Materials and Metallurgy (CRDM) - April 9, 2002
Official Transcript of Proceedings
NUCLEAR REGULATORY COMMISSION
Title: Advisory Committee on Reactor Safeguards
Materials and Metallurgy and Plant Operations
Joint Subcommittees Meeting
Docket Number: (not applicable)
Location: Rockville, Maryland
Date: Tuesday, April 9, 2002
Work Order No.: NRC-321 Pages 1-219
NEAL R. GROSS AND CO., INC.
Court Reporters and Transcribers
1323 Rhode Island Avenue, N.W.
Washington, D.C. 20005
(202) 234-4433UNITED STATES OF AMERICA
NUCLEAR REGULATORY COMMISSION
+ + + + +
ADVISORY COMMITTEE ON REACTOR SAFEGUARDS
+ + + + +
JOINT SUBCOMMITTEES ON MATERIALS & METALLURGY
AND PLANT OPERATIONS
+ + + + +
Tuesday, April 9, 2002
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11545 White Flint North
The discussion on vessel head penetration
cracking and vessel head degradation commenced at 1:00
F. PETER FORD, Chairman
Materials & Metallurgy Subcommittee
JOHN D. SIEBER, Chairman
Plant Operations Subcommittee
MARIO V. BONACA, ACRS THOMAS S. KRESS, ACRS
GRAHAM M. LEITCH, ACRS STEPHEN L. ROSEN, ACRS
WILLIAM J. SHACK, ACRS
MAGGALEAN W. WESTON, Senior Staff Engineer
I. Introductory remarks - F.P. Ford, ACRS 4
II. Bulletin 2001-01 Status and Action Plan
Beth Wetzel, NRR 5
III. Bulletin 2001-01 Technical Issues
Allen Hiser, NRR 12
IV. Industry Perspective on Bulletin 2001-01
Larry Mathews, MRP 41
V. Davis-Besse RPV Degradation NRC Introduction
Jack Grobe, RIII 71
Mel Holmberg, RIII 73
James Davis, RES 109
Industry Introduction and Background
John Wood, FENOC 118
Discovery and Characterization of the
RPV Head Degradation
Mark McLaughlin, FENOC 129
Evaluation of Degradation
Steve Loehlein, FENOC 166
Bulletin 2002-01 - Ken Karwoski, NRR 189
Larry Mathews, MRP 194
Alex Marion, NEI 203
VI. Final Comments 208
VII. Adjournment 219
MR. FORD: This meeting will now come to
order. This is a meeting of the ACRS joint
Subcommittees on Materials and Metallurgy and Plant
Operations. I am Peter Ford, Chairman of the
Materials and Metallurgy Subcommittee. My Co-Chair is
Jack Sieber, Chairman of the Plant Operations
ACRS members in attendance are Mario
Bonaca, Thomas Kress, Graham Leitch, Steve Rosen, and
Bill Shack. We also have Region III on
videoconferencing. Can you hear us in Region III?
VOICE: This is Region III. We can hear
MR. FORD: Great. The purpose of this
meeting is to discuss the vessel head penetration
cracking and vessel head degradation issues. We have
had a number of subcommittee meetings on the former
issue, and this meeting will also include the head
degradation issue observed at Davis-Besse.
Ms. Maggalean W. Weston is our 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
March 22, 2002.
A transcript of the meeting is being kept
and will be made available as stated in the Federal
It is requested that speakers use one of
the microphones available, identify themselves, and
speak with sufficient clarity and volume so they can
be readily heard.
We have no written comments from members
of the public regarding today's meeting.
For the first hour we will be talking
primarily about the cracking issues and Bulletin 2001-
01. For the rest of the afternoon we will be talking
about Davis-Besse degradation issues and Bulletin
2002-01. We have a very full agenda and ask everybody
to keep to the agenda, as written.
Jack, do you have any comments to add?
MR. SIEBER: Not at this time. Thank you.
MR. FORD: We will now proceed with the
meeting, and I will begin with Ms. Wetzel to start for
MS. WETZEL: I'd just like to follow up on
what you said about the two bulletins, and I'd like to
try to set the tone of the meeting that way.
There are two bulletins, Bulletin 2001-01
which deals with the circ issue, and that's what I
will be summarizing, and Allen Hiser will be
discussing some of the technical issues, the status of
the technical issues, now there is the Davis-Besse
issue, and the bulletin that was issued in response to
Davis-Besse, Bulletin 2002-01, which pertains to both
the head condition and axial cracking. And for the
purpose of this meeting, we would like to try to keep
the technical discussions and the questions separated
because if we mix them, it can get confusing.
Now, Jack Strosnider -- eventually these
converge, and Jack Strosnider said he would give a
summary at the end of the meeting where we think they
overlap and converge.
We do have a full agenda, and I would like
to just keep my remarks as brief as possible. I am
the lead Project Manager for Bulletin 2001-01, and I'm
just going to give a brief status of where we are on
that bulletin and the action plan for that bulletin,
and we will have many technical presentations to
follow, and you can -- there can be interrogations --
I mean, questions for the --
MR. FORD: It might be interrogation.
MR. SIEBER: It's her words.
MS. WETZEL: I wrestled with how to
Just to discuss our handouts, the NRR
folks are going to give three presentations and they
will be at separate times throughout the agenda. So,
I did try to separate the presentations there for you.
Bulletin 2001-01 is divided into short-
term management and long-term management, and right
now we're in the short-term management trying to get
to the long-term management of this issue, and the
short-term management is through dealing with each
plant on a specific basis, receiving the responses
which we've all received, inspections, and we plan to
issue three NUREGs summarizing the bulletin -- one
summarizing the bulletin responses, one summarizing
the inspection results, and a third one summarizing
our technical assessment of the bulletin.
And we also have some policy issues, and
the policy issues, the main one is managing this
through leakage or managing this through nonleakage,
and that is a major policy issues to resolve.
MR. FORD: You're going to manage it by
just regular inspection looking for leaks rather than
looking for cracks per se? Is that what that means?
MR. HISER: Yeah, there are tech spec
requirements of no leakage, and the concern relates to
do we allow a leak detection to be the main management
tool, or should ultrasonic, some sort of volumetric,
any current -- some sort of examination like that that
is capable of detecting part-through-wall cracks, the
head of the leakage, is that necessary.
MR. BATEMAN: This is Bill Bateman, from
the staff. I juts want to clarify that as it stands
right now, we are managing this issue through leakage
detection. That is how we are currently managing the
issue, through leakage detection.
MS. WETZEL: Which may be not looking
under the vessel at all, just doing qualified visuals
on the top of the heads.
MR. FORD: Could you just put a time scale
on the short-term management versus the long-term?
Short-term will be completed when?
MS. WETZEL: Well, we would like to get
out of the short-term because it is very resource-
intensive for both the staff and the industry because
we are basically dealing with this plant-by-plant, on
a plant-specific issue.
Now, the Bulletin 2001-01 only covers the
first round of inspections, and those should be
completed by the end of calendar year 2002. In fact,
I guess some second rounds start in 2002, but we would
like to have some long-term guidance in place by
January 2003, and that's -- you jumped ahead to my
last slide, but I'll discuss that a little bit more.
Long-term management, there's three parts
for developing our long-term management, which the
goal would be to have ultimately some type of
guidance, regulatory guidance or requirements in place
for inspections and inspection frequency, and in order
to do that we need to determine criteria, we need to
determine the appropriate regulatory tool --a nd i've
got some listed up there -- and then we would
implement that regulatory tool.
Technical issues -- these are the explicit
items that both the industry, the MPR and the NRC have
agreed on that are the technical issues that need to
be resolved in order to reach our long-term goal. And
I've just got a listing of them here, and Allen is
going to give a brief status on where we are on each
of those technical issues.
Industry/stakeholder interactions. That
is a very large part of our action plan. We are not
trying to solve this alone, we are dealing with the
MRP and the industry. We plan to come to you much
more, I'm sure. We've got other oversight groups,
public meeting, many public meetings, and we have a
Web site -- we actually have two Web sites, one for
each of the bulletins now -- and we try to put all of
our material up on that Web site for the public to
Conclusions. Our main goal is to get out
of this plant-specific -- where we are right now,
dealing plant-by-plant, and have generic guidance in
place, and we do have these goals of the selection of
the appropriate regulatory tool, completion of our
technical basis supporting that regulatory approach.
We do have some dates in our action plan for these,
and they are very -- it's a very aggressive schedule,
and we're not sure where we stand with that because
Davis-Besse and other plant-specific issues that we've
been dealing with, we have been working closely with
the MRP and NEI, and we do feel we're trying to work
to the same aggressive schedule to have some guidance
in place, some requirements in place for the next
round of inspections, which would be Spring of 2003.
MR. FORD: The time scale for both the
short-term and the long-term, an integration of the
two, one into the other, is it appropriate given the
risk of this particular degradation mode, presented by
this degradation mode? I mean, you talked about the
short-term ending end of 2002-2003. I'm assuming that
the long-term is five years? I don't know. For some
of these technical issues, you are talking five years
in a normal course.
MS. WETZEL: You mean to resolve the
MR. FORD: Correct.
MS. WETZEL: We're looking at resolution
of the technical issues to input into our regulatory
tool that we would start to initiate implementation of
in January 2003.
MR. FORD: Oh, so the short-term and the
long-term meld into each other?
MS. WETZEL: Yes. Yes.
MR. FORD: On a very short time scale.
MS. WETZEL: It's a very short, very
aggressive time scale, but right now the Bulletin 2001
only has guidance out to the industry for this first
round of inspections, and we would like some more
generic guidance, and they need it for planning
purposes. They are ordering new heads.
MR. FORD: Jack?
VOICE: I think the hope is that we will
have enough experience from the inspections that have
been performed and with the technical analyses that we
would be able to perform, that we could go ahead and
put in some in-place requirements for inspections that
would serve the long-term interest.
MR. FORD: Okay.
MS. WETZEL: We might not have -- by
January 2003, for instance, if rulemaking is required,
we're not going to have rulemaking completed, but we
would hope that guidance would be in place for
inspection, what type of inspections would be
necessary, and frequency of inspections.
MR. HISER: To follow up on Beth's
overview of Bulletin 2001-01, I want to go over some
of the technical status. What I want to do here is
provide an overview of the types of inspections that
have been performed in response to the bulletin,
summarize the results from those inspections, and then
discuss the status of the technical issues that Beth
listed on one of her slides.
If you remember in the bulletin, we had
the PWR plants in four categories. The first category
were those plants that had experienced cracking or
leakage from CRDM nozzles. The second group of plants
was termed high-susceptibility based on a
susceptibility ranking model that the industry
proposed. The next two groups we term moderate and
low susceptibility. Within the context of the
inspections that have been performed since issuance of
the bulletin, the plants with a cracking or leakage
history and those plants that are in the high
susceptibility bin have generally performed qualified
visual examinations of the head, looking for boric
In some cases, the licensee did opt to do
either ultrasonic examination or an AD-current
examination of all of the nozzles to provide
additional assurance. In the case of the visual
examinations, if licensees were not able to determine
that a specific nozzle was free of any deposits, they
would then follow up using ultrasonic testing to
determine whether there were flaws in the nozzle. And
in addition, ultrasonic testing was also used for
sizing of flaws in nozzles that had clear deposits on
MR. FORD: The presumption there, Allen,
is if you do not see boric acid by visual inspection,
that there is not therefor a crack. That is the
presumption. Is it possible that you could have
plugging of the annulus below the surface for which
you would not see it but there is still a crack?
MR. BATEMAN: I just want to clarify, when
you say "crack", you mean through-wall crack?
MR. FORD: Correct. Yes.
MR. HISER: The experience thus far with
inspections of nozzles that have not shown any
deposits on the head, no through-wall cracks have been
identified in those nozzles. So, at least with the
experience we have so far --
MR. FORD: And roughly 22 plants have been
inspected, is that right, approximately?
MR. HISER: Well, about 16 inspections
have been performed with ultrasonics and under-the-
head sorts of methods that can really find cracks
themselves, not just the deposits. I think that's one
of the concerns that we have in formulating the long-
term plans, is issues such as that --
MR. FORD: I guess my susceptibility in
this case is to best comment that you're trying to
move towards having a visual as the precursor to
looking more deeply. So, if you don't see any visual,
MR. HISER: Again, within the context --
MR. FORD: I'm questioning --
MR. HISER: Within the context of the
bulletin, and I think the thing we need to remember is
the bulletin is a short-term one-time action that
we're trying to use information from that to guide us
in the longer-term direction that we need to go, in
particular, given the recent results from Davis-Besse,
I think that has put a different color on where things
will end up going long-term. But within the context
of the bulletin -- and I think the results that we
have to date -- demonstrate that for the short-term I
think we have reasonable assurance that we will not
have any safety concerns relative to circumferential
cracking of nozzles. For the longer-term, I'm not
going to speculate right now as to what we'll do.
Beth mentioned one policy issue, and I'm
sure there will be other issues like that, that will
have to be dealt with before we can determine the
long-term management scheme.
MR. SHACK: When Oconee did a second round
of inspections, they came up with more cracks. Had
those nozzles been looked at with the UT or AD-
current? I mean, they presumably had passed a visual
inspection of the first -- had they been looked at
with any other tools?
MR. HISER: At that inspection, no. None
of the nozzles had been inspected with UT or anything
under the head.
MR. SHACK: So it's only a purely visual
MR. HISER: Right. Well, the nozzles that
did not have UT were cleared last spring using visual.
Let me finish this off.
With the moderate susceptibility plants
again within the context of the bulletin, the bulletin
described an appropriate inspection as being a visual
examine of the head or some sort of an ultrasonic or
AD-current examine if one could not do a visual
examine of the head. Plants have either performed
effective visual exams or, in some cases, ultrasonic
exams of the nozzle ID. In other cases, AD-current
examines of the nozzle ID and the J-groove weld have
And the low susceptibility plants were not
advised in the bulletin to perform any additional
examinations, and the responses indicate that they
would perform inspections in accordance with Generic
Letter 88-05 and in some cases they propose bare metal
visual examinations of the head.
MR. SHACK: What's the difference between
a qualified and an effective visual examination?
MR. HISER: An effective visual exam means
that you're able to view the interface of the nozzle
and the head for all of the nozzles 360 degrees around
the nozzle without impediment such as insulation or
other impediments to viewing that area, and also that
there are boric acid deposits that could obscure the
vision of that area. In contrast, a qualified visual
has the same operational aspects as the effective
visual, that you can see intersection of the head and
the nozzle, but it also has an analysis to determine
that there's a leak path from the J-groove weld to the
top of the head such that if you do get leakage
through the nozzle, that ultimately you should get
deposits on top of the head. So it's a little higher
threshold that we thought was appropriate for those
MR. LEITCH: Allen, does the inspection to
date call into question at all, or does it validate
the criteria that was used for the binning of the
plants. In other words, recall that we used effective
full-power years as compared with Oconee bias by
temperature to bin the plants, and I guess basically
what I'm asking is based on the data to date, does it
appear as though that binning is reasonable?
MR. HISER: If I can hold that just for
MR. LEITCH: Absolutely, sure.
MR. HISER: The first thing I want to do
is just provide a table that has all of the inspection
results for the plants that are in the first bin and
the second bin, so it would include all the high
In addition -- and these results include
also inspections that demonstrated no degradation, I
guess in the case of Robinson and Surry 2 and D.C.
Cook Unit 2. In addition, results are shown for two
moderate susceptibility plants for which cracked or
leaky nozzles were identified.
To date, with the inspections that have
been performed, seven nozzles have been identified
with circumferential cracks at or above the J-groove
weld. There are numerous cases of circumferential
cracks below the J-groove weld, but that does not have
a safety implication. In addition, at this point
there have been about 48 nozzles that have been
MR. ROSEN: Allen, I derive from this
table the conclusion that no cracks have been observed
in low susceptibility plants, or is that a wrong
MR. HISER: That's correct. At this
point, the only plants that we found any cracks are in
two moderate susceptibility plants. And I guess the
one point I'd like to make about -- well, Crystal
River Unit 3 was -- the nozzle was identified through
the visual exam where a deposit was identified.
Millstone 2, because of the head insulation package,
they were not able to do a visual exam, so they
actually performed an ultrasonic exam of all the
nozzles. They did identify three nozzles with part-
through-wall cracks, part-wall cracks. They were not
through-wall. There were no indications of leakage.
If Millstone had been able to do a visual exam on top
of the head, they would have identified no cracked
nozzles. So there is some difference, again,
depending on the type of inspection that was
performed. The depth of knowledge that we have from
some of these inspections clearly is dependent on the
type of exam.
MR. ROSEN: Because of the importance of
this question, I want to be sure I understood your
response. For low susceptibility plants, have they
MR. HISER: Yes.
MR. ROSEN: And no low susceptibility
plant has found any cracking, is that correct?
MR. HISER: That's correct.
MR. BATEMAN: Bill Bateman, from the
staff. I'd just like to clarify that. The low
susceptibility plants have not done any type of
volumetric inspection. So the types of inspections
that the low susceptibility plants have done have been
visuals, and I'm not sure in each and every case
they've been bare metal visuals, they may have been
visuals with insulation in place. So, not as
aggressive as the inspections that have been done by
the other plants.
MR. HISER: That's correct, and depending
on the insulation package, if a plant has insulation
directly in contact with the head, the ASME Code
required inspection would be to look at the top of the
insulation. That's not real effective in finding
deposits from a nozzle crack. The bulletin did not
ask licensees to do any additional exam beyond what
they are currently required to do, so I think that
would not have been effective in determining nozzle
leakage in those cases.
MR. ROSEN: So I should take only cold
comfort from the idea that there's no low
susceptibility plants on this table?
MR. HISER: I'd take warm comfort. There
are some plants that have looked at the bare metal --
I don't have a list right now of how many have done
which type of exam, but we can provide that
MR. FORD: On that very issue, Allen, I
seem to remember seeing a slide in the packages that
were received, there's many, many more UT exams done
than are shown on that table.
MR. HISER: Well, all of the nozzles that
have cracked or been identified as leakers have been
inspected using UT. There may be some plants that
have done ultrasonics that do not show up on this
MR. FORD: But it's important for you to
have stated that because it relates to Steve's
question, that when you've got down, for instance,
qualified visual for Oconee plants, they have all had
a UT also, to confirm that there was, in fact, cracks.
MR. HISER: Not every nozzle, for example,
at Oconee 1 has had a UT exam because it has not been
thought by the licensee nor, I think, the staff to be
really necessary at this point. The one exception to
that, it is Oconee Unit 3, which identified the first
circumferential cracks last February. If you scan
down the table to November, they had their scheduled
refueling outage, identified seven more nozzles with
cracks or leakage. Between the two inspections, they
have inspected every nozzle with UT, but I believe
that may be the only of the three Oconee plants that's
in that condition.
MS. WETZEL: This might clarify your
question. Some plants are -- they are clearing their
nozzles, first of all, by doing visuals on the top.
And if they can't get a visual on the head, then they
will go underneath and do a UT. So, some plants will
have a mix of visually cleared nozzles and UT nozzles.
MR. BATEMAN: You need to clarify that's
only for the moderate susceptibility, that doesn't
hold for the --
MR. FORD: I think maybe we're just going
round and round on this. I think in some of the future
presentations, just to reassure us, when you see a
visual or not see a visual, that has a direct factual
relationship to whether or not you see cracks.
MR. HISER: I would expect the next time
we will provide a more thorough review of the
inspection results, given the circumstances with
Davis-Besse, we wanted to put this at a relatively
MR. SHACK: Before you remove that, when
I have a crack and I have no repairs, does that mean
it's below the J-groove weld or we're operating on
sort of a crack growth analysis?
MR. HISER: I think in all cases the crack
is below the weld. And crack growth through the next
cycle did not indicate that it would go up to the weld
MR. SIEBER: Is it fair to assume that the
volumetric examination is better than a visual
MR. HISER: I think it's more thorough
because the ultrasonic exams are able to interrogate
the entire volume of the nozzle. The situation as it
exists right now is that the only -- you have the two
components in the area are the nozzle base metal and
the J-groove weld. The ultrasonic exams are not able
to interrogate the J-groove weld. So, as an example,
you could have a crack that is not detected that's in
the J-groove weld. You may think that your nozzle is
clear when, in reality, you could have a through-wall
crack in the weld. So, in the context of this
bulletin looking at circumferential flaws, though,
ultrasonics is the preferred approach to rule out the
existence of circumferential cracks.
