crack and other ones don't and, as far as I know, we don't know
why some are bad and some are good.
MR. MATTHEWS: Exactly, and --
CHAIRMAN FORD: And why some could be even worse,
which is from the safety point of view.
MR. MATTHEWS: You know, we are not saying nothing is
worse, and we are trying to account for some of that in the uncertainty and the
time period that we are telling people they need to go inspect. But just
normalizing all the plants to Oconee-3 on time and temperature -- basically, the
assumption there is everybody is exactly as bad but no worse than Oconee as
far as material properties and stresses or whatever else is driving the OD
initiated cracking.
CHAIRMAN FORD: Okay.
MR. MATTHEWS: We have already covered the rest of that.
(Slide change)
MR. MATTHEWS: This was just basically the histogram that
the industry put together based on 97-01 response. We had ranked all the
plants normalized to the time that they would reach a probability of a 75 percent
through-wall flaw that was equivalent to Cook-2 when they did their inspection.
The short bar is those plants that would have reached
equivalence to Oconee-2 within five -- effective five years. The next one was
five to 15, and the next one with all the plants that would have reached it after
15 years.
CHAIRMAN FORD: So most of them have no plans, and it
looks as if the bars are so narrow, you're talking about just two or three plants
that had plans to do anything that were over 15 years.
MR. MATTHEWS: At that point in time, that was the plans.
Those dark shaded bars were -- or I guess they are red on the graph there --
had announced plans to do inspections at some point in time. The white --
CHAIRMAN FORD: It looks like one plant. I mean, the
thickness of those bars is one.
MR. MATTHEWS: Right. One plant in the top five -- in less
than five. Three of the plants, I believe, had already done inspections, and the
other three were very nearly identical to other units that had already inspected
or announced plans to inspect. So -- in that short bar.
CHAIRMAN FORD: And this is purely mirroring the fact that
the only cracking you had seen had been at DC cook up to that point?
MR. MATTHEWS: At this point in time, the only cracking had
been DC Cook.
CHAIRMAN FORD: And this country?
MR. MATTHEWS: In this country, correct, and that was -- It
was just a normalization point to try and rank the plants. Recently --
MR. MEDOFF: May I clarify that a little bit? That's only for --
CHAIRMAN FORD: Identify yourself, and come to a
microphone.
MR. MEDOFF: My name is Jim Medoff. I was the lead
reviewer for GL 97-01.
That's true in terms of axial stress corrosion cracking induced
flaws, but there were some shallow crazed cracks found at Oconee unit 2.
MR. MATTHEWS: That's true. There were some very
shallow cracks that were monitored through repeat inspections and were not
growing.
MR. MEDOFF: So I just want to clarify that.
MR. MATTHEWS: Yes. But as far as a deep flaw that was
growing through the wall, at that point in time Cook-2 was the only data that we
had.
(Slide change)
MR. MATTHEWS: Recently, starting last fall, we found OD-
initiated flaws. These flaws are initiated below the weld on the portion of the
tube that sticks down below the weld. Either there or in the weld flaws have
been found at Oconee-1, Oconee-3 in February, ANO-1 found one flaw, and
then Oconee-2 also found some flaws. All of these are B&W units, B&W
designed units.
(Slide change)
MR. MATTHEWS: Based on that -- and I'll cover this in a little
more detail -- we decided we didn't really have a good handle on what the
material and stress was doing. So we decided the simplest thing to do was
assume everybody was very similar to Oconee, and rank them just based on
time and temperature.
Now they don't all operate at the same head temperature, but
what we did was we normalized them through the Arrhenius equation to 600
degrees Fahrenheit, and we ranked the plants. There's a lot of detail in the
color here, but I'm not sure we need to get into all that, as to who had already
done inspections, etcetera.
DR. WALLIS: I'm assuming that the only variable that matters
is these effective full power years.
MR. MATTHEWS: Effective full power years is the surrogate
we were using for how long the plant had operated, and then the temperature
of the head.
DR. WALLIS: But if there were some effect of water
temperature, which were not quite the same between plants, then this might
change things quite a lot.
MR. MATTHEWS: It could. It could change it some anyway,
but they all run with very similar boric acid, water concentration that goes down,
the very high purity water at the end of the cycle. The water chemistry variable,
agreed, is not in there. Assume everybody had similar situation to Oconee-3.
This histogram was put together based on preliminary
information that we had at the time we put this together.
CHAIRMAN FORD: Just to make sure that I and, I'm sure,
the others, understand this: What you have essentially said is that you've got
a given plant, for instance.
MR. MATTHEWS: Yes, the worst one.
CHAIRMAN FORD: Which has got a certain number of real
effective power years under its belt right now, and then you have modified those
years, taking into account the differences in head temperature between that
plant and Oconee, and the way you've changed it is by using Arrhenius -- well,
an activation enthalpy of 55.
MR. MATTHEWS: In fact, all the plants, even the Oconee
units were normalized to 600 degrees. They run slightly above 600. So their
numbers were all shifted slightly based on that. Six hundred was our base
temperature that we were using, 600 Fahrenheit.
DR. KRESS: How did you know what activation energy to put
in?
MR. MATTHEWS: We used the 50 kilocalories per mole for
crack initiation, and that was the number. The NRC had asked us some
sensitivity questions on that, and I've got some of that in here.
CHAIRMAN FORD: And that's based on the French -- No, I'm
sorry, the United States data. Is that right?
MR. MATTHEWS: 50 kilocalories?
CHAIRMAN FORD: Is based on laboratory data?
MR. MATTHEWS: Yes.
CHAIRMAN FORD: American laboratory data?
MR. BAMFORD: We have a lot of experience with cracks in
steam generator tubes, and that's kind of an amalgamation of the available
world data, and we looked at the sensitivity of that value, as you will see in a
slide coming up.
DR. WALLIS: What is the uncertainty in this 50 kilocalorie per
mole figure?
MR. MATTHEWS: We got a sensitivity study. I'm not sure we
have an uncertainty on it. That's the number that we've been using. That's the
number that's --
DR. WALLIS: Yes, but you are uncertain. It's something
between 30 and 70 or something like that. That might make a big difference to
your curves.
MR. MATTHEWS: Well, we ran the sensitivity study, and it
doesn't shift the relative rank, because all the plants, even the Oconee units,
move as you do that, and that's what we were doing was relatively ranking
them.
CHAIRMAN FORD: I think it would be fair to say, would it not,
that if you're looking at all the steam generator data plus what head penetration
data you've got, 50 is a conservative upper limit. Is that correct?
If you look at the data then, it looks like a shotgun, but it's a
reasonable upper limit. Is that a fair statement?
MR. MATTHEWS: Yes.
MR. ROSEN: Would you go back to the schematic for a
minute?
(Slide change)
MR. MATTHEWS: We'll get to this again later.
MR. ROSEN: No, the schematic of the CRDM nozzle area.
MR. MATTHEWS: I should pull those out.
MR. ROSEN: Slide six. Take out your light pen, and trace for
me what you mean by an outside diameter weld crack. Show me exactly where
it initiates and what the leakage path is that you think --
MR. MATTHEWS: Cracks were initiating in this region here
on the outside diameter of the tube, some of them.
MR. ROSEN: Close to the weld?
MR. MATTHEWS: Yes, most of them probably very close to
the weld, propagating along the weld interface in an axial direction, penetrating
both into the tube and, in some cases, into the weld material. And when it
reaches this point right here, there's an only an interference fit, and then a gap
above that, and that's where the leakage was occurring.
MR. ROSEN: How far from the weld, below the weld, was the
furthest crack initiating?
MR. MATTHEWS: I believe they've had axial cracks that
extended all the way to the end of the tube down here.
MR. ROSEN: So that's how many inches?
MR. MATTHEWS: Well, it depends on the penetration and
the design, but the diameter here is four inches, and this is pretty much the
scale for one of these penetrations out on the edge.
MR. ROSEN: So it could be six inches perhaps to the
bottom?
MR. MATTHEWS: Between five to six inches, yes.
MR. ROSEN: Thank you.
CHAIRMAN FORD: It's a good point, Steve. So there's an
axial crack going up that interface. Where does it go circumferential, at that
point there?
MR. MATTHEWS: Right here?
CHAIRMAN FORD: Yes.
MR. MATTHEWS: Along the heat effective zone from that
weld, that is where circ-cracks have been detected on three penetrations in the
U.S.
CHAIRMAN FORD: And will you be discussing later on -- I'm
sure you will be -- the extent of that circumferential cracking and the safety
input?
MR. MATTHEWS: Yes, I'll get into a lot of detail on what was
found at Oconee.
CHAIRMAN FORD: I'm sorry. This is so interesting, I'm
jumping. Why should it go circumferential?
MR. MATTHEWS: The only reason it goes circumferential is
if the axial stresses in that region are sufficient to support a crack that's in a
circumferential direction.
CHAIRMAN FORD: And there's analysis to show that?
MR. MATTHEWS: Yes.
CHAIRMAN FORD: Okay.
MR. ROSEN: But at some point, clearly, it's penetrated the
wall. Right?
MR. MATTHEWS: It has either penetrated the wall and
bypassed the weld or it's gone through the weld to this triple point right here
where you have the weld material, the head and the tube, and gotten above the
weld into this annulus region above the weld. The flow path either through the
crack to above it or, if the crack extends all the way to the ID of the tube, which
a few of them did, you could have a flow path going this way.
DR. WALLIS: What are the stresses that induce these
cracks?
MR. MATTHEWS: Most of the stresses are probably residual
stresses from the manufacturing process. These penetrations, in most cases,
were not stress relieved with the head.
DR. WALLIS: So that could be a considerable variable
between plants in the way in which the stresses were relieved and the
manufacturing?
MR. MATTHEWS: The manufacturing processes were very
similar for all the heads, but yes, there could be some variation.
MR. HUNT: I think the answer there is the stresses were not
relieved after manufacture for any of them. The J-groove welds were prepared,
and then the head was put into service, went through a hydro test in the interim,
but there was no stress relief done to the J-groove welds. So it has all the
welding residual stresses locked in.
MR. ROSEN: Have you seen any cracking initiate in the weld
material itself?
MR. MATTHEWS: There was one crack at Oconee that it
wasn't clear whether it initiated in the weld or in the tube. I believe, you know,
it was in both. The initial discovery of the crack was by PT of the weld area, and
that's where the crack showed up, the weld. Was that on the uphill side or
downhill? Downhill side. They found a couple of little PT indications on the
weld itself, and that was the initial indication, and as they ground out, they
discovered the crack actually penetrated into the tube material, through the
weld, to this annulus region. I have some pictures on what we saw when we go
tin there.
DR. WALLIS: So these stresses that caused the cracks were
residual from manufacturing. So if you took these things and put them in the
same temperature environment, which was not in the reactor at all -- it was just
in a bath -- you would expect the same kind of crack growth?
MR. MATTHEWS: With the same stresses, I would suspect.
DR. WALLIS: Well, if it's all residual stresses, then the fact
that it's part of a reactor is irrelevant, isn't it?
MR. MATTHEWS: Yes.
DR. WALLIS: Is that your contention, that that is the case?
MR. MATTHEWS: Yes, I think so.
DR. WALLIS: That any kind of loads imposed by the fact that
it's part of a reactor or that it's in this environment is irrelevant?
MR. MATTHEWS: Well, it's also subject to the operating
pressure stresses.
DR. WALLIS: But that hasn't been mentioned yet. Does that
play a role?
MR. MATTHEWS: They are not the driving stresses, I don't
believe. I believe most of the driving stresses are the residual stresses from the
manufacturing process.
MR. LEITCH: When comparing plants, why is it that time at
temperature is the variable of interest rather than number of thermal cycles?
MR. MATTHEWS: I believe -- and somebody correct me if I'm
wrong -- that the initiation of the cracking in alloy 600 tends to be more of a --
It's not a fatigue type of initiation. It's just a PWSCC stress corrosion cracking,
and time at temperature is the driver there, and stresses in the material
properties.
MR. BAMFORD: This is Warren Bamford again. To clarify
that, the stresses that -- or the transient stresses that occur in the upper head
region of an operating PWR are very mild, because the closure head region,
that whole region is essentially a static area.
You get some water coming in from t-cold, and you get some
water coming in from t-hot, and there's some mixing there, but the flow is very
small there. So the transients that affect that region are very minor, and we
actually looked at fatigue crack growth and other things that might go on that
might affect this cracking when we first were looking at this back in the early
Nineties.
The conclusion was that the overwhelming factor driving the
cracks was residual stress, and everyone else, I think, worldwide has agreed
with that. So I don't think there is any question about that.
CHAIRMAN FORD: So would you mind going back to the
previous graph, because this, I think, is going to be -- You may very well be
coming back to this graph.
MR. MATTHEWS: I'll save it out. I have another copy later
in the presentation.
CHAIRMAN FORD: Just to be absolutely sure, the only
variable -- You're going to be using this to make the argument, presumably, that
this is the beginning -- the Oconee and the ANO experiences in this country.
You're trying to rank all the other stations in comparison, and the only variable
you're using for the top head is a temperature.
MR. MATTHEWS: Right.
CHAIRMAN FORD: Warren correctly pointed out just now
that the main mechanical driver, of course, is the residual stress. Do we know --
and my guess is no -- how the residual stresses vary between these various
plants? I don't know how you would do that.
MR. MATTHEWS: Well, they calculate them. We don't have
any details, I don't believe, on the residual stresses.
CHAIRMAN FORD: So one of those plants that you're saying
could be 50 years out might be, in fact, only two years out, because there's the
upper bound of the actual residual stress profiles.
MR. MATTHEWS: Well, the manufacturing processes for all
of these were very, very similar. So you would expect the residual stresses to
be similar.
CHAIRMAN FORD: But you have no data to see what the
distribution of residual stresses --
MR. MATTHEWS: We calculated those stresses, I guess, for
various plants in the original model as a result of the weld residual stresses, the
ovalization on the tube that occurs in the welding process, and the material
properties, the yield strength of the tube, etcetera, and built a good model for
calculating that.
CHAIRMAN FORD: I understand how a finite element might
well look at those specific effects of those variables on the residual stress
profile, but there's no way of looking at the plant at the righthand side of that
graph and saying it should be there, and it shouldn't be over that side, because
the residual stress aspects have changed. My point is it's an unknown variable.
MR. MATTHEWS: It's not a perfect model. There's no
question about that.
CHAIRMAN FORD: I'm just trying to understand what the
potential flaws in the model that you are using are.
MR. MATTHEWS: Right. That's one of the uncertainties, is
the driving stresses, the material properties. What we've tried to do is say, well,
what we know is Oconee-3 is the worst we've seen, and we are going to
benchmark to there on the properties that we do understand.
DR. WALLIS: It's the worst you've seen, but you are guessing
that there aren't worse ones out there somewhere, that they would have shown
up if they had been worse. Is that the idea?
MR. MATTHEWS: Yes. We think so, and that's the position
that we are taking, at least right now, but we've got uncertainty here, we're
saying, and we're not just going to look at the next plant on the list. We're going
to go out for a ways.
DR. WALLIS: I think you need to get into the matter of
uncertainties of all of this, and it's not just one figure, really. It's a question of
what happens if you go to some other limit of assumptions or look at the
sensitivity. Are you going to give us sensitivity studies?
MR. MATTHEWS: Well, the only sensitivity study I know has
been done right so far has been on the activation energy.
MR. BAMFORD: We were given some additional assurance
when we set up this original time-temperature model and ranked all of the
plants, and it turned out Oconee -- all three Oconee units were at the very top
of the list.
So that gave us some confidence that the model made some
sense relative to what we were seeing out there.
DR. WALLIS: The Arrhenius relationship, simply a curve fit
to an exponential or something. Is that what it is?
MR. BAMFORD: Sure.
DR. WALLIS: And I'm not an expert on this field, but if I look
at some data from something similar and I try to curve fit, do I get a lowest
scatter around this curve or does the data from these sort of phenomena fit this
curve very, very closely when you take a lot of lab data?
MR. BAMFORD: Well, you know, what we are doing is a
deterministic model, and we are not trying to apply -- At least at this point, we
are not applying any statistics to it, but the thing I wanted to point out was that
we didn't go in with any bias in the way we set the model up.
DR. WALLIS: My sense is that this is a very crude
representation of what happens?
MR. BAMFORD: Very simple, that's right.
DR. WALLIS: And expected to be very accurate?
MR. BAMFORD: Well, we tried it, because it was simple, and
we were amazed at how the Oconee plants jumped right out at the top of the
list, and that gave us some confidence to proceed, I think.
Now, obviously, we can improve on it, but I think it seems that
we have some confidence in it based on experience, at least at this point.
MR. MATTHEWS: Need more data, though. Need more
inspections. Now we've had some inspections this past spring, visual
inspections that detected no leakage from other plants that are very close to
Oconee in this time and temperature model.
(Slide change)
MR. MATTHEWS: Got a lot of information here on what
actually happened at Oconee and A&O, and I'll walk through that and, if we get
too detailed, just let me know.
Visual inspection of Oconee-1 head identified small amounts
of boron that were accumulated around nozzle 21 and several of the
thermocouple nozzles, and we have some pictures of some of this later on.
When they inspected the Oconee-3, they found several
nozzles -- there's a list of them here -- that had boron accumulated at the base
of the nozzle, indicating leakage.
Then when Oconee-2 came down, there was also leakage
around four of their nozzles.
DR. WALLIS: Now this boron accumulation -- it's because the
water comes out and evaporates and leaves behind the boron, and the water
disappears?
MR. MATTHEWS: Yes. Well, what little bit of it there is
vaporizes, and the --
DR. WALLIS: And the boron stays there?
MR. MATTHEWS: Yes.
DR. WALLIS: How much boron is there is a measure of how
much water has leaked?
MR. MATTHEWS: Yes. And it depends also on what time in
the life of the plant it leaks. Early in the life, there's a lot of boron in the water.
late in life, there is almost no boron in the water. So how much boron
accumulates depends on when it leaks, how much it leaks.
DR. WALLIS: When you say small amount, you mean less
than an ounce or something?
MR. MATTHEWS: I'll show you some pictures. I think
Oconee-1, they were estimating less than a cubic inch of boron crystals.
DR. WALLIS: This corresponds to how much water?
MR. MATTHEWS: We didn't do that calculation.
DR. WALLIS: Didn't do that calculation? It's a sort of --
MR. HUNT: It was about a gallon of water.
DR. WALLIS: It's how much?
MR. HUNT: About a gallon.
DR. WALLIS: About a gallon of water?
MR. HUNT: Yes.
DR. WALLIS: That's all that's leaked out of this thing?
MR. HUNT: Yes. It depends on the assumptions of the boron
concentration.
DR. WALLIS: So it's a gallon of water that has leaked and left
that boron behind? That's all?
MR. HUNT: Yes.
MR. MATTHEWS: Very little. PWSCC cracks are very, very
tight.
CHAIRMAN FORD: Larry, we are peppering you with
questions.
MR. MATTHEWS: Yes.
CHAIRMAN FORD: And we are about halfway through your
time. You know what you've got in front of you.
MR. MATTHEWS: I've got a lot of detail on what happened
at Oconee in A&O, and pictures and other inspections that have taken place in
the industry in the submittals that we've made. I can walk through --
CHAIRMAN FORD: I think we're going to have to go very
fast. I'm going to assume that most people have seen some of this information.
The thing I'm personally very interested in is your arguments on the safety point
of view, the crack growth rate point of view, i.e., what's going to happen in the
future. Those are the things I'm interested in. I don't know if any other
members have got their own interests.
MR. MATTHEWS: I'll try and get on down to those.
(Slide change)
MR. MATTHEWS: Oconee here had modified their ports so
they could -- their service structure.
(Slide change)
MR. MATTHEWS: You can see their thermocouple nozzles.
Only two units have those, and they weren't used. I showed you where those
were.
(Slide change)
MR. MATTHEWS: This is a picture of one of the leaking
thermocouple nozzles. You can see just a little bit of boric acid or boric acid
crystals that had deposited there as the water had leaked out and ran toward
this. That's one of the mouse holes that is in all the B&W units.
(Slide change)
CHAIRMAN FORD: And we will be talking the NDE
techniques are being developed? Will we talk about that?
MR. MATTHEWS: Yes. They have 69 CRDMs. They are
hotrolled and annealed B&W tubular products for Oconee. The nozzles are
shrink fit into the vessel head and welded with that J-groove weld.
These are the summary of the leaks that were discovered on
Oconee-1 and Oconee-3. The models that we had for the original OD initiated
cracking, we are predicting it would occur predominantly on the outer rows,
because that's where the residual stresses were the highest. These cracks
were more scattered throughout the head.
CHAIRMAN FORD: And is that telling you the model needs
to be tweaked a bit or what?
MR. MATTHEWS: Well, it's telling us that the model that we
had for the ID initiated flaws isn't predicting what is happening here with the OD
initiated flaws.
(Slide change)
MR. MATTHEWS: AT Oconee all eight of their small
thermocouple nozzles had flaws. The CRDM, they only had one CRDM nozzle
at Oconee, Nozzle 21, that had a flaw. That flaw was int he weld metal,
predominantly axial and radial in orientation, and this is a photo of the boron or
boric acid crystals that had accumulated around that nozzle.
(Slide change)
MR. MATTHEWS: When we got to Oconee-3, there were
nine CRDM nozzles that were found leaking. These had numerous axial flaws,
axially oriented flaws. OD initiated circ flaws that were relatively deep were
found below the weld on four of the nozzles, and they discovered OD initiated
circ flaws above the weld that were identified --
DR. WALLIS: For how long had they been leaking when they
were found?
MR. MATTHEWS: We are not sure. This was the first
indication that they had that they were leaking, but the heads, B&W heads,
because of the flanged arrangements of CRDMs, have over the years had
experience with boric acid accumulation. But this was the first indication that
they had ben leaking.
I think everybody probably believes these cracks were there
for more than this last cycle, but probably quite a bit --
DR. WALLIS: It's roughly for a cycle?
MR. MATTHEWS: I think it was much more than a cycle, but
you know, that's my opinion.
MR. ROBINSON: We have kind of theorized, Larry, that it
could be as much as -- This is Mike Robinson from Duke Power.
We have theorized ourselves that the cracks could have been
there and the leaks could have been going on for a range of five to ten years,
but we really haven't -- you know, don't have any way to really prove that.
That's just an assumption on our part.
MR. MATTHEWS: One of the things Oconee had been doing,
because of the ID initiation flaws, had been cleaning their head over the years
to try and remove the accumulated boron so they could get a better look.
(Slide change)
MR. MATTHEWS: This is nozzle 56 on Oconee-3. This is
one of the nozzles that developed a circ flaw above the weld after it had had an
axial flaw go through-wall.
DR. WALLIS: Why is that different colors? Seems to be a
river running down below. Does it tell you anything, what you see? It just tells
you there's a leak?
MR. MATTHEWS: There is a leak. The white is the boric
acid crystals, some corrosion of the carbon steel, alloy steel, whatever. It's
mixed together.
DR. WALLIS: There is a stream of fluid running down below
there?
MR. MATTHEWS: A little bit, but it doesn't make it to the
service structure on this particular nozzle, or any of them, I don't think.
DR. UHRIG: Is that circumferential line there -- is that a
crack?
MR. MATTHEWS: No, the circumferential line -- you'll see
that on most of the penetrations -- is the upper end of the machine area where
they machined them for the fit, for the interference fit.
DR. WALLIS: What is all that stuff that's higher there? Is that
something running down from somewhere --
MR. MATTHEWS: That is probably -- I'm not sure they know,
but I think they believe it's the fibrous material from some of the --
DR. WALLIS: It's not cracks. It must be something else.
MR. MATTHEWS: No. It's stuff that was left over from their
cleaning operation.
DR. KRESS: What temperature does the head run at?
MR. MATTHEWS: This head runs 607, is it? 602, I'm sorry.
DR. KRESS: When the water comes out, it's almost
immediately --
MR. MATTHEWS: Oh, it flashes, yes. As soon as the
pressure drops low enough --
DR. WALLIS: That is why it is surprising it actually runs down
very much.
MR. MATTHEWS: Maybe it recondenses and then runs.
(Slide change)
MR. MATTHEWS: This is nozzle 50. This is the other nozzle
that had a circumferential flaw on unit 3. You can see some of the boron that's
-- you know, little crystals scattered around from plant leaks, etcetera, but the
leaks have typically been pretty obvious that you got something --
MR. ROSEN: And here again, all that white coloring is what?
MR. MATTHEWS: It's just a fine dusting of boric acid from
crystals. As water has leaked from various sources, even from the flanges or --
The CRDM modules are bolted above these.
MR. ROSEN: Are we talking about the same thing? I'm
talking about all of the white.
MR. FYFITCH: Yes, let me explain, Larry. Let me tell you.
This is Steve Fyfitch from Framatone.
In the B&W design, as Larry mentioned earlier, we have a
flange on top of the CRDM nozzle. It connects the control arm drive to the
nozzle, and those flanges typically leak. It's just a gasket and flange.
Over the years, we have done much better at coming up with
better gaskets so that they leak less and less, but all of the heads in the B&W
design have a coating of boric acid on the head from that leakage.
Over the years since the early Nineties, our plants have
continued to clean that boric acid off, and what you are seeing there are
residual boric acid crystals that have been washed away and have redeposited
along the head there. So really, what we are only talking about in that center
nozzle there, which is nozzle 50, right around the outside, the OD of the nozzle,
is the leakage that you are seeing from the flaw that's on the inside. It's coming
up and leaking out.
MR. ROSEN: Thank you.
MR. LEITCH: In some of the reading we had, there was quite
a bit of discussion about the interference fit and the variability in the interference
fit. But I kind of lost my way through that. Is there some -- In other words, the
question is could we have crack welds down below that, because of a very
heavy interference fit, it didn't appear as boron crystals?
In other words, is there some correlation that the ones that
were obvious leakers had perhaps even a clearance fit, and there were some
nozzles that --
MR. MATTHEWS: No, we have data on those particular
nozzles, and no, they were interference fits, and we'll show you. They are
interference fits by design at cold temperatures. Operating temperature and
pressure, things change; and we got some stuff in here on that.
MR. LEITCH: So that is going to come later?
MR. MATTHEWS: Yes, that's one of the things that we've
been concerned about and the NRC has been concerned about.
MR. LEITCH: Okay, thank you.
(Slide change)
MR. MATTHEWS: ANO, in the middle of all this, found one
leaking nozzle. It was an axially oriented -- I mean, it was a flaw that had a
circumferential part to it below the weld, and then it turned axial.
MR. BONACA: Could you go back into slide 23?
(Slide change)
MR. BONACA: Given that you have all this boric acid crystal
residue over it, how can you detect leaks positively from visual inspections?
MR. MATTHEWS: That is one of the things that we have to
do, is make sure that what we are looking at is adequate to find those kinds of
leaks, that small amount of boron, and we are orienting visual inspectors and
everybody as to what exactly they are looking for, in all of the plants.
The B&W plants are the ones with the flange. Not all the
plants have that much boric acid accumulation, and I'll show you some pictures
later on.
MR. BONACA: But the other question is: If this leakage is
coming from the flange above, how come the nozzles have no trace of deposit
on them?
MR. MATTHEWS: Oh, this leakage here has accumulated
over the years.
MR. BONACA: Yes, but I guess it would drip down through
over the nozzles.
MR. MATTHEWS: Yes, come down through the insulation.
MR. FYFITCH: Let me address that again. In Oconee's case,
you know, they have cleaned it up fairly well. This is a very clean head
compared to some of the old BW heads. Yes, indeed, you do see leakage
coming down the nozzles, but what typically happens is the flange, which is
above the insulation, when it leaks, it leaks onto the insulation, and it would tend
to come down and drip down through the insulation, and you get these crystals
that deposit on the surface.
So you do get both cases.
MR. BONACA: All right. Okay.
(Slide change)
MR. MATTHEWS: ANO doesn't have those large access
ports. So they put a video camera underneath their insulation through the
mouse hold, and this is the one flaw that they had at ANO. The picture in the
thing didn't come out, but the same picture. This picture is in the response to
the NRC questions that we submitted a couple of weeks ago.
CHAIRMAN FORD: You skipped over a graph, and thank you
for doing it in order to get moving. But then the very first bullet on it says "No
idea axially oriented flaws identified."
So how --
MR. MATTHEWS: There was no ID flaws at all. The only
flaws they had at ANO -- I'm sorry, I didn't mean to interrupt. But the flaw that's
on the OD below the weld and then propagates up along the heat affected zone.
CHAIRMAN FORD: I'm just trying to work out how you can
have an OD circumferential crack without an axial crack. I thought the axial
crack is a precursor.
MR. MATTHEWS: It was right in here, and it's circumferential.
Then when it got here when it intersected the weld --
(Slide change)
MR. MATTHEWS: All right. Here is quite a bit of information
that was -- Oconee did on their investigations. Before they did their repairs,
they did visual on all the nozzles. They performed dye penetrant on the leaker.
There was eddy current testing on the leakers and other nozzles, UT
examination looking at both the axial and circumferential direction.
(Slide change)
MR. MATTHEWS: The visual inspections were bare head
inspections. They do this every outage. The Oconee units have been cleaned
well over the years to remove most of the old boron deposits.
CHAIRMAN FORD: So when you take the head off, you've
got real access to these things, don't you?
MR. MATTHEWS: No. They only have access through like
a 12-inch hole.
CHAIRMAN FORD: That's all?
MR. MATTHEWS: Yes, at Oconee. In some of the plants it's
just through those little mouse holes that I showed you, the B&W, and the
Westinghouse and CE plants, some of them have much less access than that.
MR. LEITCH: The visual inspections you referred to were
with the head off under the head, or how?
MR. MATTHEWS: It was above the head, like what I showing
you in the pictures.
MR. LEITCH: So, really, all you are looking for is boron
crystals.
MR. MATTHEWS: Right. You're looking for evidence of
leakage.
MR. LEITCH: So that would be -- How much leakage you get
would be not only a factor of what was a crack but also the interference fit.
Right? In other words, if they are very tight, you might not get any leakage
evidence.
MR. MATTHEWS: That's definitely one of the concerns of the
NRC. We believe that most of these, if not al of them, will leak. If the crack
itself leaks, then the fluid will get on out to the top of the head.
DR. KRESS: What is the relative thermal expansion
coefficients?
MR. MATTHEWS: There's a couple of numbers. In one of
the code cases, the latest -- I mean, the latest version of the code, the thermal
expansion coefficients are identical. In an earlier one, the -- and I'll get into that.
In the earlier versions of the code, the thermal expansion would tighten the fit
up, but the pressure dilation would open it up more than the thermal expansion
tightens it up. We've got some information on that.
(Slide change)
MR. MATTHEWS: At Oconee, they also did UT exams
looking in the axial and the circumferential direction of leaker penetrations as
well as some other penetrations, expanding the scope, looking a little bit beyond
that.
(Slide change)
MR. MATTHEWS: The next three are just some of the PT
indications that were found on three of the nozzles. This is nozzle 11. You can
see that it has a circumferential flaw and axial flaws coming out the bottom of
it.
DR. WALLIS: Has anybody looked at what really happens?
When you get flashing liquid leaking out through a crack, I would think it would
flap way down in the crack, leave the boron behind, and all that will come out
would be steam. It would be a long time later that you would actually get boron
appearing out the top.
MR. MATTHEWS: The experience that we've seen on like a
flange leak or other things, you don't have boric acid accumulated all along.
Where you get it is out at the -- when it gets to the atmosphere.
DR. WALLIS: But the pressure drop is inside. That's where
the flashing occurs, and the steam would b released inside for a long time.
MR. MATTHEWS: I understand.
DR. KRESS: It depends on the pressure. When you flash
steam at a high pressure, which would have then, I suspect, near the front of
the crack, it takes the boron liquid into the steam. But if you flash it at low
pressure, it leaves it behind. So it could be carried out, actually, with some of
the steam.
DR. WALLIS: Blow it out with the steam, yes.
DR. BONACA: I have one question. Before we talked about
visual is the first step in the inspection, and it has to be -- Then after that, you
do dye penetrant and eddy current and so on.
MR. MATTHEWS: That's what happened historically.
DR. BONACA: Yes. I'm just pursuing the question. Again,
you have boron crystals all over the head. How can you be sure that you have
identified all those that leak?
MR. MATTHEWS: Well, you have to do a very careful look.
There is no question about that. And not all of the heads -- you know, and I got
a picture of a -- several pictures of some of the others I'll show you. They are
not in your packs, but they were in our submittal. Not all the heads are that --
got that much boron laying on them.
(Slide change)
MR. MATTHEWS: That was another nozzle, and here was
another nozzle that developed above the weld after this. This flaw had grown
all the way through and leaked into the annulus region.
(Slide change)
MR. MATTHEWS: AT Oconee-3 they had 48 indications in
the nine leaking nozzles. Thirty-nine of them were axial and located beneath
the weld at the uphill and downhill side, and 16 of the indications actually were
all the way through the wall. All of those were axial, and they occurred on six
of the nine nozzles.
They had two nozzles that had confirmed circ flaws. Nozzle
56, the circ flaw was above the weld, and it was through the wall. In Nozzle 50
it was a significant extent around the weld, but it was only through the weld on
the ID for a couple of pinholes on the PT. The inspection and the results
indicate that those came from the outside after the penetration had been
penetrated.
DR. WALLIS: What about all the nozzles that didn't leak?
MR. MATTHEWS: They did extent of conditions on
examinations with eddy current and UT, looking for anything else on other
nozzles. They didn't do 100 percent --
DR. WALLIS: Doesn't this give you some idea of the scatter
in the fit to this Arrhenius equation? If they have all had the same history and
some of them leaked and some of them had lots of cracks and some didn't have
cracks, it tells you something about your ability to predict.
MR. MATTHEWS: It was almost like two populations at
Oconee. It really was. What we are doing is saying everybody is as bad as
their worst.
DR. WALLIS: That's a bit disconcerting, though, because it
means that some were considerably different from others.
DR. MATTHEWS: Yes.
DR. WALLIS: And that just sort of belies some of the
predictability of things.
DR. KRESS: That could be due to cracking initiation. You
may already have cracks in some of them, small cracks, and not in the others.
If you don't have any in them, it will take a while to initiate the crack. What we're
really looking at is crack growth, I think.
CHAIRMAN FORD: Larry, Oconee was inspected
somewhere around the end of the year 2000 and 2001. What was the previous
inspection?
MR. MATTHEWS: They had done an inspection one cycle
before, 18 months, I guess.
CHAIRMAN FORD: So all indications that you're seeing there
occurred -- I'm assuming that there's no indications in the previous inspection.
MR. MATTHEWS: They say they were discovered. Okay?
CHAIRMAN FORD: Okay. How do you tell a new one from
an old one?
MR. MATTHEWS: I'm not sure you can. You could do some
analysis on the boron. It might tell you how old the boron has been -- you know,
some radiochemistry on the deposits that could tell you how old the boron is,
but I'm not sure that's very accurate at this point.
MR. ROBINSON: This is Mike Robinson again from Duke
Power. We did do some of the radiochemistry on the sample we found on
Oconee-1. As you would imagine, with some of the old boron there as well as
some fresh boron, we had a range of age from the samples that we did take.
So we could see new signs where leakage had occurred
within the last cycle. We also had evidence where there was boron again mixed
with the samples that we took that were somewhat contaminated but also
indicated a much longer period of being on the head.
As for Oconee, I guess we're somewhat fortunate. The
individual who does these inspections for us -- We do these inspections looking
at the top of the head within two days of the unit coming offline. So before we
take the head off and put it on the stand, the engineer takes a look at our head.
Again, we are fortunate. The individual who does these
inspections for us has done those for about the last 15 years. So we have an
experienced dye ed. and, as much as we've cleaned the heads, who has a
pretty good understanding of what's there.
When we found the indication on Oconee-1, we went through
this series of inspections that Larry is talking about here. We did the looks at
the ID, because again once we saw the boron, we were suspicious as to what
was there.
We thought it was, again, typical PWSCC. It was typical ID
initiated cracking. So all of our initial investigations focused on interrogating the
ID surface, trying to find a crack.
Much to our surprise, when we got our NDE back on the
leaking CRDM nozzle, there were no ID indications. At that point, we went to
the OD and started looking there and didn't find anything. We ultimately found
some cracks in the weld itself.
Oconee-1 happened. That's when we found the leaks with
the thermocouple as well as the CRDM nozzle 21. Before Oconee-1 came
down, we had the Oconee-3 refueling outage, and at that point we didn't
observe anything in Oconee-3, but subsequent to Oconee-1 we had to bring
Oconee-3 down for a maintenance outage to repair a leaking pressurizer valve.
Our sensitization to what we had found on Oconee-1
sharpened our eye when we did the inspection on Oconee-3, and I think that's
why we were able to pick up some of the leakage on Oconee-3. Our heads on
Oconee, we feel like, are in pretty good shape.
Oconee-3 was probably the least clean of the heads we have
there. So in spite of the fact that it was not as clean as the other two heads, we
were able to see again some of the small leakage.
MR. ROSEN: When you talk about circumferential cracking,
you don't talk about the extent of it. Is it all the way around?
MR. MATTHEWS: No, it's not. The two flaws on Oconee-3,
the crack was approximately 165 degrees around from the uphill side on the OD
of the penetration.
MR. ROSEN; Halfway around?
MR. MATTHEWS: Yes, almost halfway around. And there's
plenty of structural margin there to preclude rot ejection.
MR. ROSEN: That was the biggest one you've ever found,
halfway around or almost halfway around?
MR. MATTHEWS: Yes. That's the biggest flaw we've ever
found, was one of the two nozzles on Oconee-3, circumferential.
DR. WALLIS: You talk about axial and circumferential, but
aren't there some other angles?
MR. MATTHEWS: If it's not pretty much axial, we tend to call
it circumferential.
DR. WALLIS: Anything that deviates from axial is
circumferential?
MR. MATTHEWS: It certainly has a circumferential
component.
MR. ROBINSON: I think the line is 45 degrees, Larry.
Anything that's off by more than 45 degrees, we call a circ crack.
DR. WALLIS: Oh, but an ax crack, which is at 44 degrees,
eventually goes around.
MR. MATTHEWS: If it's got enough room, yes.
DR. WALLIS: It spirals.
MR. MATTHEWS: Yes. It wouldn't eject if it did that, though.
DR. WALLIS: It would screw its way out, wouldn't it?
MR. MATTHEWS: I guess it could.
CHAIRMAN FORD: Larry, if I could --
MR. MATTHEWS: We would find that.
CHAIRMAN FORD: In view of time, I think the remaining
ones you've got are just essentially telling us again you've got cracks.
MR. MATTHEWS: Yes, and the metallurgy.
CHAIRMAN FORD: Could we move on to the safety
assessment, Item 48?
MR. MATTHEWS: Forty-eight? Is that where I need to go?
CHAIRMAN FORD: I think the other one is just to do with
organization, which I'm sure is important, but I'm looking at the time.
DR. WALLIS: I think the key question is how do you reach the
conclusion that everything is okay?
CHAIRMAN FORD: I think so far what they've done is they've
told us there are cracks. Now what I'm interested in is to know what is their
assessment.
MR. MATTHEWS: Yes, and their PWSCC.
(Slide change)
MR. MATTHEWS: We submitted an interim safety
assessment to the NRC in May, and with the histogram we've already talked
about what developed as part of that, to rank the plants and sorted the plants
into various bins.
We recommended that the plants that were less than ten
years from being the equivalent to Oconee-3 perform visual examinations at
their next opportunity. Those visual examinations need to be keyed to the
results from Oconee-1 and Oconee ANA and O units, because up until that time
I think everybody expected a greater amount of leakage.
(Slide change)
MR. MATTHEWS: There's the histogram again.
(Slide change)
MR. MATTHEWS: Our bases for believing that there is no
significant near-term impact on plant safety is that the three Oconee units and
the ANO-1 unit are all among the lead units in the U.S., based on this time at
temperature.
Careful visual examination is able to detect these leaks.
Structural integrity evaluation showed that the nozzles and the welds were well
within the required margins. Leakage should be detectable at other plants, and
we'll get into that a little bit.
Several other lead units with long operating times and high
temperatures have already inspected above the heads, looking for leakage, and
have not had any significant findings.
Finally, from a safety standpoint, the CRDM nozzle ejection
is an analyzed event in the plant FSARs, and the operators are well trained on
symptom based emergency operating procedures to know how to respond to
this.
DR. WALLIS: What is missing here is the time to ejection.
Suppose there's an undetected crack. Is it ten years before it grows to the point
where you worry about it or is it one cycle?
MR. MATTHEWS: We believe it's years and years.
DR. WALLIS: Can you actually show that?
MR. MATTHEWS: I think we can, but it depends, like you
say, on the crack growth rate, and we have to get into what is the crack growth
rate.
(Slide change)
MR. MATTHEWS: The NRC has identified several questions
to us based on our submittal.
DR. WALLIS: Isn't that really key, the crack growth rate?
MR. MATTHEWS: Yes. I think it's one of the key things, and
when we use what we believe are realistic crack growth rates, we calculate that
there's years of margin, even at Oconee-3 before they would have reached an
ejection situation, even with a 165 degree flaw. What?
MR. FYFITCH: There is an overhead, Larry, coming up.
MR. MATTHEWS: Yes, we'll have that a little bit later on.
MR. LEITCH: I have a question about Number 50, just back
one, the previous one.
(Slide change)
MR. LEITCH: Several other plants with long lead operating
times and high temperatures already performed inspections from above. That
would be a visual inspection?
MR. MATTHEWS: Right.
MR. LEITCH; Now suppose they found nothing as a result of
that visual inspection. Would that have been the end of it or -- In other words,
are they all above and below?
MR. MATTHEWS: No. The below was referring to previous
volume -- or ID initiated eddy current examinations. Nobody has -- Since
Oconee-1, nobody has done any significant examinations below the head.
They have all been above.
MR. LEITCH; So these plants that might be in the family with
problems, if you will, they looked -- since Oconee, they looked above the head,
saw nothing, and that was -- That's all they have done to this point?
MR. MATTHEWS: To this point, that's true.
MR. LEITCH: Well, it says from above and below the head.
MR. MATTHEWS: Some of the highly ranked plants had
already done inspections in earlier years below the head. Ginna, for instance,
and one of the Millstone units had done inspections from below the head with
the robotic equipment, and they didn't detect anything significant.
The only significant flaw that had been detected to date was
the Cook-2 flaw in the U.S.
MR. LEITCH: So that statement then -- This is pre-Oconee
inspections?
MR. MATTHEWS: Yes. The below-the-heads were pre-
Oconee.
CHAIRMAN FORD: Before you come off that, some of the
questions associated with those bullets are addressed by the NRC questions.
MR. MATTHEWS: Yes.
CHAIRMAN FORD: Two are not -- or one is not. Jack, the
structural integrity evaluations -- is that okay, as far as you are concerned? It
is more an analytical thing. Should we be worrying about this at this stage?
Should we be following up in questions? I'm trying to cut down the time.
MR. STROSNIDER: This is Jack Strosnider, Director of
Division of Engineering.
When you talk about the -- Let me make sure I understand
your question. When you talk about the structural integrity evaluations,
basically using a limit load type analysis? You are asking if that is acceptable
to the staff?
The answer to that is yes. We think that is an appropriate
method, and we haven't identified any issues with that.
I need to point out, it doesn't include crack growth rate
analysis. I'm just talking about assessing a remaining ligament and its capacity.
CHAIRMAN FORD: We are about to come onto that very
interesting aspect, I think, in a minute.
The CRDM nozzle ejection analyzed event -- and I'm sure in
my ignorance at this point. What happens if a whole lot of adjacent nozzles are
ejected?
MR. MATTHEWS: Well, then you have a larger LOCA.
CHAIRMAN FORD: And is that a part of your safety case?
MR. MATTHEWS: It's not. Multiple rod ejections from a
reactivity standpoint is not analyzed. Lots of coolant accidents much bigger
than a 2 1/2 inch hole are analyzed, and the operators are trained on how to
respond. No matter what size the LOCA, they go to symptom based --
CHAIRMAN FORD: Multiple rod ejections are not analyzed?
The consequences are so undesirable?
MR. MATTHEWS: Not from a reactivity standpoint. The
single rod ejection was selected as a bounding reactivity insertion event for
analysis in the design specs.
CHAIRMAN FORD: And yet you were showing pictures
earlier on of a lot of cluster of OD cracks, circumferential cracks.
MR. MATTHEWS: Yes. The probability that you are going
to have more than one of these go at one time, it's got to quite, quite low. The
probability to have one go is pretty low, we believe.
MR. HUNT: This is Steve Hunt. A clarification on that picture,
the one that showed the cluster of nozzles and cracks: Those were axial
cracks. There were only two in the head that had circumferential cracks that
were measurable.
CHAIRMAN FORD: Okay. I'm trying to cut down so that
we've got plenty of time to talk about stress growth in cracking.
DR. WALLIS: We don't have to stop at 2:30, do we?
CHAIRMAN FORD: No, but -- Well, I want to give the NRR --
(Slide change)
MR. MATTHEWS: The NRC asked us several questions in
May relative to leak detection, our time and temperature histogram, the growth
rate of circ cracks, and some loose parts in risk assessment. Then later on they
asked us questions concerning show us what it looks like when you have done
these visuals at other units besides Oconee, and questions relative to the
inspection capability of the industry, besides just the visual.
(Slide change)
MR. MATTHEWS: The interim safety assessment was
prepared to demonstrate the safety of the plants. We currently have efforts
going on associated with putting together the final safety assessment.
Visual inspections of the reactor vessel top head surfaces
were recommended and are being recommended for the plants that are coming
down in the fall. Research into improved inspection and repair technology is
going on.
We are working on putting together a good risk assessment,
and the results of all this will be factored into our final safety assessment.
(Slide change)
MR. MATTHEWS: In the area of leak detection, the Oconee
and ANO plants detected the leakage, but the question is there's some plants
out there that have greater, by design, interference fits than the B&W design.
Leakage should be detectable at most other penetrations,
given similar cracks, we believe. On the other nozzles that were inspected at
Oconee that did not show the leakage outside, there was no evidence that there
was any kind of a through-wall indication on any of those.
The interference fits at all the other plants are only slightly
larger than the ones at Oconee and ANO, and further experience has shown
that it's difficult to prevent leakage of 2250 pound water without some kind of roll
or hydraulic or explosive expansion or use of a sealant.
DR. WALLIS: I would think the boron would be a sealant.
MR. MATTHEWS: The boron tends to -- Even on very tight
cracks or very tight leaks at flanges, etcetera, the boron tends to make it all the
way to the outside, and that's where -- and still leaks.
DR. WALLIS: It oozes out then, like toothpaste?
MR. MATTHEWS: Yes, I would think. I'm not sure. It's kind
of like crystals, but yes.
MR. LEITCH: So the conclusion then is that the boron is a
reliable telltale?
MR. MATTHEWS: Yes.
MR. LEITCH: And that's true for all -- regardless of PWSCC.
MR. MATTHEWS: That's how they discovered the Summer
crack was boron. Numerous piping penetrations with alloy 600 similar designed
J-groove welds have been discovered through boric acid crystals on the outside
from where they have leaked. Feeder sleeves on pressurizers -- the boric acid
comes out, and it's visible.
MR. LEITCH: But even with a very tight interference fit, the
boron will still find its way out and be a reliable indication of a crack?
MR. MATTHEWS: We believe it will.
MR. HUNT: There is one bit of supporting evidence for that,
and that was some pressurizer instrument nozzles at EDF, which were actually
roll expanded into the shell, and they cracked inboard of the roll expansion, and
they still leaked past the roll expansion.
DR. WALLIS: Is it true that experiments with leakage of
borated water at these pressures through small cracks has only been
performed on the heads of operating reactors?
MR. MATTHEWS: I would say it's probably been performed
at -- Oh, with interference fit?
DR. WALLIS: No one has actually done lab experiments with
pressure -- high pressure borated water leaking out through a tight fit?
MR. MATTHEWS: Not to date, no. I don't think we have.
DR. WALLIS: It seems like a very simple thing to do.
MR. MATTHEWS: We don't have those experiments done
yet.
DR. KRESS: Make a good Master's thesis.
(Slide change)
MR. MATTHEWS: On the leaks that occurred at Oconee and
ANO, they actually had the data from the manufacturing for what the
interference fits were, what was the OD of the machine nozzle, what was the ID
of the holes.
One of the nozzles had a gap, but the rest of the nozzles had
at least one end of the nozzle -- either the upper end or the lower end was an
interference fit, and three of them had interference fits manufactured as tight as
1.4 mils interference, and they still leaked.
(Slide change)
MR. MATTHEWS: If you look at the effect of the operating
conditions on the fit, the differential thermal expansion is only a small effect. If
you look at the older version of the code and use those values, it increases the
initial interference fit by less than 1.4 mils. But the change in fit under operating
conditions is primarily due to the pressure dilation of the vessel head.
For that example, the hole would expand 4 mils, and the
nozzle itself would expand under the pressure of .48 mils for a net decrease in
the interference fit or increase in the gap of 3.5 mils. If you do have thermal
expansion differential, it reduces that by whatever the differential in thermal
expansion is. But the gap -- or the interference fit tends to get much less as you
take the plant to operating conditions.
(Slide change)
MR. MATTHEWS: Finite element analysis has been done to
show that the outer row of the CRDM nozzles displace laterally and become
slightly ovalized in the vessel as the clearance -- if any clearance opens up
under operating conditions. That displacement and ovalization reduces the leak
path at some locations and tightens it at others around the circumference of the
nozzle and has a tendency to create a spiral flow path around the nozzle, if
those were to develop a leak.
There is also an effect, although it is pretty small, from the
flange tensioning in rotation. That tends to increase the ovality and open up
that spiral leakage path.
(Slide change)
MR. MATTHEWS: In the spring of 2001, after Oconee had
discovered their leaks and the industry was sensitized to what the situation is
and how small the boronic acid deposits are, Robinson 2, Salem 1, Farley 2 and
Prairie Island 1 all did some form of complete vessel head inspections above
the head, and McGuire 1 and San Onofre 3 did partial of some number of their
penetrations.
These heads were reasonably free of the masking boric acid
deposits, and none of these found any evidence of leakage.
(Slide change)
MR. LEITCH: I assume you can get a good look at these. In
other words, some manufacturers, it's more difficult to look at than others.
MR. MATTHEWS: Yes. Here's an example. This is not in
the handout, but this is what that shroud looks like. All the penetrations are
inside there. It's kind of tough, but there's doors so you can open the doors, but
even on many of the plants, if you open the doors, this is what you see.
You see the metal insulation and the penetration where it
actually goes in the head is below these insulation panels. So it's pretty difficult
on some of the plants to do.
This one is fairly easy to get to. Some of the other plants, the
insulation actually hugs the head. It's riveted together. It's very difficult to get
to or it is even calcite blocks that are cemented on. So some of them have a
difficult time, but some of them don't.
This is the inspection that was done at Salem and what they
were able to do. The upper head packages are different on a lot of plants, a lot
of different designs. But what they were able to do was to lift the shroud and
remove these vertical panels and the lower horizontal panels, and they get a
very good look at the penetrations.
You can see, there's not a lot of junk laying around on their
head at Salem.
MR. LEITCH; But on these plants where they did a visual
inspection, regardless of the difficulty of doing it, it did turn out that they had a
valid visual inspection?
MR. MATTHEWS: We believe those were pretty valid
inspections, yes, especially -- yes, all of them.
(Slide change)
MR. MATTHEWS: This was the inspection that happened at
Robinson. Somewhere back in time they had painted their heads. So there's
a lot of paint still there. You can even see it swathed up on some of the
penetrations, but they had a clear look.
Now the reason they got into it, they are one of the very highly
ranked plants, but what they did was they had a -- I believe it was a con seal
leak. So they had to go in and do some cleaning in some areas. While they
were there, they decided to take all their insulation off, and they damaged it
doing it, and they couldn't put it back, and they had to change their design and
put a different kind of insulation back in there. But they had that kind of mirror
insulation and destroyed it.
Prairie Island has some different package, and they can get
in and get a good look at the penetrations at Prairie Island, and they do that
routinely. But they are kind of unique.
(Slide change)
MR. MATTHEWS: This was the inspection that was done at
Farley. It's kind of hard to see. A video tape is much more -- better to tell
what's going on. But this is the penetration, and this is the actual interface with
the head, and we were able to get the video probe up to all the penetrations and
get a pretty good look.
There were a couple that had some insulation that we couldn't
quite get 360 around, but those were the kinds of inspections that have been
done.
McGuire and SONGS are listed as partial there. They are
partial, because you couldn't -- the others could not be accessed. I believe
McGuire did remove some panel to look at some of their outer row penetrations,
and San Onofre insulation package allows them pretty easy access to the outer
row or two of penetrations, but the rest of them are up under some insulation.
It's difficult to get to.
CHAIRMAN FORD: Larry, what I plan on doing is that we will
call a break at 10:15. And so we do not cut short much of the discussion -- I
think you are about to go into the histogram stuff right now?
MR. MATTHEWS: Yes.
CHAIRMAN FORD: Since that is the basis of your current
prediction methodology, let's take a quarter of an hour discussing that, take a
break, and then we will discuss the crack growth rate stuff.
Ms. Weston reminds me, we've got some time this afternoon.
So we might use that time that was going to be for discussion for the NRR
presentation.
(Slide change)
MR. MATTHEWS: I knew we had too much.
CHAIRMAN FORD: That's okay.
MR. MATTHEWS: The time and temperature histogram or
model or whatever we want to call it groups the plants according to the time --
and we are using effective full power years as a indication that the plant is at
temperature -- required for each unit to reach the equivalent effective time at
temperature as Oconee 3 at the time that the above-the-weld sort of cracks
were discovered in February 2001.
So we took their numbers, normalized theirs to 600 degrees,
took everybody else's numbers, normalized it to 600 degrees, took that
difference in time then and converted the time back to whatever their operating
head temperature is to figure out how much time in effective full power years
they have until the time that they would be equivalent to Oconee-3, and we
used that industry standard 50 kcal/mole for that temperature adjustment.
DR. WALLIS: So this is an entirely theoretical curve at this
point?
MR. MATTHEWS: Yes.
MR. ROSEN: It's more of an empirical.
DR. WALLIS: It's entirely theoretical. There is no data yet.
MR. MATTHEWS: Except for Oconee-1, 2, 3 and ANO.
DR. BONACA: But it assumes that Oconee is the first plant
that has experienced leakage, and we really don't know.
MR. MATTHEWS: One of the things that was alluded to
earlier was the --
DR. WALLIS: It is the extrapolation of orders of magnitude.
MR. MATTHEWS: Okay. That's all we got.
CHAIRMAN FORD: We talked earlier on about the effect of
residual stress profiles. I know Warren has got this capability. Can you not also
just modify this to take into account a supposed range of residual stress profiles
and modify this further?
I'm just concerned that temperature is the only variable in this
whole thing.
MR. BAMFORD: Let me try to answer that. This is Warren
Bamford from Westinghouse.
The reason that we've gone to this model is purely pragmatic.
We found that the previous model had in it materials variability. It had in it
stress variability, because we know that as you go further and further out toward
the edge of the head, the stress -- the residual stresses are a function of the
angle of intersection of the tube in the head.
So on the outer edges, stresses are typically higher. All right?
When we found out that there wasn't any pattern to the cracking that was
showing up here, the idea that the stresses were the only driver behind this
seemed to be no longer a good conclusion.
So in the time that we had, we decided to develop a simple
model to see what would happen. We developed -- We dropped the stress
effect. We dropped the material effect. All right? So we just -- We cut the
model down to its very basics, just time and temperature.