MR. SIEBER: Based on that reasoning, it
would seem to me that you need a combination of both
volumetric and visual in order to provide substantial
assurance that you aren't going to end up with a
MR. HISER: Within the context of this
bulletin and in segregating any Davis-Besse related
issues, the ultrasonic exams can detect the presence
of circumferential cracks, and we know that there's a
certain time period from initiation of a
circumferential crack to the growth of it to a
critical size, and I think we have some comfort level
in that that if we do not detect a circumferential
crack today, that it will not develop to a critical
size within a certain time period.
MR. SIEBER: Perhaps sometimes during your
presentation you could tell us why you would not
require licensees to perform both visual and
MR. HISER: In some cases, visuals cannot
be performed because of insulation package.
MR. SIEBER: Why would you not have every
licensee who is in the high susceptibility category to
do both types?
MR. HISER: Every plant that's in the high
susceptibility bin can do a visual exam of the head.
MR. SIEBER: But why would you not have
them do both visual and volumetric since each seem to
address slightly different problems?
MR. HISER: As we develop our long-term
management strategy, that probably will be something
MR. BONACA: Bill Bateman again. As I
mentioned earlier, we are managing this issue right
now as discussed in the bulletin, through leakage. In
other words, if a plant detects a leak, then they've
got to go make a repair. And when they restart, they
will have fixed all the leaks. So that's how we're
managing the issue.
Now, if we wanted to manage this thing
such that we were 100 percent convinced there wouldn't
be any leaks during the upcoming cycle, then of course
it would involve doing a volumetric examination, but
that's not the decision that was made in terms of how
we managed the issue when we initiated this bulletin.
MR. STROSNIDER: This is Jack Strosnider.
I'd like to follow up on that because it's very
important to understand the context of the information
Bulletin 2001-01 that went out, as Bill
just indicated, it provided the option basically for
people to manage this problem in this first round of
inspections by doing visual exams, looking for
leakage. In some cases, they did under-the-head
ultrasonic exams because that was actually to their
benefit, depending upon the insulation type. But the
information we're presenting is the responses and the
results of the examinations performed to Bulletin
2001-01. And, in fact, not all those inspections are
complete yet. I mean, they will go out through the
end of this year. So we're collecting information on
that and Allen is going to show the histogram in a
minute to show where all this falls in place, which we
are going to use to inform what needs to be done in
terms of the longer-term program.
We're also looking at, as we get the
results, to see if there's anything here that tells us
we need to take some more aggressive action right now,
and we haven't seen that so far. It appears that the
program is finding cracks as it should, and Davis-
Besse is another issue that we'll talk later in the
presentation as to what the implications of that might
be. But, right now, we're still collecting
information in response to the first bulletin that
went out. That bulletin had a graded approach for
inspections where people could use visual examinations
and, depending on whether they were high to low
susceptibility, different levels of qualification. So
we're collecting that information and Allen is
basically just summarizing where that is.
There are clearly some issues that come up
with regard to why doesn't everybody need to do
ultrasonic as opposed to just doing visuals, and the
policy that that was referring to earlier, that's one
example of an issue we have to answer in order to
establish a longer-term program for managing the
issue. And it's very important that we ultimately get
to that longer-term program because in the meantime
we're managing this problem with bulletins and
inspections and plant-specific activities which are
very resource-intensive, but when we get back to
summarizing at the end, maybe I'll say a little more
about that, but I just wanted to make sure we
understand what we are presenting here is in the
context of the first bulletin that went out.
MR. SIEBER: Well, my questions did not
refer to the data that's already been collected and
ready for analysis, but what the future holds and what
is the best long-term strategy that you might have.
And I take it from your answer you would consider at
sometime in the future make a decision related to
whether both visual and volumetric examinations will
be required to provide the level of assurance that is
expected. Is that correct?
MR. BATEMAN: That's correct. And like I
mentioned earlier, that was one of the policy issues
that Beth mentioned. Do we want them to continue to
manage this through leakage, or not, but that's a key
policy decision that will need to be made.
MR. SIEBER: Thank you.
MR. HISER: And I guess just one short
follow up, my guess is that the implications at Davis-
Besse may weigh very heavily in terms of what those
requirements are. And until we fully digest that
information, it's hard to speculate where we'll end
Now, this is a visual depiction of the
susceptibility ranking and the results from
inspections to date. The red circles indicate those
plants that have identified either leaking nozzles or
cracked nozzles. Within the context of the bulletin,
plants that were within up to 5 EFPY were binned as
high susceptibility plants. As you can see from --
there are two plants that are outside of that region
that did have cracking. This is the Millstone plant
which, again, did an ultrasonic exam, had no through-
wall cracks in the nozzles. It may be that if some of
these other plants did similarly intensive
inspections, they also may have identified some
cracked nozzles, but clearly their visual exams did
not find any leaking nozzles.
The green symbol plants are those that
still have to inspect. I think there are about six
plants within this regime here up to 30 EFPY that
still have inspections this spring. There are another
12 plants we'll inspect either next fall or even
Spring 2003. There are some of the plants that have
At this point, I think we think this
provides some validation of the susceptibility
ranking. The highest ranked plant with any leakage is
here at about 6 EFPY. It is the first plant out of
the high susceptibility bin. The fact that we have
not identified any circumferential cracks at higher
EFPY levels and have identified no leakers, I think,
gives us some level of comfort that for the short-term
we have an appropriate management scheme for this, and
this will enable us to develop our long-term
MR. FORD: Okay. But it's a management
scheme, it's not a resolution scheme. It will occur.
In other words, you're just going to walk up that
MR. HISER: Right, absolutely. It's just
a matter of time.
MR. ROSEN: On that same chart that we're
looking at now, the susceptibility ranking histogram,
there are many plants that have found no cracking
throughout the chart. Have you thought about what the
lessons are from having plants in the high
susceptibility region with no cracking?
MR. HISER: I think there may be many
lessons. It may point us to some additional
parameters that we need to consider, such as heat of
material and things like that. There will be
additional consideration of this data as we continue
to accumulate it.
MR. ROSEN: Please consider both sides of
MR. HISER: Absolutely.
MR. FORD: Is that part of your strategy,
this question of a quantitative root cause analysis of
this cracking? You mentioned heat variations, there's
also residual stress variations. Is it the plan in
the long-term as you go through all your technical
lists, to come up with a quantitative tool to predict
what's going to happen in the near- and long-term?
And, in fact, to improve as you go from one repair
strategy to the other? Is that one of your goals?
MR. HISER: I think to the extent that
we're able to do that and that we're able to implement
something in a reasonable manner. What we do not want
is 69 solutions to 69 problems. We'd like to have --
MR. FORD: But, surely, until you get to
that capability, you cannot regulate a plant when it
comes along and says, "Hey, I haven't seen cracking
and therefore I can go for another year", but within
that next year you should be able to tell them, "You
are a high susceptibility, a high probability that you
will crack in the next year if you continue operating
the way you are".
MR. HISER: I don't think we would err to
the wrong side of that. My guess is the inspections
will be sufficient to cover those kinds of situations
that could occur.
MR. STROSNIDER: This is Jack Strosnider.
I'd just make the comment in response to that question
that our intent would be to develop quantitative
models that can help inform the development of the
regulatory framework in the long-term inspection
program, but we have some experience with the
susceptibility models both on this type of cracking
from the susceptibility ranking that was developed
back in the '90s, and on other components like steam-
generator tube plugs and steam generator tubes, and we
know that we're not -- I mean, we're not going to be
able to come up with a quantitative solution that says
this plant is going to crack on this day, all right?
And the best we're going to be able to do is get some
relative susceptibilities, use inspection results to
inform as we go down the road, and use those
quantitative models to help inform decision, but we're
going to have to apply some judgment here, recognizing
the uncertainties in these models. And I think what
Allen was saying is we will apply that judgment to
make sure that we have sufficient conservatism in
there to account for uncertainties in these parameters
that either are not accounted for in the models, or
that, frankly, you may not be able to account for
because you just don't have the information. So we
are dealing with uncertainties here, and there's going
to have to be some level of judgment applied.
MR. HISER: As I listed earlier, technical
issues that we have covered in our action plan. They
are reflected on this slide as well. I guess the two
points I want to make on this regarding the technical
issues is that we expect the industry to do the bulk
of the work in this area, and they have taken the lead
on many of these issues, and we are awaiting in some
cases reports from them. We also have through our
Office of Research several contractors that are doing
the bulk of the work for the NRC and, as indicated,
for example, on probabilistic fracture mechanics and
residual stress activities, we do have strong
interactions between the staff, our contractors and
the industry in those areas.
MR. FORD: On that issue, does the
industry have any warning of your expectations in
these relationships? For instance, crack growth
rates, as you know very well, they are all over the
map. Are you going to go to an average crack
propagation rate, or are you going to accept an upper
bound crack propagation rate? I mean, they presumably
know what your intentions are at this time.
MR. HISER: There have been some
discussions on that. We've had, I think, several
meetings where they've presented status reports on
their review of the available data, and I believe the
industry has generally proposed a 75 percentile curve
as an upper bound. Several of the licensees have
proposed for their plant-specific application 95
percent, and that seems to be an acceptable kind of
MR. FORD: And you could relate that to
the probability of the first crack occurring, through-
wall crack, et cetera? I mean, you can relate that to
that physical occurrence?
MR. HISER: That's correct.
MR. FORD: Why isn't there repair on this
list, repair strategies? Well, for instance, if you
are going to go to 690 or the relevant weld material,
how do you know what the factor of improvement is
going to be? I don't see that on this list.
MR. HISER: To resolve the current issues
that we have with the existing Alloy 600 nozzles, this
is the list. We also have user-need in with the
Office of Research to look at the characteristics of
Alloy 690, the replacement materials.
MR. FORD: Everybody takes as gospel that
690 is better than 600, and it probably is -- well, it
is in the lot -- and to very limited experience in the
field, but we cannot put what the factor of
improvement is going to be, can we?
MR. HISER: I don't know at this point
that we can put a specific number to it. The comment
you made earlier about the susceptibility ranking,
eventually that will get cracks at higher and higher
susceptibility levels, my guess is for 690 it's only
a matter of time.
MR. FORD: I guess I'm just trying to
assess as to where we're going on all this to make
sure that in ten years' time you're not going to have
another "oh, hell, we didn't think of this" or "we
didn't think of that". I'm trying to be constructive
as much as possible here.
MR. HISER: I guess the one point that we
haven't mentioned in any detail is the number of
plants that have planned to replace their heads, and
I think many of the plants that are on the table that
have identified cracked nozzles or leaky nozzles do
plan to do that.
MR. FORD: Well, presumably replacing with
690, but is -- you're just saying, "okay, then, that's
as best as we can do", or quantifying improvement.
MR. HISER: Well, I think at this point in
time our focus is really on the Alloy 600 nozzles in
place. We do plan to address the 690 nozzle.
MR. FORD: So when you do crack growth
rate data, there will be crack growth rate data for
MR. HISER: Not -- let me point out one
other -- this technical issue list is really to
address the short-term management items that Beth
mentioned, to put us in a position to develop the
long-term management criteria. So this is -- I would
say over the next 12 months we would have completed
these issues for the present situation, but we do have
Alloy 690 growth and initiation characteristics as a
part of our longer-term research activities that we've
asked the Office of Research to look into.
MR. FORD: And all the subcontractors --
Argonne, et cetera, et cetera -- who are working on
some of these issues, they are all working to that
MR. HISER: On these issues, yes.
MR. BATEMAN: Working to what time scale?
MR. FORD: Well, the mention of all these
issues, Bill, relate to the short-term, which we said
MR. BATEMAN: No, no, no no. They are not
working to establish, for example, crack growth rates
for Alloy 690 in the short-term, to meet our short-
term schedules, no.
MR. HISER: Let me just re-emphasize that
the technical issues that are listed here are short-
term issues relative to Alloy 600 nozzles and the
existing heads. For replacement heads, repaired
nozzles with Alloy 690, they are not on these
technical issues list.
MR. BATEMAN: We have some folks from
Research here who might be able to answer your
question. Ed, do you have any ideas on when we might
have that Alloy 690 crack data?
MR. HACKETT: This is Ed Hackett from
staff. I guess the issue -- and Peter knows, I guess
-- also goes beyond just 690 versus 600. There's
weld, residual stresses, and other issues. Those are
going to be longer-term. We're hoping to have PFM
analyses completed this year for the issues that
Allen's been talking about. The other ones are
obviously be longer-term. There is crack growth rate
data on 690. I guess we could back up and maybe make
a couple of comments.
First off, I guess, there's going to be
the idea going in that 690 is less susceptible to the
phenomenon. I think, however, this issue goes not
just to the base material, it goes to the welding and
the residual stresses. So when Allen is making the
commentary on, for instance, replacing the heads, the
heads -- we can go into a lot of detail on this, but
we have limited time here. The heads, as part of the
improvement for the new heads, will include 690, but
they are also including new types of machining for the
penetrations. They are assuming new treatments for
the penetrations, new types of welding that will
induce less residual stress. These things will, in
summary, hopefully cause significant improvements.
You've asked for a number. I agree with Allen, I
don't think we have a number. And I think only part
of that would go to crack growth rates or
susceptibility of Incanel 690 versus Incanel 600, but
there are obviously data already available on 690.
There's nowhere near the amount of data that's
available on 600, and we are going to be generating
that type of information for the future.
MR. FORD: Okay.
MS. WETZEL: We have told the industry
that replacing their heads is not the end of this
issue, and there will be expectations in the future
for some sort of inspection guidance on new heads.
MR. FORD: Could you expand very briefly
because it always comes down to this question -- maybe
someone from MRP can answer this one. What is being
done specifically on risk assessment? We've heard the
Duke Oconee presentation. I haven't heard any others.
Maybe there have been others to you -- maybe Davis-
Besse has done one, I don't know. But what
specifically is being done in the risk assessment and
MR. MATHEWS: I'm going to provide a
little bit of discussion of the work that we're doing
in the risk assessment area.
MR. FORD: Okay.
MR. HISER: Since I have grossly
overstepped my time and hopefully did not set a
precedent for today --
MR. FORD: We're just asking questions.
MR. SHACK: Before you take that slide
away, have we looked at enough plants now to know that
we can do UT on all the configurations that we have,
or are we still doing development work on that?
MR. HISER: There have been isolated
problems with maintaining contact of transducer-to-
nozzle, some access problems. I think the area of the
inspections, in particular UT, has probably been the
biggest growth area so far, and hopefully will
continue to progress, if nothing else, to provide more
timely inspections. That's one of the issues right
now, is the amount of time it takes to inspect a whole
head, but there has been a lot of improvements in that
area. And I would venture at this point -- maybe
Larry can address it -- that there probably is no
situation where UT exam could not be performed on the
nozzle from the ID. For the J-groove welds, that's a
different situation at the present time.
MR. MATHEWS: There are perhaps a few
isolated nozzles on a few heads that have caps on the
bottom end of them, that the cap would either have to
be cut off or something like that to get inside, but
those are rare.
MR. SHACK: There's always exceptions.
MR. HISER: Yes, always.
I guess the main things I'd like to point
out in the conclusions is that the inspection findings
to date are generally consistent with the
susceptibility ranking approach. Implications from
the Davis-Besse findings both in 2001-01 clearly are
yet to be determined.
In addition, as Beth has mentioned, for
some plants the second round of inspections after
issuance of the bulletin will begin next spring, so we
need to be in position to have some guidance or
requirements in place for those inspections. If there
are any questions, I'll address those.
MR. FORD: I think we are about to move
now on to the next topic. I'm sorry, is there an MRP
on specifically 2001-01?
MR. MATHEWS: This is an outline of what
we're going to talk about. We're going to save the
Davis-Besse part until the end.
The first thing is the MRP has put
together and gotten approved all the way up through
the MRP management structure a strategic plan for
managing Alloy 600, 82-182 issue. This is kind of an
outline of that strategic plan. We state the problem.
We have a goal and a mission. It's laid out an
approach of how we're going to solve the stated
problem, and then we define the roles of the various
organizations in the strategic plan, and then laid out
a specific strategy in each of the five areas here.
MR. FORD: Forgive me if we've seen this
-- I haven't seen this. I'm assuming that this has
got timelines with expected resolutions at various
times, and it fits into the regulator's requirements?
MR. MATHEWS: The goal is to definitely
work within the regulator's time frame so that we have
a meaningful interaction and we don't come in --
MR. FORD: Five years too late.
MR. MATHEWS: -- five years too late. We
have a window of opportunity to influence and be a
part of what's the long-term --
MR. FORD: And the regulators have seen
MR. MATHEWS: Yes, we've discussed this
with the NRC. I don't know that they've seen the
specific details of the plan, but we gave them a more
detailed presentation on this.
In the area of the primary butt welds,
Area 1, our approach is to use --
MR. FORD: I'm sorry, could you go back to
the other one, please?
You don't mention repair there.
MR. MATHEWS: Repair. It's probably
included as a mitigation -- most of the repairs have
been handled by the vendors that are doing those
repairs in the relief requests. But we have a Repair
Committee that is working with, in each of these
areas, like on the butt welds and head penetrations,
documenting the repair techniques that are available.
MR. FORD: What other committees are there
that -- interacting with this?
MR. MATHEWS: Basically, I have an
Assessment Committee, an Inspection Committee, and a
Repair Mitigation Committee within the Alloy 600
Issues Task Force.
MR. FORD: The reason for my questions is
in these multi-organizational deals, information just
goes down a plug hole sometimes because of lack of
communication. That's why I'm asking the question.
Repair is obviously a big thing on everybody's mind,
I just didn't see it on your list, but somebody is
looking out for it.
MR. MATHEWS: It's imbedded within each of
On the primary butt weld, our strategy
primarily is to use the ASME Section 11 guidance for
inspections and frequency. We think that's
appropriate at this point, but in conjunction with the
vendor demonstrations and PDI, we're driving
improvements in inspection technology. Basically
Appendix 8 has to be implemented by next fall, or the
fall of this year, and that will require qualifying
inspections for all of dissimilar metal welds that go
on in the plant. So that's our basic strategy. We
have a meeting set up to discuss the status of PDI
this month, with NDE Center and PDI and where they
stand on qualification of inspectors for the
dissimilar metal welds.
In the near-term on the head penetrations,
we're working with the NRC. We want to demonstrate
that all the plants are safe, and there's an
acceptable risk on an industry-wide basis. We're
documenting all the inspection plans that people have
turned in for 2001, and that's going to be history
within a year, and other specific utility commitments
and plans that they are doing beyond the requirements.
We're working with the inspection vendors
to demonstrate the inspection technologies to a
standard measure. And by that we mean we have
initiated development of mock-ups, and one that will
be available this summer is a blind mock-up so that
the vendors can come in and demonstrate their NDE
technology, their UT or whatever, on a blind mock-up,
and demonstrate their capability to find flaws on
We're also working to define reinspection
requirements based on risk as we get to our
probabilistic risk assessment, and to identify long-
term mitigation techniques for RPV heads. These are
the ones that have no leakage or the ones that haven't
detected degradation at all.
In the longer-term, we want to develop
inspection guidelines for the industry, moving toward
early detection to minimize the leaks in the plants,
and we want to use our risk assessment that we're
putting together to work on that. Provide an
assessment management plan that supports the
appropriate examinations and work with the staff in
implementing a long-term strategy, and also if
mitigation techniques require qualification, we want
to be working in that area to qualify the mitigation
For all the other Alloy 600 82-182
locations, a lot of work had already been done by the
various owners groups and other entities on a lot of
the other locations of Alloy 600 or in the metal in
the plants. Our approach was to determine what's
already been done. We don't want to duplicate it and
waste everybody's resources. To that end, we sent
letters to all the owners groups and we have gotten
responses back. Our next step is to work and get
specific information on the programs that have already
been completed by the vendors, and then to identify
and evaluate all the locations not addressed in the
existing programs, and then figure out with the owners
groups and the vendors where is the right place to do
that. Is the MRP the right place where it would be
more appropriate than the owners group. And then
provide guidelines for management, and ultimately put
out an Alloy 600 management guideline which would
either provide information to a utility on how to
manage all the locations in their plant, or reference
them to an appropriate location if it's something
that's been performed by owners groups or something
MR. FORD: You know, Larry, this is a
great bulletized management thing that everybody puts
out, especially EPRI, on what they are going to do.
When did this start?
MR. MATHEWS: When did it start?
MR. FORD: Yes.
MR. MATHEWS: We've been working on it
since over a year, but just pieces of it, and lots of
it has already been completed, it's just a matter of
when we --
MR. FORD: Are we going to see some data
on that? You say some of the things are being
completed and conclusions made, presumably. Are we
going to see data to support those?
MR. MATHEWS: I'm not sure what you mean
by data, but, yes, I have more information in here.
MR. FORD: Have you got some backup slides
on crack growth and things of this nature?
MR. MATHEWS: I didn't bring them. This
meeting was scheduled after a meeting in France where
all the experts on crack growth are right now, and
that's been scheduled for a year, and I couldn't bring
my experts with me on crack growth rate, but I have
some summary information on that.
MR. FORD: Okay.
MR. MATHEWS: We're also putting together
an inspection plan on what plants ought to do to
inspect their plants. It's based on gathering --
yeah, this is for head penetrations -- for gathering
visual and nonvisual NDE data, and basically try to
see if we can't verify that the MRP time and
temperature model continues to be an effective
management tool. And, basically, like Al said, the
inspections to date tend to support that. The plants
that have shown cracking further out were not through-
wall yet, so maybe we're picking up some of the
initiation of the cracking.
It will be coupled with our risk
assessment to demonstrate that the increase in the
core damage frequency is acceptable and, additionally,
there will be other nonvisual NDE, UT, et cetera,
gathered. Hopefully we might be able to do what you
were talking about about separating segments of the
fleet and say, well, this is a different kind of
material than that, if it makes a difference.
One thing that we always keep in the back
of our minds, though, is that, well, they're all
welded in with 182 and, you know -- so, if that's a
leak path, it's a leak path, and so even though
Huntington may be a better material or whatever,
somebody may have a better material, it's still welded
in with the same weld mark.
Generally, what we've done is we were
breaking the plants into various bins, sort of like
the bulletin, only I think finer bins and we're coming
up with inspection recommendations, and those
recommendations move toward more and more aggressive
inspections as the plant gets closer and closer to
Oconee 3 in the effective time and temperature.
Like we said at one point, we have to
decide here and work with the staff on what is the
appropriate point to say it's no longer appropriate to
think that a visual is all you need to do, and you
need to move on in, and we're working to work what is
the right point for that.
MR. SIEBER: Could you elaborate a little
bit on what you mean by more aggressive inspections as
MR. MATHEWS: Well, like an effective
visual is looking at the top of the surface, and then
a qualified visual, as defined in the bulletin, was
not only do you have to be able to look, but you have
to be able to show that you have a gap at operating
conditions so that the boric acid could leak out, and
then on into under-the-head volumetric or NDE or AD-
current or UT examinations.
MR. SIEBER: So volumetric could
eventually be a part of this?
MR. MATHEWS: Yes. Yes.
MR. SIEBER: Thank you.
MR. MATHEWS: Next topic is crack growth
rate for the Alloy 600 nozzle material.
We established an expert panel -- and I've
made this presentation so many times I'm not sure how
much of it the ACRS has heard -- but there was an
expert panel set up. They reviewed a lot of data. I
guess Mr. Shack was on the initial part of that panel,
he's still involved. They are refining their
approach. We were very near, we thought, to
publishing a curve and saying this is what we believe
is the right approach, and then we found one lab
voluntarily saying, well, we might need to take a look
at our data and adjust it. And then Davis-Besse came
up, and so that's kind of created another look at
what, well, what's going on in the annulus.
So, some of these things are being
reassessed by the expert panel, or those that are in
France are going to get together in a sidebar meeting
and take a look at it, and try and reassess some of
this issue right now, as we speak. You want data
points, I don't have data points here today.
MR. FORD: Well, it's really the same
question I asked Allen. There's a load of data out
there, and it's generally rather poor data, bad
quality data because it hasn't been controlled or in
the relevant environment.
Last time you gave us a presentation on
this topic, you made the statement that the crack
growth rate appropriate for circumferential cracks was
the environment that is in the primary site, primary
water site, and we questioned that.
Is that still the approach that's being
used for the development of your master curve?
MR. MATHEWS: We're developing a curve in
primary water, and that curve, I believe, is supposed
to be the 75th percentile of all the material that's
in there, but --
MR. FORD: Yes, I know, but my question --
MR. MATHEWS: -- in the annulus region for
circumferential cracking, we're proposing that we at
least multiply -- or that we do multiply that crack
growth rate by a factor of 2.
MR. FORD: And the rationale for a factor
of 2 and not a factor of 10? 20?
MR. MATHEWS: Well, the experts kind of
looked at that -- and I'm not one so I can't give you
that -- but they had looked at all kinds of things
about what could the possible pH range be, and do we
have testing in that range, and what's the effect of
it, and they used that to come up with the feeling
that -- and I think this is where they were -- that a
factor of 2 would bound the kind of environment that
could possibly seen in the annulus. Now, they stopped
as a result of Davis-Besse, and they want to say,
"Well, let me look again", but prior to Davis-Besse
that was the feeling that based on the buffering and
the things that go on in that region -- and they
actually ran "multi-Q" (phonetic) to try and figure
out what the pH and all might be in there, and then
look at the data to try and determine what effect it
could have on the crack growth rate. And they felt
that a factor of 2 was an appropriate multiplier
MR. KRESS: Does Davis-Besse imply that
crack growth rate is not the right parameter to use
MR. MATHEWS: Well, it depends on what
you're trying to model and what you're trying to
assess. If you're trying to assess wastage on the
head, then, yes, crack growth rate is irrelevant. If
you're trying to assess whether or not a circ flaw
will go around the penetration and result in ejection
and a LOCA from the ejection of the penetration, then
crack growth rate is very relevant.
MR. KRESS: Well, I was thinking in terms
of priorities for inspection, which is based on crack
growth rates also, implicitly based on that.
MR. MATHEWS: Yeah, you know, where we
ought to go in future inspections, you know, we
believe that a visual would find this kind of
information that was existing at Davis-Besse.
MR. KRESS: Well, I was thinking of your
MR. MATHEWS: Oh, the susceptibility
ranking. I guess the one thing -- you know, we've
always talked about that ranking as so many EFPY to be
an equivalent to Oconee 3 and just kind of said, well,
okay, that says you are normalizing to a plant that's
got a 165 degree circ flaw, but it's really just a
MR. KRESS: I understand.
MR. MATHEWS: And so, you know, if a leaky
flaw is now the important criteria, that might move
you further out onto the curve as your area of
MR. KRESS: That's exactly what I'm
MR. MATHEWS: But the same curve probably
would still apply. Okay.
The crack growth curve that we're going to
come up with eventually, and we hope sooner rather
than later, is intended for disposition if you find a
flaw in the Alloy 600 thick-wall component exposed to
normal PWR primary water. It's directly applicable,
and if you find a shallow axial ID flaw, for instance,
on the inside of a penetration to determine what kind
of -- and, really, we feel somewhat of a bounding
crack growth rate to apply to figure out can I make it
to the next outage before I violate 75 percent
through-wall or whatever.
We feel it is appropriate for the nozzles
that are in use in the plants, and if you were going
to evaluate a circumferential flaw above the weld,
like I said earlier, we're recommending a factor of 2
be applied in that situation, but that's typically --
or that's going to be a hypothetical evaluation
because we're not going to leave -- I don't think
anybody is going to leave one of those in service. If
you have a circ flaw, it's going to be repaired above
MR. FORD: Could you explain why ID is
beside "real" and why "hypothetical" beside OD?
MR. MATHEWS: For instance, a plant has
found a shallow ID axial flaw. That could be a real
flaw and they could evaluate it. It's been done at
Cook, it was done at a couple other plants. They
evaluate then the growth of that flaw and determine
can we make it to the next cycle, or whatever.
For an OD flaw above the weld, you're not
going to be doing an evaluation to leave that flaw in
MR. FORD: Okay. I was just following up
on what you just said.
MR. MATHEWS: Yes. So it would be a
hypothetical flaw you might want to evaluate for some
other reason, like how long would it take to grow to
ejection or something like that, if there were a flaw.
But if you found one in your plant, you're not going
to leave it there whereas you might do so for --
MR. FORD: Is this a new approach that
you've taken, that all circumferential cracks will be
repaired or removed?
MR. MATHEWS: Well, basically -- well, I'm
talking about a circ flaw above the weld, okay, which
means you've already got a leak that went on. And if
you've got a leak, that nozzle will be repaired.
Every one that has been found leaking has been
repaired, and I don't think anybody would intend -- we
couldn't by tech specs and the staff would not let us
run with a leaky nozzle.
MR. FORD: Okay.
MR. MATHEWS: Another thing is that the
crack growth rate that we come up with and feeds
directly into our probabilistic risk assessment and
our probabilistic fracture mechanics analysis, but
we're not treating it as a curve, we're feeding the
whole database and all the uncertainty in that
database into the PFM.
Expert panel is working now to screen some
more data. Some of the data that was originally in
the database has been relooked at and screened out
because we didn't feel it was appropriate data. I'm
sorry -- this is also saying the expert panel is
looking at weld metal, what data is out there -- we
haven't come up with a curve for weld metal yet, but
they are in the process of gathering the data on the
weld metal, they are going to screen it, and they are
going to recommend an approach for the weld metal
itself. I think we all feel like it's going to be a
little bit faster than the base metal, and so we --
may not be as relevant, but they are going to come up
with some recommendations, as far as head
penetrations. For something like a large nozzle where
you've got a 2.5 inch thick weld, it could make a
difference as to how fast it grows through the weld.
Research is being initiated by EPRI in a
DOE/NEPO co-funded program on crack growth rates in
these metals, and we will continue to keep the NRC up
to date on where we stand on that. And we'll try and
bring the data and the experts next time.
In the risk assessment methodology, what
we're proposing is an approach where we predict the
probability of developing a leak using the industry
leakage experience that we have to date and feeding
that into a Weibull model, using that then to compute
the probability of nozzle ejection considering
initiation in growth rate for a circ flaw above the J-
groove weld once you get leakage into the annulus,
factor in the probability of leak detection in that
interim between the time that a lead developed and
ejection might occur, and then the growth to critical
flaw size, follow that with a computation of the
probability of core damage, considering the
probability of the nozzle ejection and the conditional
core damage probability for a small break or a medium
break LOCA, and then assess the potential effects that
might occur from collateral damage, although we think
those are minimal.
MR. KRESS: What do you mean by Weibull
model, is that just the distribution of the flaw
MR. MATHEWS: Well, it's the distribution
in time of leaks developing --
MR. KRESS: It's the time distribution of
the leakage rates?
MR. MATHEWS: Right. It's the
distribution to predict when a particular plant might
experience -- be expected to experience a leak. And
it's based on our time and temperature model.
MR. KRESS: Why do you call it a Weibull
MR. MATHEWS: I'm not a statistician, but
MR. SHACK: They use a Weibull to describe
the statistics of the process.
MR. KRESS: To describe the flaw sizes?
MR. SHACK: No, describe the probability
of a leak.
MR. ROSEN: On your last point on the
slide, assessing the potential effect of collateral
damage, as I understand what you said, you said that
would be done after the calculation of a conditional
core damage probability.
It seems to me that if you have a
probability, however small, of collateral damage, it
ought to be part of the calculation of core damage.
In other words, that's not a quality for consideration
after-the-fact, it's part of the analysis.
MR. HISER: It would be factored into what
is the effect on the conditional core damage
probability given an ejection versus a small break
LOCA in a pipe.
MR. ROSEN: Given an ejection that results
in damage to other rod drives, perhaps?
MR. MATHEWS: That goes into the
assessment, what other rod drives might be damaged,
how badly might they be damaged, what would that do
then to the core damage probability.
MR. ROSEN: Okay. I think that's the
right way to do it. It should not be considered as a
qualitative consideration after the conditional core
damage probability is calculated, it is part of the
quantitative assessment, I think -- should be part of
the quantitative assessment.
MR. MATHEWS: It depends on how we get
into it, but I think to do it absolutely rigorously
correct, I think you're right. I'm not sure that our
proposal right now is --
MR. ROSEN: It's just another set of
sequences in the analysis. They may have very low
probabilities, but they should be part of the total
core damage probability.
MR. MATHEWS: I see what you're saying.
I'm not sure we were headed in that direction. We'll
go back and look at it.
The probabilistic fracture mechanics model
that has been developed, the key elements of that is,
like I said, the probability of leakage, using the
Weibull model, simulated in a Monte Carlo model, the
fracture mechanics modeling for stress intensity
factors, for through-wall cracks, part-through-wall
cracks, and multiple flaw initiation, stress corrosion
crack growth statistics, the whole database and all
the statistics with the crack growth rates being fed
in. We can factor in the effects of inspections in
the model, and what that -- turn them on and turn them
off in different probabilities of detection, and that
can be used to determine what is an appropriate
inspection interval. And then inspection reliability.
That's the POD.
MR. FORD: So this is just --
MR. MATHEWS: I suspect it is except that
we're looking at the whole fleet.
MR. FORD: You're looking at the whole
MR. MATHEWS: All the PWRs. The model is
intended to be applicable to all the plants.
MR. FORD: How can it be applicable to all
the fleet. Each plant has got very specific
MS. KING: We're building a B&W model.
We're putting together some Westinghouse and generic
models because obviously they have many designs, and
a CE model, so there will be several versions of the
MR. MATHEWS: They are all structurally
very similar, but the dimensions would be different,
and tolerances, et cetera, would be different.
I guess all this shows is how the
inspections would be taken credit for. You assume a
sample, initiate a crack, grow it to leakage, and then
at that point in time if you're doing an inspection,
there's some probability that the leak would be
detected and, if so, you take it out of the statistics
at that point in time. If it's not detected, it goes
on and continues to grow, and maybe you do a different
inspection or a volumetric inspection at a later point
in time, and depending on the inspection scheme that's
fed into the probabilistic fracture mechanics, once
something is detected it is taken out of the future
Some preliminary results -- and I must
stress very preliminary -- the increase in core damage
frequency for a high temperature plant is a product of
these factors. The probability of a nozzle ejection
after a first inspection is calculated to be less than
10-3. Conditional core damage probability for a small
and medium break LOCA, the largest number we could
find for these high temperature plants was 5 x 10-3.
That product is 5 x 10-6.
MR. FORD: Are those values -- for
instance, the condition of core damage frequency for
small break and medium break, those are for specific
geometries where you might have multiple raw
ejections, or collateral damage, if that's the right
MR. MATHEWS: The condition of core damage
frequency was taken from the IPEs or the plant's
probabilistic risk assessments for medium break LOCA,
and it was not for a top-of-the-head LOCA.
MR. FORD: So the presumption here is --
MR. MATHEWS: So, top-of-the-head, in many
ways, is better than out on a -- but collateral damage
has been qualitatively assessed at this point, and the
vendors do not expect that to have any significant
impact on the core damage probability. There's just
not much up there. There's other rods, but there's
not going to impact your ECCS systems that you need to
mitigate the accident, et cetera. So the effect of
the collateral damage is expected to be minimal.
We're not through with that yet. But we do expect
most plants to come out to be less than 10-6, or 5 x
I've only got one more slide.
MR. ROSEN: I want to make sure I
understand what you have on this slide. The
assumption here is that you have -- correct me if I'm
wrong -- you have a nozzle ejection as a result of the
propagation of the kind of damage we're seeing.
MR. MATHEWS: Yes.
MR. ROSEN: And that causes small break
LOCA, or it is the small break LOCA?
MR. MATHEWS: It is the small break LOCA.
MR. ROSEN: It is the small break LOCA.
Well, of course, I understand that it is a small break
LOCA, but why would you -- are you multiplying those
terms together? What is the meaning of the
MR. MATHEWS: Well, the probability that
you have the nozzle ejection for a year --
MR. ROSEN: 20-3, right.
MR. MATHEWS: -- times the conditional
core damage probability, the probability that you
damage the core if you do have the small break LOCA --
MR. ROSEN: I see. What you are saying is
you have the ejection, that is the small break LOCA,
and the probability that the safety systems in the
plant do not act to prevent core damage is --
MR. MATHEWS: The biggest one we could
find was 5 x 10-3.
MR. ROSEN: Because, otherwise, if they
do, you just have a small break LOCA.
MR. MATHEWS: Yes. If the systems all
work, you don't really have a problem -- well --
MR. ROSEN: It's spraying boric acid all
over the place, but -- you have a problem. You've got
a big --
MR. FORD: The biggest uncertainty there
is the probability of the nozzle ejection because that
relates to the whole question of uncertainties about
crack initiation and crack propagation, et cetera.
Have you discussed this with the staff?
MR. MATHEWS: Yes, and we've had some
technical meetings with both Research and with the
NRR, and went into more detail than we've got here on
exactly how we're modeling it.
MR. FORD: And there's no disagreement, in
MS. KING: We've worked to take the
comments that we've received from NRC Research,
especially on the PFM model, and incorporated those
suggestions back into the model as we've had these
meetings. We've had one conference call and one
meeting, and we're planning meetings and trying to set
up some meetings in May to come back to these issues
as we start to run base cases.
MR. FORD: I can see how when you don't
have a crack to start with, I can see you can go
through a fleet sort of argument for that. But when
you've already got a crack, or rather you predict
you're about to get a leak at a specific plant, can
you use that fleet data of 1 x 10-3, that generic
probability of nozzle ejection? You can't, can you?
MR. MATHEWS: No. Probability of ejection
is not 1 just because you've got a leak.
MR. SIEBER: No, but in light of the
Davis-Besse event, where you're also imbedding in that
probability of detection, then 1 x 10-3 is, to me, not
a good number.
MR. MATHEWS: This is after a first
inspection. I've done an inspection, didn't see a
MR. FORD: And you say that 10-3 that
within the next inspection you are going to have a
leak, initiate a circumferential crack and it will
whip through and --
MR. MATHEWS: In order for that to happen,
you know, within that sort of time period, you're
going to have to have very high growth rates, and
that's why the number is so low.
MR. FORD: Okay. I understand.
MR. MATHEWS: I only have one more slide,
and that's the impact of Davis-Besse on this.
MR. FORD: This is the impact of Davis-
Besse on 2001-01?
MR. MATHEWS: Yes, on the PFM model that
MR. FORD: Okay. Then I think we'll stop
before we get into the Davis-Besse specific
MR. MATHEWS: We're going to update the
PFM model as we need to, as a result of that. We
still have to figure it out, but a preliminary
assessment is that the model and results wouldn't be
significantly affected for growing a circ flaw and
ejecting the rod. It's not talking about the wastage
issue, just growing a circ flaw and a nozzle and
ejecting the nozzle.
There are gap elements on the opposite
side of the crack in the PFM that provide restraint.
One way that you might do is remove that restraint or
increase that gap to inches instead or mils, and
that's something that could be done, although it's not
totally obvious to me this is the way to address the
wastage issue, and we have to wade through all of
There is no back-wall constraint on the
part-through-wall crack in our model, so it really
wouldn't have an impact on that. It's only once you
get a through-wall crack the nozzle has a tendency
then to try and lean and the back wall on the other
side has elements in the model that could be adjusted
to account for lack of a back wall there. But like I
said, it's not totally clear yet to me that's where we
need to go.
MR. FORD: As an educated member of the
public, my gut would tell me that can't be right.
MR. MATHEWS: What's that?
MR. FORD: That whole reasoning, that the
vessel wastage have no impact at all on the likelihood
of having an injection.
MS. KING: That statement is meant only
for our part-through-wall model.
MR. MATHEWS: Well, no, it applies to
MS. KING: Therefore, vessel wastage is
not a factor, and this only applies to the part-
through-wall model of our PFM.
MR. MATHEWS: The way we grow the model in
the probabilistic fracture mechanics is as soon as you
get a leak, we assume you have a significant part-
through-wall model. Our part-through-wall crack -- I
think it's 20 degrees around --
MS. KING: Thirty degrees.
MR. MATHEWS: -- 30 degrees around 50
percent through-wall, in that part of the model, as
that crack then propagates around the nozzle in the
model, until it's 180 degrees -- I think it's 180
degrees -- it stays a part-through-wall model, and in
that part of the model as that part-through-wall crack
propagates, there is no back-wall element that's part
of it, so wastage is not a part, not a factor in --
MR. SIEBER: Of that.
MR. MATHEWS: -- of that part of the
growth. Once you reach 180, it goes through-wall in
the model and then it does become a factor in the
calculation, if we model it, if that's the way we want
to do it.
MR. SIEBER: Did you consider, though,
that once you waste the material in the head, you're
down to essentially a cladding member, which in the
case of Davis-Besse deflected, and whether the nozzle
separates or not, the cladding may burst open and
you've still got your small or medium break LOCA. Is
that factored into these risk numbers?
MR. MATHEWS: No.
MS. KING: At this point, no.
MR. MATHEWS: No. These risk numbers were
put together for the Bulletin 2001-01 assessment.