When we looked at what came out, the Oconee plants came
out right at the top of the model when we just simply ranked them. We weren't
comparing to anything. We just ranked them. The Oconee plants all came out
right at the top.
So that gave us some confidence that maybe this is a good
way to rank things. Then we started ranking them to -- ranked the other plants
relative to Oconee, because we really had put a lot of sophistication into some
previous models, and we found out that what was happening at the Oconee
plants and at ANO didn't seem to correspond to the level of sophistication.
So we had gotten more sophisticated than we had any right
to be, I think. So we tried to back it down. But your question about the residual
stresses, I think, is -- There is a brief discussion as well.
Residual stress calculations were done with sophisticated
elastic plastic finite element models by at least five different outfits that I'm
aware of. The results were very, very similar from all the different models.
That led us to the conclusion that there really isn't that much
variability in the residual stresses. The only difference is the angle of
intersection between the tube and the head, because the welds are made at an
angle.
In fact, there's such an amount of deformation that it causes
the tubes to become oval when they stick down inside the head. They actually
are ovalized, and they are set in that position. So there is a lot of residual stress
there.
The models that have been done by five independent
organizations all gave essentially the same kind of results. Now the other thing
you need to keep in mind with residual stresses: You don't get much higher
than yield level residual stresses.
So the variability here is not huge, and as soon as you go
above the weld region in these tubs, the residual stresses drop off very quickly.
So I don't think there is that much variability in the different
residual stresses.
CHAIRMAN FORD: The reason I would debate that is your
residual stress model, the model itself, not the data -- the model itself is
reproducible between five laboratories, whatever.
MR. BAMFORD: Right. Now we might all be wrong, okay?
But there's a lot of consistency there.
CHAIRMAN FORD: Two questions I would like to ask. One
is that model that says it should be all around the circumference of the head,
and it's not. Therefore, the model may be correct, but the data is giving you
something else, because of whatever it might be.
MR. BAMFORD: That's right.
CHAIRMAN FORD: And so that's a variable that is not taken
into account.
MR. BAMFORD: There is clearly more to the story than we
are able to account for at the present time, and we are working on that. But we
also have to deal with the plants that are out there that have to operate in a safe
condition.
So where we are right now is taking our best shot with the
information we have at hand.
MR. FYFITCH: Let me add one more thing. Steve Fyfitch
from Framatone again. However, with the B&W design, though, the shape of
the head is much flatter than most of the Westinghouse units. So when you
calculate the residual stresses, the differences from the center nozzle, which
has a uniform weld around it, versus the nozzles that are on the outer periphery
do not change that drastic compared to when you calculate it for a
Westinghouse head.
So those residual stresses are pretty much even for the B&W
plants.
CHAIRMAN FORD: Larry, I've got a request. Are you going
to be giving the presentation tomorrow to the full ACRS Committee tomorrow?
MR. MATTHEWS: Wasn't planning on it.
CHAIRMAN FORD: Yes?
MR. MATTHEWS: No. I wasn't planning on it. Did they say
yes?
CHAIRMAN FORD: I don't know.
MR. MATTHEWS: News to me, if I am.
CHAIRMAN FORD: Well, there is going to be a presentation
from someone tomorrow. I thought it was going to be you.
MR. MATTHEWS: I thought it was going to be you.
CHAIRMAN FORD: My request is that, you know, a lot is
riding on this prediction model, this histogram, and you are saying the Oconee
data. Can we see some data tomorrow to show that?
MR. MATTHEWS: We have a little bit here.
CHAIRMAN FORD: You've got some data with Oconee
points up at the top and everybody else below?
MR. MATTHEWS: Yes.
CHAIRMAN FORD: Okay, good.
MR. MATTHEWS: And skip the 40 kcal/mole?
CHAIRMAN FORD: Yes.
MR. MATTHEWS: That would just move the histogram
around slightly.
(Slide change)
MR. MATTHEWS: The ten-year period that we selected for
inspection recommending that the people inspect was to account for all these
uncertainties. Is it enough? I don't know. We thought it was enough for an
initial crack this fall. It encompasses 25 of the 69 units in the U.S.
DR. WALLIS: What does ten-year period mean?
MR. MATTHEWS: We were recommending that everybody
who was less than ten years away from being equivalent to Oconee do an
inspection this fall -- that's got an outage this fall.
DR. WALLIS: That's an engineering judgment?
MR. MATTHEWS: Yes, it's just an engineering judgment.
MR. HUNT: This is Steve Hunt. To put that in perspective,
the predicted time for Oconee is approximately 20 years. So we are going back
to plants with half the time at temperature as Oconee.
MR. MATTHEWS: Right. And all but two of those top 25
units will have an outage by the spring of '02 in which they can take a look at
their heads, and we would reassess that after we get any data from the fall
outages.
(Slide change)
MR. MATTHEWS: This was a different way of looking at the
histogram that actually has numbers on it. Some of these numbers have
changed. This is what we submitted. Plants have taken another look at what
their real head temperature is instead of some super-bounding, conservative
number they put in there.
If you look at this -- and you have a black and white copy, but
the top three units right here, this is time for the plant to be equivalent to
Oconee-3, and this is just where the unit stacks up in the rack.
This is Oconee-3, and the other two units here are Oconee-1
and 2, and those have all done inspections.
This is ANO, but after some reassessment -- or maybe this
is ANO. This is one of the other plants that did an inspection this spring. This
one did one, and this one did one. All those plants did visual inspections, full
visual inspections, of their heads this spring.
CHAIRMAN FORD: But that is not your data -- that's not the
proof?
MR. MATTHEWS: No. This is just how they wrapped up and
saying we are going to get to them fairly quickly by looking at, you know, 25
units here before ten years. All of those units except for two of them would
have outages before next spring.
DR. WALLIS: So if you could detect cracks in one that's out
to, say, EFPY of 50, that would be a big surprise.
MR. MATTHEWS: That would be a big surprise.
DR. WALLIS: That would tell you that your theory wasn't very
good.
MR. MATTHEWS: It sure would. Here is another variable we
don't know. All of the red squares here have outages scheduled in the fall, and
we have recommended that all of them below ten years do a visual inspection
of their heads this year.
MR. LEITCH; Is it possible to say what made Oconee the
outlier? Was it time or temperature? In other words, they operate at a higher
temperature?
MR. MATTHEWS: They are an old plant. They run at a fairly
or quite high head temperature, and they have had very good runs on those
units.
MR. LEITCH: So it's really kind of a combination of the two.
It's not just one that predominates. They are both --
MR. MATTHEWS: Yes. The B&W units typically run at some
of the highest head temperatures of any of the units. These plants out here --
we call them t-cold plants. They bypass an awful lot of the cold leg flow back
to the head and keep the head pretty close, in some cases, to the cold leg
temperature. So they are operating down around 560, 570 degrees with lots of
temperature margin to the 602 that the Oconee units were running at.
Most of these units are Westinghouse and CE units. Most of
them are in the -- below 600, but above 585 or so, up closer to 590 to 600, most
of these, and the main variables between them is the -- Well, the only variable
on this chart is the time and the temperature and normalizing it to 600 degrees
Fahrenheit.
DR. UHRIG: Why is there a large gap in there?
MR. MATTHEWS: This big gap is -- This is probably the
oldest cold head plant, and this is one of the newest hot leg plants.
DR. UHRIG: Difference in hot and cold is 15 degrees?
MR. MATTHEWS: No, it's significantly more than that. I don't
have the exact number, but these plants here run in the 590 to 600 range.
MR. HUNT: It's the difference between around 600 for a hot
head and 550-555 for cold leg. So it's about 45 degrees.
MR. MATTHEWS: And this cracking in the model tends to
take off at 50 calories per mole, really takes off around 600.
DR. WALLIS: And because it is an exponential relationship,
50 degrees makes a big difference.
MR. MATTHEWS: Yes, even the -Q over RT.
DR. UHRIG: I didn't realize it was 50 degrees here.
MR. MATTHEWS: Yes.
(Slide change)
MR. MATTHEWS: This is the same data, just blown up for
the first ten years. Some of these plants have said they have gone back and
looked. What we used when we initially put the histogram together was the
temperatures that were in the 97-01 submittals. Some of the plants had just
made awfully conservative estimates at that point in time.
DR. WALLIS: It means you expect cracks in one year?
MR. MATTHEWS: Yes. Well, no. You expect to be at the
equivalent time and temperature as Oconee-3 in one year. I'm not going to say
they are going to crack.
If you had exactly the same properties and stresses and
material and everything else that Oconee-3 had, yeah, I guess you could say
it would be expected.
DR. WALLIS: You guys are running a very interesting
experiment.
MR. MATTHEWS: Expensive, too. It's expensive to get the
data out of it, too. But that's our histogram, and that's the basis, and our ten-
year margin there was to try and cover some of these uncertainties. That's half
the life of Oconee, as far as time at temperature, and we are saying everybody
who is that close ought to be taking a look.
DR. WALLIS: So nothing you've said so far tells us why these
plants are safe. That's what we are going to do with the crack growth argument,
is it?
MR. MATTHEWS: Well, we believe Oconee was safe. They
had plenty of margin to rod ejection at Oconee.
DR. WALLIS: Well, that comes because of crack growth
analysis or something?
MR. MATTHEWS: At the time that they shut down.
CHAIRMAN FORD: What Jack was saying is at this particular
time now with current cracks as they are now, they are safe. It doesn't say
what is going to happen in the next fuel cycle if you don't know how much it is
going to grow.
DR. WALLIS: But that's the whole thing that matters.
CHAIRMAN FORD: That's what we are going to discuss.
MR. BAMFORD: In two slides, we are going to cover that.
DR. WALLIS: But that's the key thing, isn't it?
MR. BAMFORD: Yes.
CHAIRMAN FORD: Could I suggest that -- because this
might take a wee bit of time. Could I suggest that we take a quarter of an hour
break, and we will adjourn for 15 minutes.
(Whereupon, the foregoing matter went off the record at 10:13
a.m. and went back on the record at 10:32 a.m.)
CHAIRMAN FORD: I would like to bring the meeting back to
order. Larry, would you like to continue on the glorious subject of crack growth.
DR. WALLIS: I'd like to bring up -- go back to 66, having
thought a bit about it.
(Slide change)
DR. WALLIS: About the cold plants and the hot plants. You
said the ones on the right are cold plants, 550 degrees instead of 600. That's
why they are on the right.
This is a five percent difference in ranking temperature. So
if we have a five percent difference in activation energy -- If a cold plant has,
let's say, 55 kilocalories per mole instead of 50, wouldn't that make it equivalent
to a hot plant?
MR. MATTHEWS: Well, it's absolute temperature and not --
DR. WALLIS: It is. That's right. It's only a five percent
difference in absolute temperature. So the only point is that the uncertainty in
activation energy would move these points around a lot.
MR. MATTHEWS: Well, we had the sensitivity -- We did a
20 percent sensitivity study.
DR. WALLIS: But that's assuming they all have the same
activation energy. They have differences in activation energy between plants.
MR. MATTHEWS: Why are you going to have a difference
in an activation energy for --
DR. WALLIS: I just don't know. But how close are the
activation energies likely to be? I just don't know what the scatter is likely to be.
MR. MATTHEWS: Yes, there's the sensitivity where we went
down to 40.
DR. WALLIS: On 64, which we skipped over -- That assumes
they are all same activation energy. The point is, if there is a scatter in
activation energy between plants -- I just don't know how certain you are.
Seems to me that the number for activation energy is uncertain, to some
degree.
MR. MATTHEWS: I guess I would expect it to be the same
kind of uncertainty for all the plants, though.
DR. WALLIS: Yes, but it's uncertain. The point is there is an
uncertainty. That uncertainty could make a cold plant like a hot plant, if it's only
five percent. That's the point.
MR. MATTHEWS: Can you address that?
MR. BAMFORD: One of the things that comes out when you
start looking at these things is the difference between susceptibility between a
550 and 600 degrees F. is almost two orders of magnitude. So the sensitivity
to the temperature is very high.
DR. WALLIS: No, but assuming the same activation energy --
MR. BAMFORD: Well, the sensitivity is a function of the
activation energy, and we looked at a different activation energy. Probably, we
should show that slide to see what the impact is, because the impact turned out
to be small.
DR. WALLIS: No, but that's assuming it's the same between
plants. The point is, if --
MR. BAMFORD: Well, you could look at it as different --
DR. WALLIS: -- the activation energy of Oconee is 50, all it
has to be is 55 for a cold plant, and the cold plant becomes like Oconee. Isn't
that --
MR. BAMFORD: Well, it's the other way around. It would be
45.
DR. WALLIS: Whichever way it is. Forty-five, yes. Or it's
supposed to be a five percent effect or -- It's a five percent effect, rather than
a ten percent effect. So it's 47 1/2.
Just look at degrees Rankine. Five percent in degrees
Rankine is equivalent to five percent in activation energy, and what is the
reasonable uncertainty in activation energy?
MR. MATTHEWS: I guess the uncertainty in the activation
energy is not the same, in my mind, as the variability from plant to plant.
DR. WALLIS: Same thing. I mean, think of it as the same
thing.
MR. MATTHEWS: I guess I don't. The uncertainty is how
well do you know the activation energy for stress corrosion cracking in Alloy
600.
DR. WALLIS: Okay, for anything. There's two questions. Do
you know it at all, and how much does it vary between plants?
MR. MATTHEWS: I guess the biggest part of the uncertainty
I always envisioned would be how well you knew it, not how much that variable
would vary from plant to plant.
DR. WALLIS: Well, it's completely out of my field. I don't
know what -- how well you know something like activation energy. Is it likely to
vary five percent between plants? Ten percent? Hundred percent? Fifty
percent?
MR. FYFITCH: Let me just add something. Steve Fyfitch
from Framatone.
If you look at historically all the test data on Alloy 600, whether
it be bar material, wrought material, rod material, any kind of product of Alloy
600, for stress corrosion cracking under primary water conditions, the range of
activation energies that have been published for crack initiation are in the range
of 40-50 kilocalories. Okay?
DR. WALLIS: So it's an uncertainty of maybe ten percent or
so?
MR. FYFITCH: In that range, yes, about ten percent. If you
look at the range in activation energies for crack growth, they are, you know, 35
to 50 maybe, maybe even less than that.
MR. BAMFORD: Yes, I would say 30 to -- maybe 33 to 36,
something like that, for crack growth. What we're really trying to do here is
focus on crack initiation.
DR. WALLIS: But the point is then that your graph is based
on the same activation energy, and there's an uncertainty in activation energy
which is quite capable of moving the cold plants to be like hot plants.
MR. FYFITCH; It wouldn't be that bad, though. I mean, if you
do the calculation, for a 50 kcal/mole activation energy, it's 600 degrees versus
a 40 kcal/mole activation energy at 550, the numbers don't change that
drastically.
DR. WALLIS: That's the whole point.
CHAIRMAN FORD: I think you had two questions. First of
all, would you expect the 50 and the 40 or whatever to be absolute values, and
for a given phenomenon --
DR. WALLIS: That's less important than, I think, the variability
between plants.
CHAIRMAN FORD: Well, the variability between plants,
because there are different conditions in the plants.
DR. WALLIS: Because everything is benchmarked to
Oconee, it doesn't really matter what the values are. What matters more is the
scatter between plants, variability between plants.
CHAIRMAN FORD: For this sensitivity study we did where
we changed the activation energy from --
DR. WALLIS: Would you write down this Arrhenius equation,
just to see -- show that when the temperature changes and the activation
energy changes, you get the same number? They change in certain
proportions.
MR. MATTHEWS: It's E to the -Q over RT.
DR. WALLIS: It's in Appendix by five percent and T changes
by five percent. Then you get the same number, right?
MR. MATTHEWS: Right.
MR. BAMFORD: And the development of the model is in
Appendix B of our interim report that was submitted in --
DR. WALLIS: We don't need it. As long as we know we've
got this equation, then we're saying that a five percent uncertainty in activation
energy -- a five percent variability between plants in activation energy is like a
50 degree change in temperature.
MR. MATTHEWS: Well, one thing about this study we did,
the Oconee plants operate very close to 600. So the adjustment to their EFPY
from 602 to 600 is pretty small. If you take the plant that's out in the far-out
category and adjust their number from 550 or 560 to 600, it's a pretty big
adjustment to stretch their time out.
If you drop that activation energy to 40 kilocalories per mole,
Oconee's adjustment is still going to be very small; whereas, that other plant
then gets a significantly different adjustment, and that's kind of what this effect
would say.
The adjustment for Oconee being the base unit, it wouldn't
move very much one way or the other, because it's pretty close to 600.
DR. WALLIS: Well, it's the base unit. It's not going to move
at all. Everything is hung on it.
MR. MATTHEWS: Well, I mean, as far as if you're calculating
the --
DR. WALLIS: Zero is Oconee on your graph.
MR. MATTHEWS: Right, Oconee-3.
DR. WALLIS: It's just that you can jiggle the other points
tremendously by giving --
MR. MATTHEWS: And what I'm saying is that by looking at
the sensitivity -- look at the sensitivity study. Oconee wouldn't change their
EFPY very much by going from 602 to 600, if you went from 50 to 40. It's not
a big adjustment. It's a very small adjustment in temperature, small factor on
their EFPY.
A plant that is at 560 gets a big adjustment. It shoves them
way out in time. If you dropped it to 40 kilocalories per mole, yeah, it's a
significant bump up. But if you look at what it does to the histogram, and those
plants are so far out that it still doesn't get them into very near time frame for --
DR. WALLIS: That's because time is also short for them.
Right?
MR. MATTHEWS: Right.
DR. WALLIS: Right, but the rate is the same. Yeah.
MR. BAMFORD: I think we should also mention a couple of
other things. Setting aside the model, the actual temperatures at the plants are
very well known. In other words, the head temperature of the plants -- there's
very little --
DR. WALLIS; Absolutely.
MR. BAMFORD: -- uncertainty there. Okay. But now the
other thing that's really important to keep in mind, if you look at the available
information from labs and actual tests that have been done, when you get down
to temperatures that are in the 550 to 560 degrees range, it's very difficult to get
stress corrosion cracks to propagate at all.
In fact, some labs have claimed that below 550 there is no
stress corrosion cracking in inconel or in Alloy 600. I'm not so sure that we
would go that far, but there's a huge difference in the susceptibility when you
get to a lower temperature.
So the plants that are at the lower temperatures are far, far
less susceptible than the ones that are at the highest temperature. The highest
temperatures -- I've done a lot of lab testing of this material, and at the highest
temperatures you can get cracks to grow quite quickly, but at the lowest
temperatures it's very, very difficult.
So I think we need to keep that in mind, too, as well.
DR. KRESS: Are you saying that the Arrhenius relationship
no longer applies at the lower temperatures?
MR. BAMFORD: No. I'm saying it does apply, and the
Arrhenius model is a very good representation of what we actually see in the
labs. But the contention that a five percent change in temperature for a plant
that's at 550 could put them into a much higher susceptibility area, while that is
in fact true according to the model, we know the temperature of the operation
quite well, and we also know that low temperatures, down in the 550 range, are
very, very unlikely to show stress corrosion cracking unless you have long, long
times of service.
DR. WALLIS: Essentially saying the activation energy is very
unlikely to be below a certain value.
MR. BAMFORD: I believe that's another way of saying it.
That's right.
MR. MATTHEWS: Given that activation energy or whatever
it is, the ten years here that we've used -- if you think about what that really
means, plants beyond ten years have operated in an effective time at
temperature less than half the time that Oconee has.
If you go further out, you know, 30 years, that's ten years
before Oconee started up. So it's a significant amount of time that we are
tacking on here for our recommendations for inspection.
(Slide change)
MR. MATTHEWS: Circumferential crack growth: One of the
things that's been a concern is how fast do these cracks grow, the
circumferential cracks, once they get into the annulus environment.
We've got data from five available sources of carefully
controlled PWSCC tests of the Alloy 600 and the 182, using PWR conditions.
OD initiated cracking requires water or steam in that annulus, and a pressure
boundary leak is necessary for that to get there.
Crevice region could contain some oxygen from the
containment atmosphere, but at temperature this oxygen would be fairly quickly
consumed with the low alloy steel nearby. This reaction, plus the extremely
tight fit and the distance to the OD of the head, make a high oxygen
environment seem unlikely.
(Slide change)
MR. ROSEN: One moment. If the oxygen is consumed, as
you suggest, would it not be replenished?
MR. MATTHEWS: Would it what?
MR. ROSEN: Would it not be replenished by diffusion from
the containment atmosphere into the crack?
MR. MATTHEWS: Yes. Over time that's the only way it could
get in there, and it would have to diffuse upstream.
DR. WALLIS: Well, if there is no leak, there is no stream.
MR. MATTHEWS: Right. Well, if there's no leak, it's going
to be hard to get the oxygen in there, I think.
The circumferential crack growth rate: Since the fluid contains
lithium hydroxide and boric acid in this region, it's likely to be similar to a
controlled PWR environment. The comparison of --
CHAIRMAN FORD: Before we get into that one, surely the
primary liquid is boiling?
MR. MATTHEWS: Yes.
CHAIRMAN FORD: Therefore, you have something like a 30
percent lithium hydroxide solution.
MR. MATTHEWS: Yes. It could concentrate.
CHAIRMAN FORD: What you don't have in the primary
environment -- You sure has heck don't have 30 percent lithium hydroxide.
MR. MATTHEWS: No.
CHAIRMAN FORD: So you have a very much more alkaline
solution in the annulus, do you not?
MR. MATTHEWS: You've got the acid in there, too.
DR. WALLIS: You've got lithium borate, haven't you?
CHAIRMAN FORD: Yes, but you're doing simple titration.
You don't know that it's -- they are equilibrating each other. It's a weak acid and
a very strong base.
MR. MATTHEWS: Yes, it is a strong base.
CHAIRMAN FORD: I'm just questioning that, and it's not just
an academic debate, because you then go on to say that the disposition curves
that you are developing from -- that have been developed, the primary side,
apply to the circumferential cracks on the OD. It's based entirely on that
assumption in that first bullet.
MR. MATTHEWS: Well, comparing the crack growth data
from both the BWR and the PWR environments, a highly oxygenated
environment --
CHAIRMAN FORD: Well, I don't debate the second bullet.
MR. MATTHEWS: Okay.
CHAIRMAN FORD: It's the first bullet.
MR. MATTHEWS: That in a caustic environment it would
potentially grow significantly.
CHAIRMAN FORD: Are we looking here at two things?
Before you actually get a through-wall crack -- Before you actually get a leak,
things are at PWR environment. As soon as you get a leak, you start boiling off
the steam, you get a very concentrated solution.
So after you get a leak, things could happen in a different
environment altogether.
MR. MATTHEWS: I guess I've heard some people don't
really believe it would be significantly different in that environment. The stuff
is going to get out.
MR. FYFITCH: Let me add something. Steve Fyfitch,
Framatone.
Certainly, you can debate what the environment is in that
annulus region. Remember, we are talking a shrink fit that opens up into a
counter-bore area. In that counter-bore area where the cracking will be
occurring, it's through a very tight crevice. So you have to look at it from a
corrosion crevice standpoint.
So initially you would expect that to be essentially primary
water.
CHAIRMAN FORD: Correct. But time zero, primary water.
MR. FYFITCH: And with time it may change. With time it may
not change. But we haven't really studied that in detail. Nobody has tried to
mock it up. Nobody has really looked at that in a lot of detail.
So at this point in time, I don't think we can really debate
whether it's a primary water environment, a BWR environment or a
concentrated caustic environment.
DR. WALLIS: Well, it's never BWR water in the crack, once
you've got a leak. Stuff is flashing and boiling and steam is driven off very
rapidly.
CHAIRMAN FORD: And you've got acid crystals. I mean,
what you are seeing, you're seeing visual evidence of a concentrating
mechanism.
MR. FYFITCH; On top of the head.
CHAIRMAN FORD: Presumably from the bottom.
MR. FYFITCH; On top of the head.
DR. WALLIS: Well, what's in the crack? It doesn't flash at the
top of the crack. It flashes at the place where it's pinched down the most, which
is the bottom of the leak.
MR. FYFITCH: Right, but it doesn't always condense --
DR. WALLIS: -- through the weld, and flash is in the cracks.
The crystals form in the shrink fit.
CHAIRMAN FORD: I guess the very fact that there was -- is
indicating there's a question.
MR. FYFITCH: Yes, and I totally agree.
CHAIRMAN FORD: And then the answer to that question has
got very large ramifications, because you are using the disposition curves
developed in the PWR environment to disposition the cracks which are going
on the OD. Correct?
MR. BAMFORD: That is essentially true, but you have to
keep in mind that over the years we've gotten -- we've inspected over 6,000
penetrations, and of those some four percent have been found to be cracked.
All right? And all of the cracks have been axial except for the very first crack,
which was at Bugey-3, and two of the cracks -- I guess three cracks at Oconee
unit 3 and maybe one other one. But there's only a couple of circumferential
cracks that have happened, and these two cracks that are through-wall at
Oconee unit 3 are the only two where the question about the crack growth rate
would be relevant.
CHAIRMAN FORD: But aren't those --
MR. BAMFORD: The other ones are all axial, and they have
all been part-through. We have only had -- We've only had these leaks that
have been found in the last six months plus the one at Bugey.
CHAIRMAN FORD: But aren't the circumferential cracks on
the OD above the J-weld -- aren't those the ones which are the greatest safety
concern?
MR. BAMFORD: Absolutely, that's true. But there are only
two -- three.
CHAIRMAN FORD: Regardless of whether there's only two
so far, regardless of the number, those are the ones that we should really be
concerned about the absolutely veracity or defensibility of the disposition
curves.
MR. BAMFORD: We agree with you.
CHAIRMAN FORD: And, therefore, you better be dark sure
that you are developing that disposition curve in the right environment.
MR. BAMFORD: We agree. That information doesn't exist
right now.
DR. WALLIS: Right. So you're guessing.
MR. BAMFORD: We are taking educated guesses, yes. You
could say that.
DR. WALLIS: Well, that's what we are doing, too, you know.
MR. BAMFORD: We are all in this together.
DR. WALLIS: Yes, but it seems to me that there should be
an analysis performed: What happens in the crack with boiling lithium
hydroxide? CHAIRMAN FORD: It's not an easy
experiment to do, but it's an experiment that could be done.
DR. WALLIS: But you could also do some analysis.
CHAIRMAN FORD: Then the question comes out: What's
the impact of this on the safety aspect? I've interrupted too much.
DR. WALLIS: Well, yes, if it does have a big impact, then it's
not good enough to guess, seems to me.
MR. MATTHEWS: Some of the data that we got on -- I guess
it's on the next side. If we use the crack growth rates that are typical of the
PWR environment, we've had two totally separate analyses. One was kind of
bounding on crack growth rate from data that we've seen, and I guess I've got
the wrong slide up for that.
(Slide change)
MR. MATTHEWS: If you look at the Oconee nozzles, which
were cracked --
DR. WALLIS: I'm sorry. When you say temperature is a
stronger variable than environment, have you allowed the environment to vary
up to --
MR. MATTHEWS: Well, that was comparing the BWR to the
PWR environment.
DR. WALLIS: -- 30 percent lithium hydroxide or whatever?
MR. MATTHEWS: Those tests haven't been conducted.
DR. WALLIS: There is no information whatsoever on crack
growth rate?
MR. MATTHEWS: Wasn't there some test at higher
concentrations?
MR. BAMFORD: We have done a series of crack growth
tests where we varied the boron concentration in a PWR environment and
varied the lithium concentration. We got -- My recollection is the lithium
concentration ended up about 50 percent higher than the nominal, and we
found that there was no impact on the crack growth.
DR. WALLIS: We are talking here about many, many percent
higher, aren't we?
MR. BAMFORD: Well, we're speculating that it could be
many, many percent higher. I guess what we need to figure out is whether that
is, in fact, true or not. Your point is well taken.