2002-01 and where we go with that, basically, I don't
think the industry doesn't ever want to let that
MR. SIEBER: I would hope so. On the
other hand, it's good for us to know what happened the
MR. MATHEWS: Yes. And I think Davis-
Besse is going to --
MR. ROSEN: Jack, in a way, you're
following up on what I think is the weak point here.
On your slide 13, you talk about collateral damage
not being expected to be a significant contributor to
core damage frequency, that's an unsupported
assertion, almost unsupported, and I think you need to
back that up with some analysis that you make
available to us.
MR. MATHEWS: And that is the intent. We
have some preliminary stuff from each of the vendors,
and that's their conclusion at that point, but it's
not a rigorous analysis at this point, but we intend
to follow up and make sure that it's an appropriate
conclusion to make, not just --
MR. FORD: We'll stop here. If I could
make a request, the next time you see us, which
hopefully will be within a couple of months, that you
bring us some back-up data so that the committee can
get an idea of, for instance, the scatter of the crack
growth rates happens to be just one thing, your
assumptions in the risk assessment, and things of this
nature because although these are great conclusions,
we have no way of assessing what goes behind them.
MR. MATHEWS: Understand. I understand.
And I would have brought more on the crack growth rate
MR. FORD: And I recognize you have a
restriction of time. Thank you very much, indeed, I
We will go into recess for ten minutes
only, and then we'll start talking about Davis-Besse.
(Whereupon, a short recess was taken.)
MR. FORD: The meeting will be in session.
I'd like to start the discussions on the Davis-Besse
situation. Jack Grobe is going to give the kickoff.
MR. GROBE: Thank you very much. Good
afternoon. My name is Jack Grobe. I'm Director of
the Division of Reactor Safety for the NRC Office in
Region III in Chicago, Illinois.
I've compared the materials that we're
going to present with what First Energy is going to
present. There is a bit of overlap, but there's also
some additional information.
Thirty-four days ago, Davis-Besse
management informed the NRC that during a repair of a
crack on one of the control rod head penetration
nozzles they discovered an unexpected several-inch-
deep cavity in the reactor vessel head. NRC Region
III and Headquarters management chartered an Augmented
Inspection Team to identify the facts and
circumstances surrounding the formation and discovery
of that cavity. Our purpose for the presentation here
today is to give you a summary of the results of the
Augmented Inspection Team's findings.
With me here today are two members of the
team. On my immediate right is Mr. Mel Holmberg. Mel
is a senior metallurgist on my staff in Region III,
and on the other side of the projector is Dr. Jim
Davis. Dr. Davis is a member of the research staff
here at NRC Headquarters.
Put up the next slide, please.
We're going to cover three topics today.
We'll provide a characterization of the control rod
drive penetration and reactor head inspection results.
We'll discuss several methods and results of those
methods for identifying reactor head corrosion earlier
than was identified at Davis-Besse. And then,
finally, we'll discuss the preliminary causes for the
head corrosion. We look forward to addressing any
questions you have. Please don't hesitate to
interrupt us at anytime.
I'd now like to turn it over to Mel and
get started. Thanks, Mel.
MR. HOLMBERG: Good afternoon. My name is
Mel Holmberg. I'm an inspector with our Region III
office in Illinois, and I'm also a team member of the
Augmented Inspection Team that conducted inspections
of the Davis-Besse site beginning on March 12.
Today I will be discussing the reactor
vessel head inspection results in this portion of my
presentation. As has been discussed earlier, this
included identification of cracked nozzles, 5; 3 that
had through-wall cracks; and the cavity near nozzle 3.
In addition, there was an area of metal loss at nozzle
2 that was identified..
This slide is depicting a cutaway view of
a nozzle -- not necessarily specific to any plant.
Just to give some idea of scale, it is typically a 4-
inch outside diameter pipe, if you will, approximately
3 feet long from the center nozzles, and it has a
stainless steel flange welded to the top.
Where the nozzle penetrates the head is
typically an interference step.
Now, for Davis-Besse, in response to the
Bulletin 2001-01, conducted an inspection of all 69
nozzles in the reactor vessel head. This included
both an ultrasonic inspection and visual inspection.
The ultrasonic inspection performed was conducted
initially from below the reactor vessel head, using
what they call the circ related probe. This is an
ultrasonic probe set up for time-of-flight or tip-to-
fraction type of UT method, and it was specifically
oriented to give maximum response or sensitivity to
After conducting the inspection, they had
five nozzles -- or, actually, 6 initially -- that had
potential cracks. They followed that up with a top-
down UT on all these 6 nozzle locations. And this
top-down is a rotating head probe UT with roughly ten
different transducers, and oriented at various angles
so that they could, in fact, characterize in detail
both axial and circumferential oriented cracks. Based
on that exam, 5 of these nozzles were confirmed to
The 5 nozzles with cracks, I want to
briefly discuss the cracks that were found. In nozzle
1, there were 9 axial cracks detected. Two of those
were through-wall. The length of those flaws was 1.8
inches and 3.5 inches. In nozzle 2 --
MR. SHACK: That was the through-wall
MR. HOLMBERG: That was the length of
those flaws. There were 2 flaws in nozzle one that
were through-wall. The length of those flaws, one of
them was 1.8 inches long and the other one was about
3.5 inches long. These flaws typically traverse the
MR. SHACK: How much of that was above the
MR. HOLMBERG: Okay, I'll get to that.
One of the flaws actually did not really extend to any
significant extent above the J-weld, it basically just
barely crossed it. The second one crossed it by about
half an inch above the J-weld.
For nozzle 2, this had 8 axial
indications. Five of those were through-wall and the
length of those through-wall flaws ranged from 2.7
inches up to about 3.9 inches in length. And
anticipating your next question, the greatest extent
above the J-weld was approximately 1 inch for the
longest flaw in that nozzle.
MR. ROSEN: How thick is the vessel head?
MR. HOLMBERG: 6.6 inches.
MR. ROSEN: That's 6.6 inches of the low
alloy steel, and then the stainless steel cladding on
the interior surface.
MR. HOLMBERG: In addition to the axial
flaws on nozzle 2, there was also one circumferential
flaw identified above the J-weld, and that was 1.2
inches in length, and it was not through-wall.
MR. FORD: This is on nozzle #2.
MR. HOLMBERG: Nozzle #2, correct. For
nozzle #3, there were 4 axial flaws identified, 2 of
those went through-wall, and the length of those were
4.1 inches long and 3.8 inches long. The extent above
the J-weld for the longer flaw was 1.3 inches, and
that's basically the characterization of the ones that
had through-wall flaws. I can give you the other two
if you'd like, but they weren't through-wall and they
didn't really traverse the J-weld.
Okay. The path obviously for leakage --
MR. SHACK: Some of these are Oconee 3
heats, right, or are these particular nozzles the
Oconee 3 heats?
MR. HOLMBERG: All three of these were
through-wall flaws, are also heat that was used at
Oconee, 4 of the 5 nozzles from that heat.
A through-wall flaw in this region
DR. DAVIS: Excuse me, Mel. Four of the
five penetrations that had cracks were from that heat.
Just wanted to make sure that was clear.
MR. HOLMBERG: Okay. Starting to talk
about the primary coolant, obviously if it moves
through the cracks, it will flow up along outside of
the penetration tube and end up deposited typically as
a popcorn kernel-type deposit of boric acid.
To fix the five cracked nozzles, the
Davis-Besse staff machined the lower part of the
nozzle such that it machined up through the attachment
weld. In fact, it was during this machining process
that the nozzle 3 rotated slightly and shifted.
Again, this was an unexpected phenomenon because the
nozzle at this location, in fact, is supposed to have
an interference fit.
During a subsequent investigation into
this shifted nozzle, the Davis-Besse staff identified
a large cavity adjacent to the nozzle. The picture
now on the screen is trying to depict a profile view
of this cavity. The cavity dimensions such that it's
roughly 6 inches long. And by length, I'm talking
moving this direction toward an adjacent nozzle,
that's penetration 11, and it's 4 to 5 inches wide at
its widest point, and for this entire area, the 6.6
inch thick steel head has been corroded away, which
left the stainless steel liner as the floor of the
cavity. The stainless steel liner was, in fact,
measured and found to be pushed up into the cavity
approximately 1/8th of an inch. This condition was
likely caused by the normal operating pressure of the
reactor coolant system.
MR. SIEBER: I presume that the cladding
is not designed to be the pressure boundary.
MR. HOLMBERG: The cladding is not
considered pressure boundary, it is there for
MR. SIEBER: Thank you.
MR. FORD: Are we going to comment later
on, Jim, to describe your analysis of the -- or your
opinion about the nature of the corrosion?
DR. DAVIS: We'll do that at the end.
MR. FORD: Good. Thank you.
MR. SHACK: As to the stainless steel
yielding that you described, was it something that was
going to continue to yield, or had it yielded as far
as it was going to go, or do you know?
MR. HOLMBERG: We don't know that. They
are trying to, as part of their safety evaluation,
determine in fact the failure point. I think they're
using 11 percent strain, to answer your question, in
terms of what they consider the failure point. The
amount of yielding represented only a few percent
strain. Probably they can give you a better number,
the utility has been working on that aspect. We did
not investigate that end of it in terms of the safety
evaluation. That was not part of our charter to try
to determine the safety significance at this point.
The picture now on the screen is an actual
picture of the cavity as viewed from the top of the
head. Note that the sides of the cavity generally
sloped down toward the bottom such that it's a larger
cavity at the head surface. The cavity is generally
smooth in texture. The picture that you're viewing is
a picture from, if you will, the penetration 11, the
downhill side, looking back to where the nozzle 3
position would have been. The nozzle has been removed
and the kind of shiny machined area is where they've
actually machined up through the attachment weld.
In addition to the visual inspections and
measurements that were done on the cavity, the cavity
was inspected with ultrasound from below or underneath
the head, and based upon that ultrasound result the
cavity appears to be or may be larger than what is
visually observable from the top of the head.
MR. SHACK: Where would the axial crack be
on that picture?
MR. HOLMBERG: The large axial crack, the
largest axial crack, the one with the 1.3 inch extent
above the J-weld, is aligned basically in the center
of the cavity on the downhill side, the zero-degree
side is the reference that they usually talk about.
The other flaw in there was located directly adjacent
to it on the uphill side, and it extended for about .8
inches above the top of the J-weld.
MR. ROSEN: Your comment that the cavity
may actually be larger than what we see here, I'm
having visualizing what you mean.
MR. HOLMBERG: I do have some additional
data on that.
MR. GROBE: This is kind of a busy slide,
but we anticipated you might want some more
information on this.
MR. HOLMBERG: Okay. What I've drawn here
is taken from one of their NDE reports, and what it is
trying to do is give you a grid map, if you overlay
it, looking down from above the head so you've got the
correct reference frame, what the thickness of the
cavity is as measured -- now this is taken from below,
but it's from ultrasonic thickness measurements. And
you'll notice -- all I did was nothing more than
connect the dots at data points where they've got
readings that are roughly in the .3 inch category,
indicating that you have only a stainless steel
cladding layer at that point.
Visually from above, you don't see that
shape. What you see is a shape that tapers in roughly
a "V" shape toward nozzle 11. Here you will notice
that the cavity goes outward and, in fact, begins to
expand as you approach nozzle 11. That is not what you
see when you look at the cavity from above.
MR. GROBE: In addition to that, the
cavity, when viewed from above, does not extend the
whole way to nozzle 11 whereas this data might tell
you something different.
VOICE: I believe in our presentation
we'll provide more detail on that.
MR. ROSEN: That implies there's sort of
a cavern under some of --
MR. HOLMBERG: Could be. I think the term
that they're using that I've heard kicked around is
possibly "debonding". They feel there is likely metal
behind there, but the UT is showing us that there is
some sort of separation there --
MR. ROSEN: Between the cladding and the
MR. HOLMBERG: That's what I've heard
characterized so far, yes.
MR. KRESS: Are all those numbers supposed
to be 6.6?
MR. HOLMBERG: No. There's another
interesting phenomenon. They have -- you'll see some
numbers in there that are roughly at the midpoint,
3.something inches, and those are believed to be
laminations, part of the fabrication process that the
UT is picking up.
Now, in addition to the cavity at nozzle
3 during the machine repair on nozzle 2, a second area
of metal loss was detected, again, in a similar way,
during the machining. In this case, the penetration
didn't move, but they identified a cavity that was
behind the penetration of roughly 1.6 inches, as you
see, extends below the bottom, so that the cavity that
was initially exposed was this area here that's been
machined out by the repair process. It extends, at
the point that we left the site, about 4.2 inches. It
was believed to go all the way to the surface.
Subsequent to our departure, they have removed the
nozzle and I believe they can confirm the dimensions
on the height of the cavity, if you will. The width
is 1 3/4 inches, and then trying to anticipate your
questions, yes, there was -- the crack with the
largest extent above the J-weld was in the same
quadrant as this cavity.
MR. SHACK: Now, on the top surface here,
they see only the sort of popcorn-style boric acid, or
MR. HOLMBERG: This whole area was covered
with several inches of -- and I'll get to this later
on -- but lava-like boric acid by the time we roll
around to this average.
The cavities both here and the larger
cavity at this point are believed to be caused by
boric acid corrosion, and through the larger cavity at
nozzle 3, an estimated 35 pounds of steel have been
corroded away. And we'll be providing a little more
detail in the root cause section, but that ends
basically this section of my presentation.
MR. GROBE: That's the extent of what we
were going to present on characterizing the inspection
results as far as the physical characteristics of the
head and the penetrations.
MR. FORD: Could I ask a question, which
I don't think you've got the answer to. How sure are
we that a circumferential crack was not through-wall?
I understand that the head is being removed --
MR. HOLMBERG: Let me explain a little
bit. The way that the UT process works is if the
crack was to propagate through-wall, they'll lose what
is called the "lateral wave", the wave that goes
between typically a time of light transducer sets up
a surface wave they call a "lateral wave", and they'll
see a signal response, and that -- if it actually
breaks that surface, that lateral wave will then
disappear and they'll know it's a surface-breaking
flaw, i.e., that it's coming through the surface we're
scanning on, which is the inside surface. So, because
of the technique that's used, I think there is a fair
amount of confidence that that did not go all the way
through the wall.
MR. FORD: But there will be a destructive
MR. HOLMBERG: It's already been done. We
destroyed all these cracks during the repair process.
Let me back up. There may be a cracked tip or end in
penetration 3 that was removed, but I know of no
cracks currently that we're aware of that exist.
MR. FORD: That's a pity because that's a
crucial part of the root cause examination.
MR. HOLMBERG: Yes, it is.
MR. ROSEN: In response to the question on
the nozzle 2 diagram about whether or not you had a
confirmation on the surface of the popcorn kind of
leakage that's been expected, your comment was, no,
the lava-like deposit obscured it?
MR. HOLMBERG: Yes. There was a very --
MR. ROSEN: Could you tell me more about
MR. HOLMBERG: Yeah, we're going to be
getting into that in more detail later on, if we can
just hold that for a few minutes, but basically the
brief answer is there was a thick layer of boric acid
and corrosion products that prevented or obscured this
region from any inspection, so they really couldn't
see the classical popcorn type --
MR. ROSEN: And you'll tell me about the
extent and nature of that deposit?
MR. HOLMBERG: Yes.
MR. ROSEN: Okay.
MR. FORD: Well, that whole question, the
root cause, what we understand to be why you got so
much corrosion in that annulus? Will we be coming to
MR. HOLMBERG: Yes.
DR. DAVIS: But we're not going to give
you a very good answer.
MR. GROBE: At the time of the inspection
-- the inspection ended about ten days ago -- the
licensee had not yet completed their analysis of what
they believed was the root cause. We provided them a
series of questions, about 30 questions, that when we
left the site were of still concern to us, and we
expect to get their root cause analysis shortly, and
anticipate that it will answer all of our questions.
And I believe, from looking at their slides, they have
quite a bit of discussion of the root cause in their
MR. SHACK: Where did you get the sequence
of -- you have a lava-like flow of several inches of
boric acid covering the whole head, and then somebody
is shocked to find that there's boric acid corrosion?
Is that roughly the sequence?
MR. HOLMBERG: Yes.
MR. SIEBER: Another question. There was
a confirmatory action order issued by Region III, and
one of -- I think there were five conditions in it --
and one of those was to preserve the site of the
incident. And given that, if the repair process then
destroyed the actual flaws, is that consistent with
the condition in the Confirmatory Action Letter, or if
it is, why would we give up that important piece of
MR. GROBE: It wasn't a matter of giving
it up. The discovery of the cavity occurred after the
machining was completed on penetration 3. It actually
was during that process -- during the process of
machining out the weld and the penetration in
preparation for finalizing the repair, the machining
equipment moved and the penetration cocked just a
little bit, and that was the discovery. So all of the
information was lost simply because of the repair
technique. The CAL was issued after that.
MR. SIEBER: Oh, okay. Thank you.
MR. GROBE: If there's no other questions
on the material we've presented so far, I'd like to
move on to talk --
MR. SHACK: Did you find out what the leak
rate was, what their sump leak rate was?
MR. GROBE: Yes.
MR. HOLMBERG: We won't spend a lot of
time on their what they call "unidentified leakage
trend", but that is the balloon portion of the graph
up there, the problem being that there's a fair amount
of scatter down in the .1 to .2 gpm range, which is
kind of where we believe that the leak rate for these
cracks -- total leak rate for all the cracks -- was in
that band. So, trying to track or trend that
specifically with the other masking type of things
that were happening on leakage rate alone, it was
something that did not provide a definitive "ah-ha,
here's where you see it", not that you couldn't see
something in the data, it's just there was so much
other activity that was potentially masking that
happening in the same time that that is something we
MR. SHACK: Their total leakage then is on
the order of .1-.2 gpm?
MR. HOLMBERG: Yeah. You'll see before
the big spike there that that's roughly down in the .1
range. The big spike actually -- I don't want to
digress too far -- is associated with a model
variation that they made to a rupture disk downstream
of a pressurized relief valve where they had actually
punctured the rupture disk purposely to allow it to
leak because they were afraid that the rupture disk,
if it was allowed to function as originally design,
would then torque itself off the pipe. It was a
design error they were trying to correct. But that
introduced leakage into the containment atmosphere
because there was a minor seed leakage past the relief
valve. So that was a source of leakage for much of
the unidentified leakage peak that's there.
In addition, you also have -- and we'll
get into this more -- the flanges themselves above the
CRDM penetration nozzles that provided leakage at
various times and various outages.
MR. GROBE: Just to give you some
perspective, the peak there is a little over 3/4 of a
gallon per minute, so below the tech spec limit for
MR. SIEBER: Do you believe or surmise
that the indication that the plant operator had that
containment particulate radiation had increased
significantly based on filter change requirements and
measured levels, that that was reasonably -- could be
reasonably assumed to come from rupture disk leakage,
or would that have been an indication of some other
leak in the pressure boundary?
MR. GROBE: All of these questions are
going to what we refer to as "missed opportunities",
and Mel has a presentation that if he went through it
might answer most of your questions.
MR. HOLMBERG: We're just about ready to
jump on that, that's the next area.
MR. SIEBER: Well, let's let him go
MR. HOLMBERG: What I intend to discuss
now are some opportunities to identify which were
available to the Davis-Besse staff to identify
corrosion of the head at an earlier point in time.
Specifically, I will be discussing the
containment air cooler and radiation monitor clogging,
and the deposits of boric acid which remained on the
To do that, I want to make sure we have a
common understanding of the reactor vessel head
configuration because one of the principal sources of
leakage was, in fact, the flanges, and by flanges, I'm
referring to where the control rod drive mechanisms
bolt up to the top of the nozzle flange.
Historically at Davis-Besse -- and, in
fact, at other B&W designed plants -- these have
leaked in the past. The leakage which occurs at these
flanges travels and deposits itself down on this
insulation layer and, in addition, it runs down the
side of the nozzles and ends up as deposits on the
reactor vessel head.
The area here is referred to as a service
structure which surrounds the head and supports this
insulation layer, and also surrounds the outside of
the control rod drive mechanisms. So it forms a very
more or less tight enclosure, if you will, surrounding
the top of the head preventing a direct readily
The leakage from these flanges not only
deposits on the head, but it can also result in some
airborne amounts of boric acid which become captured
by the ventilation system, which takes a section
inside the service structure and then moves it out and
basically exhausts it high in the containment top of
Now, similar to flange leakage, leakage
from the cracked nozzles would deposit boric acid on
the head, but it would also expel some amount of boric
acid into this cavity area which also would then be
captured by the ventilation system and then dispersed
into containment. And this would include not just the
boric acid, but any corrosion products that may be
From the previous discussion, one of the
places that boric acid deposits have been historically
found, where they've collected in containment is in
the containment air coolers. The containment air
cooler is designed to cool the containment, as the
name would imply. By doing so, though, it condenses
moisture in the air and ends up in collecting the
boric acid and, in this case, corrosion products that
were present in the containment atmosphere.