DR. WALLIS: Well, I think rather than speculating, we are
saying that when you flash off steam, it will be. I don't think we're speculating.
At some point you are going to get very concentrated solutions. You have to.
MR. BAMFORD: Well, the question really is does the solution
when it flashes to steam automatically concentrate itself or does it not?
The experience with the boron, a part of it at least, if you look
at the evidence, is that the boron seems to not deposit itself in the crevice. It
seems to deposit itself only when it gets to the atmospheric pressure when it
gets up to the top of the head.
DR. WALLIS: People have popped these things apart and
found that there is no boron in the crevice.
MR. BAMFORD: Very little compared to the boron on the
head, I believe.
DR. WALLIS: Well, it's a very small crevice, yes.
MR. BAMFORD: I agree.
MR. MATTHEWS: They have opened -- The evidence that
I've heard about is a leaking flange or something like that. The boron deposits
are on the outside. They are not actually open --
DR. WALLIS: Well, actually, open leak is going to blow the
deposits out, but if it's little leaks, starts as a little leak --
MR. MATTHEWS: No, I'm talking about weeping flanges.
The boron is on the outside. it's not deposited in the crack there.
CHAIRMAN FORD: And we know that for a fact?
MR. MATTHEWS: Well, I've heard that. I haven't gone and
looked at it, but that's what I've heard people tell me.
MR. BAMFORD: But our evidence is that -- we have not seen
evidence that high concentrations of lithium cause accelerated crack growth.
Now you can argue that we haven't gone to super high concentrations of
lithium, but we have gone to higher concentrations than the nominal, and we
don't see an impact, and our judgment is simply based on that, because that's
all the information that is available at present.
MR. MATTHEWS: We had two different analyses that have
been done of the Oconee flaws that were at 165 degrees to calculate how long
they would have had to reach the code allowable with a safety factor of three.
In both cases, it was in the four to five year range.
Admittedly, the crack growth rates -- one was a kind of a
bounding crack growth rate on lab data, and the other one was the modified
Peter Scott model that we have been using for years.
CHAIRMAN FORD: Now the Peter Scott model, just form my
remembrance, is based on the estimated crack growth rates observed in steam
generator tubes, the primary site.
MR. MATTHEWS: But it's been modified in the process by
the industry over the years for this base metal of the head penetrations. That
was the model that was used in our earlier responses to --
CHAIRMAN FORD: Now what was the basis for the
modification?
MR. MATTHEWS: Warren?
MR. BAMFORD: Lab data on 17 heats of Alloy 600.
CHAIRMAN FORD: Okay.
MR. MATTHEWS: Not tube data.
MR. HUNT: It has also been correlated with EDF cracking
experience, too, Ringhals cracking experience.
MR. MATTHEWS: Okay? So even if we're off, they still had
significant amount of time there to get to the code margins, and then to get on
down to an ejection at operating pressure, there's still a lot more margin left for
those penetrations.
CHAIRMAN FORD: That is all reasonable, assuming you
don't have really concentrated lithium hydroxide.
MR. MATTHEWS: That makes it grow significantly faster.
CHAIRMAN FORD: Which you would assume based on
United Kingdom data for the fusion reactors.
MR. MATTHEWS: Yes.
CHAIRMAN FORD: But for this particular material under
these particular circumstances, you know, it's an assumption so far.
DR. WALLIS: Where does the lithium come from?
MR. MATTHEWS: It is put in for pH control in the water
chemistry.
MR. SIEBER: But it's more volatile than the boric acid. So I
would expect that the crack environment would become acidic as opposed to
basic.
CHAIRMAN FORD: Yes, that's right. Let me ask a question.
With this uncertainty about the effect of lithium hydroxide -- the concentration,
whether it exists, and then if it does it, how much does it increase the crack
growth rate? -- how much margin do you have? If it increased the crack growth
rate by an order of magnitude, would you expect -- How would that affect your
safety analysis?
MR. MATTHEWS: I guess if the crack growth rate was ten
times faster, it would have cut down on the amount of time that a flaw as big as
Oconee 3's would have had from four to five years to significantly less than four
to five years. I haven't got the numbers, but an order of magnitude is a factor
of ten, I guess.
CHAIRMAN FORD: Why do you say four to five years?
Where is that coming from?
MR. MATTHEWS: Well, if we use the Peter Scott model or
the other way we did it with the bounding crack growth rate data, 165 degree
flaw had four to five years before it could have propagated to the point where
we would have barely met code margins, and even more time than that before
it could have gotten to the point where we only had like a 30 degree ligament
left and could have resulted in an ejection.
DR. WALLIS; It seems to me, there's a very interesting
question here. I mean, your shrink fit may be actually saving you, because it
may be allowing you to leak fast enough that you don't build up a concentration
of lithium. Worse situation is a crack growing with a very small leak.
So the crack growth and the leak rate and all these are all tied
together, and it would seem to me someone has got to analyze all these
interrelated things and figure out what's likely to happen.
MR. MATTHEWS: Trying to get there.
DR. WALLIS: Yes, but you have this very crude model based
on Arrhenius with one constant.
MR. MATTHEWS: Well, that model is not a predictive model.
All we are trying to do with that is rank the plants to figure out -- We don't have
much data, and we're trying to rank the plants to figure out which ones ought to
be the ones to go take a look to give us some more data. That's where we are.
CHAIRMAN FORD: And there's no argument with that. Now
just coming back to this lithium hydroxide, you mentioned earlier on, Warren,
that with Bugey-3 you did some subsequent inspections. Or did you say it, that
they had done some subsequent inspections on the OD cracks? If so, what
was the average crack propagation?
MR. BAMFORD: Well, there was only one crack at Bugey-3,
and it was removed. So they never did any follow-up inspections there. But
there have been other follow-up inspections at other plants.
CHAIRMAN FORD: And?
MR. BAMFORD: But keep in mind that we only have two --
We have the little small circumferential crack that was removed at Bugey-3, and
we have these two circumferential flaws at Oconee that were through-wall and
leaking, and maybe there's a third one, a small one at Oconee. But we don't
have multiple measurements of the cracking of these circumferential flaws.
MR. MATTHEWS: All the circ flaws in a leaking environment
have been repaired immediately, as I recall.
MR. BAMFORD: Yes. We would not be interested in leaving
a circumferential flaw in service.
MR. MATTHEWS: It's not the place to get this data.
CHAIRMAN FORD: Okay, thank you.
(Slide change)
MR. MATTHEWS: The next slide is on loose parts. Basically,
if you have enough flaws -- I'm going to skip it -- If you have enough flaws, axial
and circumferential, below the weld hook-up, the potential is there, although we
feel it is quite low, to create a loose part.
Basically, the worse consequence from that that we see is a
stuck rod from that one -- one stuck rod from that loose part, and --
DR. UHRIG: There would be a leak?
MR. MATTHEWS: No. No, you could create a loose part
without creating a leak, if all the cracking is going on below the weld. But the
worst consequence is any other kind of loose part up in that region, you could
possibly jam a control rod with a loose part. The probability, we're going to get
more than one before you find that one is pretty low.
DR. UHRIG: As I recall, Oconee had loose parts monitors.
Am I correct on that?
MR. MATTHEWS: On the vessel?
DR. UHRIG: No, I think it's just in the steam generators.
MR. MATTHEWS: Well, he's nodding his head. One of the
most probable places for a loose part that's generated here to go is the steam
generator, yes.
DR. UHRIG: That's the ones I'm most familiar with.
MR. MATTHEWS: And that would be picked up.
(Slide change)
MR. MATTHEWS: From a risk calculation -- We have risk
calculations that are now in process. The efforts include interaction with all the
PWR vendors to make sure it's applicable to all the plants.
It is going to be consistent with some of the past approaches
we have taken. WE have heard the staff has conservatively estimated a
conditional core damage probability at about 10-3, assuming a rod ejection.
That would be, I guess, consistent with a small break LOCA or medium break
LOCA.
I heard today they may have a number that's quite a bit
higher, and I'm not sure how they got that. But we feel the probability of ejection
event is likely to be a few orders of magnitude less than 1 certainty. So the
probability is going to be getting down into -- or the core damage frequency
from rod ejection because of this is going to be, we feel, quite low, but we
haven't finished the analysis to prove that yet.
DR. KRESS: How do you calculate the probability of rod
ejection?
MR. MATTHEWS: What do they call it, probabilistic fracture
mechanics is one of the things, plus they are going to look at the --
DR. KRESS: So you do have to put in the uncertainties?
MR. MATTHEWS: Yes.
DR. KRESS: Crack growth and certainly, strength and --
When the thing goes, it's like a pressurized thermal shock.
MR. MATTHEWS: I believe all that will be in there.
DR. WALLIS: But we don't have lithium and stuff in the --
MR. MATTHEWS: We would have to account for it in the
uncertainty.
DR. KRESS: You have to put that in the uncertainties, don't
you?
(Slide change)
MR. MATTHEWS: I am get to a summary. This is the same
one I had up front. Okay? Why I put it up front -- I wasn't sure I was going to
get here.
Axial cracks alone in the CRDM nozzles do not impact plant
safety. We didn't fix that first slide. We should have.
DR. WALLIS: These are the cracks which might be spiral
cracks?
MR. MATTHEWS: They could be 45 degree cracks, but by
the time they got to where the thing could eject, there would be a lot of leakage,
I'm sure.
CHAIRMAN FORD: Now we didn't address this in the
presentation, this particular aspect, and I'm assuming from the staff's point of
view that's an okay statement. Yes?
The very first bullet there, we didn't address this during this
presentation from a technical point of view. I'm assuming that is an accurate
statement.
MR. STROSNIDER: Yes. Just briefly with regard to axial
cracks, I think if you go back and look at the work that was done in the mid-
Nineties and Generic Order 97-01, a large part of the basis for our accepting the
susceptibility model and the industry proposed inspections at that time was
because of the low safety significance of axial cracking.
The critical flaw sizes are very large, and --
DR. KRESS: That is based on the fact that it just leads to a
LOCA model rod ejection?
MR. STROSNIDER: The circumferential crack changes the
complexion of the problem considerably, because of the potential for LOCA.
We did acknowledge that potential back in some of the safety evaluations that
were written, in fact pointing out that if this sort of thing came up, the industry
needed to inform the NRC and it would have to be dealt with. So that's where
we're at now.
DR. WALLIS: Could we go back to definition. An axial crack
is something less than 45 degrees from the axis?
MR. MATTHEWS: That is what we have kind of used.
DR. WALLIS: And when it becomes 46 degrees, it becomes
a circumferential crack?
MR. MATTHEWS: Go ahead.
MR. STROSNIDER: This is Jack Strosnider again. Actually,
referring to some of the safety evaluations that were written back in the mid-
Nineties, there was actually an agreed upon definition, if you will, of anything
more than 45 degrees off axis would be considered circumferential.
DR. WALLIS: This is very strange. I mean, a crack which is,
say, 44.9 degrees is okay, but if it becomes 45.1, it suddenly becomes a terrible
thing because it's circumferential?
MR. MATTHEWS: An axial crack will lead to a leak. That's
where it can ultimately come to, is a leak, but it cannot lead to a major rupture
of the pipe. It just can't get that long.
DR. WALLIS: Well, I don't understand this, and there's
nothing magical about 45 degrees.
MR. MATTHEWS: Well, that was just a definition.
DR. WALLIS: It can be 42 or some other number.
MR. BAMFORD: I think we need to keep in mind, though, that
the cracks are predominantly either 100 percent axial or they follow the profile
of the weld because of the stresses.
DR. WALLIS: This is misleading, this talk about axial and
circumferential. It gives the impression that it's either this way or that way, 90
degrees.
MR. BAMFORD: No, but that's the experience. That is, in
fact, the experience. You don't have a family of cracks. It could be any
orientation. The cracks orient themselves perpendicular to the maximum
principal stress.
DR. WALLIS: But you don't know what that is.
MR. BAMFORD: In most of the -- That's right. The
evaluations that we've done have shown that the maximum principal stress is
hoop stress. All right?
Now what happens is at the very top of the weld, then you end
up with a situation where the hoop stresses decrease very quickly as you go
above the weld, and the axial stresses that are there from the weld itself stay
high right along, right at the top of the weld. That seems to be consistent with
what's happened with these two cracks that we have seen in Oconee, that they
follow that. They stay in the high stressed area.
DR. WALLIS: Here are your arguments about stress are
based on these residual stresses from the welding operation?
MR. BAMFORD: Correct. From the evaluation -- From the
multiple evaluations that we've done and where we have compared a number
of different calculations and found consistent results.
DR. WALLIS: I thought we discovered earlier that models
based on that didn't work out very well. So we don't really know too much.
MR. BAMFORD: I am talking about finite element stress
analyses, and they are pretty well understood and --
DR. WALLIS: -- go back to how the thing was welded, and
they figure out the residual stresses from the history of how it was welded. Is
that what happens in the finite element analysis?
MR. BAMFORD: That's correct. In fact, the actual welding
of the head penetration is modeled into some of the finite element results.
DR. WALLIS: This is -- technology. so we can believe the
answer?
MR. BAMFORD: Yes, and we've gotten multiple results that
were consistent. So we have a lot of confidence in the residual stress
calculations.
DR. WALLIS: To go back to the first issue, what is axial and
what is circumferential, it seems to me you have to use words which describe
the reality and aren't misleading. I got the impression that axial cracks were
one direction, and circumferential were 90 degrees.
There are real cracks which are at all kinds of angles.
MR. MATTHEWS: Well, most of the cracks that have been
observed have either been pretty much axial or have a significant
circumferential component, and the ones in --
DR. WALLIS: Nothing in between? Nothing in between?
MR. MATTHEWS: Not a lot. The ones at Oconee tended to
follow the weld profile with circumferential -- major circumferential cracks.
MR. STROSNIDER: This is Jack Strosnider. I guess I would
just make the comment: Maybe that wasn't the best definition in retrospect, but
the intent -- The intent was to identify the potential for a crack that could run
around such that the tube could be ejected. That was the concern, and that's
what that was driving at.
Now when you start looking at the axial geometry and the
orientation of these cracks because of hillside and one thing or another, it may
not have been the best definition. But the intent was to look for those sort of
cracks that might lead to a guillotine failure of that penetration.
DR. BONACA: I seem to have read somewhere in the
material, not from this presentation, that circumferential cracks were observed
where multiple axial cracks with some kind of, you know, radial initiation then
merged into one common circumferential crack, then moved across. There was
the result of multiple axial cracks.
MR. MATTHEWS: I think that has been a hypothesis as how
one of the circ cracks at Oconee may have grown, but I'm not --
MR. ROBINSON: Larry, this is Mike Robinson again. On
Oconee 3 one of the nozzles that did have the circ crack in it, we were able to
remove a sample of a circ crack and look at it in the lab. Part of the sample that
we did take, when we put it in the lab and examined it, we did identify several
axial cracks that actually intersected with the circ crack.
DR. BONACA: All right. That's what -- But it is not the only
way you are going to get circumferential cracks. You are telling me that there
are other ways in which they can develop.
MR. MATTHEWS: If you can get coolant corrodant into the
environment where you have the high axial stresses, it should grow
circumferentially also.
MR. MATTHEWS: I've already talked about this. We believe
there's reasonable assurance that PWRs do not have circumferential cracking
that would exceed the structural margin.
DR. WALLIS: What does reasonable assurance mean?
MR. MATTHEWS: I haven't got a number. We feel pretty
confident that the program we have to go out and see how bad the problem is
is the right program.
DR. WALLIS: But if someone else feels less confident, how
do you convince them?
MR. MATTHEWS: We go through a lot of detail about that it
will leak. There's plenty of margin at Oconee.
DR. WALLIS: And then you calculate some number which
gives you assurance?
MR. MATTHEWS: I don't have a number. I don't think we've
done that.
DR. BONACA: But the consequence of these conclusions is
that a large number of units will not perform the inspections between now and
next spring?
MR. MATTHEWS: Yes.
DR. BONACA: Is there any plan for when they are going to
be performing inspections or you just simply left to -- I mean, there is a lot of
stuff hanging on these assumptions and conclusions and confidence.
MR. MATTHEWS: Well, we have recommended that all the
plans less than ten years do a visual at their next refueling outage and, like we
showed on the curve, that is going to pick up all but two plants by next spring
will have done a thorough visual of the top of their head, less than ten years.
DR. BONACA: Yes, about 25 plants.
MR. MATTHEWS: Yes.
CHAIRMAN FORD: So should that sentence be revised, and
the question is the time: Reasonable assurance would exceed structural
margin before spring '02 or within the next ten years?
MR. MATTHEWS: It's before spring '02. We are not trying
to nail down anything very far out in the future. We are trying to set a program
that's going to get us some information on what the status is.
DR. BONACA: Not before '02. I mean, this family of plants
is going to be only about 25, not all of them.
MR. MATTHEWS: Yes, it's not all the plants. It is the ones
that are less than half the life of -- more than half the life of Oconee on the time
at temperature.
DR. WALLIS: If you were to make a bet on this, the
reasonable assurance, what sort of odds would you give?
MR. MATTHEWS: I don't have a lot of money.
DR. WALLIS: It's just a probabilistic question, just a question
of probability.
DR. BONACA: You know, I get enough confidence in your
presentation to feel reasonably comfortable with the 25 plants. I'm not sure if
I'm comfortable on the others.
MR. MATTHEWS: I think the industry was comfortable with
the 25 plants as being the lead unit and taking a look at those plants. You
know, what we find in the first plant that deviates from what we expect, the
whole thing is going to be reevaluated.
DR. BONACA: That makes sense.
MR. ROSEN: What I'm surprised about is that you haven't
made any points about plants operating -- that most plants operate for most of
the time with all rods out.
MR. MATTHEWS: And that is a very good point. The rod
ejection accident or the rupture and ejection of one of these housings for 99.9
percent of the time is not the classic rod ejection accident that occurs in the
analysis of reactivity insertion event -- it's just a LOCA, because the rods are
operating all the way. It's just a very small LOCA.
The only time it ever would be a problem from a reactivity
standpoint is in that very narrow window of start-up or shutdown where the rods
have gotten a pattern that resulted in a high rod work that could possibly
approach the rod works that were assumed in the rod ejection accident for the
FSARs.
DR. BONACA: That's correct.
MR. MATTHEWS: And then on top of that, it would have to
be that housing that had the crack, and it would have to eject at that point in
time for it to be any kind of reactivity problem. Otherwise, it's just a small LOCA.
CHAIRMAN FORD: I have an associated question from a
colleague who wasn't here, Dr. Dana Powers. Let me read it to you, and I ask
you guys to help me in the interpretation of the question.
"What do we have on the risk analyses for small break LOCA
with failure to SCRAM?" Then subsequently: "Have these analyses treated
neutronic effects and the possible effects of high burnup fuel?"
MR. MATTHEWS: We are doing our risk assessment now.
I'm not sure I got the answers to the failure to scrim. It's not clear to me why
you would get a failure to SCRAM. It would take an awful lot of concurrent
damage from that ejection to result in the rods not going in.
Probably, the most likely thing is you are going to destroy the
cables, which is going to be one of the fastest ways to get the rods in, in the first
place.
The only way you prevent one from going in is to severely
deform an adjacent housing, and a foot away from a 2 1/2 inch opening -- I don't
have the numbers yet, but to deform one over far enough that the rod -- or the
drive rod -- is going to bind and prevent the rod from going in seems fairly
unlikely to me. But we haven't finished the numbers yet.
What was the second part of that?
CHAIRMAN FORD: Have these analyses treated the
neutronic effects and the possible effect of high burnup fuel?
MR. MATTHEWS: Oh, well, we haven't done them yet. So --
CHAIRMAN FORD: So the answer is no?
MR. MATTHEWS: No.
MR. ROSEN: You said 2 1/2 inch opening.
MR. MATTHEWS: Or I guess it's 2 5/8, the idea of the nozzle.
It is a four-inch nozzle, but it's a 5/8 inch long. Two and three-quarters, is that
what it is? There's a two and three-quarter inch hole left.
When the top piece goes away, the bottom piece would still
be there. If the ejection resulted from a circumferential flaw above the weld, you
still got the part that's connected to the weld intact. So you only have a 2 3/4
inch hole in the vessel, and it's got a rod stuck through it.
DR. BONACA: Yes, it's fully open. You got the rod -- Yes.
MR. MATTHEWS: So it's a fairly small LOCA, and the only
way you could get failure to SCRAM is severely deform a significant number of
other CRDM housings, which are -- 5/8 inch on a four-inch nozzle is a pretty
hefty wall on it.
MR. ROSEN: So the most likely thing to happen, if you had
an ejection, would be you would have a 2 3/4 inch hole open in the top of the
vessel, and there would be no reactivity effect at all -- I mean from the ejection.
MR. MATTHEWS: Well, the SCRAM would be minus the one
rod that is surely jammed at the top at that point.
MR. ROSEN: Well, sure.
MR. MATTHEWS: But they always assume a stuck rod.
MR. ROSEN: But there will be no insertion of reactivity.
DR. BONACA: Well, if you drop the rods and you SCRAM,
you have effectively equivalent of a rod ejection. I mean, you have one rod
failing to SCRAM -- to insert.
MR. MATTHEWS: Typically, SCRAM -- one rod doesn't go
in.
DR. BONACA: -- go down to zero, you know, a lower power
level or zero power level where, you know, the rod is worth a lot. So I don't
think you can make an analysis of the fly.
MR. MATTHEWS: No. But I think SCRAMs typically assume
the -- I mean the analyses assume at least one rod doesn't go in.
CHAIRMAN FORD: Okay, the schedule?
(Slide change)
MR. MATTHEWS: We have some activities ongoing, and I
didn't get a chance or somehow I missed talking about a couple of these.
We were reasonably going to get some final inspection
recommendations out by the end of June for the plants that are coming down
this fall. We kind of delayed that when we heard about there might be a bulletin.
We wanted to see where that goes, but we will get recommendations out to the
plants on what they ought to be doing in the fall.
We have convened or are convening an expert panel on crack
growth. The intent -- That's an international expert panel with people from
several countries around and experts from the U.S. to look at crack growth,
crack growth rate, crack growth database, what data do we know and where are
the holes, and are the holes worth doing the experiments to fill in.
CHAIRMAN FORD: Is this an EPRI sponsored panel?
MR. MATTHEWS: Yes.
CHAIRMAN FORD: Similar to one that was convened for
boiling water reactors?
MR. MATTHEWS: I think it is similar to that.
DR. BONACA: Is there any plan to do some testing? I mean,
here we have the long discussion that left us with the question of --
MR. MATTHEWS: Well, one of the things out of the expert
panel is where do we need more data, and at that point we would fold that into
an industry program to go get that data, if it's useful data to go get, if it is going
to help.
CHAIRMAN FORD: Now this is different from the NRC expert
panel, as I understand it?
MR. MATTHEWS: Yes.
CHAIRMAN FORD: Okay.
MR. MATTHEWS: We have all the inspections that are
planned for those units in the fall outages.
The final RPV penetration safety assessment, taking
everything we know into account at that point in time, we would plan to get by
the end of the year. It would take in account the fall inspections.
Then we would be reassessing and getting new
recommendations out before the spring, based on whatever we see in the fall.
I have already covered the other ongoing activities up front.
CHAIRMAN FORD: Is there a timetable for the other
activities?
(Slide change)
MR. MATTHEWS: The risk assessments we've started, and
we are going to get to them as soon as we can. I'm not sure -- do we have a
deadline on that?
Probabilistic fracture mechanics would be in there also. The
NDE demonstration: We are working to have some demonstrations of any
volumetric techniques that are going to be used this fall. We are working to
have those available and demonstrated before the fall.
Information and training packages would be available for the
plants to use to get ready for the fall visual inspections.
Flaw evaluation guidelines are a longer term thing. It is to
help us figure out how to long term manage this thing, but we are working on
that right now also in case somebody does find something in the fall. You know,
is there something that could be acceptable?
Review of repair and mitigation strategies is more of a long
term thing. How do we wrap it up long term?
DR. KRESS: I'd like to return back to Dana's question for just
a moment, the question of the potential that you won't SCRAM. Let's presume
you break one of the control rod drive tube rods over near the periphery, and
you suddenly have high pressure water and steam injected at sonic velocity and
flashing as it comes out of that into this region where you have a cover over it
and perhaps leak past, but the potential for building up pressure on one side,
putting a torque on this head, perhaps creating a bending stress that might
bend the other tubes to the extent that maybe one or two nearby won't be able
to insert the rods again.
I think that's what Dana had in mind. The question is has that
been looked at an analyzed from the standpoint of what the stresses actually
are and whether there would be a bend?
MR. MATTHEWS: Those are -- Excuse me. I didn't mean to
interrupt. The consequential damages are part of what we will have to factor into
the risk assessment when we are pulling this whole thing together.
These are very hefty tubes, like I said, and you don't have to
go very far away from a small ejection until the pressure drops off very rapidly.
When it is hitting a round surface, you know, you've got an even lower force --
DR. WALLIS: Drops off because you have already blown out
the shroud or something?
MR. MATTHEWS: No, I'm just talking about if you break a
pipe. You don't have to go very far away from that --
DR. WALLIS: No, but it goes into a volume.
DR. KRESS: Yes, and it's pressurizing the volume.
MR. MATTHEWS: Well, if it pressurizes the volume, then you
don't have the differential across it to bend it.
MR. SIEBER: I think the volume you are talking about is the
volume of the shield cover, which is pretty flimsy. You can't pressurize that.
MR. MATTHEWS: I depends. It may be an inch thick. I'm
not sure. It depends -- Plants vary on how thick that thing is, and it's not air-
tight. I'm not even sure what is on top of it. It may actually just blow right up
through there. I'm not sure. It's not --
DR. KRESS: I think that is the problem Dana had in mind
there.
MR. MATTHEWS: You have large openings in there for
ventilation. Those CRDMs have to be kept cool. So those openings and fans
and air ducts -- the main reason you have the shroud is for an air duct.
MR. ROSEN: You may find that when you do the analysis
that the pressure differential -- If you do a transient and pressure differential
analysis -- never, never reaches very high pressure in that area.
MR. MATTHEWS: Across the --
MR. ROSEN: It vents in a lot of different directions.
MR. MATTHEWS: Yes.
DR. KRESS: I think that's the likely result, yes. So you
wouldn't have a bending torque on it.
MR. ROSEN: Exactly. As he said, it is intended to be a lot
of ventilation in that area because of the heat. It's naturally going to be venting.
MR. MATTHEWS: The insulation packages that it is venting
into -- you know, those are just -- they are light weight mirror insulation or they
are blankets or stuff like that. It's not a sealed-up area.
DR. WALLIS: -- constant for thermal distortion by heating up
one side to 600 degrees when the other side is cold is fairly long. So you think
that distortion won't happen until you have SCRAMed and everything is fine?
DR. BONACA: Still, I mean, one thing that is important to
note is that the ejection accident by the expectation of the FSAR is not a 10-3
event. It's supposed to be a much more unlikely event than that, and that the
most severe case is the zero power case where you essentially eject the rod,
and you create that by having an effective SCRAM.
I mean, you have one rod out, and the rest comes in. Shut
down the reactor, and you have the highest worth out, just because -- and you
are blocking core. So I mean, it's not an issue that can be downplayed. I think
it has to be evaluated, because it has significance.
CHAIRMAN FORD: I would like to open up the meeting to the
subcommittee for any last minute questions. What I plan on doing is stopping
at around about 11:30 for lunch until 12:15. We'll cut 15 minutes off lunch, and
then we will go straight into the NRR presentation.
So any last minute -- Graham?
MR. LEITCH: I would like to hear a little more about the
nondestructive examination that is being contemplated. I guess I see, first of
all, what's been done so far is a visual examination on top of the head. I notice
from the pictures there were some dye penetrant examination beneath the
head.
What is contemplated? Is this an ultrasonic demonstration?
What are we talking about? PT? UT?
MR. MATTHEWS: From an under-the-head standpoint, you
really want to do as much of this robotically as you can, because it's a very high
dose -- very high dose environment.
In the early Nineties technology was developed for examining
the ID surface of the penetrations, and that technology was an eddy current
probe that examined the ID surface looking for ID connected flaws. If anything
was found, UT technology was available to go in and size those flaws.
It was all geared toward ID connected flaws, because that's
the dominant thing we had seen at that point in time. There were -- In the
mock-ups and the demonstrations that were done in the early Nineties or mid-
Nineties, there were circ flaws on the ID of the nozzle. Looking for those also,
but we didn't have any OD initiated flaws in the mock-up.
So, basically, we don't have any qualified techniques for
looking for this kind of situation. We are working to get mock-ups built. We are
working to develop the techniques.
Primarily, the only way we can query that volume right now
is a UT examination for the tube. Some vendors are saying they are developing
eddy currents for looking at the OD of the tube below the weld for the OD -- or
looking at the weld material itself for connected flaws there. They haven't been
demonstrated. We are working to try and get those things set up and see if
those technologies are available.
The plants that are going to be doing any kind of volumetric
exams -- it would be -- Westinghouse plants have an interfering -- and I'm not
sure about the CE. They have an interfering thermal sleeve. So they only have
a gap, a small gap between the ID of the penetration and the OD of this thermal
sleeve. So anything delivered to the ID of the penetration has to be on a kind
of a saber, and it's a saber that is rastered back and forth around the thing,
looking for eddy current, the primary technology.
Now we are talking about putting UT probes on there and
trying to detect flaws anywhere in the tube, ID or OD. It takes longer, and it
takes a different set of transducer packages.
It depends on whether you are looking axially or
circumferentially, and that stuff is being worked on by the inspection committee
and by the EPRI and DE center to try and build these mock-ups and work with
the vendors, who are themselves working on the techniques.
MR. LEITCH: But an inspection of the weld per se, you're
talking mainly about the tube. The weld itself -- it's a very complex geometry.
MR. MATTHEWS: Yes, it is, and the weld is going to be very
difficult to examine volumetrically.
MR. LEITCH: So the 25 plants that are going to do
inspections -- I guess I'm not real clear what that means.
MR. SIEBER: They are visual.
MR. MATTHEWS: Those were intended to be visual, and I'm
not sure the NRC is going to agree with that. But, you know, that's our intent.
MR. LEITCH: And then if the visual shows something, then --
MR. MATTHEWS: Yes. Anytime you find something on top
of the head, you know, all bets are off. You got to go figure out what it is, and
you got to figure out how bad it is and what the extent is, and if it is coming
through-wall, you got to repair it.
MR. LEITCH: So these NDE techniques that are still under
development are not intended to be operational by the fall outages?
MR. MATTHEWS: Some plants will probably do a best effort,
which means they will put some probes in there and see what they see. But,
you know, it's not a PDI type qualification. We don't have the time. We don't
have the blocks, and we don't have the capability to do that type of qualification
at this point in time. Eventually, we'll get there.
You know, the ID connected flaws -- we got there. We had
very good qualification programs for all of the vendors who were doing those
types of inspections. We are not there yet on the OD flaws.
MR. LEITCH; Now the photographs there at Oconee show
that you had done some PT there, evidently.
MR. MATTHEWS: They did PT. What they did at Oconee on
the first one they did, they found the boron. They did the eddy current, and
there was nothing on the ID of the tube. Are you sure it's leaking? Then they
went back, and they did more exams, and they couldn't find anything, and they
finally did PTs.
The only thing they saw on the initial PT was a couple of little
spots. We'll clean that up and, as they ground it into an axial flaw that was in
the weld and the OD of the tube. The PTs that were done on Oconee 3 were
on the leakers. Once they knew it was leaking, they went in, and they did PT
on those leakers.
Did you do any PTs on any other nozzles? Those were the
only ones they did PT on. PT -- you got a person standing there.
MR. LEITCH: Yes, it's very high in radiation.
CHAIRMAN FORD: Any other questions?
MR. ROSEN: The PTs were under-head PTs. Right?
MR. MATTHEWS: Under the head, yes.
DR. BONACA: At Oconee, did they detect all the nine leaking
nozzles by visual inspections in the first pass?
MR. MATTHEWS: Yes. I believe it was first pass. They
looked. They saw them.
MR. ROBINSON: Mike Robinson again. We initially identified
six leaking nozzles with the head on the vessel. We took the head off the
vessel, did the clean-up, and at that point we saw three other nozzles that
looked suspicious. We called those as potential leakers, and did our normal
pre-repair NDE on those and, once we saw some indication there, we said we
had the nine leakers.
DR. BONACA: The reason that I am asking is that I am still
a little bit concerned about detectability. You know, they pointed out that it is
difficult to distinguish those boron crystals on top of the head from leakage from
the flange, from actual leakage around the nozzles.
The reason why I am raising it is that plants will go through a
visual inspection first, and is it so sure that just visual will identify these cracks?
MR. MATTHEWS: We feel that visual will find it.
DR. BONACA: Well, in this case, for example, they only
identified six. Now if those six were not leaking, the other three would not have
been seen.
MR. MATTHEWS: No. Six were identified before they even
took the head off the vessel. The other three were identified once they did a
more thorough exam with the head on the stand.
DR. WALLIS: It's not clear that these leaks have come out --
you see something coming out the top or they are actually the worst thing. You
could have a very fine leak of steam with a crack actually growing
circumferentially inside, which wouldn't -- you know, you have a very small leak,
because you've got a very tight tube up there. It doesn't really tell you what is
happening inside where the crack could be growing circumferentially.
MR. MATTHEWS: Right. Well, the only three circumferential
flaws that have been found were also associated --
DR. WALLIS: But you are lucky that you have a big enough
leak before you get the circumferential crack growing that you can see it. It's
a race between these different things that are going on at the same time.
MR. MATTHEWS: We haven't seen any evidence of any kind
that would have a crack --
DR. WALLIS: But the leak is not a symptom of the degree to
which the circumferential crack has grown.
MR. MATTHEWS: Oh, that's true.
DR. WALLIS: It's a symptom of the degree to which an axial
crack has grown, presumably, and also the ability of this pressure -- this what
do you call it, fit, this tight fit, to let something come out.
MR. MATTHEWS: To let it out, yes. We as an industry don't
want to manage this issue by looking for leaks. That's not the right way to
manage it. We want to develop the tools and a program for the industry that is
going to be more proactive than trying to find a leak and fix it.
Just for the near term, the technology is where it is, and that
is what we have, and that is where we were trying to go for this -- Fall outage
is what we are saying.
CHAIRMAN FORD: Unless there are any other major
questions right now, I would like to adjourn the --
DR. WALLIS: A procedural thing: Are we going to give some
advice about what to say before the main committee this afternoon? I think he
needs some advice about what to tell us tomorrow, because we can't possibly
go through all this tomorrow.
MR. MATTHEWS: Oh, no.
DR. WALLIS: Are we going to do that this afternoon?
CHAIRMAN FORD: Let's hear the NRR, and then we'll give
advice.
DR. BONACA: Also we should ask the NRC if maybe the staff
wants to just give a presentation without any --
CHAIRMAN FORD: Hold on, guys. We are adjourning now
until -- Recess until 12:20.
(Whereupon, the foregoing matter went off the record at 11:36
a.m.)
A-F-T-E-R-N-O-O-N S-E-S-S-I-O-N
(12:23 p.m.)
CHAIRMAN FORD: I would like restart this subcommittee
meeting. Jack, would you like to introduce your team?
MR. STROSNIDER: Yes. I have a few opening comments,
and then I will introduce the staff.
My name is Jack Strosnider. I am Director of the Division of
Engineering. First of all, I wanted to start off by thanking the Committee for
setting up this session and hearing this issue today. I know you have a very
busy schedule. However, we do think it is very important that the Committee
understand this issue and understand about the staff's approaches to dealing
with it.
We see this as a major issue in terms of addressing our
principal performance goal of maintaining safety, and that is why we are going
forward with the Bulletin. So, again, I think it is important for the Committee to
understand what we are doing there.
I also want to say thanks to Larry Matthews and the industry
for their presentation. I think, if nothing else, I want to say we appreciate that
they went first today.
Seriously, I think they did give a good summary of what the
issue is, and also what we know and what we don't know. That is part of the
reason, when we talk about what we don't know, why we are looking at a
bulletin.
The bulletin we are talking about is a request for information,
and that request for information is intended to help us verify compliance with
existing regulations, and also to determine what additional future regulatory
actions might be appropriate.
With regard to some of the questions -- and I think the
Committee did a very good job this morning focusing in on some of the major
issues which have also been of concern to the staff. I am going to tell you right
up front that the staff doesn't have the answers either.
So when you go forward with your discussion this afternoon,
recognize that we don't have all the answers. Again, that is the reason we are
going out with this request for information.
Now requests for information can sound -- That might sound
somewhat benign, but in fact, I think when you see some of the discussion we
had with regard to issues like how do you qualify your visual examinations and
things like that, that there are some challenges in there for the industry, most
definitely, in order to be able to answer some of the questions and address the
technical issues and the regulatory aspects.
As far as expectations or requests from the Committee, we
are on a schedule for issuing this bulletin August 1. That's our milestone. We
will go up to the Commission something on the order of ten days or so before
that through an information Commission paper.
We would like to see a letter from the ACRS that would
support that schedule and provide your perspective on the staff's approach
technically and process in terms of how we are addressing the issue.
With that little introduction, I would just point out that then we
have at the table -- We have Al Hiser and Mark Reinhart, Tad Marsh and Ed
Hackett in the Office of Research.
Al is going to walk through basically what the bulletin request
looks like, some of the information we are looking for, and some of our thought
process, what's behind that.
Mark is going to talk about the risk perspectives that we have
been able to develop to date. Ed Hackett is going to summarize for you an
effort that the Office of Research undertook with regard to this issue. They have
contracted four experts who are sitting at the table across from us here to take
a look at this issue from a technical point of view, and he is going to summarize
their efforts and going to point out that we got a lot of really good support there.
His people did some hard work in a short time. We appreciate that effort.
Tad Marsh is going to talk about the process, what the generic
communication process is and, I think, a little bit about the schedule, some of
which I just mentioned.
So with that, I will turn it over to Al Hiser.
MR. HISER: Thank you. Hi. I am Alan Hiser with Materials
and Chemical Engineering Branch of NRR. What I want to do is discuss the
NRC staff activities in this area and, in particular, the draft bulletin that the staff
is proposing at this point.
(Slide change)
MR. HISER: The slides that are in the package that have
been handed out include a lot of background, and what I'll do is skip over that
and jump right to slide 5. But in addition, I want to talk about the staff
approach, applicable regulations, the staff assessment that has been performed
to date, and then go into details on the proposed information request in the
bulletin.
In terms of safety perspective, again on slide 5, failure of a
CRDM nozzle does constitute a LOCA and control rod ejection, which are
analyzed events. Some of this, Mark Reinhart will go over a little bit later, some
of the more detailed things. I just wanted to sort of take a big picture
perspective on things.
From existing PRAs, one would indicate that a level of risk
exists here that requires increased attention. I think that is what we are putting
on this.
Now to go back a little bit to Larry's presentation, the worst
case crack that was found at Oconee with a high susceptibility plant did have
a remaining ligament margin of about 6 to failure. There is about 180 degrees
remaining in the crack. Failure would be predicted to occur with about a 30
degree ligament remaining.
DR. WALLIS: Do you know that by some kind of visual
examination?
MR. HISER: Do I know which part of it?
DR. WALLIS: How do you know that you've got this much
left?
MR. HISER: The structural integrity calculations.
DR. WALLIS: Did you cut the thing apart to find out or how
did you know that you had this big a ligament left?
MR. HISER: That's what the licensee indicated from their
examination.
DR. WALLIS: Did they use a surface visual examination,
superficial?
MR. HISER: I believe they did ultrasonic -- I'll let Mike
Robinson address that.
MR. ROBINSON: The 165 degree arc is the arc link that was
repaired once we found --
DR. WALLIS: You actually took it apart and looked at it?
MR. ROBINSON: We looked at part of it, but in the course of
repairing the indication, we ground out an area that was in the 165 degree --
DR. WALLIS: so it's a pretty good measure of what
happened?
MR. ROBINSON: Yes,sir.
DR. WALLIS: Thank you.
MR. HISER: Based on this experience, we have no reason
to conclude that cracking won't affect additional units. We have no reason to
believe that in Oconee units, in particular, with the circumferential cracking are
unique in any way fabrication-wise, construction-wise or operation-wise that
would indicate that they are the only units that would be affected.
We do think that timely, effective inspections would provide
additional information on the extent of the problem, and would provide us with
confidence that safety is maintained and that regulatory requirements are
satisfied.
(Slide change)
MR. HISER: Now looking at the overall staff approach to this,
we held a public meeting with the industry on April 12 of this year. We
requested, and the industry submitted, a report in May. Larry went over, I think,
in pretty good detail the contents of that report.
The staff did submit questions to the MRP initially in a FAX
form and then formally near the end of June, and we held a public meeting with
the industry in early June where they presented initial responses to our
questions.
From the information that we have seen, the staff has
concluded that we should propose a generic communication. The purposes of
this communication are to assess compliance with regulations and to provide
staff with information on licensee actions that they propose to address the issue.
In particular, we are looking to determine the prevalence and
severity of PWSCC in vessel head penetration nozzles. The one caution I
would lay out is that the staff is in, say, the first step of a multi-phase effort
where at this point we are in an information gathering phase and, based on the
information, we will determine the need for additional regulatory actions and
what the nature of those actions should be.
DR. WALLIS: On page 5 you talk about timely effective
inspections. Are you going to tell us what kind of inspections those are?
MR. HISER: I will provide some details on what we think they
should be.
DR. WALLIS: Are you going to tell us that looking for boron
crystals on the outside is a true indication of what is happening inside?
MR. HISER: In some circumstances, we think that can be the
case.
DR. WALLIS: Okay. That's a pretty equivocal answer.
MR. HISER: Very equivocal situation.
(Slide change)
MR. HISER: What I would like to do is go ahead and skip
slide 7, which would just be restating what Larry described this morning, and
then just go into a little bit of detail of the staff concerns with the MRP report.
The first thought that the staff had on the report is that the
susceptibility model has large uncertainties to it. We know it doesn't
encompass all of the factors that are important. It only looks at operating time
and the time that the plant was operating -- operating time and operating
temperature.
We do believe that the susceptibility model provides a useful
plant ranking relative to Oconee Unit 3 from which the staff has some ideas on
how to address the overall problem, and we do acknowledge. I think the
industry addressed a little bit this morning, that this is not a predictive model.
Plants predicted to be within X EFPY of Oconee Unit 3 will not
necessarily develop cracking at that time. It may be subsequent to that. It may
be prior to that. It's not a predictive model. It is just a relative ranking of where
the plants lie.
DR. WALLIS: Now this morning we talked about uncertainty,
and we didn't get some quantitative evaluation. Did you do a quantitative
evaluation of these uncertainties?
MR. HISER: No, we haven't.
DR. WALLIS: It would seem important to do that, because
you've got this nice curve. But if there is a great deal of uncertainty, then it
doesn't tell you as much as you would like it to tell you.
MR. HISER: I think, as we go into the staff presentation, you
will see that we are not focused on the susceptibility model. What we are doing
is allowing it to give us some information on which plants may be more
susceptible and to help us in our information gathering process.
DR. KRESS: Now one view could be taken, that Oconee
might have equivalent stresses or even stress distributions across the rods,
tubes around it, encompass the full range of stresses, that it has the same
chemistry and that the material construction of these tubes are about the same,
and that the weld materials are the same.
So that in terms of uncertainty, these things are captured in
the Oconee case, and the only variable that is really different from it and the
other plants is the time and temperature.
In that case, seems to me like it would be a predictive model,
because you know when Oconee went, and in ranking things relative to it on a
time-temperature basis, you have captured perhaps the uncertainty, and it
would be predictive in terms of when to expect these other plants to have the
same problem Oconee had.
What is wrong with that view?
MR. HISER: Oh, I think that's a reasonable view, but given
the uncertainty that exists in the model, if we say a particular plant is one EFPY
away from Oconee, I wouldn't want to go back in a year and then expect to find
cracking.
There may be incipient cracking at the present time. It may
be that there are some local fabrication methods or something like that that
would maybe push them out further in time.
I think the uncertainty really lies in --
DR. KRESS: What I had in mind there was not all the Oconee
tubes cracked, just some of them. It was those that had the extreme ends of
the uncertainty. Now you talk about another plant. You wouldn't expect maybe
it to not crack within one or two years or whatever the prediction is, because it's
not going to have the extreme ends. But what you can say, it's not going to
crack before this time. That's the important part.
DR. WALLIS: I am not sure about that. How many cracked
at Oconee?
MR. HISER: There were nine nozzles cracked, two --
DR. WALLIS: Okay, nine out of so many. Suppose it's a
statistical thing with some probability. If it were one out of, now that tells you
something. It's nine out of. So the chance of not getting one out of in some
other one is not the same as the chance of not getting nine out of.
I would think someone would do some statistical analysis
about that.
MR. STROSNIDER: This is Jack Strosnider. I would like to
comment on this question, if I could.
I think if you try to look at this in terms of all the random
variables that are involved in susceptibility or when cracking is going to occur,
you've got a long list. You've got the time. You've got the temperature. You've
got the microstructure. You've got some fabrication history. We don't know
about -- that you don't know about in terms of how things might have been bent
or what cleaning solvents might have been used, etcetera.
So you could come up with a long list of random variables that
would have to go into the evaluation. Now I think the question that Dr. Kress
was asking is could you assume that Oconee represents the spectrum, a
spectrum of those.
I don't think we can necessarily make that assumption.
Number one, we don't have the information to confirm it. But number two, when
we look -- I think if you look back at the 97-01 experience where some
microstructural data was available, there's a certain number of heats that were
used at Oconee, but you don't know that you've got the worst heat. It certainly
doesn't represent every heat material that's out there.
Just as an example, come back to the earlier question with
regard to doing an analysis to understand the variability in terms of the
uncertainty of this model. That's something we would all like to do, but in order
to do that, you have to exactly the sort of data that I'm talking about, which --
DR. WALLIS: But when you've got a complex model like --
situation like this, you can make some sort of simplified statistical model.
MR. STROSNIDER: Right. But I think at this --
DR. WALLIS You can make some postulates. Then, it seems
to me, you can get sort of the probability of one, two and three, based on that
model, and you've got nine happening here. So that you cannot just -- Then
your curve that we show would tell you something about the probability of nine
occurring at these other plants.
We really want to know an estimate of the probability of one
occurring in a plant. Seems to me, you could do that based on some gross
guess of the kind of statistical --
DR. KRESS: Well, you have to make some guess about how
representative --
DR. WALLIS: -- a distribution or one of those magical things.
DR. KRESS: It's like he said. You have to make some --
DR. WALLIS: But do it. Show us an analysis that predicts
something and not just words.
MR. STROSNIDER: I would suggest you have to be very
careful, because when you start trying to predict probabilities of things occurring
like that, you are going to have to define the populations, the statistical
populations; and I come back again to you need the data that we were talking
about that we don't have in order to define those populations.
DR. WALLIS: But you have to do something.
MR. STROSNIDER; We have looked at things from a
statistical point of view in terms of sampling, and I think we can talk about that
when we get to it.
DR. WALLIS: So someone has done that?
MR. STROSNIDER: Yes, but it's not the level of detail that
you are looking for, because as I said in my introductory remarks, we don't have
the information to do that analysis.
Yes, you can make some assumptions, but how many
assumptions are you willing to make? So at this point --
DR. WALLIS: Well, make the simplest assumptions to get
started, and see what you come up with. And then explain it.
MR. STROSNIDER: Agreed. But at this point the assumption
we are making is that there's uncertainty in the susceptibility ranking.
DR. WALLIS: Well, that's not an assumption. That's a given.
MR. HISER: One of the industry recommendations in the
report was that plants within 10 EFPY of Oconee Unit 3 should take some extra
precautions, I guess, in doing their examinations. They should make sure they
were extremely careful.
From the staff review of Generic Letter 97-01 modeling that
was performed, Arkansas Nuclear-1, Unit 1, was at that point predicted to be
more than 15 years away from -- based on susceptibility.
Four years later --
DR. WALLIS: Away from what?
MR. HISER: I'm sorry?
DR. WALLIS: Away from what?
MR. HISER: Away from being susceptible to PWSCC.
DR. WALLIS: Well, they are all susceptible. You mean
having cracks that go through?
MR. HISER: Actually, the model at that point was in
comparison to DC Cook. So it was again in a relative ranking sense, Arkansas
Unit 1 was 15 years away from having a susceptibility --
DR. WALLIS: The same kind as Oconee?
MR. HISER: Same conditions. Well, actually, the same as
DC Cook Unit 3 at that point.
MR. HAMILTON: If I could comment -- John Hamilton from
Energy Nuclear.
The statement is correct that Arkansas Nuclear 1 was ranked
relative to DC Cook, to the benchmark of DC Cook under 97-01. When the
current MRP rankings were based on just time and temperature and excluding
the material factors gives -- moves ANO-1 into a position comparable to
Oconee.
MR. HISER: Yes, the point we want to make is that modeling
retrospectively is able to explain things, but in trying to use a model in a
predictive manner in any sense, the 10 EFPY threshold would not be supported
based on that experience. It may be in five years we come back and say, well,
the model did an excellent job.
I guess the only point is we don't think 10 EFPY is the proper
threshold to cut off additional attention.
DR. WALLIS: You have a very good initial model which
enables you to interpret new data as it comes in. It may be that after a year you
will get more or less confidence in that model.
MR. HISER: Right. Absolutely.
Now the staff also had questions regarding the adequacy of
visual examinations for detection of boron. As Larry pointed out, the
observations at Oconee were that there were very small quantities of deposits.
Less than one cubic inch is what has been quoted.
The staff concerns related to, first of all, the variability in the
interference fits from plants to plant. I think we found that the drawing --
DR. WALLIS: Can I go back to that. Did they do tests of the
ones that did not show boric acid deposits to show that, if there were big cracks,
there would be necessarily boric acid deposits? I mean, did they do tests to
show that the ones that did not have deposits were not cracked?
MR. HISER: No.
DR. WALLIS: Well, I would think you have to do that.
MR. HISER: At Oconee --
DR. WALLIS: Your whole hypothesis is that, if there's a crack,
there's a leak, and there's a boric acid deposit, if it's a big enough crack.
MR. HISER: At Oconee they found nine leakers, Oconee Unit
3. They did ultrasonic examinations of those nine plus an additional nine, and
found no additional cracks.
DR. WALLIS: No additional cracks in the other nine?
MR. HISER: Correct, in the other nine. That's out of 69 total
in the head. So they did volumetric examination of 18 --
DR. WALLIS: So it's a sample, and then you would have to
look at some kind of statistical model to tell whether that was a good enough
sample and all that sort of stuff.
MR. HISER: Right. Absolutely.
DR. WALLIS: But your hypothesis says that you can use the
presence of boric acid crystals as a true indication of the kind of cracks you are
worried about.
MR. HISER: That is the industry's --
DR. WALLIS: Somebody's hypothesis.
MR. HISER: Right, that's industry's assumption, and that's
what the ASME code assumes at the present time.
MR. ROBINSON: Alan, just to add also that on Oconee-1 we
looked at an additional eight nozzles for extent of condition, and of those eight
that we looked at, we found similar conditions like we found on Unit 3, again just
some minor craze cracking in nozzles that were not leaking.
So we looked at a sample on both Unit 1 and Unit 3. The
extent of condition inspection showed only the minor craze type cracking.
DR. WALLIS: You would think there would have to be some
which are on the point of leaking and have pretty big cracks. But you didn't find
anything like that?
MR. ROBINSON: No, sir.
DR. WALLIS: There must be some in the intermediate stage,
presumably. They have to go through that stage, don't they?
MR. ROBINSON: They have to go through the stage, but of
the ones that we inspected, we didn't find any like that.
DR. WALLIS: So it's a big of a conundrum. You've got the
ones that cracked and leaked and the ones that didn't crack much at all.
There's nothing in between.
MR. ROBINSON: And that's the mystery of this thing. If you
look at the two samples of the nozzles that are leaking and the ones that we
have examined and are not leaking, they are like two entirely different
populations.
You've got the severe cracking in the ones that do leak. You
have minor craze cracking in the ones that aren't leaking.
DR. WALLIS: That's disconcerting, because it means there
may be some cause which we don't know about which is causing some to crack
much more than others.
MR. HISER: Can we clarify one thing? The leaking nozzles --
there were cracks found in all leaking nozzles.
MR. ROBINSON: This is true.
MR. HISER: Okay. In one nozzle at Oconee Unit 1, there
was a part through-wall, OD initiated circumferential flaw. It's about 20 percent
through-wall.
MR. ROBINSON: On Oconee-1 it was a crack that initiated
in the weld that moved into the nozzle base material and traveled up to the
annular area, and that crack was radial and totally axial. There was no -- I'm
sorry, there was a small circ piece to the one. But Unit 2 we did find a small circ
crack on Unit 2.
MR. HISER: Okay, Unit 2. So you could call that the
intermediate step. Unit 2 did have a part through-wall circumferential crack.
Now back to the --
DR. KRESS: So are you saying 15 years would have been
a better choice? Fifteen effective full power years?
MR. HISER: I think something more than ten. Again given
the differences in the models, ten does not seem to be sufficient was our
conclusion. In a few slides, the staff looks at the susceptibility rankings, and we
have some conclusions on appropriate subpopulations to look at from the
plants.
CHAIRMAN FORD: Just to -- As you go through this, these
are the staff concerns arising out of industry MRP whatever the number was,
44.2.
MR. HISER: Right.
CHAIRMAN FORD: And the resolution of those concerns
have to be resolved before the fall outages or before the fall/spring or two
outages?
MR. STROSNIDER: This is Jack Strosnider. Let me see if
I can respond to that.
If you look -- When we get into the information we are
requesting in the generic letter, we talk about if a plant does not intend to
perform inspections before a certain date, they need to provide a justification.
The justification would have to address these sort of issues.
In fact, it's the industry's responsibility to respond to these
questions and to provide the information necessary to support safe operation
of the plant.
Now that doesn't mean that we aren't, you know, as the
technical staff, trying to understand these things ourselves through our research
activities, etcetera, but the whole process we are working through here is to get
a communication out to the industry that says you need to provide your basis
for when you are inspecting and what your technical justification is, and it needs
to consider all these sort of issues.
CHAIRMAN FORD: Okay, I understand. Keep going.
MR. HISER: Okay. Now again, some of the problems with
the small quantities of the deposits are the variability in the interference fit and
how that may restrict deposits flowing from the crack up to the top of the vessel,
and also the tightness of PWSCC cracks.
I think we had a quote earlier today of one gallon of leakage
at Oconee over a 12-month period. So there is not much leakage from these
things.
DR. WALLIS: One gallon a year?
MR. HISER: In a year. Yes, Oconee Unit 3 had cleaned the
head 12 months earlier, then did a visual in a 12-month period. Now that
assumed -- Well, that's what they found.
DR. WALLIS: One gallon a year? The velocity up the crack
is very, very low, isn't it? And yet we are told it carries boron up there. It's in
solution, because it's vaporized.
Again, it will be useful to have someone explain an analysis
of these things in terms of these sorts of numbers. I mean, is it a diffusion
phenomenon, a flow phenomenon. What happens to the boron? Where do you
expect to find it? What kind of concentrations?
Is someone going to present this sort of thing?
MR. HISER: We don't have information on that. I mean,
again that's --
DR. WALLIS: Well, I mean if I've got something like this in a
class of graduate students, I would say go away and do some homework; make
some calculations about flow rates, rates of this, that and the other, come back
with some answers tomorrow. Right? With the best that you know.
MR. STROSNIDER: If I might interject, that's basically what
the purpose of the bulletin is, telling the industry to go off and get those
answers.