The plant has cleaned the containment air
coolers periodically and identified boron deposits,
and they are normally white in color. However, in
1999, a more frequent cleaning of the containment air
coolers was required, which indicated an increase in
volume of the boric acid present in containment.
Also, the color markedly changed in that it was a
brown or rust color.
At this point, the Davis-Besse staff had
assumed that the increase in boric acid deposit in the
containment air coolers was from known sources such as
the flange leakage, and that the color change was due
to the age of the deposits or rusting of the
containment air coolers. The NRC team believes that
the change in color of the deposits represents an
indicator that corrosion was occurring in containment
and, as such, represented a missed opportunity to
identify the vessel head cavity penetration --
MR. ROSEN: Hold it right there.
MR. HOLMBERG: Yes, sir.
MR. ROSEN: When you say the Davis-Besse
staff assumed changes, et cetera. Was that an ad hoc
kind of thing, or was this a conclusion of a root
cause analysis that was the result of operation or
there corrective action system?
MR. HOLMBERG: I don't believe there was
a formal root cause investigation, if you will. There
was -- what this was was a conclusion based on
interviews with the people involved with
identification of the brown deposits at the time, what
their conclusions were, what actions they took to
follow up on those conclusions, and so forth.
MR. ROSEN: So I take from your response
that you found no documents in their corrective action
system of formally analyzing these findings and
dispositioning them in one way or another?
MR. HOLMBERG: Correct, on the containment
MR. ROSEN: And on the color change?
MR. HOLMBERG: Correct, specifically on
the color change I don't believe we had anything
formal that discussed exactly their conclusions. It
was more based upon the interviews with personnel
MR. ROSEN: Anecdotal kind of analyses?
MR. HOLMBERG: Right. What were you
thinking at the time, what did you think it was, that
type of question.
MR. ROSEN: But no formalized analysis.
MR. HOLMBERG: Right. But when we move on
to the next indicator, there is more that was done
with the next indicator.
MR. GROBE: I was just going to say, if
you get a chance after the meeting to examine that
chart in more detail. The time that the containment
air coolers was cleaned prior to 1998 was in 1992, and
there was no cleaning necessary between '92 and '98.
That large spike which was caused by
leakage unrelated to -- largely unrelated to head
leakage, resulted in numerous cleanings during the '98
time frame. And then in the middle of '99, there was
a mid-cycle outage to repair or put in a modification
to fix that problem. And you can see leakage went
down dramatically. But cleanings continued to be
necessary through the end of '99, 2000, and 2001, and
the details of numbers of cleanings and time frames
are up on that chart.
MR. HOLMBERG: And the more significant
thing is probably the color change, in our mind, at
MR. ROSEN: And you'll tell me when they
finally entered this in the corrective system and did
some sort of root cause analysis?
MR. HOLMBERG: Well, I'm going to get to
the next indicator which was treated more rigorously
than this one.
MR. GROBE: The answer to your question is
this specific issue was not entered into the
corrective system, although it has been thoroughly
investigated since the cavity identification.
MR. HOLMBERG: In addition to the
containment air coolers, another area which would
collect boric acid and corrosion products is the
radiation monitor system filters. The filter is an
element that has a normal frequency for changing
basically set up on a monthly basis. However,
beginning in May of 1999, the filters had to be
changed more frequently such that by November of 1999
the filter had to be changed every other day, and this
was because of recurring clogging and the deposits
that were clogging these filters generally had a
yellow or yellow-brown color. And this, again, was
new, something new to them. And in this instance,
Davis-Besse staff did act on this new indicator and
did send the deposits out for analysis by an outside
laboratory, and this lab concluded the deposits were,
in fact, iron oxide corrosion products produced from
a steam leak.
The Davis-Besse staff did make attempts to
try to determine the source of these corrosion
products, but they were not successful. The team
believes that these deposits were likely corrosion
products from the corrosion of the head cavity and, as
such, represent a missed opportunity to identify the
cavity at nozzle 3.
MR. GROBE: Let me just add a little bit
more to that, Mel. Again, the details of the data are
displayed on that chart. The frequency of filter
changeouts increased to every other day, and the
licensee proceeded to install a bank of HEPA filters
with high-volume fans in containment for a period of
time, which resulted in the frequency of filter
The frequency increased again in the 2000-
2001 time frame, and we're again back at the every-
other-day time frame in the fourth quarter of 2001.
MR. HOLMBERG: The next indicator that I
want to discuss has to do with the boric acid control
program itself. This is a program that was
implemented shortly after the NRC Generic Letter 8805
was issued. The program essentially requires
inspections of areas which are likely to experience
leakage by looking for boric acid deposits. Further,
the program requires removal of boric acid from
components and evaluation of the component affected by
boric acid. And, again, the visual inspection for
looking for the presence of boric acid can be an
effective way for detecting small leaks in the reactor
coolant system. The example that's on the slide there
is that one drop per second leak can result in
accumulation of approximately 15 pounds of boric acid
over a one-year period.
I want to return your attention to the
head configuration because what we're talking about
now is how these inspections of the head itself were
conducted. Historically, as we already discussed, the
head had deposits of boric acid that accumulated, and
the accumulation was on the head itself, underneath
the insulation, and the volume of deposits we're
talking about here, the number that was estimated
before we left the site was roughly 900 pounds is what
was on there by this outage.
MR. SHACK: That's not the historic
experience at the end of the cycle, is it?
MR. HOLMBERG: No, it progressively got
worse, and we'll step through some of these head
inspections. I may not give you the numbers you want,
how many pounds were left on there because I didn't
have that information, but the 900 pound estimate was
the basically as-found condition in this outage.
Again, what I want to emphasize here is
the challenge to the Davis-Besse staff for performing
head inspections. Specifically, this service
structure that supports the insulation here has 5 x 7
inch openings, about 18 of them around the
circumference of the head, and through that opening
they tape a video camera, if you will, to a pole, and
push it up through that opening. And it probably
doesn't do justice here to the challenges this
represents. The curvature of the head on a B&W design
is, I believe, the most curved, if you will, of any of
the head designs, and it makes a challenge in terms of
trying to get anything attached to a straight pole up
on top of the head.
MR. GROBE: Mel, just for dimensional
purposes, right at the top of the head, what is the
distance between the insulation and the top of the
MR. HOLMBERG: This is a 2-inch gap where
it approaches the insulation here at the very top.
Again, particularly near the areas of the center of
the head, this represented a challenge.
MR. ROSEN: Where was the rod that was
corroded most severely in relation to this diagram,
was it right in the center, or was it off to the edge?
MR. HOLMBERG: Dead center is rod #1,
penetration #1 essentially, and if you count in a
square pattern around the outside, you'd have like 3,
4, 5 around it. So it's the next ring around it.
MR. ROSEN: So it's very close to #3,
which was the one that was corroded most, it's very
close to the top dead center, a foot off top dead
MR. HOLMBERG: Very close.
MR. KRESS: Is that insulation to protect
the control rod drive mechanisms to keep them cool?
MR. HOLMBERG: That's correct.
As discussed earlier, this accumulation of
boric acid on the head and the inspection challenges
due to the configuration did not go unrecognized by
the Davis-Besse staff. a modification to the service
structure surrounding the head was proposed as early
as 1990 to allow better access for inspections and
cleanings, however, this modification was never
Beginning in 1996, when a head inspection
identified that boric acid deposits were not being
removed and that was contrary to the boric acid
control program requirements. Further, they
recognized that the boric acid deposits could be
indicative of cracks in the nozzles, but the Davis-
Besse staff did not consider that this was a likely
source of the deposits for a number of reasons.
And the Davis-Besse staff was not
successful in removing deposits near the center of the
head because of the limited access and the cleaning
methods that were employed. Therefore, the decision
by the Davis-Besse staff to delay the implementation
of the modification to the service structure that was
first proposed in 1990 played a key role in preventing
an opportunity for effective head cleaning and
inspection. Further, the boric acid deposits left on
the head following the 1996 inspection may have
prevented viewing the corrosion cavity at nozzle 3 at
an early stage.
MR. SIEBER: What head-cleaning method was
the licensee using at this time frame?
MR. HOLMBERG: At this time frame it was
a manual method. It was basically a --
MR. SIEBER: Squirt water?
MR. HOLMBERG: -- like a paint scraper
taped to the end of a vacuum hose pushed up underneath
the -- in through those 5 x 7 openings and up onto the
MR. SIEBER: So that would have the same
difficulties as the camera in that it can't make the
MR. HOLMBERG: Right. The hose was
flexible, so it may have had a little more reach, but
the deposits were at least by 1990 becoming more
adherent. They were no longer loose and white in
form, and that was the next point I was going to make
MR. SIEBER: And they were going
MR. HOLMBERG: Yes.
By 1998, this is the next refueling
outage, the deposits had formed a semi-continuous
layer over the nozzles in the center of the head. The
deposits were more adherent and brown in color. This
was a change from a previous inspection which had
identified a white, loose or powdery form of boric
acid. The change in color or form was not evaluated
by the Davis-Besse staff.
Now, by 2000, the Davis-Besse staff again
inspected the head, and this is a picture of the head
as it was found in early 2000. In fact, this picture
is from the outside of the service structure, and what
you are looking are areas where boric acid and
corrosion products have spilled out of what they call
the "weep holes" -- these are the inspection ports
I've been discussing where they have to put a camera
up through there to do the inspection, and they are
essentially blocked through the wall of the head. So
there is a thick layer of boric acid that covers at
this point approximately 24 penetrations.
MR. ROSEN: What is that material down
adjacent to the circle?
MR. HOLMBERG: This is where the corrosion
products and boric acid have flowed down and pooled,
if you will, along the --
MR. ROSEN: That's the iron oxide and
boric acid mixed together --
MR. HOLMBERG: Yes. One other thing I
want to mention here is the characteristics of this
boric acid a little bit. The boric acid and corrosion
products, as you can see, are red rust color, but they
are also very hard. And the term used in their
corrective action system to describe it is "lava-
like". In fact, they had to use crowbars to remove
the boric acid from the head. In addition, at this
point they weren't making headway with the crowbars
and they implemented a washing of the head with 175-
degree water. Both of these techniques, though,
ultimately were not successful in 2000, such that a
thick layer of boric acid was left on the head at the
center penetrations, so that the cavity at nozzle 3,
for instance, would not have been something that would
have been uncovered by their attempts to clean the
MR. SIEBER: Is it fair to assume that
when boric acid is corroding iron, it changes into
another chemical compound which has different
characteristics, and so that boric acid is probably
not as reactive as pure boric acid would have been,
but is probably harder and more tenacious in its
MR. GROBE: You're getting into several
issues involving the chemistry, and they get right to
the issue of how much of this corrosion was top-down
and how much was bottom-up, so to speak.
Jim, why don't you go into a little bit of
boric acid/boric oxide chemistry and talk a little bit
DR. DAVIS: Basically, what happens is
around 300 degrees you start converting the boric acid
to boric oxide and releasing steam, and it's not clear
how quickly this reaction occurs. And then once you
get up about 378 or 380, the boric acid that's left
actually starts to melt. We think it's a mixture
somehow of this, and plus you are adding additional
boric acid as time goes on, to the bottom. So, it
becomes very complex exactly what you have there, but
from our interviews we know that the nature of the
boric acid definitely changed dramatically with time.
It looks like when you get boric acid
deposits from one cycle, you can go in there and -- if
you have access -- you can vacuum them up without a
whole lot of difficulty, or you can power-wash them
out. But there are some concerns there about power-
washing because in the peripheral penetrations you
have a gap there due to the J-groove welding process.
You could actually fill those gaps with a boric acid
solution, and that was their fear, that they were
going to do that, and that was one of their
justifications early on for not removing the boric
acid from the head.
MR. SIEBER: Thank you.
MR. ROSEN: Has there been a look at what
the effect of that corrosion product that's dripped
down to the bolt circle is on the bolting?
MR. HOLMBERG: There's been documents in
the past where they've had not necessarily red-colored
boric acid, but incidents where the flanges have
leaked and, in fact, have come out the weep holes and
ended up on the same area back in 1991 time frame,
where they removed them and then they document that
there's no evidence of corrosion.
So, the answer to your question is they've
documented they haven't seen corrosion due to --
MR. ROSEN: Is that because the material
of those bolts is different than --
DR. DAVIS: No, it's not.
MR. ROSEN: It's carbon steel, too?
DR. DAVIS: Those are carbon steel. In
fact, the reason this area was cleaned up was because
they couldn't get the head studs off to remove the
head. But I didn't find the Commission report on the
condition of the studs, which Brian Sheron asked me if
I found anything, and I didn't. I don't know if the
Root Cause Team did or not.
MR. GROBE: One of the items required in
our Confirmatory Action Letter was what we refer to as
"extent of condition", a thorough evaluation of the
reactor coolant system for any other corrosion, and
that will be captured in continuing inspections, and
the licensee is in the process of doing that
MR. LEITCH: Can you describe how the
joint between the service structure and the head -- is
that just sitting on there, or is that intended to be
DR. DAVIS: Those are weep holes.
MR. GROBE: His question is the attachment
of the service tray, is it welded onto the head?
MR. HOLMBERG: This part appears to be
welded. This is the bolting connection to the rest of
the service structure.
MR. LEITCH: I see that, but I was just
wondering, the lower part of it there, below that bolt
circle, is that welded to that?
MR. HOLMBERG: It appears to be.
MR. GROBE: I see some other folks that
have spent some time looking at this nodding "yes".
VOICE: It's welded with bolts
MR. HOLMBERG: In summary, the team
concluded that the Davis-Besse staff had several
opportunities to review the containment air cooler,
primarily the change in the color of the boric acid,
the RE filters, again, where you get confirmed iron
oxides and, finally, the head inspections themselves
where there was a change in the color and nature of
the boric acid.
So the Davis-Besse staff had several
opportunities to identify and prevent the corrosion
cavity, and failed to do so. And that concludes this
portion of the presentation.
MR. GROBE: Any other questions before we
go on to root cause?
MR. KRESS: Do they have temperature
measurements in the control rod drive area up above
MR. GROBE: I'm sorry, could you repeat
MR. KRESS: Do they have temperature
measurements in their control rod drive area above the
MR. HOLMBERG: Yes, there are temperature
elements in the service structure area.
MR. KRESS: Did those change over time?
MR. HOLMBERG: I don't know the answer to
that. On the face of it, I'm not sure -- they are far
enough removed from, say, the source of this leakage
and underneath the insulation is where the head is.
I'm not sure that there would have been a definable
trend, particularly since the flange leakage would
have been closer to those temperature elements.
MR. GROBE: The answer is we don't know.
Okay. Jim Davis now is going to talk a
little bit about the probable cause that we received
prior to the completion of the inspection, and then go
into some of the questions that we had with respect to
that probable cause. The licensee has an extensive
presentation of this material in their slides.
DR. DAVIS: The Root Cause Team concluded
that this damage was caused by boric acid corrosion,
and it probably started four to six years ago, and we
think that's reasonable. But the details of the boric
acid corrosion and the effect of the cap above this
nozzle is not known, or was not known at that time.
Perhaps they have some more information now.
MR. FORD: But you are looking at an inch-
a-year sort of corrosion rates?
DR. DAVIS: Or more.
MR. FORD: Or more. Are there any
confirmatory experiments existing in the literature to
explain how you could get an inch a year corrosion
DR. DAVIS: There are quite a few.
MR. FORD: And will that be presented
DR. DAVIS: I'm not sure if they're going
to present that information because I think they
concluded that it was a couple inches a year was the
corrosion rate, and you see rates up to seven inches
MR. FORD: Quoted in the literature?
DR. DAVIS: Yes.
MR. FORD: That's what I thought. But
those are primarily from impingement rather than
general corrosion, which -- I'm just trying to tie you
down on your definition of corrosion. You're not
talking general corrosion?
DR. DAVIS: Yes.
MR. FORD: You are?
DR. DAVIS: Wastage.
MR. FORD: As opposed to impingement
DR. DAVIS: Yes. What you get is
concentration of the boric acid with time by
evaporation of this solution, and when it gets very
concentrated, that's when you get the very high
MR. FORD: But the pH would be limited to
about 4, would it not?
DR. DAVIS: Experiments have done with a
range of pHs, and you still see the high rates when
they get very concentrated, and with a crack an inch
long, the leak rate goes up exponentially with length,
and you're adding a lot of boric acid under that cap,
and it also probably occurs at a lower temperature,
but it's not exactly sure what temperature the really
high rates are occurring at.
MR. FORD: I guess what I'm trying to
drive at -- and maybe it will come out in the next
presentation -- in order to explain 1-to-10 inches per
year, in these prototypical geometries for annulus, et
cetera, you are talking about steam escaping through
a crack onto that surface, and there are data
available that would explain that, in the open
literature as well as closed literature.
DR. DAVIS: It's probably more in the
closed literature or EPRI guidelines.
MR. FORD: Well, there's at least two
references in environmental degradation conferences
which would explain those sorts of rates under those
prototypical conditions, is that correct?
DR. DAVIS: Yes.
MR. FORD: So, from what we know right now
in the literature, open and closed, you could explain
these corrosion rates of the pressurized steel.
DR. DAVIS: It appears that way.
MR. HOLMBERG: Yes, however, the B&W
owners group did experiments, and based on their
experiments came up with a number for corrosion which
was 1.07 cubic inches per year. So that was what was
used to state that the reactor would remain within
structural requirements for six years, and that figure
is certainly not --
MR. FORD: Probably wrong.
MR. HOLMBERG: Correct.
MR. BONACA: I have a question which I
guess -- other plants like Oconee, they had leakage
through cracks, but they did not experience this kind
of wastage. Why was it, location, or what?
DR. DAVIS: I think it was more a matter
of detectibility, what they call the "popcorn"
indication. So they went in and did a UT and I think
they caught this before it started occurring --
MR. BONACA: What you are really saying to
me is that this is a process that could occur for any
other plants where you have cracking, and as long as
you don't identify it early enough.
MR. GROBE: The length of the cracks at
Davis-Besse were longer than observed at any other
plant that's been repaired.
MR. HOLMBERG: I want to stress the key
length that the analysts that I talked to, who has
done two of the Oconee units and several other plants,
was the distance above the J-weld. And the other key
thing -- and I don't think I brought it out earlier --
is the cracks that were OD-initiated at Davis-Besse,
which was also consistent with Oconee, but that is
different than other sites of experience. I want to
make sure I'm clear on that.
MR. ROSEN: Does the presence of the lava-
like deposits distinguish Davis-Besse from the other
MR. HOLMBERG: That's our understanding.
I've got Region III plants that I'm experienced with
MR. STROSNIDER: This is Jack Strosnider.
With regard to the last two questions, the first
comment I'd make is, understanding that the definitive
root cause of this gets to the question of why here
and not at the other plants -- and there's a lot of
thoughts right now, but we really don't have that
answer nailed down, and we're waiting for the licensee
to provide -- and the industry to provide -- some
additional information in that regard, and we're
scratching our heads also.
With regard to the lava-like flow
indications, the subject of the Bulletin 2002-02 (sic)
which we'll talk about, we're asking people to go out
and look and see if they have some more conditions.
So, we have responses. We haven't seen anything --
based on our review so far, we haven't seen anything
similar, but that review is still in progress, and
we'll summarize that when we finish this part of the
MR. FORD: Jack -- I think I know what
you're going to ask, you go first.
MR. BONACA: Just to say we have a number
of lessons learned regarding played out on cold
surfaces in containment, and to what extent are these
observations going to be made part of programs for the
other units. I mean, clearly, the timing here of
identification of leakage through a crack is critical
because you are saying that it is possible that this
could be repeated as an event at some other unit, and
also that we have learned that -- so is there anything
being done to try to develop programs by which you
have inspections in containment and -- you know, just
HEPA filters and -- you know?
MR. BATEMAN: Jack, if I could interject
here, we did issue an information notice, I guess,
last week when we talked about this phenomena of the
containment air filters and the radiation elements and
changes in unidentified leak rate, to alert other
utilities of those potential signs of problems.
MR. GROBE: And what Jack and Bill are
indicating is just the earliest part of getting
information out and getting information back so that
we can consider what are the appropriate inspections
both from the utilities perspective and also from our
perspective. This had been going on for a number of
years, and we hadn't identified it either.