DR. WALLIS: So wait and do all the paperwork and then
someone sits down and does some thinking. Is that what happens?
MR. STROSNIDER: Well, we'll get into the work that we've
been doing. As I mentioned earlier, Research brought contractors on board to
start looking at this issue, and we are trying to do that.
DR. WALLIS: You have so much inertia to get going.
MR. STROSNIDER: I'm sorry, I didn't hear you.
DR. WALLIS: You seem to have so much inertia to get going
on something.
MR. STROSNIDER: Maybe we'll address more of this as we
get through the presentation.
MR. HISER: So the staff has -- Regarding the visual
inspection, staff really has two concerns. One is: Is there sufficient deposit that
is available on the head for detection; and secondly, what are the difficulties
involved in identifying the leakage or the deposits that one sees and identifying
whether they came from vessel head penetration nozzles or from other sources,
as indicated here.
Now one point that, I guess, I would like to make regarding
insulation, just to make sure that we have a clear understanding of the situation
regarding insulation -- This is a similar schematic to what Larry showed this
morning.
The insulation at, I guess, all of the B&W is in a horizontal
position like this, such that the head surface is readily available for inspection.
Many of the plants, I think, from Westinghouse and Combustion Engineering,
the insulation is contoured to the head and, in some cases, offset by several
inches, providing a gap through which one could do some sort of an inspection.
In other cases, it is either directly lying on top of the head or
is even adhered to the head. So the difficulties in doing the visual inspections
in those cases are -- The problems are clear and were not addressed at all in
the industry report.
As we discussed earlier today, the remaining ligament
margins that the industry cited in the report did not include a clear discussion
of time margin and crack growth rate. Their response to our REI questions did
provide some information on that.
Sort of sum up the staff concerns, we are concerned that a
plant -- or a nozzle could reach a critical crack size before one is able to detect
leakage. With the visual examinations, these are on a periodic basis,
depending on the cycle length for the plants.
There is no continuous monitoring that could provide any
intermediate assurance that there was no leakage occurring. And in addition,
the inspection under insulation needs to be addressed.
Now the report itself did not provide too much discussion on
postulated accident analysis and risk insights. The staff perspective will come
from Mark Reinhart, and the staff again is really concerned with how -- this
issue regarding compliance with the regulatory requirements in this case.
(Slide change)
MR. HISER: Now regarding the regulatory requirements, the
staff has gone through the regulations and the next two slides provides some
detail on areas that we think there would be questions.
10 CFR 50.55a references Section XI of the ASME Boiler and
Pressure Vessel Code, and in particular the code does not permit through-wall
cracking of pressure boundary components.
Technical specifications for each plant also do not permit
through-wall leakage. Clearly, if we have boric acid deposits, those that are not
attributable to flange connections or things like that, then there would be
questions about compliance with these.
The General Design Criteria in Appendix A -- you know, we
have particular criteria that we think apply in this case, if not in a regulatory
sense, then at least in a philosophical sense: That one should not have -- or
one should minimize probability of rapidly propagating fracture of the reactor
coolant pressure boundary, and the reactor coolant pressure boundary should
have extremely low probability of abnormal leakage.
(Slide change)
MR. HISER: Flipping to Slide 10, from Appendix B we have
some of the criterion there that we think apply. One is control of special
processes, which would include things like non-destructive testing, that they
should be accomplished or controlled and accomplished by qualified personnel
using qualified procedures in accordance with codes, standards, specifications,
criteria and other special requirements.
In addition, activities affecting quality, from Criterion V, should
be prescribed by documented instructions, procedures or drawings, including
appropriate acceptance criteria.
Then Criterion XVI related to corrective actions. Conditions
adverse to quality should be promptly identified and corrected with a
determination of the cause of condition and implementation of corrective action
to preclude repetition of the problem. We think this applies not only to plant
specific items requiring corrective action, but also from incidences at other
plants. So we think that would apply in this case.
So these are the regulatory requirements than we think apply
in this case.
(Slide change)
MR. HISER: Now looking at the staff assessment of the
situation, looking at the susceptibility rankings that were provided by the MRP,
the staff has identified subpopulations of plants based o their susceptibility.
There are four specific populations. One is those plants that
have identified cracking at the present time. In particular, that would include the
three Oconee units, along with Arkansas Nuclear 1. That's sort of a special
subpopulation.
(Slide change)
MR. HISER: If we look at the overall susceptibility rankings,
an inferior version of Larry's slide from this morning without the pretty colors --
If we look at the rankings in an overall sense, we identified, if you will, a natural
break in the data at around 4 EFPY.
What we would submit is that the plants that are less than 4
EFPY away from Oconee Unit 3 define a subpopulation.
DR. WALLIS: These are the cold plants and the hot plants?
MR. HISER: These would be probably, I guess Larry would
say, the hot plants that have been operating for a long time.
DR. WALLIS: Well, I know, but the break is between the cold
and the hot.
MR. HISER: No. This is --
DR. WALLIS: Different scale?
MR. HISER: Yes. This is the fine scale.
DR. WALLIS: Oh, I'm sorry. Excuse me. Yes, you are right.
MR. HISER: So this is the overall rankings. So if we look at
this point down here at about 4 EFPY, look at plants below that as being a
subpopulation. Then look at plants at about 30 EFPY, so between 4 and 30
EFPY is a separate population. We would have those three subpopulations,
and then really this is a balance of plants.
DR. WALLIS: Now if your uncertainties are the order of 2
EFPY, that would sort of mean that your distinction is no longer -- in the fine
scale is no longer so significant. We don't know the uncertainties. They haven't
been quantified for us in terms of EFPY.
MR. HISER: That's correct, but I think in the way that we
choose -- that we have proposed to use these subpopulations, I think that we
are just using it as a guide for information collection. We are not proposing any
actions at plants at this point. We are just looking to gather information so that
we can assess the magnitude of the problem at this point.
DR. WALLIS: I guess if you -- I'm sorry. If you knew
something about what you think your uncertainty is, this would tell you about
how surprised you are if you find a crack at, say, Number 6 or 3.
MR. HISER: Right.
DR. WALLIS: So you do need to get your state of knowledge
now in order in order to interpret any new data you get.
DR. BONACA: Before you move on, on slide Number 11, you
had plants with low susceptibility, and you say that PWSCC not likely through
current license period. Do you mean the 40 years of life?
MR. HISER: For the first 40 years. Yes. And those would be
plants that are more than 30 EFPY.
DR. BONACA: So you have that kind of level of confidence
in your predicting capability?
MR. HISER: We have a relative confidence at this point. The
plants that are in the first three subpopulations, the first plants have
demonstrated a problem. The second plants, second group of plants, we
expect that it's likely to occur in the near term.
For the plants that are between 4 and 30 EFPY with moderate
susceptibility, we don't think it's likely to occur in the near term, but it could
occur. We would not be shocked based on uncertainties in the modeling.
DR. BONACA: Sure, I understand.
MR. HISER: The last group of plants clearly has lower
susceptibility than the first group. This represents about a third of the PWRs.
Any actions that might be required there clearly would be able to key off of
findings from the first three groupings.
DR. BONACA: Yes. I was just focusing on the statement
"current license period." That's a long time.
MR. HISER: Right.
MR. STROSNIDER: This is Jack Strosnider. If I could
interject just for a second a thought.
The way we are using these rankings is sort of a graded
approach to the information that we are requesting. All right? So I think you will
see some of that come together when we actually get into the information
request, and how we use these different categories to say here's what we are
asking licensees to provide us.
DR. BONACA: I understand, and I agree with the approach.
When I read the words that you use there, it expressed some level of
confidence that I'm not sure the current -- you know.
MR. STROSNIDER; And I don't think we want to express any
level of confidence other than here's a graded approach to collecting
information so that we can decide then what additional actions might be
appropriate.
DR. WALLIS: However, we were told that you wouldn't be
shocked if you found them, but you would be shocked if you found cracks in the
bottom layer there, the 24 plants total.
MR. STROSNIDER: I think we would be very shocked.
DR. WALLIS: It would force you to reevaluate all your
assumptions.
MR. STROSNIDER: Absolutely.
MR. HISER: I think that would be a very surprising
occurrence, given that many of the plants are 100+ EFPY away.
As Jack mentioned, what we are looking to do within the
bulletin is to verify compliance with the regulatory requirements, and we think
this is best achieved through qualified examinations. On the next page, I'll go
over what we think qualified examinations are.
This is a graded approach that is keyed on that the
subpopulation at each plant is listed within. In this case, we think examination
of 100 percent of the vessel head penetration nozzles is appropriate.
There was some discussion about the CRDM nozzles. There
also are thermocouple nozzles. I think there are vent pipes in some of the
heads. There are other penetration nozzles in the heads that are fabricated
from similar materials and would be expected to have similar cracking histories.
Why do we think 100 percent of the nozzles is pertinent is
that, from looking at the statistics of the situation, there really is no -- very little
benefit to doing a small inspection, limited inspection of nozzles.
If you look at the leakage history of the nozzles, it's not even
possible to define a certain part of the head as not having exhibited any
leakage. So we think all nozzles are created equal and deserve equal attention
in this case.
MR. STROSNIDER: Al, if I could interrupt you for just a
second. There seemed to be some interest earlier in the statistical evaluation.
Lee Abramson from the Office of Research is here. He assisted us in that
evaluation. If you are interested in hearing about that, I would suggest maybe
Lee could answer any questions you have.
DR. WALLIS: Maybe there's some data in curves. We could
just be given the papers so we could look at them.
MR. STROSNIDER: Well, there's actually -- We have a write-
up with regard to some of the analysis, the sampling analysis that he put
together. We could provide that.
DR. WALLIS: I think it would be more efficient than trying to
do it orally.
MR. STROSNIDER: Okay. We can do it that way.
(Slide change)
MR. HISER: Now regarding qualification of the examination
methods, the staff has identified three --
DR. WALLIS: I'm sorry. Would you mind just going back to
12 for just a quick question. I just want to make sure.
(Slide change)
DR. WALLIS: The triangles -- This is really the cumulative
number of units, isn't it, on the top?
MR. HISER: Yes.
DR. WALLIS: Cumulative number of units. So the three
triangles down in the lefthand side there, that's the Oconee plants, and
presumably there's another triangle somewhere farther up which is the ANO.
Yes?
MR. HISER: Right. I'm not sure. It's one of these points. I
know the industry -- We were told last week that this evaluation was their initial
cut at things. They have gone back and have sharpened the pencil a little bit,
and there's a little bit of shifting of some of the units.
DR. WALLIS: So there is a -- My eyesight, I can't tell the
difference between some of your symbols there. But there is one associated
with later at the top righthand corner, the far righthand one, later.
Now I can't read it very well, but the one that's furthest to the
left on that graph -- isn't there one of those points at one year, effective power
year, one of those things that's not supposed to be inspected yet? Is my eyes
off?
MR. HISER: I would defer to Larry, if you have your color
slide?
DR. WALLIS: Well, regardless of the specific question --
MR. MATTHEWS: There were two plants in under ten years
that would not have had a refueling outage by -- I am not sure if that fourth dot
on the graph is one of them or not.
DR. WALLIS: But that's how this graph would be used, is to
say, well, hey, Mr. Plant, fuzzy on the righthand side, why aren't you inspecting
before '02 or that's the reasoning behind this?
MR. HISER: Yes. I think our bulletin requests that they
provide the basis for why they do not need to do inspection.
I think we're done with the susceptibility rankings.
(Slide change)
MR. HISER: Okay. If we look at the examination methods,
the staff has again provided a graded approach, if you will. For those plants
with moderate susceptibility, we think a VT-2 visual examination that is qualified
is a reasonable approach.
The qualification that we think is appropriate in this case is
one that demonstrates the capability of detecting small amounts of boric acid
deposits and the ability to discriminate deposits from VHP, vessel head
penetration, nozzles and other sources. Presumably, if you can't say it's from
another source, then you have to assume it's from one of these penetration
nozzles.
Again, that would be appropriate for the moderate
susceptibility plants, those from 4 to 30 EFPY of Oconee, and that would
represent 31 plants total, at least from the initial susceptibility rankings.
Now the next approach would be a plant-specific visual
examination qualification. In this case, on a plant-specific basis we think that
a demonstration would be required to demonstrate that VHP nozzle cracks will
lead to deposits on the head, and that includes consideration of interference fits
and other plant-specific as-built considerations.
DR. WALLIS: So the real question is whether you can detect
enough boric acid in time before there is a circumferential crack which is
growing sufficiently to cause you problems for all possible situations of
interference at some whatever.
MR. HISER: That's exactly right.
DR. WALLIS: And we haven't seen any quantitative analysis
of that. It's just someone's hope that that's the case?
MR. HISER: We would expect some sort of a demonstration
that that is the case.
DR. WALLIS: I think you need that.
MR. HISER: If it cannot be demonstrated, then we think that
visual examination is not appropriate. You have to be able to demonstrate that.
In addition, again the two-step process. Step 1 is, if boric acid
leaks out, it will come to the surface. The second part is that, if it's there, that
I'm able to find it. So I must be able to reliably detect it,and also identify the
source of the leakage. That would include considerations of things such as
insulation, preexisting deposits or other impediments to the visual examination.
DR. WALLIS: We heard about lithium. Where does the
lithium go when it comes out?
MR. HISER: I haven't heard of detection of lithium.
DR. WALLIS: Where does it go? You only find boron on the
outside. You don't find any lithium?
MR. HISER: I'm not sure what was found at Oconee, if it was
only boron or if they did any --
DR. WALLIS: Well, is this lithium borate or what is this stuff
that you are seeing?
MR. FYFITCH: Steve Fyfitch, Framatone.
The boric acid concentration in the reactor is anywhere from
about 1800 ppm down to zero as you go through the cycle. The lithium
concentration is 2 ppm down to almost zero.
So the amount of lithium in the boron that you are finding on
the head is so minuscule, it's hard to detect it.
DR. WALLIS: But it's enough to make the environment in the
crack region possibly alkaline.
MR. FYFITCH: If it were to concentrate, yes.
MR. HACKETT: This is Ed Hackett. I think I would add a
further comment to that. Dr. Sieber mentioned earlier, too, that the species that
I think you would be concerned about is lithium hydroxide, and it's a much more
volatile situation than the boric acid.
So probably, in addition to the concentrations, that would be
another reason why you are not seeing any deposit or anything like that.
DR. BONACA: I would like to ask a question then. Just
Oconee performed an inspection the previous cycle. Right? And there was no
indication of leakage. Now they performed this inspection and found some
circumferential cracks that extend almost half the circumference. Some were
less.
Either from a detectability standpoint or from a crack growth
rate standpoint, what does it tell us? I mean, I hear projections now that it will
take many years before these cracks can extend beyond that. Is there
someplace where you are going to address these issues or talk about them?
MR. HISER: Not within the context of the bulletin. What I can
--
DR. BONACA: Did I explain what my trouble is there?
MR. HISER: My understanding is that Oconee Unit 3 at its
previous outage had completed cleaning of the head, and at that point they had
a clean head that they were able to do effective detection of the boric acid. One
year later they detected boric acid.
DR. BONACA: So it may have been that there was some
leakage, but it was not identified.
MR. HISER: The one comment that I heard--
MR. ROBINSON: This is Mike Robinson, again from Duke
Energy, and I'll try to address your question; because we asked ourselves the
same question.
We had the Unit 1 outage in November of last year, and that's
when we first found the first signs of leakage on top of the head. Unit 3 had
been down for its refuel earlier than Unit 1. We had to bring Unit 3 offline in
February for a maintenance outage.
We started back in 1993 and in '94 cutting the holes in the
service structure and doing head cleanings during each refuel outage to get the
heads to a good condition to where we could do good visual inspections.
When we did the inspection on Oconee 1 and found the leak
-- again, that was prior to Oconee 3 coming down. The fellow who does our
inspections, obviously, became a whole lot more sensitized to what to look for.
Prior to finding leaks on Oconee 1, the expectation was, if you
have a leak through one of these nozzles, you're going to find pounds of boron
on top of the head, much like what we saw down at VC Summer.
So the mindset was, if you are looking for leakage, you would
expect to see something fairly large, and again it was just a total shift for us
once we did see something that looked suspicious to now identify that as true
leakage.
We suspect on Oconee 3 that we had had some leakage in
prior years. We suspect, although you can't prove, but we think we had some
cracks at the point of actually going through-wall to where we did see the leak
once we came down for the forced maintenance outage.
DR. BONACA: Okay. This explains to me a little bit why, and
there may have been some leakage before. However, what you are telling me
gives me concern about how much it will take, how long it will take for the future
plants to be able to identify. I mean, what you are telling me is that you need
significant cleaning of the head before you can really be sure that you can see
a leakage.
MR. ROBINSON: A real key is to have a good clean head.
DR. BONACA: That's right, and many of these plants do not
have.
DR. WALLIS: Well, it tells us something else. The real leak
started several years ago. Then the zero hour for your graph certainly change.
MR. HISER: That may be true.
MR. ROSEN: What is the expectation here? Do we think the
nine cracks that we found at Oconee are all the cracks that's going to happen
to that head or is it eventually are they all going to crack?
MR. HISER: I don't think the staff believes they are the only
nine that would ever develop in that head. Given the distribution of the
phenomenon, you know, we are some point early in the curve. I would expect
ultimately, if you run the plant long enough, every one will crack.
MR. ROBINSON: Again, we think that PWSCC is a like a
cancer. Once it starts, it's going to continue to grow. We know we have
susceptible material. We know we've got the temperatures, all the kind of
things that you need for this phenomena to be there.
That's one of the reasons we have made the decision to
replace the heads at Oconee.
DR. BONACA: Thank you.
MR. HAMILTON: John Hamilton with Energy Nuclear. I might
comment on the ANO experience in the outage previous to this spring. There
was a visual inspection, and there was some boric acid in the vicinity of the
nozzle that we found leaking this spring.
In the previous outage that boric acid was examined, and
we've attempted to determine where it was coming from. The determination at
that time was that it was not a control rod nozzle leak. A photographic record
was made, and in the outage in the spring we again examined it using a robotic
video camera, and concluded that it was a control rod nozzle leak at that time.
What we have now done is that we cleaned the head
thoroughly after the outage and made another baseline video record so that,
any future outage, we'll be able to easily determine what the situation is.
DR. BONACA: But still, I mean, for this 20-odd plants that will
inspect their head over the next nine months, what I understand is it there will
be difficult to characterize a small leakage, because the heads are now clean.
I'm trying to understand, because if you look at it, you cannot
characterize it. You cannot make any conclusions. Then the best you can do
is to commit to another inspection two years from now, maybe year and a half,
whatever the cycle length is, which puts off quite a bit the time which they are
detectable.
MR. STROSNIDER: This is Jack Strosnider. I think, when
you see -- when we get to how we have constructed the information request,
you will see that we are trying to address that issue. If licensee cannot perform
a qualified or plant-specific qualified visual examination, then they need to
provide a basis why they are not doing a volumetric examination.
DR. BONACA: Okay.
MR. STROSNIDER: I think when we get through -- when you
see how we've structured that, we have tried to address that issue, because it's
not clear that waiting outage after outage to collect that kind of data is
acceptable.
MR. MATTHEWS; This is Larry Matthews again. In some of
the slides I showed, many of these plants don't have anywhere near the degree
of masking boric acid sitting on their heads that the B&W units do, because they
don't have those flanged CRDMs. They have Conoseal or canopy seal welds
that seal those up pretty good.
Now some plants have canopy seal weld leaks occasionally,
too, but those get cleaned up. So like the Robinson picture I showed, that's a
pretty clean look, and Salem was, too.
So, you know, it's not like every plant is sitting here with half
a ton of boron sitting up there, and you're trying to pick a teaspoon out. It's not
that way at all the plants, certainly, and I think the B&W plants have been
working on their issue for a number of years.
MR. STROSNIDER: Just to follow up on that thought for a
second, I would just point out that recognize that the bulletin is addressed to all
the PWR licensees. This is a plant-specific issue when you start asking what
is the condition of the head.
So, really, it's probably not possible to come up with a generic
solution to that. You have to go out to each licensee, and they have to assess
the condition of their head and whether they can effectively perform this sort of
examination. So that's another reason that we are looking at a bulletin.
MR. HISER: In terms of a qualified volumetric examination,
this would be one that has a demonstrated capability to reliably detect cracking
on the outside diameter of vessel head penetration nozzles.
In this case, we think it's appropriate for plants that have
identified cracking. As I think Mike Robinson said, the cancer is there. We just
want to determine how far it's spread. At this point we think that's four units
altogether.
We think this would also be appropriate as a default if the
visual examination cannot be qualified, either the VT2 visual or the plant-
specific visual, and clearly would be applicable to any plant that finds leakage,
because then, again, we know they have the disease.
(Slide change)
MR. HISER: IN terms of the proposed information request,
the request is to licensees, and we ask them to provide within 30 days of the
issue date five particular items.
Actually, Item 1 is pertinent to all licensees. Items 2, 3 and 4
are to the various subpopulations, and then Item 5 is also pertinent to all
licensees.
Item 1 is for each plant to provide its plant-specific
susceptibility ranking, and including all of the data used to determine that
ranking, and also to provide a description of the vessel head penetration
nozzles, including the number, the type and materials used to fabricate them.
This will provide us with a background on what is in each plant
in terms of the nozzles and where they lie within the industry's susceptibility
histogram.
Now for plants that have identified leakage or cracking in their
nozzles -- and that again would be the three Oconee units and Arkansas
Nuclear Unit 1 -- we ask them four specific questions.
One is to describe the extent of nozzle leakage and cracking
that they have identified to date; to describe the inspections and other corrective
actions that they have taken, repairs and other corrective actions.
We ask them to discuss their plans and schedule for future
inspections, in particular, the type of inspection, the scope, qualification
requirements and acceptance criteria.
Regarding how those planned inspections can be used to
demonstrate compliance with regulatory requirements: If the inspection plans
do not include inspections before the end of this year, we ask them to provide
the basis for concluding that the regulatory requirements will continue to be met
until the inspection is performed.
If the inspection plans do not include volumetric examination,
which the staff had concluded earlier is appropriate, of all of their vessel head
penetration nozzles, then we ask them to provide the basis for concluding that
the regulatory requirements will continue to be satisfied.
(Slide change)
MR. HISER: So that's the information request for plants who
have demonstrated cracking. For those that the staff identified as high
susceptibility -- in other words, those plants within 4 EFPY of Oconee Unit 3 --
as ask them to describe the vessel head penetration nozzle inspections that
have been performed in the last five years so that we have a background on the
types of inspections that they have been able to perform based on things such
as insulation and preexisting boric acid deposits.
A second question is for them to provide the plans and
schedule for future inspections.
Item 3 relates to how their planned inspections will meet the
regulatory requirements. if the inspection plans do not include any inspection
prior to the end of 2001, then we ask them to provide the basis for concluding
that they will continue to meet the regulatory requirements until they perform
their inspection; and if their inspection includes only visual examinations, to
discuss corrective actions, including alternate examination methods such as
volumetric, if leakage is detected.
CHAIRMAN FORD: On Item c(1), I'm assuming that the
scenario is that they have found a boric acid deposit at the top of that tube. If
the regulatory requirement is that they cannot go through the pressure
boundary, which I am assuming would be the circumferential crack going all the
way through, a lot is going to depend on how they reply to you for the
disposition curve or the crack propagation item.
MR. HISER: c(1) assumes that they do not plan to do any
inspection in the short term, during, say, the fall outage season.
CHAIRMAN FORD: Okay. But it's still the same thing.
Provide basis for concluding the regulatory requirements, i.e., they won't have
a through-wall crack, will continue to met until the inspections are performed,
i.e., some ISI period.
MR. HISER: Right.
CHAIRMAN FORD: In the future. That's going to depend on
how satisfied you are with the velocity stress intensity disposition curve. Yes?
So are you going to have before the event your approved disposition curve,
what you will accept? Would you accept a disposition curve based purely on
crack growth rates in the primary coolant?
MR. STROSNIDER: Al, let me interject. This is Jack
Strosnider, because I was going to address this later in my concluding remarks.
We are asking for these assessments, basically, to come in
from the industry, and one of the important things is going to be that we have
some continuing dialogue as they are developing what these responses are
going to look like; because it's not going to serve anybody well if we come in in
the September time frame or so and we have a disagreement on whether it's
an appropriate answer.
So -- But recognize there is a real challenge here in terms of,
if you want to tie it to crack growth data, you know, what's going to be able to
be done by that time. But the best answer I can give is that I think we need to
have this continuing dialogue.
We have had good communications with the industry, and that
needs to continue. But we do recognize that we are taking on an issue where
in the September time frame we are going to get these responses and have to
determine whether we think they are adequate or not.
DR. WALLIS: Well, can we be more specific? Are you going
to require that they analyze the effect of concentration of lithium hydroxide in the
space, possible effects of it, or that they make an analysis, an assessment of
it?
MR. STROSNIDER: I would suggest that, if their justification
-- If they are going to provide a justification for some later date of examination
than what is in this request, then they are going to have -- and if it includes
some assumed crack growth rates, that we are gong to have to have
discussions on the technical basis for those growth rates.
DR. WALLIS: Well, discussions -- I mean, if they come back
with an assessment which completely ignores, in effect, which we've questioned
at this meeting, are you going to accept it?
MR. STROSNIDER: It could come back perhaps and assume
some very high growth rates.
DR. WALLIS: Assume? I mean --
MR. STROSNIDER: I think the answer to your question is we
expect them to address those types of issues and providing a credible technical
basis. Yes, they need to understand the environment and the growth rate, if
that's what they are going to rely on.
DR. WALLIS: Well, I think you ought to come back with the
technical questions to which you want answers and not leave it all up to some
kind of dialogue. You ought to specify we want these technical questions
answered. -- just wait for you to make an assessment and see whether or not
you want to raise those questions.
MR. STROSNIDER: And in fact, we have provided the
industry with a list of technical questions on several different previous
occasions. Those are already documented, and it includes the kind of things
you are talking about.
DR. WALLIS: Thank you.
(Slide change)
MR. HISER: For the plants with moderate susceptibility, those
with susceptibility rankings from 4 to 30 EFPY of Oconee Unit 3, we ask them
to discuss their plans and schedule for future inspections. Question b. is that,
if inspection plans do not include a visual examination at the next scheduled
refueling outage, to provide the basis for concluding that the regulatory
requirements will continue to be met until they perform the inspections.
Then the last item on this page is, I guess, identified as 5 in
the draft bulletin. For plants with refueling or scheduled maintenance outages,
within 30 days after restart we ask them to describe the extent of nozzle
leakage and cracking that they have identified and, Item b. there, if the
inspections, repairs and corrective actions are different from those that they
provided to us previously, we will ask them to describe what they actually did.
DR. BONACA: For plants with the low susceptibility, you have
no requirement at all?
MR. HISER: They would fall under Item 5 at this point.
DR. BONACA: Item 5?
MR. HISER: Again, the bulletin is a short term, Phase I, if you
will, of trying to gather information from those plants. We wouldn't really expect
to find anything.
DR. BONACA: Last bullet on page 17?
MR. HISER: Yes. This is Item 5. I'm sorry, they should have
been numbered instead of with bullets.
DR. BONACA: So everybody has to answer that question?
MR. HISER: Right, for the last one. That is the proposed
information request.
(Slide change)
MR. HISER: In terms of the proposed required responses,
this is what licensees must provide us. The other is a request, in all honestly.
Within 30 days of the date of the bulletin, we ask them to
submit a written response indicating whether they will submit the requested
information from the three previous slides, and secondly, whether the requested
information will be submitted within the requested time period.
Now both the requested information and the required
responses are both 30 days. This could be one submittal. Could be two
submittals. If they were to provide us for Item 2 here that they will not meet the
requested time period, then clearly, that would be a second response.
For addressees who choose not to submit the requested
information or are unable to satisfy the requested completion date, they must
describe in their response any alternative course of action that they propose to
take, including the basis for the acceptability of the proposed alternative course
of action.