MR. BONACA: Because, I mean, up to now,
in my mind, I've been focusing purely on the visual
inspections of the head, whether there is something
more we have learned from this were precursors of
deposits elsewhere and in the atmosphere of the
containment that may give some significant element to
a problem that --
MR. GROBE: That's correct.
MR. FORD: I'd like to follow up on the
discussion about how close are we to a cliff edge, if
you like, that all reactors that found axial cracks
could potentially have within some unknown time period
this same sort of problem, which comes down to the
importance of the root cause analysis. In order to
get one inch per year, it's my understanding from the
open literature data, that it is an impingement sort
of problem, i.e., it's very important on the angle of
attack of the impingement. Axial cracks should not,
therefore, give the problem that we are seeing here,
but circumferential cracks would. And that's why I
asked the initial question, how sure are you that
Davis-Besse did not have the circumferential through-
wall crack? That was the reasoning behind my question
and, of course, we don't have the answer to it.
MR. HOLMBERG: Yes. And on top of that,
the circumferential crack -- again, if you look at the
wastage area, the one that's aligned is basically the
longer axial crack.
DR. DAVIS: And there are no circ cracks
in nozzle 3.
MR. FORD: Okay. So you are still going
-- if you were a betting man, Jim, you're still going
towards corrosion as opposed to impingement attack,
which has got a huge impact, therefore, on what the
environment is really in the annulus and is, in fact,
not only on the wastage, but also on circumferential
crack growth rates.
DR. DAVIS: I'm not sure that I would say
that 2200 psi steam hitting a steel surface is not
going to do any damage.
MR. FORD: Well, it's just coincidental
that it happens to do damage at around about 1 to 10
inches per year.
DR. DAVIS: It may be a combination of
both steam-cutting and boric acid corrosion, and we're
hoping that the Root Cause Team gets some evidence
because they're going to cut that hole out and they're
going to examine it and they should be able to tell if
there's steam cutting from --
MR. FORD: I realize we've got a bulletin
out on this to try and define the problem, and in that
Bulletin 2002-01 there is, I believe, a statement on
coming up with a root cause analysis within a certain
period of time, am I correct?
MR. BATEMAN: All the bulletin does is ask
licensees to go out and inspect to determine what they
have on the top of their head.
MR. FORD: Did I not see some document --
MR. STROSNIDER: Ken Karwoski might want
to correct me if I get it wrong -- there's some
discussion in the bulletin about, I think, the fact
that we don't understand the root cause at this point,
but these are the conditions that existed where this
occurred, and we're directing plants to go out and
look and see if they have similar conditions. Not
knowing the precise root cause, we had to cast a net
broader than you would if you knew that root cause
precisely. So there is some discussion in there, and
there is an expectation that -- and I don't remember
the exact language -- at some point we will get a root
cause, but we didn't have it at the time we wrote the
MR. FORD: But will you be discussing
MR. STROSNIDER: Ken Karwoski is going to
talk about the bulletin when we finish this part.
MR. GROBE: Through the discussion -- John
Wood, when is the root cause analysis -- do you
anticipate that will be submitted soon? We did a lot
of speculating up here.
MR. WOOD: Yes.
MR. GROBE: Weeks, months, next week?
Unless there are any other questions for
the team, that completes our presentation.
MR. FORD: Thank you very much, indeed,
I understand now we'll go into about an
hour and a half of discussions from First Energy.
I've had a request here that after this
presentation, so we all know how to manage our lives,
after this presentation we'll have a break for ten
MR. WOOD: Good afternoon. My name is
John Wood, and I'm Vice President of Engineering
Services for the First Energy Nuclear Operating
Company. Next slide, please.
As far as our presentation this afternoon,
I'll be giving some background information, then turn
it over to Mark McLaughlin who will be discussing
discovery and characteristics of our reactor vessel
head degradation, and then over to Steve Loehlein to
discuss the evaluation of the degradation. Next
Our objective of this presentation is to
provide the results of our recent inspections and
subsequent investigation of the degradation found at
the Davis-Besse Nuclear Power Station.
For background, Davis-Besse is located in
northwest Ohio, near Oak Harbor. It began operation
in August of '77. It is a raised loop, 177 fuel
assembly Babcock & Wilcox pressurized water reactor,
operating at 2772 megawatts thermal, about 930
megawatts electric. It has approximately 15.8
effective full power years at the conclusion of its
last operating cycle, and what you see next are the
nominal operating conditions, that being 2155 pounds
per square inch for pressure, and a Tave of a normal
582 degrees F., with a hot leg temperature of 605
degrees F. We have 69 nozzles located in the top of
our reactor pressure vessel head, 61 of those nozzles
are used for control rod drives, that gives us 8
additional. Of those 8 additional, 7 are spare and 1
is used for reactor vessel head, vent from the top of
the reactor vessel head to the steam generator. Next
We've covered this diagram in some detail
already, but I would like to point out that the head
insulation is permanently installed, not meant to be
removed. The dose rate at the flange level is about
1/2 of a manrem per hour, and the dose underneath is
about 3 rem per hour.
MR. BONACA: Do you mean millirem?
MR. WOOD: I mean rem, 1/2 rem per hour --
MR. BONACA: What kind of insulation is
MR. WOOD: It is a mirror type insulation,
stacked stainless steel. It is located on support
steel that is carbon steel, however, and much of the
service structure, as outlined there, is carbon steel
We show there the 18 access openings, or
"mouse-holes", the 5 x 7 holes that we referred to
earlier, and those provide the access into that area
between the insulation and the top of the head.
I will mention that the service structure
also has ductwork that allows cooling air to be pulled
through. There is no forced air underneath the
insulation other than what might come up through the
mouse-holes and out through the openings that the
nozzles penetrate through the insulation.
MR. SIEBER: It would appear, if I look at
the support steel that's underneath the insulation,
that it actually adjoins the head next to the center
nozzles, is that true?
MR. WOOD: I don't believe it actually
rests on the vessel itself. It's due to the
orientation, I believe it's off to the side in that
MR. SIEBER: Looks like it would be almost
impossible to see the center nozzle.
MR. WOOD: I believe if you come from a
particular access opening, or one of the mouse-holes,
you can go directly to the center.
MR. ROSEN: Let's clear up the radiation
levels. This is shut-down radiation levels --
MR. WOOD: That's correct.
MR. ROSEN: -- at ten days after shutdown,
let's say, those are approximately 500 millirem per
hour at that support steel plate?
MR. McLAUGHLIN: What that is -- you know,
we've done a significant amount of work inside the
service structure, and what we're giving you is the
effective dose rate that our workers are seeing inside
the service structure. So that's in -- if you look in
the service structure, we've had workers inside this
area doing insulation removal and several other
activities. The effective dose rate that they have
received to date in that area is approximately 450-500
millirem per hour.
MR. ROSEN: Thank you.
MR. SHACK: Where does it go to 3-r?
MR. McLAUGHLIN: Underneath the vessel.
The contact radiation reading in this area here, after
we did the under-head decom is 3-r per hour. If you
want an effective dose rate for the workers down in
this area here, it's about 700 millirem per hour is
the effective dose rate that our workers have been
receiving when they go under.
MR. WOOD: If we go to the next slide, we
have here a couple of pictures of the reactor vessel
head as it sits on the reactor head stand. This is
during one of our refuel outage. You can see this
portion being the service structure, if you were to
open it up, you would see then the control rod drive
mechanisms. Some of those mechanisms have been
removed in order to do work inside that structure.
And, typically, you can see the individuals on top on
the left-hand side of the screen there, they would be
working with about 22-foot poles in order to service
the flanges that are located at this location. Next.
We've already talked some about typical
control rod drive nozzle. It shows the Alloy 600 --
MR. ROSEN: Could you go back to that
other picture again?
The men on top of that structure are in
full anti-Cs. Do they have controlled breathing
MR. WOOD: No, not contained breathing
I wanted to point out the Alloy 600
Incanel. The reactor vessel closure is about 6 5/8
inch thick, with the nominal clad thickness of 3/16 to
3/8 of an inch.
If we go on to the next page, there are
some unique features at the Davis-Besse site. Our hot
leg temperature runs about 4 degrees F. higher than
other Babcock & Wilcox plants. That's slightly higher
because of our core delta-T being slightly higher due
to being 2772 megawatt thermal. We also have the head
vent which goes to the top of our steam generators.
There is no counterbore present at the nozzle
penetration. We should back up one slide, if we
This actually depicts a counterbore
situation here, and at this location at Davis-Besse,
we were one of the last 177 fuel assembly B&W plants
produced. They ended up just drilling holes and doing
a shrink-fit using liquid nitrogen without a
counterbore in the regions that are shown here. That
is a unique feature. Don't know that it's a
significant feature in what we have found.
If we could go on to page 10.
We've heard today about Bulletin 2001-01,
which was issued August of 2001. As a result of that
issuance, Davis-Besse worked with the NRC staff to
extend their outage from the requested December 31,
'01 inspection date, and through those discussions
they were successful in extending the date to February
16th. In that deliberation they committed to doing
100 percent visual examinations of the reactor
pressure vessel head penetrations, and committed to
doing 100 percent ultrasonic examinations of the
nozzles. Next page.
There were some compensatory actions that
were taken in order to be granted that extension. That
included a temporary lowering to Thot to reduce
susceptibility to primary water stress corrosion
cracking during the remainder of the operating cycle.
That was reduced about 7 degrees from the 605 that I
mentioned earlier, which is normal, to about 598.
We also minimized unavailability of
safety-related equipment during the remainder of the
operating cycle. Dedicated an operator for emergency
core cooling system transfer from borated water
storage tank to the reactor building sump, and also
conducted additional operator training. Each of the
first three represented about 16 percent to 17 percent
improvement in the core damage frequency as a result
of doing those steps. Next page, please.
Davis-Besse, of course, was aware of what
was happening in the industry in regard to primary
water stress corrosion cracking, had anticipated
seeing some cracking in their nozzles. In fact, the
planning for RFO 13 was to plan for four nozzles
needing to be repaired, and that was based upon the
susceptibility rankings that we talked about earlier,
which are based primarily on operating time which we
were a little behind Oconee, and head temperature
which we were a little bit higher than Oconee.
I'll now just cover a few of the sequence
of events that have brought us here today. We
commenced the outage on February 16, and moved the
head to its head stand about a week later, started the
UT examinations which revealed cracks through-wall on
nozzle 3. We made our event notification announcement
to the NRC at that time.
We then the next day completed the rest of
the UT examinations and indicated that of all 69
nozzles, we had five denoted with cracking. Those are
listed there, and Mark will be giving you much more
detail on each one of those. And we confirmed those
then using the top-down inspection tool that Mark will
also be discussing.
I would like to point out on the bottom of
that page 13 that we did understand from the UT data
that we had suspect areas behind nozzles 2 and 3, and
also you'll hear more about a nozzle 46 that Mark will
talk about, that did not have a crack but had the
indication in the back plane that needed to be
investigated. Next page, please.
On March 5, as Mark was watching the
inspection screen, noted that there was unexpected
movement of machining tool during the nozzle 3 repair
effort, and we proceeded to go down path and removed
nozzle 3 on March 6. We found degradation on March 8,
which you saw the picture of in staff's presentation,
and shortly thereafter there was an Information Notice
on the event that was issued to the industry March 12,
and Davis-Besse received a Confirmatory Action Letter
on March 13, which included six items for
consideration, the six being the quarantine for root
cause analysis, determine what the root cause was,
evaluate the extent of condition with respect to the
degradation mechanism, NRC review and approval of
repairs, NRC restart approval, and assessment of
At this time I should mention that there
was a question earlier about that safety significance,
and what we have recently signed out as of yesterday
to the NRC was that we believe that the clad, as it
existed, would have held to 5600 pounds per square
inch, and that assessment, the PSA portion of that, is
included in the letter that was sent out yesterday.
Just to complete the sequence of events,
on March 18 NRC notified the industry of the issue
under Bulletin 2002-01. We completed repairs to three
nozzles -- 1, 5, and 47 -- on March 27. We just
recently removed nozzle 2 that would discuss some of
the findings there, and then on April 4, we just
talked about in here that NRC issued Information
Notice to the industry in regard to the containment
air coolers and radiation detector potential
indications for the industry to be aware of.
And then that brings us to now a
discussion that Mark McLaughlin will cover in regard
to the discovery and characterization of degradations
that we found.
MR. McLAUGHLIN: Good afternoon. My name
is Mark McLaughlin. I am currently the Field
Activities Team Leader. Since August, I have been the
Davis-Besse Project Manager for the Bulletin 2001-01
I'd just like to point out a couple of
things on this slide. This gasketed joint here at B&W
plants is not seal-welded as in Westinghouse plants.
A couple of dimensions for the nozzles to orient you,
the outside diameter of the nozzles is 4 inches, and
the nozzle wall is .63 inches. The head thickness is
6 5/8 inch thick, and the cladding is 3/16 nominal
I'll go over our examination plan coming
into this outage. The basis for our examination plan
was to verify the condition of the head, to assess and
fix any cracks that were found, and then there's one
other important thing that we were going to do before
the head was placed on the reactor vessel, and that is
clean the head. To do that, I contracted with Master
Lead Decontamination Services because they had the
equipment and expertise to clean the head through the
Our examination plan had three steps. The
first step was to perform a visual examination so that
we could categorize any of the nozzles that would have
been put into one of the three categories, either no
leaks, obscured, or suspect.
The second step of the process then was to
perform ultrasonic examination of all 69 nozzles which
at the time was the most extensive examination in the
industry. To do that ultrasonic examination, we
employed two different tools. One was the under head
blade probe UT, and the other one was a top-down
rotating UT tool.
If any flaws were found, then our plan was
to evaluate the flaws using the NRC guidance. That
guidance has different criteria for pressure boundary
or non-pressure boundary flaws, and our definition of
pressure boundary was from the bottom of the weld, up.
This slide shows a picture of one of the
tools that we used. This is the blade probe. This
tool is inserted in the gap between the guide tube and
the nozzle, so it inspects from the inside diameter of
the nozzle, looking through the nozzle material, out.
The advantage of this tool is that it saves some time
because the control rod drive mechanisms do not have
to be removed to do the inspection.
The actual transducer set that we used was
optimized for circumferential flaw detection. Before
the outage start, during the preparation process for
these inspections, we brought in the EPRI test block
so that we could test out or demonstrate the actual
equipment that was going to be used at Davis-Besse. To
help us with that, we had an EPRI individual who was
onsite, providing oversight of that demonstration.
The particular test block that we used had an actual
crack from another plant that they had retrieved, so
we felt that that was an excellent demonstration of
the equipment prior to using it at Davis-Besse.
MR. FORD: So the operators who are using
this have never done this before?
MR. McLAUGHLIN: The operators, the ones
that we are using? Yes, they were experienced. They
had done it at another plant.
MR. FORD: One other plant? What I'm
trying to get at --
MR. McLAUGHLIN: One other plant that I
know of, yes, using the actual configuration of
equipment that we used here.
MR. FORD: The reason for my questioning,
so we are not dancing around, is how sure are we that
that circumferential crack wasn't all the way through,
and the only evidence that we've got is based on the
output from this. And I'm just trying to get a
feeling as to how reliable is that conclusion that the
crack was not all the way through?
MR. McLAUGHLIN: I'm 100 percent positive
that that circumferential was not through-wall. The
reason I can say that is because the second part of
our inspection was if a flaw was found with the circ
blade, then we followed it up with the top-down tool,
so we actually removed the control rod drive
mechanisms. And the top-down tool with the ten
transducers, that's going to characterize any cracks
found in these nozzles.
MR. FORD: Because the upshot is that I
suspect -- if what you are saying is correct -- then
we must regard incidences of axial cracks as
potentially giving rise to a lot of steel corrosion at
these sort of rates.
MR. McLAUGHLIN: I would agree that for me
the biggest thing that opened my eyes when we did find
cavity 3, is the fact that axial flaws, or axial
cracks, are significant.
MR. FORD: Okay.
MR. McLAUGHLIN: Another unique feature of
the ultrasonic testing method that we used here is
that it can identify a leak path, and I'll show you a
UT scan showing leak path in a little bit. The circ
blade probe is deployed using the ARAMIS robotic
system that was developed in France, and we also had
an automated data acquisition system to retrieve the
As I just said, if any flaws were found
using the circ blade, our plan was to pull the control
rod drive mechanism and then use the top-down UT tool
to characterize any axial and circumferential flaws.
The top-down tool, because it does have
the ten transducers, it's optimized for
characterization of axial and circumferential flaws as
well as it has shown good capability of finding a leak
MR. SIEBER: That's a rotating probe,
MR. McLAUGHLIN: That's correct.
The third step in the evolution then would
be to evaluate any flaws that we had found. The
guidance that was promulgated in the letter from the
NRC to NEI was the basis for our flaw evaluation
criteria. This guidance, I will say, is for crack-
like flaws in the nozzle. The guidance offers
different criteria for pressure boundary and non-
pressure boundary flaws, and essentially our plan was
to repair any outside diameter initiated flaws in the
pressure boundary region. We would evaluate -- our
plan was to evaluate any inside diameter initiated
flaws. We would have done a crack growth rate and made
sure that they wouldn't grow greater than 75 percent
through-wall within the next cycle.
For non-pressure boundary flaws, the two
evaluations that stand out to me are you need to do a
loose parts evaluation, and essentially what that is
is if you had a circumferential flaw below the weld
and an axial flaw that could meet up with that
circumferential flaw, there is a chance that a piece
of the lower non-pressure boundary nozzle could fall
off and become a loose part in the reactor coolant
The other evaluation that would need to be
done if you had an axial flaw, you need to do a crack
growth calculation to ensure that that flaw would not
grow up into the pressure boundary within the next
MR. FORD: I'm assuming your crack growth
evaluation would be along the lines of the MRP and
whatever is approved by the NRC, is that correct?
MR. McLAUGHLIN: Yeah. What we had
committed to do was use the MRP guidance. Luckily, we
didn't have to get into that, as I'll show here in a
little bit, because originally when we were looking at
that, the MRP was supposed to have guidance out prior
to our outage, but that has been delayed.
MR. FORD: Are you going to talk now or
later about the repair criteria, or the approach, the
qualification, et cetera -- your first sub-bullet,
repair all OD initiated flaws.
MR. McLAUGHLIN: As far as the criteria of
what we would repair, this is the criteria. Any
outside diameter initiated flaws in the pressure
boundary region would be repaired.
MR. FORD: But the question is, how would
you repair it?
MR. McLAUGHLIN: The repair method that we
chose, and that was based on industry experience with
this repair method was the Framatome repair method,
which goes in and machines out the bottom of the
nozzle, and then puts a new pressure boundary weld
essentially up inside the head material itself, and
that's what we chose based on -- that equipment has
worked very well, and it seemed to us that that was a
very good repair approach overall.
MR. FORD: Now, when you say "seemed to
us", this has been approved by the staff?
MR. McLAUGHLIN: Yes, it has.
MR. FORD: And this is what will be
MR. McLAUGHLIN: No. The repair for the
cavity is considerably different than the repairs for
-- because the repairs that you're looking at here
leave the nozzle installed.
MR. FORD: And the repairs for the cavity
will be discussed tomorrow?
MR. McLAUGHLIN: That's correct.
MR. FORD: And just to put it out of our
misery, the repair for the cavity, that has been
approved by the staff?
MR. McLAUGHLIN: No, it hasn't. As a
matter of fact, a repair for the cavity hasn't been
presented to the staff as of yet. That's why we're
going to have our meeting tomorrow, to present our
overall concept for repair.
MR. FORD: Outside of the bounds of this
MR. McLAUGHLIN: Next slide, please.
Okay. So that was our plan. Now I'm
going to give you the results. The results of our
inspections are we found 5 nozzles with axial flaws,
3 of these nozzles the axial flaws were through the
pressure boundary, 1 nozzle had a circumferential
crack. The extent of that circumferential crack was
29 degrees in circumference, which equates to
approximately 1.2 inches long, and it was
approximately 50 percent through-wall.
All of our cracks that were found were
outside diameter initiated, and they were -- at least
a portion of them was into the pressure boundary so,
therefore, all the nozzles with cracks found were
going to be repaired.
The other thing I want to mention is that
nozzle 46 showed a shadow that was found on the UT.
However, it did not have any cracks going up to that
shadow, or there were no cracks found in the nozzle
MR. SIEBER: Do you have an explanation as
to why there was a shadow?
MR. McLAUGHLIN: I'm going to get -- we'll
talk about what we're doing with nozzle 46 right here.
MR. SIEBER: All right.
MR. McLAUGHLIN: I just want to give you
a rundown on the review process that we used for
reviewing the ultrasonic testing data.
The first review was performed by Level II
analysts. The second review then was -- and it was a
100 percent review -- was performed by the vendor
Level III. We also had our Davis-Besse Level III
review the data, and to present -- to have 100 percent
oversight, we brought in an EPRI person to oversee the
entire data collection process and review process.
Now, what I want to say is, after the
first four reviews here -- I'm going to call those the
initial review. All the cracks were found in all the
nozzles. There were 63 nozzles that were found
without cracks -- I'm sorry -- actually 64 nozzles
that were found without cracks -- got to get my math
right -- and then one nozzle was found with an
Nozzles 2 and 3, though, had anomalies
that we couldn't explain at the time. We did note
that further investigation was going to be required.
And then, like I said, there was a shadow that was
noted on nozzle 46, but there were no cracks leading
up to the shadow. So, in accordance with our repair
plan at the time, nozzle 46 was not considered a
repair candidate. The reviews, those first four
reviews, focused on finding cracks.
Now, based on the nozzle 2 and 3 corrosion
findings, we performed a follow-up review, and that's
what the last bullet there is. We wanted to have
another review done by Framatome and a new EPRI
individual of all the data looking for anomalies we
had seen in nozzles 2 and 3. So we went back and did
an experience history of the UT data.
Nozzle 46 was again identified as
requiring additional investigation. This review also
confirmed that we had found all the cracks the first
What we've done with nozzle 46 so far is
we've removed the control rod drive mechanism
associated with that nozzle. We inserted the top-down
rotating UT tool to confirm the findings. The
findings were confirmed. We performed visual
inspections of the top and did not find any corroded
areas like we had seen with nozzles 2 and 3. So what
that led us to was, okay, we don't have anything in
the nozzle material itself, or there was no cracks in
the nozzle material. We can't for sure explain why
there is a shadow there.
So the next thing we wanted to look at
was, okay, let's do a dye penetrant test on the wedded
surface of the J-groove weld, and that's what we did.
The dye penetrant test, we found four rounded
indications. We ground those indications to an eighth
of an inch depth. We cleared one indication, and we
found two others still rounded.
So what we've done to this point I would
say is not destructive, however, we conservatively
have placed nozzle 46 in the quarantine associated
with our Confirmatory Action Letter, and we're
evaluating further actions. So that's where we're at
with nozzle 46. Next slide.
This slide shows the relative positions on
the head of the nozzles that were found. One thing I
want to point out is that nozzles 1 through 5 are
manufactured from the same heat. And then I also
wanted to show you the location of the cavity on
nozzle number 3.
MR. ROSEN: Have you gone back to other
places where other people have done the UT examination
and seen whether are any anomalies in their data,
anything that looks similar to what you're seeing?
MR. McLAUGHLIN: We have not. I can't
speak for with Framatome to say with they have or not.
MR. ROSEN: Have you asked yourself what's
different about 4?
MR. McLAUGHLIN: We have, and we just
can't -- we don't have any explanation why 4 is -- I
mean, if you look at the other plant that has this
heat, they did ultrasonic testing and the majority of
theirs are not cracked. Now, why did four out of five
of ours crack? I couldn't tell you. Maybe I'll pass
that question off to the root cause, but as far as I
know, I don't think we have an answer as far as from
an industry standpoint now of why -- obviously, this
heat, though, there's something with it.
MR. FORD: There's something really about
this propensity towards cracking, and that's
understandable. It's extreme sensitivity to heat-to-
heat variations, and we don't know why, unfortunately.
MR. McLAUGHLIN: Correct.
MR. FORD: But in terms of the quarantine
and the root cause analysis, we're not going to get
much more, are we? Everything is destroyed.
MR. McLAUGHLIN: That's correct. The
machining process, unfortunately, removes all the
cracks. I mean, that's what it's designed to do, and
it did that. So, yeah, there's no cracks that we can
pull out of these nozzles and say, you know, send it
off to a laboratory and do any testing.
MR. FORD: Okay. Well, we'll get into
those discussions when we come to the root cause --
MR. BIFITCH: This is Steve Bifitch
(phonetic) from Framatome. We have nozzles 3 and 2 in
quarantine right now, and the plans that are in place
are to take those nozzles and do destructive failure
analysis of the nozzles. Obviously, the cracks are
now gone, but we can do things with the nozzles such
as look at the micro-structure, look for areas that
are possibly cold-worked that could cause higher
propensity for stress corrosion cracking and things
like that. So we have plans in place to do that, but
we have not continued with that at this point. They
are still in quarantine.
MR. McLAUGHLIN: So, hopefully the
laboratory testing on nozzles 2 and 3 that have been
removed -- because it is the heat material, the actual
heat material, maybe that will tell us something --
and help further the root cause for the industry.
MR. FORD: Just for my information, what
does "in quarantine" mean, they can't do anything to
it? They can't touch it? They can't --
MR. McLAUGHLIN: No, no. What in
quarantine means -- and this was something we worked
out with the staff. What we do is before we go in and
do anything that could affect root cause related data,
we submit a written plan to the staff. The staff
reviews it and then we discuss it, and so far we've
discussed it over the telephone, and if there's any
comments, then we incorporate those into the plan.
And we've broken it down into small enough sections
that it makes it, I think, relatively easy to review,
and then it also helps us to follow that plan. And
that's the way we've proceeded so far with the
MR. SIEBER: Has anybody attempted to
identify every nozzle and every point up from that
MR. McLAUGHLIN: We know every nozzle in
every plant that has that heat in it.
MR. SIEBER: And how many plants does that
affect, do you know, or can you tell us?
MR. WOOD: I believe it affects three
plants, ourselves and two others.
MR. ROBBIN: This is Mike Robbins, from
Duke Energy. At our Oconee 3 plant, of the 69 nozzles
that are in Oconee 3, 68 of them have this heat
material, and most of the cracks we found at Oconee 3
are of the same heat material.
We've also taken samples of the Oconee 3
nozzle material and have done fairly extensive
metallurgical work looking at those nozzles to see if
there's anything unique or different about the
material, and there's nothing in the characterization
that we've seen so far that would suggest there's
anything obvious as to why these nozzles cracked. If
you look at the micro-structure, the grain sizes,
those type things, you see pretty much what you would
expect to see of Alloy 600 material.
MR. WOOD: So the answer is two plants,
Oconee and Davis-Besse.
MR. McLAUGHLIN: I believe that that's
true, there are two.
DR. DAVIS: ANO has one nozzle in this
MR. McLAUGHLIN: Okay. I'm sorry. Next
What I'm showing here is -- essentially,
this is ultrasonic test data rollout of the nozzle, so
if you could envision that you would roll the nozzle
out flat, a couple of things I want to point out on
this. If you look across the top, the degrees, zero
degrees, just for orientation purposes is downhill.
The left side shows inches, and the way that the
measurement is done is from the top of the flange of
the nozzle down to the bottom of the nozzle, so that's
why the numbers decrease as you go from the top to the
bottom -- I'm sorry -- increase as you go from the top
to the bottom.
The solid black line in this area here,
that depicts the J-groove weld, so that the pressure
boundary area is defined. The bottom -- along the
bottom there where the numbers and the colors are,
those are just crack numbers. And I just wanted to
show you that on this nozzle, this was the crack that
was found with the top-down ultrasonic testing
equipment and, as you can see, it does not proceed all
the way through the pressure boundary. This nozzle,
however, because the crack did go up into the pressure
boundary, this nozzle has been repaired.
This is nozzle #5. It had a crack similar
to the one in #47, small crack that went up into the
pressure boundary, did not go through the pressure
boundary. This nozzle has been repaired also in
accordance with our plan. Next slide, please.
This is a rollout of nozzle #1. A couple
of things, as you can see there are a significant
number of cracks in nozzle #1. Two of them go through
the pressure boundary. The crack that I want to point
out is this crack right here, and in a couple of
slides I will show you there is a leak path that was
associated with that. Remember, I said earlier that
the UT data can actually detect a leak path. This will
be the crack when we looked at the printout for #1
that caused that leak path. Again, this nozzle has
been repaired in accordance with our plan.
MR. SIEBER: Is there any significance to
the angle of the stripe on these?
MR. McLAUGHLIN: That shows the relative
MR. SIEBER: That's not the crack?
MR. McLAUGHLIN: -- the crack, no. That's
where the crack actually grew up at that angle. So it
could be an axial crack, but it didn't grow straight
up and down the nozzle, and that's what that's
MR. SHACK: Suppose I had a J-groove leak
and I got some OD attack, how sensitive is the blade
UT to the OD initiated cracks? How deep would it have
to be before I'd see it?
MR. McLAUGHLIN: From a UT standpoint,
what it's looking for is a gap between the outside
diameter of the nozzle and the nozzle bore itself.
From a UT standpoint, it doesn't really matter if it's
a couple of thousandths or several inches. So it does
not have to be a very large gap. And if you want a
real good explanation of the UT and the process that
we use to find a leak path, I have Kevin Hacker here
from Framatome and he can explain that.
MR. SHACK: All my question is, if I
initiate an OD crack, can I see a 10 percent through-
wall OD crack with the blade UT?
MR. McLAUGHLIN: Yes, you'd be able to.
MR. SIEBER: One other question before you
leave this. These are all axial cracks?
MR. McLAUGHLIN: That's correct, yes.
MR. SIEBER: If you had a circumferential
crack, what would it look like on that drawing?
MR. McLAUGHLIN: The next slide I'll show
MR. SIEBER: Okay. I'm a good straight
MR. McLAUGHLIN: Excellent lead-in, thank
Okay. This is the results of nozzle 2
inspections. A couple of things I want to point out
on this nozzle 2 -- well, actually three things. One
is, as you can see, there is the circumferential flaw
that was found. I want to point out this crack here.
This is the second longest one above the weld that's
been found to date. And the other thing I want to
point out is we'll see in a few slides, the corroded
area for this nozzle came down approximately like
this, came up -- so these are the three cracks here
that caused that corroded area. Next slide, please.
MR. SHACK: Your laser pointer was
approximately correct on the height above the J-groove
MR. McLAUGHLIN: I'm sorry, what was it?
MR. SHACK: Just draw it for me again on
this picture where the corroded area is on nozzle 2.
MR. McLAUGHLIN: It would be right around
-- just over past the 270, come down about like this,
in that area was the corroded area that we found.
MR. ROSEN: I'm sure everybody else in
this room knows except me, the lines that go this way
across, that's the weld area?
MR. McLAUGHLIN: These lines, these black
MR. ROSEN: Yes.
MR. McLAUGHLIN: That depicts the weld,
MR. FORD: I'm jumping the gun to the root
cause. Why didn't you see -- why would you not expect
to have seen excessive corrosion on the other side?
That third crack along there looks about the same
extended -- in your comments, you said that you're
correlating excessive corrosion at one inch per year,
or thereabouts, to the length of the crack, the axial
crack. So why there and not at the other --
MR. LOEHLEIN: We will be talking about
that, but clearly you'll see here on this slide and on
the next one, it's the length above the weld. It
really is the crack length above the weld that's
different. This crack over here is only about a half-
inch above the weld, and the crack through a weld that
size is pretty minor.
MR. FORD: And that difference is enough
to make a difference between microns a year and inches
per year? I don't believe it. I find it hard to
MR. LOEHLEIN: We'll go into that in more
MR. FORD: Okay.
MR. McLAUGHLIN: Next slide, please.
This is the same rollout of nozzle #3. I
want to show you the middle again, just like Steve is
talking about, this was less than an inch above the
weld. This crack over here is kind of hard to see due
to the color, but this is the crack that caused the
corrosion or the cavity around nozzle 3. And if you
note, it does extend approximately 1.2 inches above
the weld. So it's the longest crack above the weld
found to date. Next slide.
What I wanted to show you here is I wanted
to show you the leak path that can be detected with
the ultrasonics. What this is is a plot of the
reflected sound from the nozzle-to-head interface.
The red indicates areas of lack of contact, however,
UT cannot determine the depth of that lack of contact.
So it could be a couple of thousandths or inches, and
the UT can't really discern the difference. The dark
areas are areas of good contact.
One thing I want to point out, at the top
of the head here, you can see that from the UT trace.
That's the top of the head. This black is the J-
groove weld. And then, again, I wanted to show you
the leak path, and you can see the crack coming up
through the weld area, and this red area going all the
way out through the top of the head, that's the leak
MR. SHACK: So that's my zero azimuth of
the other plot.
MR. McLAUGHLIN: Yes. What this is, this
plot is from the top-down tool. The top-down tool --
the reason -- anyway, the degrees don't line up
because the top-down tool is indexed to an index mark
on the top of the flange, and all those index marks
point to one axis on the head. So the rollout won't
be the same orientation as what you see in there.
MR. SIEBER: Do I interpret all the red
areas between the weld and the interface as cavities
or leakage? How do you interpret that? I can see the
MR. McLAUGHLIN: You mean these areas
MR. SIEBER: Right.
MR. McLAUGHLIN: If you look at it, there
are a couple of cracks there, and they probably did
start having some minor amount of corrosion. So
there's a good chance that there was a small --
MR. SIEBER: So that's like a labyrinth.
MR. McLAUGHLIN: -- of boron in between
the outside diameter of the nozzle and the bore.
MR. SIEBER: Sort of like a labyrinth in
MR. McLAUGHLIN: Correct. If you look at
it, the leak path doesn't go straight up. The actual
contact area is -- I'm sure there is gaps
microscopically, and the water is going to follow the
easiest path up, and that's what it's doing.
MR. SIEBER: If you would slice that up,
you would see the micro-structure with these various
cavities and cracks in it, if you were to do a
destructive examination of that?
MR. McLAUGHLIN: If you could remove a
nozzle intact by removing the J-groove somehow?
MR. SIEBER: Yes.
MR. McLAUGHLIN: If you had a slice there,
you could see those cracks. And if you sliced it up
MR. SIEBER: You would see these cavities.
MR. McLAUGHLIN: You may be able to.
There is a gap always -- you know, it's shrink-fit,
but it's not going to be a perfect fit. And the reason
I say that is because when we did the repair of this
nozzle here, the cut line was right here. So you're
going to see some of this. We performed dye penetrant
testing on this area down here of the bore, and there
was nothing found.
Now, the repair process does remove a
small amount of bore inside diameter, so that may have
cleaned that up, so it's not very deep.
MR. SIEBER: So one could conclude that
when that became a through-wall crack and borated
water began to go through it, it was not a jet
impingement situation, it had to start as a corrosion
situation to develop enough space in order to get the
steam cutting velocity high enough to do steam erosion
damage to the head.
MR. WOOD: If you look at that, I think
you can see where the popcorn boron gives rise to the
places where it comes out at the top of the head.
MR. SIEBER: I presume it's coming out at
that point at a pretty -- pretty fresh and pretty low
flow and not a lot of iron in it.
MR. McLAUGHLIN: I would imagine as far as
this nozzle, consider what we found with the dye
penetrant testing, I would believe that there was no
iron removal in this area. There was probably a small
amount of corrosion, like I said, that could have been
removed during the machining process.
MR. SIEBER: Thank you very much.
MR. McLAUGHLIN: Next slide, please.
This is the same type of printout or plot
for nozzle #2. There are a couple of things I want to
point out on this. Here's the three cracks that we
showed you earlier. You can see this red area, and
then, of course, it wraps around to here. Another
thing that I want to point out is this area right here
follows the contour of this weld. This is the top of
the head. However, you can't see it right here in
this area, and you can't see the head here. And that
was bored out -- this is the area that we found that
there was corrosion. There's about an eighth of an
inch of steel lost at the top of the head.
So the UT did show that there was
something going on up there.
MR. SIEBER: What is the significance of
the plot to the right of the --
MR. McLAUGHLIN: I'll have to refer that
to Mr. Hacker because I'm not sure. What is the plot
to the right, Kevin?
MR. HACKER: That's the outside surface of
the nozzle. That's representative of the depth, and
the left side of that view being near the ID surface.
Kevin Hacker, Framatome.
MR. McLAUGHLIN: Next slide, please.
This is the picture that you saw earlier.
We stole it from AIT. We felt this was an excellent
representation of this nozzle. Again, at the top,
it's about an inch -- or essentially all the way
through the nozzle, it's 1 3/4 inch wide. It starts
approximately 2 inches above the top of the weld, and
it does extend all the way through the top of the
head, and it ranges from 1/4 to 3/8 inch deep. It's
about 1/8 inch at the top of the head.
I guess the one thing that I did want to
point out is we removed nozzle 2 to help in
characterization of the root cause. When we did that,
the metallurgist who reviewed that cavity, we did some
extensive video tapes, we also did an impression of
the area. They looked at it and determined that this
was corrosion, not erosion. So I think that that's
kind of significant. It feeds into what we're seeing
MR. FORD: How did he come to that
MR. McLAUGHLIN: I'll refer that to Steve
MR. FORD: Are you going to cover it later
MR. McLAUGHLIN: Are you going to cover
MR. LOEHLEIN: We can talk about that.
The metallurgist is right here. Steve Bifitch is
here. He's one of the members of the team, he and Dr.
Mark Burdofski (phonetic) from our Failure Analysis
area of Beta Labs reviewed that extensively this past
Friday, and did conclude it's corrosion. If you want
to talk about it, Steve, go ahead.
MR. BIFITCH: Yes, it's a little detailed.
When we reviewed the videotape, you could see -- I
mean, obviously, the video camera that you're looking
at gives you a very good close-up picture. You could
see typical remnants of corrosion, generalized
corrosion that you would expect to see. You see
things basically eaten away, and you're not seeing a
flow type pattern that I would expect from steam
erosion. Now, obviously, when we get a better look at
it, I asked the Framatome folks to go back in there
and look at it again and take some measurements with
rollers and stuff, so that we can get a better
characterization of what it actually looks like
because this is just a schematic based on what we knew
about a week ago.
MR. LOEHLEIN: But, Steve, isn't it also
true that from the impressions and everything, we know
that the areas of deepest penetration are somewhat
higher up in the annular region than the actual crack
MR. BIFITCH: Yes, looking at the --
MR. LOEHLEIN: Corrosion as opposed to
erosion because it's not actually right lined up at
the exact leak points, but higher up.
MR. FORD: You've got independent data --
I mean, you've come out with a hypothesis right now.
Do you have independent data, in either the open or
closed literature, which will confirm that hypothesis
with relevant corrosion rates?
MR. BIFITCH: We'll talk about that during
the root cause portion of this presentation, but to
answer the question, yes, there is an adequate amount
of data in the literature and in the closed literature
from the EPRI guide book that verifies what we're
MR. FORD: General corrosion rates of 1/4
inch per year for this one, without any flow assistant
effects at all?
MR. BIFITCH: Yes.
MR. SIEBER: This doesn't surprise me
because fluoritic material out in the air exposed to
high concentrations of boric acid corrode pretty fast.
I've seen bolting --
MR. ROSEN: We've seen reactor coolant
pump bolts made of this kind of material extensively
corroded back in the mid-'80s. So general wastage
like this is possible with those kinds of rates
without any flow phenomenon.
MR. SIEBER: And all of that can occur in
MR. ROSEN: Well, it can occur very
quickly. I don't know --
MR. SIEBER: Well, if at the end of the
refueling, the next refueling, it's there.
MR. FORD: And this hypothesis would also
explain why you see it specifically on this geometry
and not on Oconee? It does not explain it, or it --
the question was, you've got a hypothesis which you've
backed up by independent data, to explain why you've
got corrosion rates of this magnitude on that
particular geometry, annulus geometry, et cetera, and
does that same hypothesis explain why you do not see
it at Oconee?
MR. LOEHLEIN: There's a metallurgical
answer and then there's a root cause answer that we'll
go to. Do you want to talk about the metallurgy,
MR. BIFITCH: Well, you say of the extent
that we're seeing nozzle 2, there's very little
corrosion, in reality. I mean, that's not a lot of
MR. FORD: Okay. But it's the same --
that same hypothesis presumably explains why you've
got 1-to-10 inches per year on nozzle 3?
MR. BIFITCH: Yes, from a root cause
standpoint -- and, again, Steve will get into this --
but we feel that nozzle 3 had been cracked and leaking
much longer than nozzle 2, and the same for nozzle 1.
So the age of the leakage is significantly different
between 3, 2 and 1.
MR. FORD: So it would be about a factor
of 10 difference in time?
MR. LOEHLEIN: We'll get into that.
MR. McLAUGHLIN: Next slide, please.