So that would be the required response.
CHAIRMAN FORD: Allen, we've got exactly one hour left.
I would like to put aside a quarter of an hour anyway at the end of the talk. It's
quarter past one. Just so that we have some general comments from the
subcommittee and, more importantly, give you advice as to what is going to
happen tomorrow.
Bearing that, we've got three more talks, and I could leave it
up to you to decide. You've heard some of the comments that went on this
morning, and they are cut and paste or whatever it is to individual contributions
to address those concerns. That would be really helpful. But I want to leave a
quarter of an hour aside for any general questions.
MR. MARSH: We'll prioritize the presentations for you.
CHAIRMAN FORD: I suppose sub voce that we had better
keep quiet.
MR. LEITCH: Just one question regarding the Oconee units.
From reading this, it appears as though you are not requiring anything special
of Oconee as far as a mid-cycle shutdown to take a look at these.
In other words, I would expect that the other CRDMs at
Oconee are perhaps the highest susceptibility areas that we have, because we
don't really understand exactly why some of them have cracked and some of
them haven't cracked.
So is it correct that we are just allowing Oconee to operate on
a normal refueling cycle?
MR. HISER: The bulletin that we propose, again, is step 1,
just trying to gather information. Once we have input on what the licensee's
plan and also what other additional data we would get from them, we would
determine the need for additional regulatory action.
At this point, we are just in the information collection phase.
MR. LEITCH: Asking them what their plan is?
MR. HISER: Right. And again, with the proposed publication
date of August 1, that, hopefully, would provide us with information by
September 1. So we would be able to proceed at that point, once we have
analyzed the submittals.
MR. STROSNIDER: This is Jack Strosnider. I wanted to
point out, if I understood the question, if you look at the information request for
plants that have identified cracking, we are asking them to provide a basis. If
they are not inspecting before the end of 2001, they have to provide a basis for
doing that, and similarly if they are not doing a volumetric examination.
So I think that Oconee would fall into that case, and they
would have to provide a justification why they are not going to take those kind
of actions.
By the way, I do think Oconee, the unit with the circ cracks is
shutting down this fall, and I think that would have been a shorter operating
cycle than normal anyway, because the last shutdown was just this past spring.
MR. HISER: Okay, thanks.
MR. REINHART: I am Mark Reinhart, the Acting Chief of the
NRR Probabilistic Safety Assessment Branch, and I'm going to talk about the
risk perspective.
(Slide change)
MR. REINHART: So when you look at this next slide, it really
should say developing risk perspective, gathering what we know now. We are
looking at a situation where we have the circumferential crack CRDM, and we
are saying one scenario could be a rod ejection. One scenario could be a
LOCA.
The rod ejection would be reactivity concerns. We talked
about that this morning, and I think our expectation is that most plants operate
with the rods out. So we are not so much concerned other than maybe in the
collateral damage arena.
DR. BONACA: Just a comment on this morning. I mean,
because they are running with the rods out, you know --
MR. REINHART: Right. During the start-up.
DR. BONACA: -- effect of the SCRAM maybe equivalent of
the rod ejection from zero power, which is the most severe. Then it is analyzed,
always separation from the LOCA. You have to look at the two combined
events.
MR. REINHART: Yes, absolutely.
DR. BONACA; It makes it a very complicated scenario.
MR. REINHART: It would. It definitely would. The LOCA we
put in the medium category, trying to mix apples and apples. In IPE guidance,
a 2 to 6 inch break would be a medium LOCA. So that's why we considered
that.
Both of these are analyzed events, but as we've brought out
all morning and afternoon, there are a lot of significant uncertainties. So we are
trying to gather information as we go and not lock ourselves in, but be ready to
address those uncertainties when we can.
We are looking at various analyses and scenarios and
struggling to see which fit, which don't fit, under which circumstance.
Collateral damage is one of our concerns. What will happen
if a CRDM ejects? What type of internal, external damage would it cause?
What about nearby control rod drive mechanisms? We don't know, but we want
to try to understand that better.
Another concern is for plants that have blanket information on
the head, the CRDM ejection, the medium LOCA, blowing that insulation, where
would it go? Would it get in the sump or would it block recirculation? Injection
and recirculation are key vulnerabilities in the medium break LOCA category.
So what we did, we said we are going to just see what we can
say at this time, assuming -- we'll take about a medium break LOCA, and we
just take our core damage frequency to the simplest form.
We have an initiating event frequency, and we have a
condition of core damage probability, and we use the IPE data we have. For
that initiating event frequency, we need to know a lot before we can really say
much about it.
We talked about the chemistry, the materials, what
mechanisms are involved, what are the synergisms, crack initiation, crack
propagation, probability of rupture. All that needs to come together to really say
what is the initiating event frequency.
So we said what can we say? Let's go to our basic equation,
set that initiating event frequency equal to one. We will assume we have it.
What does that give us in condition of core damage probability?
So if we looked at our IPE results, we had a spread. Most of
them came into the 10-2, 103 range. The highest outlier was 4.7 times 10-2, and
the lower is categorized as less than 10-4. So there's a spread, but most of
them fall in that 10-2, 10-3 range.
DR. BONACA: But those results was for a medium LOCA,
right?
MR. REINHART: I beg your pardon?
DR. BONACA: That was based on a medium LOCA.
MR. REINHART: Yes. Assuming we have an initiating event
frequency of 1 for a medium break LOCA.
DR. BONACA: That's right. And so there is no consideration
of possible damage tied to the rod ejection.
MR. REINHART: We are not looking at collateral damage
there. We are not looking at operator action recovering there at this point.
DR. BONACA: That's a big --
MR. REINHART: Yes. It is part of the uncertainty. We
expect the operator is going to be able to do a lot to mitigate this accident. We
expect that there might be some collateral damage that might make it very
difficult.
DR. BONACA: You mean the old -- the FSAR shows
significant fuel damage for the zero ejection accident. So I just --
MR. REINHART: I beg your pardon?
DR. BONACA: All the FSARs or the neutronic analysis show
some degree of fuel damage for rod ejection from zero power. I think that that's
a potential candidate here that may bring that into the -2 or 3 to a much higher
number.
MR. MARSH: Well, but the damage that is caused by the
core -- caused to the core from the reactivity transient is not the same criteria
that you look at in terms of dose rates and things for LOCA purposes.
You could get damage from reactivity transients, but the
acceptance criteria for a LOCA is a different -- Now you're looking at damage
caused by melting, not damage caused by reactivity.
In other words, that adds to the dose rate inside of containment but not due to
off-site dose or things of that sort.
So you do accept some fuel damage.
DR. BONACA: If you have some center line melting or if you
have some clad failure. I mean, it just happens. If it's there and if you have
IE=1 and you have some fuel damage in -- That doesn't seem right.
MR. ROSEN: I don't think, Mark, that the presentation here
showing an assumed initiating event frequency of 1 is very useful. I would
prefer you just left that out and just talked about the conditional core damage
probability, because we know it's not 1. We are not going to always have these
things.
MR. REINHART: I agree, but by definition to get conditional
core damage probability, that's the condition.
MR. ROSEN: Well, perhaps, but people can misunderstand
that.
MR. REINHART: I very well understand that.
MR. ROSEN: And in that sense, I don't think it's very useful.
DR. WALLIS: It seems very strange. Did you deduce it from
the CDF? I thought your CCDP was a separate calculation. Then you
multiplied by the IE(f).
MR. REINHART: You can take your condition of core damage
probability, and then you multiply it by initiating event frequency to get your core
damage frequency.
DR. WALLIS: But assuming it is one, then you've got 102 and
you've got 100 reactors. That's not acceptable.
MR. MARSH: It's only meant to show in the relative sense
what the mitigation systems are in terms of their strength.
DR. WALLIS: It's not very useful, though, is it?
MR. REINHART: Well, it is useful in the sense that we can
home in on areas we need to look at, and we talked about we need to look at
injection. We need to look at recirculation.
DR. BONACA: What they are saying: Given that, you have
a break.
MR. REINHART: Right.
DR. BONACA: But the comment I am making: Given that you
have a break, and they are not contending that the way you are dealing with,
you know, if you have another event such as rod ejection that may give you fuel
damage -- I'm not saying you will have it, but I'm saying you have to look at it,
because I think it's credible -- then the number E-2 to E-3 is one.
You have already a fuel damage there, and now if you had a
hole in the system, you are going to have loss of coolant with fission product
through it. I mean, in containment.
MR. REINHART: So you're postulating the worst case
scenario of (a) you have the rod ejection from zero power giving you fuel
damage.
DR. BONACA: Yes, and I'm not saying it is going to happen.
I think, however, that the dynamic effects of it, given that you have all the rods
out, may be that you are dropping the rods in the core, and one is stuck out.
This is not purely a stuck rod evaluation for a margin evaluation. It is a dynamic
effect.
If that is the case, you will have some fuel damage, and then
you don't have to wait for a LOCA to cause you -- You already have it. So --
MR. MARSH: We are not trying to imply that this is the core
damage frequency. That's not what this is.
DR. BONACA: No, this is only to say you have to look at it.
You have to look at it.
MR. STROSNIDER: This is Jack Strosnider. I would really
like to comment on this use of the conditional core damage frequency. All right?
And I would like to put it in this context.
If you look at the situation the NRC is in right now, I would put
it in the context of decision making under uncertainty, and you have to make a
decision when you've got a lot of uncertainties involved here, and you have to
make a decision about what the appropriate regulatory action is.
One thing that might help to inform that decision is to
understand the consequences of the event, should it occur. All right. So let's
look at the conditional failure probability.
Let's assume that the event actually happens, and you look
at the numbers here. These numbers tell you that you need to provide some
increased attention on this. This is part of our basis for going the route of the
bulletin and taking the action we are taking.
If these numbers were several orders of magnitude lower for
this particular event, you might reach a different conclusion about your
willingness to accept the uncertainties that are involved. Right? But when we
look at these numbers, we conclude, no, there's the uncertainties associated
with the potential for this event occurring.
When I look at the consequences of it, I need to better
understand them, and I need to ask the industry to take some action to provide
that sort of information, and that's what drives us to the bulletin.
DR. BONACA: Sure. My only problem was the numbers may
be even higher.
DR. WALLIS: Well, you have to do something. If you are
going to use numbers like E to the minus two, that something might be
draconian.
MR. STROSNIDER: I'm sorry. I didn't hear the last part of
what you said.
DR. WALLIS: If you take one times E to the minus two and
your CDF is E to the minus 2, then the action indicated may be far more severe
than you are actually proposing to take, if you are going to throw around
numbers like this.
MR. STROSNIDER: And I come back again to put this in the
context of decision making under uncertainty. How strong should my action be
to decide to understand the uncertainties associated with the potential for the
initiating event? If I understand the consequences, that helps to tell me what I
need to find out, and in this case we conclude we need to find that out.
DR. WALLIS: Your action has to be commensurate with the
risk and, if you -- What I would like to see is how small does IE(f) have to be in
order for the kind of actions that you propose to take to be commensurate with
this risk.
MR. REINHART: I think you are raising good points. I think
when I said this is a developing risk perspective, we are trying to put together
what we can to just get ourselves a feel of where we are.
I think what Jack is saying is the bottom line of this slide. We
know we need management attention. We have management attention. We
have ongoing interest in the risk arena. We are trying to get information from
industry.
We appreciate your comments, and we'll definitely feed those
in there as we go through the next iteration of the --
DR. WALLIS: Yes, but you see, my concern is your attention
-- the degree of your attention must depend on your assessment of what IE(f)
is, and saying it could be one doesn't tell us anything.
MR. REINHART: Well, since we don't know -- See, we don't
know what it is, and we're not saying that it is. We are saying --
DR. WALLIS: But that tells us nothing. If you are assuming
it is one, then your attention may not be adequate.
MR. REINHART: What would you propose we say it is then?
Maybe I'm misunderstanding.
DR. WALLIS: Well, if you are going to assume it's one and
there's a core damage probability of E to the minus 2 for all these plants, that's
not acceptable, is it?
MR. REINHART: We are not saying that that's the case. We
are doing like a desktop scenario to try to get us --
DR. BONACA: I thought that those graphs were probably
characterized as the probability of a small break LOCA will be still on the order
of 10 to the minus 3. I mean, that's what we heard.
CHAIRMAN FORD: As I understand where you are right now
is you are just trying to paint a worse case scenario, but you would answer the
question do we shut all reactors down now. The answer is no.
MR. REINHART: Right.
DR. WALLIS: Why is it no?
MR. MARSH: Because the number is not one. It's 10 to the
minus 3.
DR. WALLIS: That's silly. That's silly. If it is one, we shut
them down, but it's not one. so we don't. That just tells you nothing.
MR. STROSNIDER: Let me try one last question here, and
then I'll give up on it. But if the conditional core damage probability were 10 to
the minus 6 as opposed to 10 to the minus 3 to 10 to the minus 2, would you
have a different perspective on the discussion we are having today? That's the
point we are trying to make.
DR. BONACA: And the point I wanted to make is that that
may be actually one, if in fact this would result in rod ejection; and the strength
is more in the IE that we heard this morning, that the probability of a small break
LOCA resulting from these cracks in the nozzles was more on the order of 10
to the minus 3. That's what we heard, and if there is -- then still this is the order
of what you expect for a small break LOCA.
MR. ROSEN: Take it for what it's worth, Jack. My original
comment was that that's misleading, and I think this discussion -- and confusing
-- This discussion makes that point.
DR. WALLIS: But I think that, logically, you should say, if you
have 10 to the minus 6, you don't do anything. If it's 10 to the minus 4, you're
satisfied. That means you have to take action to bring IE(f) down to 10 to the
minus two.
MR. SIEBER: That's right.
DR. WALLIS: And you have to show somehow that all these
things you are doing in this wordy way reaches that conclusion. I don't see any
connection between the actions you propose to take, which sound reasonable,
and the risk assessment.
DR. KRESS: I don't think it has to be 10 to the minus 2. Ten
to the minus 1 would probably do it. You're talking about a time frame involved
of a few years, and I personally believe there is significant evidence to pin down
an initiating frequency a little better, because we have this susceptibility
analysis.
I think that is a way to get to this initiating frequency, and I
think it only has to be about .1 and not 10 to the minus 2.
DR. WALLIS: Whatever it has to be, there has to be some
logical connection --
DR. KRESS: I agree with you on that. I think they have to pin
that down a little better, because the action that they take should be
commensurate with the risk. That's the only way you can figure out what the
risk is. You have to pin that number down to some extent.
CHAIRMAN FORD: As an uninformed risk analysis guy, I
don't understand it. It's very helpful to me to -- You have used this worst case
scenario, and you're telling us, okay, guys, we are concerned. We are not so
concerned we're going to shut the whole fleet down tomorrow, and it's not such
a minor problem that we can walk away from it.
Now you are going through on your final -- you are going to
go through and refine it.
DR. WALLIS: They have not given any evidence that there's
no reason for concern. If you put down here if it's one and you get CDF -- What
are you saying then? There's nothing here that says it's less than E to the -2.
MR. MARSH: It is only going to get better. He's already
assuming the event.
MR. HACKETT: This is Ed Hackett. Let me try a slightly
different spin on this, because I think where Dr. Wallis is going is sort of what
process are we following to get there for this initiating event frequency.
In that regard, I think there are several encouraging things.
I'll, hopefully, discuss a few of them in my presentation, but Larry presented
earlier the elements of a probabilistic fracture mechanics assessment. I think
that is what needs to be done here.
I think part of the problem and part of the problem with us
answering Dr. Wallis' question here and struggling, obviously, is that we haven't
done that. We are trying to, you know, sort of marshall the resources and get
the process together to do that, but that's what needs to be done.
CHAIRMAN FORD: In fact, if you are going to cover part of
that, may I suggest just from the point of view of timing, please go straight into
your presentation, Ed, where hopefully you will cover some of these aspects.
MR. HACKETT: Sure.
CHAIRMAN FORD: Now I've managed to wrangle out
another quarter of an hour from --
DR. BONACA: I want to say that the CCDP here in this
context is still wrong. What I'm saying is that all you did, you took the IPEs and
you look at the medium LOCA, and that's 10 to the minus 2, 10 to the minus 3,
ignoring the potential consequences to core damage of the rod ejection.
DR. KRESS: Yes, you better take that seriously. You need
to make the calculation and see what it is.
DR. BONACA: That's a true error to take the IPE medium
LOCA, because here you don't have a medium LOCA. You have a rod ejection
coming through. Okay? It may have no consequence. I haven't done the
calculations. All I know, because I used to make some of these calculations
myself, is that you may have some -- So just looking at the LOCA, conditional
core damage is not enough.
MR. REINHART: We appreciate that comment.
MR. SIEBER: On the other hand, during the start-up of a
PWR, the way you start it up, the chance of getting a big reactivity excursion in
the source or intermediate range is relatively small, because you are so heavily
borated, and you pull your rods out first to generally the bottom of the bite, and
then --
DR. KRESS: Yes, but here you just got the opposite.
DR. BONACA: This break has been around here for a year
and a half.
DR. KRESS: The boron is depleted down to a fairly low level.
DR. BONACA: I am making the point that don't ignore it. Just
you have to look at it, this number here.
DR. KRESS: I think you can -- You don't want to have this
event happen, even though it's probably not a catastrophic event from the
standpoint of a LERF or damage to the public. I think it's within your design
basis accent. You're not even going to exceed 10 CFR 100. But if this thing
happened, you would have a real problem. I don't think anybody wants this to
happen.
So I think you need to take Mario's comments seriously and
see what sort of -- You're not going to get extensive core damage, but you will
get enough that you wouldn't want this to happen. So you better look at the
neutronics and make a calculation to see what that does to you, that rod
ejection, because I think he's absolutely right.
MR. REINHART: We have definitely written that down, and
we will do that.
MR. HACKETT: I'll take off with what Office of Research was
asked to do. I'm Ed Hackett. I'm Assistant Chief of the Materials Branch in the
Office of Research.
(Slide change)
MR. HACKETT: This slide shows an overview of what NRR
requested us to do and sort of some ongoing activities that we have.
We did form an independent group of experts, all of whom are
here with one exception today. I'll talk about some preliminary conclusions and
recommendations that came out of their work and some kind of integration of
their work with what the staff has bee doing.
In addition, we have ongoing support to NRR that's --
Hopefully, I guess in the best of senses, it's transparent, but we have ongoing
support to NRR that is in the areas that are specified here: EAC, non-
destructive evaluation, structural integrity and fracture mechanics, and also
PRA.
If the past is any indication, we are also planning on having
our support principally in terms of our staff and contractors who are associated
with non-destructive inspection technology being able to support inspection
oversight activities for the upcoming outages.
(Slide change)
MR. HACKETT: The next slide -- I should point out, too, to try
and stay consistent with Dr. Ford's request, I think there's a lot of this I can go
over very quickly.
DR. WALLIS: It seems to me I looked at this. You ought to
have someone who is going to tell you what the clues are likely to be, what kind
of mass transfer and chemical events are likely to occur in these cracks and in
these spaces. I don't see that expertise listed here.
MR. HACKETT: That is a good point, Dr. Wallis. Those are
pieces that I think for the long term aspect of this problem need to be
addressed. This group was put together largely to address some of the shorter
term aspects, but I think we are going to get off into areas as you suggest as we
go on. So we will hit those areas.
The folks who are on the independent group of experts, as I
said, are all here right over at the table there to my right: Dr. Bill Shack, your
colleague, from the Argonne National Lab on EAC; Dr. Steve Doctor from
Pacific Northwest National Lab for NDE.
Gery Wilkowski and Richard Bass actually have collaborated
a fair bit between leakage integrity and structural integrity. They are both here
also.
The only non-PhD on the group, Mr. Mark Cunningham,
couldn't be with us this afternoon, but basically I think Mark Reinhart has
summarized what Mark would have said, had he been here.
(Slide change)
MR. HACKETT: The next slide shows what we asked the
group to do. As Dr. Wallis was pointing out, there's really a short term and a
long term aspect to this issue. We really at this point have been focused on the
shorter term issue in terms of supporting NRR for the issuance of the generic
communication, and also a little bit further afield for the guidance for the
inspection activities for the fall outages.
Jack mentioned in his opening remarks, and I would like to
echo that, that we are very satisfied with what we ar able to do, what the group
is able to do in a very short time, and it's only about two weeks that they were
able to pull together a fair amount of information that we are actually still in the
process of digesting, and they are here to support us at this meeting today.
With that, I propose skipping over my slide five. I think we
have pretty much beaten up the susceptibility evaluation, unless anyone has --
I don't think we have much to offer there at this point except to concur with a lot
of what's been said.
DR. WALLIS: Well, what did the group of experts say about
the industry model? Did they accept that? Did they not accept it?
(Slide change)
MR. HACKETT: The bottom line -- I'll just skip to that -- is the
last bullet on the slide here. I think what it represents is the best shot you are
going to get at this for right now.
DR. WALLIS: Is it good enough?
MR. HACKETT: I guess it remains to be seen. We are
accepting it for now as sort of the best we got and, as Allen characterized in his
presentation in trying to move on in terms of prioritization from there.
So, hopefully, the answer is yes, that it was good enough for
that purpose, but I think only time is going to tell for sure.
(Slide change)
MR. HACKETT: In the area of EAC, we could spend a little
bit more time at least. This is an area that, I think, a lot of the discussion here
is focused on. It was a key driver or probably the key driver for this issue.
I think our consideration and speaking for the experts also is
that the annulus region between the head and the VHP will be a site for
concentration of aggressive chemical species. I don't think there is any doubt
about that.
Also the initiation frequency and crack growth rates for the
situation, as has been pointed out, are not known. We have not modeled that.
That would be a very difficult thing to model. I think several of the ACRS
members here have indicated what is really needed here is data.
I think this would be one of those cases where a couple of
data points would be worth a thousand expert opinions, but we are not going to
have that near term. Hopefully, that is something we are going to be working
toward.
I think we consider that initiation at multiple sites around the
circumference is likely, once you get this kind of phenomenon occurring. That,
obviously, complicates the situation immensely. When you look at the
implications of that on an effective crack growth rate, it could make the crack
growth a lot faster.
DR. WALLIS: You mean, the thing looks like a sieve.
MR. HACKETT: The potential for at least multiple initiations,
hopefully, wouldn't be quite a sieve, but I think the situation could be that it is
cracked at a number of locations around the circumference.
I think the crack growth -- I'll elaborate on the last bullet, too.
The crack growth rates in excess of one inch per year are certainly possible.
Dr. Shack in his examination went a little bit further than that, and I'll just
elaborate on that briefly.
He examined some literature data that was specific to vessel
head penetration materials. Albeit it is a limited dataset, but in looking at that
and attempting to bound the crack growth rates in that data, what Bill found is
an indication of a crack growth rate on the order of 30 millimeters per year. It's
a little bit over an inch per year.
In contrast with, I think, the industry's submittal or response
to NRR's recent set of questions was indicating more about half that growth
rate, maybe about 15 millimeters per year. I think Bill in his analysis indicated
that that would represent more of a 30 percentile type number, if that sounds
right, Bill.
DR. KRESS: But you would still have three more years
before Oconee has a ligament problem?
MR. HACKETT: Well, the complicating feature there is the
fact that these also only address PWSCC conditions, existing data. There has
been an awful lot of speculation and discussion here about what this
concentration of the chemical species in the crevice would do.
I think everyone would probably consider it would make the
situation worse. So the $64 question is how much worse. We don't know the
answer to that right now.
MR. HISER: Actually, it would be half that, because you have
two tips growing. So it is effectively the equivalent of two inches.
DR. WALLIS: There is no two-tip, because you have multiple
sites.
MR. HACKETT: It could be more. It could even be more than
two.
DR. SHACK: Now again when I did that, I came up with --
Even for the PWSCC, there's a distribution of crack growth rates. It depends
on the heats of material. It sort of looks log normal. You know, we said it was
log normal. It even looks log normal.
The one inch per year is kind of like the 98 percentile, and go
to what industry's model is. It was -- a log normal distribution, something like
a 33 percentile. So there is a distribution of rates, but the one inch per year is --
I consider 98 percentile an upper bound.
CHAIRMAN FORD: Well, now you've got the interesting
situation. It's exactly analogous to data that was available for low alloy steel
pressure vessels. You've got an enormous crack propagation rate, which you
can't live with.
So how do you regulate that? How would you regulate that,
which is the situation?
MR. HACKETT: That is what -- Maybe if we could hold that
to the end, I'll try and come to that. I think at least it's unfortunate I have to go
this far to make that kind of case, but one of the things that would argue for the
fact that they are not fast is we haven't seen anything.
We haven't seen penetration accidents, you know, worldwide
at this point. So they are probably not that fast, but we don't have the data to
show it at this point.
One other point I wanted to make in this area is another point
that Dr. Shack brought out in his analysis. We didn't discuss this much earlier
today, but a limiting step as regards the environment here is likely to be the
initiation in through-wall growth or through-weld growth on the J-groove weld.
One of the things you could look at, and I think Dr. Wallis was
going to this earlier, was the situation with the welds are likely to be more
variable for all the usual reasons that metallurgists would offer, and the bottom
line is -- So you are likely to see a lot of variability and
shouldn't be surprised in that, you know, one happened at Oconee in one
location and didn't happen in other places. But then you get the propagation --
or you get the initiation and propagation to that J-groove weld. Now you have
a much more uniform population of vessel head penetration housings.
Then you are probably going to start to see a fairly aggressive
attack fairly fast after that. So I'll come back to this in the examination aspect,
but I think what it points to is that's a limiting step, and that maybe needs to be
a bit of a focus for some of the non-destructive examinations.
I would also propose in the interest of time skipping the next
slide, because I think we covered the boric acid deposit annulus leakage issue.
DR. WALLIS: There was a question about what you learn
when you see boric acid deposit in terms of what is happening inside and how
sure you can be about what is happening inside from the amount of boric acid
you see on the outside. That connection needs to be made.
MR. HACKETT: I would agree, and it has not been drawn
conclusively. I think I would tend to concur with a lot of what I heard here this
morning, in that from what we have seen and what the experts have said, what
is going to happen is you are going from a very tight PWSCC crack in a J-
groove weld into this relative -- I think Bill referred to a relative chasm of an
annulus, and you are going to flash right there.
There's a huge delta P across there, and you are going to
start the concentration at that point. So from the standpoint of what that means
to the EAC part of it, it is obvious that you are concentrating a species.
What it is going to do with regard to the accumulation of boric
acid crystals and what makes it way out, I think, is a much more complicated
issue. I think it is obviously highly uncertain as to exactly what is going to come
out of there at this point.
So maybe I'll just summarize by saying that without going
through the slide.
(Slide change)
MR. HACKETT: Another important aspect that we will be
coming up on, once we get through the near term focus on the issuance of the
generic communication is the issue with the inspections, and that's been very
thoroughly covered today, too.
Just to reiterate some of it, I think volumetric examinations are
indicated for plants with known cracking. Allen covered that. It depends on how
you take the meaning of preferred, but I think it would be the preferred
inspection method for high susceptibility plants in general, but that remains to
be seen, what's going to be done.
The vendors: It is known, obviously, that there are current
equipment capabilities, but as Larry pointed out, not currently qualified
inspection methods for the OD phenomenon.
I think it's fair to say the inspections can be effective, if
adequate pre-qualifications can be performed. But then you are going to be
down to the issue of the limitations on the number of methods, likely to be UT
methods, and teams that could be field for these fall outages.
I think industry has talked about estimates on the order of four
or five teams that might be able to be fielded potentially, or maybe it's not even
that high. That is, obviously, something that needs to be looked at hard.
The other point I would add to this that I didn't get on the slide
is back to this inspection of the J-groove welds. I think a combination of Bill's
write-up along with Steve Doctor's would be indicating that that could be a very
pacing item here.
If you are going in looking in the fall outages with the method
that you are going to be looking under the head -- and let's just take the
scenario where you find a crack in a J-groove weld, but you don't seem to find
cracks in the housing. I still think that is going to be a situation where people
aren't going to rest real easy.
Once you are cracking through that J-groove weld, I think you
are going to start to have some problems pretty quick. So looking at the J-
groove welds then, you have to talk about -- There was some discussion earlier.
That's obviously a very difficult inspection.
Penetrant exams are a possibility but, you know, you have
dose considerations unless you can do that in an automated sense. Probably
more likely are eddy current or UT, if that kind of tooling can be developed.
At any rate, I think there is a recommendation there that that
would probably be a good thing to focus on.
(Slide change)
MR. HACKETT: We were also asked, and the group was
asked to comment on online monitoring for leakage or cracking. This is an
interesting area, because the bottom line is it is technically feasible. It has been
demonstrated, especially abroad. There is an online leakage monitoring system
that EDF is employing at right now, I believe, about 25 of the French plants that
uses N-13 monitoring. It is supposedly effective down to one liter per hour type
of leak rates.
Acoustic emission monitoring has been demonstrated in this
country in nuclear plant applications for identifying cracking in plants.
DR. WALLIS: This is a whistling?
MR. HACKETT: Basically, you are looking -- It's an acoustic
signal that you would get from the crack propagation or initiation.
DR. WALLIS: It's from the crack? It's not from the steam
squirting through?
MR. SIEBER: It's the fluid. You can't hear the crack.
DR. WALLIS; It's the steam squirting through.
MR. SIEBER: All these are very gross kinds of things. If you
are talking about a gallon per year or a gallon per month, acoustics isn't going
to find it. N-13 will not find it or N-16. You can't find it by radiation, because if
you are sitting right on the reactor head, it's pretty hot there.
MR. HACKETT: Dr. Sieber goes exactly to one of the
conclusions that the industry reached in their response to the NRC, is that a lot
of these would have some real problems in the --
MR. SIEBER: I can't see how you would do it.
MR. HACKETT: In addition to that, even if they are feasible,
the last bullet, I think, applies. It's probably not going to be anything that is
going to be impacting U.S. plants in the near term. It would require a longer
term development effort.
Obviously, EDF and the French regulator concurred that they
thought it was a workable situation for their plants. I think it would remain to be
seen, and it would be the industry's decision whether to employ that sort of
thing.
(Slide change)
MR. HACKETT: Cutting to structural margin and trying to get
to this conclusion we have been talking about, a couple of things. The expert
group, in addition to some of the staff, have basically verified the structural
margin calculations by the industry, and that is to say Inconel 600 is a very flaw
tolerant material, especially in the forged version.
It can tolerate very large through-wall circumferential cracks
while still maintaining the structural margins. As pointed out earlier, the margin
calculations don't really consider the crack growth or the time effect.
I think what, obviously, this is all crying out for in trying to
integrate the conversation that was occurring previously is what is lacking from
our side and the industry's side, I think, in a lot of cases, for lack of some
appropriate data, is an integrated assessment of the structural integrity that
would address the EAC.
Really, a lot of it is the linkage between the environmentally
assisted cracking and the residual stress state that exists around the
circumference of the penetrations, and also the inspections, what you can and
can't do in terms of the future outages.
I think my own assessment of this, and I was glad to see that
in the industry's response, is this really needs to be done in a probabilistic
sense. I think the code they would likely use for this, also that the NRC has
employed before, is PC PRAISE.
We employ a very similar methodology for accepting different
phenomenon, and we've talked to the Committee before about pressurized
thermal shock, and there we employ a probabilistic fracture mechanics
assessment that uses the code FAVOR, which was developed at the Oak Ridge
Laboratory.
That is really what needs to be done here, because you are
dealing with an overwhelming number of variables to be assessed here. It has
to be fundamentally done in a probabilistic sense that would, hopefully, get you
at an initiating event frequency within some reasonable margin of uncertainty.
That's where we are not right now.
I think, obviously, as Jack was indicating, the expectation on
the part of the staff is that this thing is obviously not an event frequency of one.
It is, hopefully, significantly less.
I think what we can't do is say we think it is this number as a
median number with about this uncertainty band. So that is, hopefully, what we
are driving toward.
DR. WALLIS; How do you get probabilistic information for this
of aggressive chemical attack when you don't have any data?
MR. HACKETT: That is a real good question. I think, as you
mentioned earlier, there are some assumptions you could make. I know some
industry experts might be able to comment on this even more eloquently, but
they employed a code previously in some evaluations for BWRs called VIPER,
which did get into probabilistic aspects of the chemical species for BWRs.
So it can be done. Some assumptions have to be made. It's
nicer still if you have the data. I think in the near term, we are obviously not
going to have that data. So that will be one area where we will have to make
some assumptions and then try and integrate this whole thing.
I guess that's what I would say in that regard.
(Slide change)
MR. HACKETT: Then in, I guess, sort of the summary -- and
I guess I said a lot of this already. So what are we doing?
We are developing -- trying to develop this integrated
perspective and, as Jack mentioned, a lot of this will rely on ongoing dialogue
with the industry and consideration of the expert group reports and other
analyses.
We are going to put this integrated -- the short term version,
at any rate, the integrated perspective would be documented in a memorandum
that we would be proposing right now would go from Jack Strosnider and Mike
Mayfield, the two respective division directors in Offices of NRR and Research,
to their office directors.
We will, hopefully -- I think more than hopefully. We'd better
have it done this month. I don't think we really have anymore time than that.
That will be made public once we get that through concurrence.
What I would add, too, is that perspectives and
recommendations from what I've been talking about here have been factored
in, in an online sense, into what's gone into the generic communication.
The last bullet then: It is not anticipated that any further
technical evaluation in the near term here would have a significant impact on
the communication, but would, obviously, I think, in this case influence
development of longer term programs for dealing with the issue.
I think Ill just conclude with that and see if there are any
questions. If not, I'll turn it over to Tad.
DR. WALLIS: You talked about an integrated assessment of
everything, the chemistry and the flow and everything. Will we ever see some
kind of presentation on this, so that people understand it?
MR. HACKETT: I would hope so. I guess the timing is what
is going to be key. I know Larry had indicated in his presentation that they were
driving toward having a lot of this work done by, I think he said, end of the
calendar year.
So somewhere -- It won't be within the next couple of months,
I think, but maybe we would be looking at coming back before the Committee
early 2002 calendar year to be able to try and look back at this and here's the
kind of integrated perspective we can bring to the thing, like we, hopefully, are
able to do now with pressurized thermal shock, but hopefully, it won't take us as
long, because PTS has been a long time in the coming. We will try and do it
quicker this time.
CHAIRMAN FORD: Any other comments? Okay. Thanks,
Ed. Thank you very much.
MR. MARSH: Mr. Chairman, I had a brilliant and highly
informative presentation to make.
CHAIRMAN FORD: We have been allowed to go on until
quarter to three, but I do want to spend a quarter of an hour in general
discussion and getting some advice.
MR. MARSH: Okay. Well, let me proceed. My name is Tad
Marsh, and I'm Chief of the --
CHAIRMAN FORD: If you could just try --
MR. MARSH: Five, ten minutes? Fine.
I'm Chief of the Operational Experience and Non-Power
Reactors Branch, and I have the programmatic responsibility for generic
communications.
(Slide change)
MR. MARSH: This part of the presentation today was meant
to step back from the technical and talk about the process: Where are we in
terms of generic communications?
I'm going to breeze through some of these slides pretty
quickly. What I would like you to get from the first slide is that the agency made
some substantive changes in the generic communication process in 1999, and
there is a SECY paper, 99-143, which describes them.
Among the things that we did, we added more rigor into our
process. We added some more vehicles, a regulatory issues summary, and we
added some other features which I will ask you to go take a look at that SECY
paper, if you would like.
(Slide change)
MR. MARSH: The next couple of slides talk about the
vehicles themselves, bulletins and generic letters specifically, because those
are the regulatory vehicles that require information back.
(Slide change)
MR. MARSH: As a process matter, generic communications
cannot require anything beyond responding. They cannot require a plant
change. They can't require a plant shutdown. They can only require
information back. They can request actions. They can request information, but
they can only require responses back.
(Slide change)
MR. MARSH: If we were in the mode of requiring actions, we
would be in the mode of a rule or an order, and we are not in that space. We
are in the generic communication space. But it is important to note that, in
terms of generic communications, this is the highest vehicle that we've got. A
bulletin is the document that conveys the most significance. So from a
perspective of significance, that is where we are.
(Slide change)
MR. MARSH: I'd like you to understand a little more about the
differences between a generic letter and a bulletin, because the staff at one
point was considering a generic letter. Since we were seeking information,
another vehicle is to use a generic letter as opposed to a bulletin.
Setting aside that the bulletin conveys more safety
significance and more importance, which is the first major difference between
the two, generic letters also take much more time.
This is a much more public part of the process. We put it out
for public comment. We get comments back. We convey those comments up
to the Commission. It's a much more protracted environment.
As a benchmark, bulletins should take on the order of eight
to ten weeks, being as expedient as you can. There are ways to make that
even shorter, but in order to go through all the hoops that you need to do, about
eight to ten weeks for a bulletin.
A generic letter, on the other hand, can take five to six months
and more, depending upon what happens, depending upon the comments that
you get, depending upon the interactions with the Commission, etcetera.
So you can see an order of magnitude difference in terms of
the documents and how long they take.
Another key ingredient in this process is that in a generic letter
our procedure says the first thing you do after you get permission to proceed
pursuing a safety matter is interact with the industry.
Whatever venue that may take, whatever organization is that's
responsible for this issue, you interact with them, the thrust being let's try to get
a cooperative arrangement to solve the technical problem without relying on a
generic communication or some sort. That's the first step, and that has taken
place here.
In fact, the staff has been working for roughly six months with
the MRP on this issue, thinking that we would reach a resolution pathway. At
some point, we diverted. We decided that we needed to take a regulatory
action beyond relying on the industry for information.
That occurred probably two months ago when we had several
REIs. The questions and commitments and things were not reaching to a timely
resolution. We went to a different track, a regulatory track, and the track
demanded more action on our part. So that's the pathway that we are on.
(Slide change)
MR. MARSH: There is a diagram in the back which comes
from the SECY paper which has that process, that generic communication
process, working with the industry, etcetera. What it lacks in that diagram is
feedback loops, because we did go from a generic letter route to a bulletin
route.
Any questions before I launch on to what we have been
doing? Okay.
(Slide change)
MR. MARSH: I am going to skip the next slide 5, which talks
about requests for action, requests for information. If we had more time, I would
like you to understand how we get to the various documents themselves.
I do want to talk about milestones, because the staff has been
working aggressively with the industry in trying to come to resolution on these
issues.
You've heard a lot of this, but this is, more or less, the
sequence of steps that have been taken, interactions that have taken place.
Key, I think, is many, many meetings, many public meetings with the MRP, and
we are sensitive to that, because we have jumped over into a bulletin space,
which is not as public a process as a generic letter. But we have had many
public interactions, and I think those have worked.
We issued an information notice, which is another one of our
regulatory vehicles, in April this year, and we conveyed results of the Oconee
Unit 3 results. We have had various REIs back and forth on trying to seek more
information.
(Slide change)
MR. MARSH: On Slide 7 I would like you to see that we
briefed the Commissioner of Technical Assistance two times. That is important,
because we wanted to keep the Commission informed.
We indicated publicly in early June that we were headed
toward a generic communication. In other words, we needed to take a more
aggressive regulatory approach. We did that through a communication with NEI
and through a public meeting and through meeting announcements. That
occurred prior to the June 7th meeting.
That June 7th meeting, which was an important meeting,
conveyed to the industry that we were concerned enough that we were headed
for some type of communication. We were unsure what type at that point.
Then June 11: Ed has talked about the experts that have
been convened through Research which were helping NRR in this regard. We
have briefed CRGR once, July 2nd. That was a pre-brief. It is unsure whether
we are going to have the formal brief, because they may be satisfied with the
mark-up of the document coming from this discussion and coming from our own
management discussions. So we believe we are in good shape with respect to
the CRGR.
We also had a public meeting in July.
(Slide change)
MR. MARSH: Next and last slide talks about the steps that
are in front of us. Today ACRS Subcommittee and tomorrow's full Committee
meeting are key. As I say, we may have a CRGR meeting, a follow-on meeting,
if they so choose.
We do seek a letter from you with any comments or
suggestions that you may have, and we need CRGR endorsement. That is a
requirement for a bulletin.
I should say you can not have CRGR endorsement, but it
needs to be particularly urgent, and they ask that you come back to them
following the issuance of a generic letter or a bulletin, if that's the route. In this
case, we seek them in advance, and we have been keeping them informed.
We will be issuing a Commission information paper, and there
is normally a ten-day time period where we wait for any comments they may
have, and we will be issuing the bulletin, hopefully, by August 1st, which if you
look at the agency's generic communication record lately, the last couple, three
years, this is the first bulletin that we have issued since '97.
There's lots of reasons why that generic communications
have dwindled in numbers, part of which we think the process has improved.
But in terms of a time frame, I think eight weeks to ten weeks is the right time
frame for something of this significance, and it speaks well, I think, for how
we've been doing for addressing the issue.
That concludes my comments.
CHAIRMAN FORD: Tad, thank you very much indeed. I'd
like to open up the meeting now for some general comments. Steve, you said
you had some questions and comments.
MR. ROSEN: I have one. After listening to all this, it occurs
to me that the aging management implications for plants that have applied for
or indicated that they will apply for license renewal are important. What are
your thoughts in that area?
MR. STROSNIDER: This is Jack Strosnider. I believe the
Committee actually -- on one of the last licenses that was issued actually
addressed this issue in their letter. If I can characterize the bottom line, it was
this issue is going to have to be dealt with during the current licensing period,
and whatever comes out of it that people would have to follow.
When you look at the time frame for when the renewed
licenses actually go into effect, we expect that this issue has -- It has to be dealt
with before that, and that was -- I want to be careful, because I don't want to put
words in the mouth of the Committee, but that was my recollection of the
message.
DR. BONACA: Our thought was there is no plan in place that
we can put -- that will predict what may happen to some component, you know,
40 years of life. All we can expect, however, is that programs are in place that
would provide inspections timely and be insightful enough to identify the
gradient degradation mechanism and provide corrective actions.
MR. STROSNIDER: Let me add one thing to what I said
earlier. You know, what we are talking about today with regard to this bulletin
is really a one-time sort of a snapshot in time: Let's deal with the short term.
There is a recognition by the staff and by the industry that
there needs to be a long term program put in place. In fact, the ASME code
already has a group off looking at this, and we'll be pushing for some longer
term augmented program that will address this. But when I say longer term, it's
not that long. It's not all through license renewal period. It's much sooner than
that.
CHAIRMAN FORD: Any other questions?
MR. SIEBER: General comment?
CHAIRMAN FORD: General comments, yes.
MR. SIEBER: I can offer a few things. First of all, I think that
using the bulletin format was the way to go for this issue. So the choice is right,
probably the simplest one, considering the fact that I think the issue is relatively
urgent.
I concur with Dr. Wallis that there seems to be a lot of
uncertainty in the machinations that were gone through to determine
susceptibility ranking and phenomenologically describe actually what is going
on.
So when I look at the data in view of my not very good feeling
about the certainty of the rankings, I wonder why one would pick four years as
a cutoff point for that second group of reactors rather than ten years. Seems
to be a sort of a logical break point at ten years. That would pull in double the
amount of plants in that period of time. So perhaps there is an answer to that.
I think another question that comes up is the idea of collateral
damage, if you would get a circumferential crack. It seems to me that since the
CRDM housing is unsupported at one end, that crack when it got to 280-290
degrees, the remaining ligament would act like a hinge, and rather than just
blow off, it would probably take the direction that the hinge would allow it to take.
The only restraining thing would be the drive shaft that remains inside the tube.
So I think that's an issue that needs to be looked at as to
whether that is likely and, if it is, would the adjacent rods have dropped prior to
damage to any other housing. I sort of doubt that it would fracture another
housing, but I'm not sure that it wouldn't bend on it.
So I think that that, to me, is a concern, and it's because of the
geometry and the fact that it's not supported at one end. I've seen some
circumferential cracks that finally broke in pipes that gave that hinge effect. It
just sort of goes off to the side. So I think that that's an issue.
I would feel much more comfortable if a lot of these
uncertainties and analyses that haven't been done were completed so that,
even though the bulletin would go out, I think that we would profit from having
more knowledge about probabilistic fracture mechanics and this geometry and
what the spread of the data is and just exactly how well, with how much
certainty, are all these factors established.
I think that that's a pretty good concern of mine. But
otherwise, I think that, in light of what we know and what the industry has seen
and reported, I think that the issuance of the bulletin is a good idea, and you've
got to try to keep to your schedule.
One other comment. I'm familiar with weld repairs under
Section 11. I wonder that, if you had a through-wall crack in a J-weld and you
repair it by grinding it out and then doing -- you know, basically welding it back
shut -- what do you do with all the boron crystals that are in this interference fit
above it, and how does that affect the remaining life of whatever is in that nozzle
area? Does that make the nozzle much more susceptible? Is there a way to
clean it out, because you know it's going to be there?
DR. KRESS: Steam it.
MR. SIEBER: Well, you may get more steam than you want
there, if you know what I mean. Anyway, that's a concern that I would have with
weld repair under the code where you are, in effect, putting a canopy weld on
with a long manufacturing crack right above it. So I don't know. Maybe
somebody could answer that for me now or later.
Those would be my concerns.
CHAIRMAN FORD: Graham?
MR. LEITCH: I guess the acceptability f this whole approach,
to me, seems to lie best on three principal legs. One is that the time-
temperature relationship will identify susceptible plants, and I think, in spite of
the uncertainties in that information, I think the fact that the plants -- that it would
have identified the plants that actually have the cracks gives me some
confidence there, although I don't know complete confidence. It does seem to
be kind of the best that we could do at the moment, based on the data that is at
hand.
The other major thing in my mind is that the boron crystals will
be a telltale sign that we have a crack below that, as a visual examination
looking for boron will tell us what we need to know.
I guess there I have a fair amount of confidence that even
small leaks will, even through this interference fit, likely yield boron crystals that
will be amenable to visual observation.
The third leg of the stool in my mind is that we understand
crack growth rate. I guess there my confidence is least among these three
areas. I just don't have a good feel that we really understand how fast these
cracks can go.
I have had some experience that seems to suggest that the
growth rate may not be linear. That is that the cracks may suddenly grow and
then stop and then grow again and then stop, that there is some nonlinearity to
this growth, particularly in an environment where we don't quite understand
exactly what the environment is in this tight annulus or in these cracks.
So I guess, to sum up my comments, I would just say that I
am most concerned about our understanding of crack growth rate and what that
suggests for the frequency of inspections and future plans. But I think you are
on the right path to accumulate that information and get as much data as we
can and see where we go from there.
DR. KRESS: My view is very much like what Graham Leitch
just expressed. I really think we can buy off on the susceptibility analysis, time
and temperature.
I think it should be -- Some attempt should be made to look
at the variability of the other variables in there, the materials and the stress and
so forth, to try to estimate the possible ranges of uncertainty in that. But I think
that will probably be an acceptable way to determine the susceptibility and,
therefore, to choose which plants to look at first.
I share Graham's view that the growth rate is of concern.
There, I think you need to maybe utilize the early inspections of the plants in
such a way that you can actually use it as data to determine that growth rate.
Several inspections of a -- You know, when you find a crack in one of the plants
like Oconee, do something about your inspection frequency to try to see if you
can extract the growth rate out of that.
I think it would be useful to do some of Graham Wallis'
analyses which are primarily thermal hydraulics to determine what the chemical
environment is in that annulus and in the crack itself as a way to understand the
growth rate or at least to have additional data at your fingertips.
So I would encourage you to try to do some. They are
relatively simple. You know, it's not a big effort to do that particular calculation.
So I think I would encourage that.
I think the inspection process could be thought of as a graded
thing. As you do these early ones and you don't find much, you may want to
relax how fast you do the others and which ones you draw in, but that's
something you can decide later on after you see what you get with the first ones
there.
I think you need to do some looking at validating the reactivity
insertion effects that Mario brought up. I'm pretty sure that design basis
reactivity insertion calculations that have usually been made in the first place
are probably okay, and they tell you you are not going to exceed 10 CFR 100,
and that should really be all NRC is concerned with. The utilities may be
worried about more than that.
What bothers me there is I'm not sure it is just one rod, and
I worried about the concept that Jack Sieber brought up about can we really be
sure it's just one rod, and do those design basis analyses use the right energy
level for the insertion? Do they rely on keeping below an energy level that you
don't disperse the fuel and, if so, has that properly factored in the burnup effect
that we have seen recently.
Maybe one needs to relook at that part of it when one looks
at the reactivity insertion rate. That's pretty much my comments.
CHAIRMAN FORD: Mario, do you have anything extra to
say? Oh, I'm sorry, Steve. I'm sorry, I thought you had finished.
MR. ROSEN; No, I had one more point I would like to make,
Peter.
My view is that regulatory compliance issues notwithstanding,
I think the staff needs to put a high priority on the risk estimate. What they
really need to do -- Tom was alluding to this -- is to track through with the best
estimate way you can what would really happen if we had a full circumferential
crack of one of these housings, so that we can really put this issue in context
for ourselves, the industry and the public.
DR. BONACA: I can only second what I heard before. I
agree with those points of view. Again, on the issue of rod ejection, I think,
Tom, you expressed the whole thought of collateral damage here and the point
that Jack took was very well described there. It is an issue that you have to look
at, and just to have an appreciation for the potential issue of it. What is the
whole separate issue?
The other issue that I think -- You know, in general when I
look at the program presented here by the industry and by the NRC, I feel
comfortable with that, with one exception. I mean, and I'm sure you share this,
the effectiveness of the visual inspection. So I raised that issue before.
You are going to go there and look at these plants. The
number of plants you are going to look at is a good number, is a solid number.
It's in excess of 20, but you know, the only question is what are we going to
learn from this?
You know, I didn't get out of this meeting with a warm feeling
that, you know, we will look and find. I think in some cases we won't. So we
are left still with that question of, you know, given the condition of the head and
the insulation and so on and so forth, we'll have to learn how comfortable we
can be.
DR. KRESS: I think we have to take comfort that Oconee
didn't break before they saw something. It leaked before a break.
DR. BONACA: I agree. I agree with that.
DR. KRESS: And I think that is the comfort level you have to
assume.
DR. BONACA: Yes. I'm only -- You know, we'll have to see
in the next few months what we learn about the inspections and the visual and
effectiveness of the visual inspections.
CHAIRMAN FORD: Bob?
DR. UHRIG: Well, I guess I have some concerns about the
time-temperature model. My concern here is the fact that the three Oconee
plants came out at the top of the list. Top priority may be fortuitous more than
related to the model itself.
It reminds me a little bit of my graduate school days when
they said you could fit any set of data with a straight line on log-log paper.
I am concerned here that this alignment of plants here -- and
a little bit was expressed over here. Why not go out ten years, not four years.
I think that whole group of high temperature plants, if you want to call them that,
particularly the older ones, are prime candidates for inspection at the first
opportunity.
Also one other last comment would be: There may be some
foreign technology out there available in terms of sensors and ways of
inspection that would be useful, and it ought to be looked at.
CHAIRMAN FORD: Thank you.
DR. WALLIS: Well, you have heard some of my concerns.
There are really two things. One is knowing where we are, and then the other
is knowing what to do.
In terms of knowing where we are, I feel that the risk analysis
didn't tell us anything, and we really need to have some estimate of this 1-EF,
even if it's difficult.
Of course, there are questions about the integration of the
flows, the chemistry, the leaks, the cracks and so on. There's been too much
emphasis on the crack. I think there's a whole lot of integrated phenomena
gong on here we've just begun to understand.
So knowing where we are is subject to a lot of uncertainties
there. Of course, other questions have been raised, and my colleagues have
raised them.
I guess what you are looking for is comments on whether the
action proposed is appropriate, whether the bulletin is the right approach,
whether what's in the bulletin is right. That would, I think, require a study that
I haven't yet made of what actually is in the bulletin, and somehow trying to link
that to what I think we know technically.
That's where personally I feel a little uncertain. I mean, I can
comment technically about flows and chemistry and stuff, but then the
regulatory environment for someone like me is always a somewhat arcane one,
and whether or not this is appropriate regulatory action is difficult for me to
assess. But I guess we have to do that, because that's the main question.
So I guess we will address that tomorrow unless we write a
letter. I've got to somehow make the link between these technical things and
what I think I know and think you don't know, and whether this is the appropriate
thing to do in the near term and in the longer term. That's where I think we have
some thinking to do.
CHAIRMAN FORD: I think, summarizing, as there are only
three minutes to go: I think my advice for tomorrow is, bearing in mind that what
we are going to try and convince the whole ACRS Committee, that what I think
you are hoping for is a supportive letter to say the bulletin is the way to go, and
I don't think there is going to be any argument that that is true.
There will be a whole lot of technical questions, and we will
be all brought up very, very similar technical questions, in the short time
available at the meeting tomorrow just to focus on those, and then heard about
the inspection and how good is the inspection. Is visual inspections worth it?
Obviously, it's one thing to do, but should we be putting efforts into other areas?
The question of crack growth rates: What the environment is,
things of this nature. And then there's the risk assessment that came up. Are
we absolutely sure that we should not be shutting the reactors down right now?
I don't think that is the case. That's a worst case scenario.
Is the time-temperature histograms that we've been using --
is that an adequate way to prioritize inspections? That's the thing that needs to
be addressed in a bit more detail, to the exclusion of some of the other things,
given the short time that we have.
DR. KRESS: And Dana is -- we are sure going to ask his
opinion.
CHAIRMAN FORD: About this question of the --
DR. KRESS: Maybe we want to be prepared to answer it.
CHAIRMAN FORD: There will be certainly a question from
Dana Powers on the whole question of the SCRAM and --
DR. KRESS: Reactivity and failure to SCRAM.
MR. HACKETT: Failure to SCRAM in the LOCA, right?
CHAIRMAN FORD: That question, for sure, will come up.
Are there any other last minute questions. Jack, do you have --
DR. WALLIS: I have another view, too. This is just today.
This is an ongoing drama, and I expect that we will learn a lot in the next few
months.
CHAIRMAN FORD: Oh, yes. You know, the thing that is
really going to encourage me is the interaction between you and Research.
They did not give me any forewarning as to the things they were going to talk
about, and I find it very encouraging that you got a real good group of experts
that are coming up with the answers.
I'm sorry. I'm talking to jack there. You have heard all the
questions, obviously. You can address this.
On that issue, Mag, how much time have they got? Do you
know? Tomorrow?
MS. WESTON: Each group will have 15 to 20 minutes only.
The other amount of time should be reserved for discussion and additional
questions that the Committee may have to wrap up the issue before they write
the letter.
CHAIRMAN FORD: Okay. Are there any last minute
comments, questions? Okay, thank you very much.
MR. HACKETT: Chairman Ford, if I could just a second --
Sorry about that.
There were just two I wanted to leave you guys with, because
I think two very important comments were made, and one part I forgot to
mention on the crack growth rates.
Several of you brought up crack growth rates. One of the
things that would happen here, depending on the cracking phenomenology, if
it goes through-wall preferentially going around the circumference, then you
tend to move yourself back to a PWSCC environment because of the reservoir
of the primary system.
Anyway, that's just something for folks to think about.
The last part was what Dr. Uhrig raised, and I could echo that.
The Europeans, we believe, are probably significantly ahead on this issue in
terms of inspection capabilities from some of what we have seen.
So there is some information to be gleaned out of that, too.
Sorry about that.
CHAIRMAN FORD: Thanks very much.
(Whereupon, the foregoing matter went off the record at 2:47
p.m.)
Page Last Reviewed/Updated Tuesday, August 16, 2016
Page Last Reviewed/Updated Tuesday, August 16, 2016