This is the same data that we had earlier
for nozzle 3. A couple of things that I want to point
out. No. 1, if you look up here, we should see the
head, the top of the head should have been up here.
If you see these two lines here and here, those are
the outlines of the cavity. Obviously, we didn't know
it at the time that we took the UT data, but -- so
this entire area here is the cavity and this is the
crack that caused that cavity. Next slide, please.
I just wanted to use this picture to
introduce the cavity to you. A couple of things I
want to point out. This distance here is the 4 inches
where nozzle 3 was removed. This is the remnant of
the J-groove weld that's left. And then this area
here is the exposed cladding. There's also an under-
hang in this area here that actually extends down to
about right in this. It's enough so that you can
actually stick your fingers underneath there.
MR. FORD: That's what you call a "nose"?
MR. McLAUGHLIN: Nose?
MR. McLAUGHLIN: Next slide, please.
I'll just go over what was going on at the
time when we discovered the cavity. We were
performing the machining operation on nozzle #3. The
machine that we use is hydraulically locked into the
nozzle. There was an unexpected movement of the
machining tool, it actually rotated 15 degrees and
then stopped. We stopped at that time, stopped the
machining operation because we knew then that the
nozzle had rotated.
When the machine was removed, there was
some mechanical agitation with that process. That
helped loosen up the nozzle further, and the nozzle
then was -- a lot of people have seen pictures of the
nozzle leaning against the flange that was next to it.
There is approximately 1/2 inch in between from one
flange to another, so it's not a real big area, or big
We did remove the nozzle and cleaned the
cavity, and that's when we discovered that we had some
significant degradation of the reactor vessel head.
Next slide, please.
Again, this is another picture of the
nozzle area itself. What I wanted to do is kind of go
over some of the actions that we've taken to gather
data and characterize the cavity itself. I want to
point out, like I said earlier, all these actions were
reviewed and did have concurrence from the staff prior
to being implemented. We had a written plan and then
we had a work order so that we could follow our
administrative process through to ensure that there
wasn't anything missed in the data gathering.
The first thing we had to do was remove
insulation to gain access into the cavity. We
performed several video inspections of the cavity
area, as well as nozzles 2 and 1. We've collected
boron and corrosion samples from both the cavity and
from the corroded area in nozzle 2. We had a
collection device underneath nozzle 2 when we pulled
that nozzle out.
We've taken ultrasonic readings and
mechanical measurements so that we can get a good idea
of the extent of the cavity, and we've done some
liquid penetrant examinations of the cavity as well as
taken impressions of the cladding area. Next slide,
This is a tool that we had built to aid in
taking mechanical measurements of the cavity. As you
can see, the distance is about 4 inches. This fixture
here was installed in the bore of the nozzle where
nozzle 3 was removed so that way we could index from
the nozzle in all our measurements that were taken.
We also used this little jig here so that
we could take measurements off and we would know what
the angle that we were taking those measurements.
MR. ROSEN: Did you clean the hole up at
all, or is that the way --
MR. McLAUGHLIN: It was cleaned at this
point when we did these measurements.
MR. ROSEN: You just scraped it with
sandpaper or something like that?
MR. McLAUGHLIN: Brushes.
MR. ROSEN: Wire brushes?
MR. McLAUGHLIN: Not wire brushes, but
We also probed the underhang area with a
mirror, and used a wire so that we could determine
where the farthest point was. The farthest point is
approximately right in here, and the last slide that
I have shows the actual dimensions of that.
MR. SIEBER: What was the surface like
after you used the brushes on it? Was it solid
material, or was it spongy?
MR. McLAUGHLIN: No, it's very solid
material. It's actually pretty smooth. It's kind of
got contours to it. I don't know, I guess these guys
could probably characterize it a little bit better.
I mean, I have gone out and felt it and touched it a
few times, but --
MR. SIEBER: At those radiation levels?
MR. McLAUGHLIN: I took some of these
measurements myself. I guess my feeling is that if
I'm going to be the project manager and the team lead,
I need to see what it is that I'm up against, and I
needed to experience it first-hand.
MR. SIEBER: I just want you to be aware.
MR. McLAUGHLIN: I agree. We do practice
From a dimensional standpoint, I'll point
out a couple of things. From here to here is
approximately 6 inches. From here to the edge of the
cladding here is approximately 5 inches. The farthest
point that we saw and measured from the edge of the
bore to here is just a little over 7 inches. One
thing I want you to notice is the 13-inch cutout line
that we have. That dimension is approximate at this
point. What that's showing is our plan going forward
is to use an abrasive water jet process to remove this
entire cavity. We chose the abrasive water jet
process for two reasons: One, that we could remove
the entire cavity with it, and the second is that
there won't be any heat input from the removal process
that could destroy or alter any information that can
be gathered from the cavity.
The other thing I wanted to point out is
that we took ultrasonic UT ratings of the cladding for
thickness. The readings we got had an average of .297
inches, and the one single point, the lowest point,
was .24 inches.
For my part, I've described our plan.
I've described our findings. I've talked to you about
the cavity discovery and the characterization of that
cavity. Are there any further questions?
Okay. With that, I'll turn it over to the
person who I'm sure you all want to talk to, Mr. Steve
Loehlein, to discuss the root cause.
MR. FORD: Can I just ask a timing
question, Steve? How long do you think -- assuming we
don't ask too many questions, roughly how long are you
going to take?
MR. LOEHLEIN: Well, when we've done this
presentation just sort of in a dry run fashion, it's
been 20 minutes to half an hour, but it really is
determined a great deal on how many questions we get.
So if you're asking should we take a break --
MR. FORD: I think what we'll do is take
a ten-minute break. I'd like to finish at 6:00
o'clock, however, so let's make it no longer than ten
(Whereupon, a short recess was taken.)
MR. FORD: We are now back.
MR. LOEHLEIN: Once again, good afternoon.
I am Steve Loehlein. I am the Root Cause Team Leader.
Before I get started, I just want to make one comment
based on a question that had been asked earlier of Mel
Holmberg, and that had to do with our condition report
records for things like steam relation of boric acid
on the vessel flange and the containment air coolers,
and the root cause report that we have prepared does
have condition report references historically that
were written on those subjects. So there is some
information on that for Mel and for whoever, and when
they see the report they'll see them in there.
I'll start off by saying that soon after
this damage was recognized at nozzle 3 and then soon
after that in nozzle 2, Davis-Besse's management team
realized quickly they needed an investigative team
with members who would have a variety of expertise and
a variety of experience. They wanted to have a team
that was going to have objectivity. That's why
persons like myself who are from Beaver Valley Power
Station, and another member of the team that I've
brought in from Beaver Valley who is our Latent Issues
Program Manager, and we also wanted to have, of
course, ownership by Davis-Besse staff for the results
of the root cause, so we have members on the team
directly from Davis-Besse staff, and we wanted to have
the finest technical expertise on the team that we
could get, so we augmented our folks with the
technical expertise from Dominion Engineering, from
EPRI MRP, from Framatome, and we had a failure
analysis expert from our Beta Labs also come in and
Before I get into the root cause
discussion, I want to familiarize people with the
terms we're going to use here because we have under
the root cause determination process that we have in
our company, we have definitions for specific terms,
and they are up here on the screen. Probable cause is
for us, by definition, a root cause that cannot be
validated after-the-fact. We also have root causes
that are the more what I could call common definition,
and that is that root cause is something that, if
eliminated, would have prevented the incident or
event. Similarly, I think our definition of
contributing cause is pretty familiar in that it is a
cause that either increases the likelihood or the
severity of the incident or event.
The other thing I'll point out before we
get started is that there's going to be a lot of
discussion that talks about probable cause for the
cracks, and then root causes for the damage that
occurred at Davis-Besse, and I think by now we've
heard a lot about the differences. We have
discussions about PWSCC and then we have discussions
So by this time, probably to no one's
surprise, the damage to the RPV was not identified
until we had machined on nozzles 2 and 3. That was
just by happenstance because at the time the damage
wasn't known, so we're not likely to be able to find
the data that will prove that PWSCC caused the
cracking in these nozzles, but we believe that this is
highly supported by the evidence that's available.
Since PWSCC is a known mechanism in the industry, it
really doesn't explain the damage that occurred to the
So, from root cause base, we identified a
root cause which was something that permitted the
conditions to develop on the head that allowed the
corrosion to occur, and what we determined was that
Boric Acid Corrosion Control and Inservice Inspection
programs were such that they allowed for the
accumulation of boric acid to remain on the head.
What this did or what this resulted in is the plant
did not identify through-wall cracks and leaks during
prior outages when they existed, that the plant
returned to power with boron remaining on the head
after outages, and that we were unable to identify the
damage that was occurring on the RPV head by 12RFO,
which is the outage prior to this one that we're in
A number of contributing causes are
identified in our report. The major ones I'll go over
here. The first one we've heard some about before are
environmental conditions, cramped conditions and so
forth caused by the design, the very tight fit between
the insulation layer and the top of the head, the
small drainage openings that are used for access, the
high radiation area, the temperatures, all these
contributed to making this access for cleaning and
inspection difficult. So the same three bullets
appear under there: It made the identification of
cracks that did not occur in prior outages, cracks and
leaks, we returned to power with boron on the head in
the center head region, and we did not identify the
damage when it began.
Another important contributing case were
equipment conditions that we had due to uncorrected
CRDM flange leakage. We talked about -- a little bit
earlier, I think John Wood showed the first slide, and
it appeared later, that showed where the flanges are
and how there's the insulation layer between, and so
forth, and the historical problems with flange leakage
on the B&W plants -- Davis-Besse was no exception --
had a number of flange leakage issues in earlier
years, which now appear to be corrected, but some of
those were bad enough to allow boric acid to leak down
onto the head in regions where it was pretty
inaccessible, and so accumulations from boric acid
leaking from above were something that was
internalized by the organization as common.
MR. SIEBER: Steve, how long do you think
this corrosive environment was present, how many
MR. LOEHLEIN: We have a timeline later in
the presentation that I can go -- it's probably best
if I go over it then.
MR. SIEBER: Okay.
MR. FORD: I just want to be sure because
it's been intimated in some of the documents that's
been going around that a potential source of the boric
acid or whatever the environment is, the boric acid
rich, in the annulus originated from the flange region
and dripped down. That's been intimated. And what
you are saying is, no, that may have confused the
issue, but it was not the prime source, that the PWSCC
was the prime source of the annulus environment, is
MR. LOEHLEIN: PWSCC is what we've
concluded is the initiator of the cracking, not the
initiator of the wastage. I don't know if I've
misinterpreted your question, and whether you're
asking how does that relate to the leakage from above?
MR. FORD: As I understand --
MR. WOOD: I think you are correct in the
way you stated that, that because there had been
flange leakage over a number of years, that that was
then attributed to the boron that was seen on the head
versus the leakage coming out of nozzles as being the
MR. FORD: That's in no way intimating
that the leakage occurred in the flange above dripped
down and went into the annulus and caused this
problem, that's not the issue.
MR. LOEHLEIN: No, we did not. In other
words, just to be clear, the flange leakage that
occurred over the years did not have anything to do
with this wastage incident, or anything we've been
able to find.
As part of the probable cause for the
nozzle leakage, we did assemble information on PWSCC
and other possible reasons for cracking. I think by
now we talked about the main factors associated with
primary water stress corrosion cracking, susceptible
material, high tensile stress, and aggressive
environment. Of course, all of these were present at
DB as they are at other PWR plants.
MR. BONACA: I have a question. Your root
cause, you go -- I mean, somebody could ask a question
of how far did you go back into asking why this
happened, and you're saying the plant did not identify
through-wall cracks during prior outages, plant
returning to power with boron on the RPV head after
outages -- we know these things happened, of course.
But there were questions that were raised by the NRC
on the missed opportunities, for example. I would
like to understand, given that your filters needed to
be replaced every other day, what do you attribute
that to and did not connect at all. I would like to
MR. LOEHLEIN: Well, the condition report
records and the interviews we conducted, the plant
staff did not make the connection is all we can say
about it. We investigated this from root cause
standpoint, and we can say that that connection was
not made, that it was -- that the source could be
nozzles. It was felt to either be corrosion from some
MR. BONACA: I'm not saying that we want
to evaluate this here, all I'm only saying that to do
it through root cause analysis that would prevent a
recurrence of this nature, you would want to go
farther back to understand really how come we
misinterpreted these issues.
MR. WOOD: hat's correct.
MR. BONACA: What do we need to do to
prevent recurrence of such event.
MR. LOEHLEIN: That's correct. We are
looking at the management issues that allowed us to
have that blind spot in our thinking.
MR. BONACA: The reason why I'm bringing
it up is because I think it is important generically,
as I said before, to other units to try to read from
apparently maybe indirect readings, you know -- they
are not doing direct -- but, really, they are maybe
not specific in indicating the crack or the issue, but
boron deposits somewhere --
MR. WOOD: And I believe that the AIT
agreed with that, and that's why Information Notice
2002-13 was issued in order to draw the analogy to the
containment air coolers and the radiation elements.
MR. LOEHLEIN: It's also been mentioned
earlier that in comparing Davis-Besse to others, we
have observed that all the through-wall leaks at
Davis-Besse are from a material heat. The displayed
leakage in another plant, it's the heat identified
there. We also noted that all these locations are at
the top of the head, which is a region expected to be
of lower stress than other regions in the head, but
it's also true that nozzle 4 is exactly the same in
terms of location and all that, yet it had no cracks
identified at all, and it is the same heat.
We also considered other possible causes
of the cracks, like thermal fatigue, inner granule
distress corrosion cracking, RCS chemistry, and some
others, and we were able to dispel all those and we
are pretty well convinced that primary water stress
corrosion cracking was the initiator as far as cracks
So that led us to, again, what was
different about Davis-Besse's cracks, and it's been
mentioned earlier. It's an important difference in
that the through-wall cracks above the weld are the
largest that have been reported to date.
MR. SHACK: Is that true even for the circ
crack at Oconee?
MR. SIEBER: Probably not.
MR. LOEHLEIN: I don't know that about the
circ crack at Oconee.
MS. KING: Christine King, EPRI MRP. I
think what you're referencing is the axial length.
This is a discussion -- a comparison of the axial
flaws found in the industry today. Oconee still
remains our largest circumferential flaw identified.
MR. SHACK: My real question is, do you
believe the leaks through these cracks are larger than
the leak through the Oconee circ crack? That seems to
be where we're headed here. Did anybody check that?
MR. LOEHLEIN: As part of this root cause,
we would not have studied that. There's going to be
plenty of ongoing work that will compare this to other
things that are known and other events that are
reported in the Boric Acid Corrosion Guidebook and
MR. FORD: But, surely, for the probable
cause, root cause analysis to be valid, you've not
only got to explain quantitatively why you've got
cracks and other people don't. You've got to go
through that process and, therefore, you'd need much
more of a database than just that to prove your case.
For instance, the other nozzles which cracked at your
plant, which did not show the excessive corrosion,
were they .9 of an inch, .8 of an inch, and they
should therefore have a plot of amount of corrosion
versus crack length, axial crack length, and would be
uniform for all plants with that heat.
MR. LOEHLEIN: I don't think you'd ever be
able to do that because every nozzle is loaded
differently, has different residual stresses, responds
differently during plant heatup and --
MR. FORD: Well, that then gives rise to
the occurrence of the PWSCC, the stresses aspect.
MR. SIEBER: Then there is the time.
They've been able to analyze to some extent how long
this condition persisted.
MR. LOEHLEIN: I guess what I'm saying, if
it were that predictable and you could reduce it to
those kinds of numbers, we would have had leaks at
nozzle 4, and we don't. We don't even have cracks.
MR. SHACK: But you are arguing that the
difference -- the reason why your behavior with
leakage is different from the other plants with
leakage is simply that you're older. I mean, your
argument leads to the conclusion that this will happen
at all plants that leak. Is that --
MR. LOEHLEIN: What we would say is that
if a leak is not attended to and it is allowed to
continue where it can create boric acid pools above
it, and then that leak continues to get worse and can
allow the boric acid to remain wetted near that
annular region, that significant corrosion rates can
begin. And we'll get into the timeline and all that
a little bit further here, but time is the issue. How
long do the leaks exist? How much boric acid do you
apply to the region? And we'll get into that. But
the leakage rates, the important thing to understand
about the leakage rates is that they are not at all
linear with the axial crack length, they are quite a
bit nonlinear. And so the crack lengths, as they
enlarge, produce rates and can produce leak rates
MR. SIEBER: Is there a reason for this,
the physical reason for this, the chemical reason for
MR. LOEHLEIN: There are a number of them,
and there's models that have been run for it, and
we'll talk about them on succeeding slides. So why
don't we go on and move forward.
MR. SIEBER: I think it's interesting to
point out that every crack starts as a small crack,
and there is crack growth going on in every plant that
there's a crack initiator. So, sooner or later you're
going to get to a critical crack size that causes
leakage that meets these conditions unless its
repaired, but all of these are covered under the Code.
You have to repair them once you find them, under the
Boron Pressure Vessel Code.
So looking at nozzle leak rates, what we
believe they were at Davis-Besse, we examined the
subject area from two perspectives, one was the
analytical one and one was from available plant data.
Different analytical models were looked at. There's
a model out there that looks at this crack in a pipe,
there are others that are finite element type analyses
and which we're able to model whether the region is
supported by a surrounding material like the head, or
whether it's relaxed like you would see after enough
corrosion takes place that there is no supporting
mechanism, and the overall range on these predictions
is fairly large -- 0.025 to 0.87 gpm is what we came
up with on those approaches.
Looking at plant data, though, which is
using things like the unidentified leak rate and the
amount of boric acid on the head, and so forth -- and
our Root Cause Report goes into some detail as to how
we arrived at this -- the most probably leak rate
range at the end of the cycle for nozzles 2 and 3
combined is .1 to .2 gallons per minute.
MR. SHACK: That first bullet, is that for
a given crack size?
MR. LOEHLEIN: I think we did that for a
range of -- we did that for a range --
MR. LOEHLEIN: Right, 1.2 inch crack above
the weld. And I think the .87 comes from the finite
element model that tries to model this as an
unsupported opening gap. And in answer to your
question earlier, if you have an unsupported crack
like that and you have pressure forces and other
things on it, you can open up that crack so that
linear measurement alone is not going to be a good
predictor of the flow rate you get out of it because
it's opening in width as well.
MR. SHACK: But the crack size doesn't
seem to be a very good predictor either. I mean, the
estimate for Oconee 3 is 1 gallon total leakage, and
a fracture mechanics analysis of that crack would give
you a much larger leak rate, which says it isn't the
crack size that's controlling the leak rate.
MR. LOEHLEIN: Right. There's a couple of
things that go on here. And if you really study the
Boric Acid Corrosion Guidebook -- which Mr. Hunt has
encouraged me to do a couple of times now, so I have
read it a couple of times -- there's a lot of
information out there that talks about how in the
early stages, as tight as these fits are, and so
forth, that you don't get a lot of leakage. So time
really is on your side at the front end of this thing.
As long as the gap is tight, and you'll see a little
bit of boric acid and so forth, but at some point, as
demonstrated, I think, in one of the tests that EPRI
did where we're injecting the annular region, once
there's an opening up of that gap through some -- even
if it's galvanic corrosion, if it goes on for several
years, even though it's a minor rate, it opens up the
gap eventually enough to where now oxygen can mix, and
now the crack length that prior to that didn't provide
much flow, now provides enough flow now, if that boric
acid is allowed to accumulate, stay in that region,
which it's going to tend to do much easier at the top
of a head than at the steep slope end of a head, now
you've got a number of factors working against you as
far as creating an environment that's going to allow
the boric acid to remain wetted. When it remains
wetted, it drops to the temperature of the steel in
that region, and now all of a sudden you have an
environment that allows, by all the math, quite a
higher corrosion rate. And, again, if that's allowed
to continue even further and further along in time,
this is the -- time is the enemy on this.
The overall band for leak rate, we say the
absolute minimum from all sources of information would
be 0.04 gpm and the max would be 0.2 but once again
0.1 to 0.2 is what we expect.
Obviously, the damage to Davis-Besse's
head occurred over some period of time. We have
evidence from videos of the head conditions in past
outages. We've had changes in containment conditions,
other evidence available to us, we were able to build
this probable timeline.
Now the way we've built this, it's really
built from the baseline of a couple of key facts. One
is in 1998 we saw the first signs of red-colored boric
acid coming form the drain holes on the vessel. Then
in 1999, which is a little bit after that, is when we
started to have the problems with iron oxide appearing
and clogging the filters to the rad monitors. We
believe that those two facts are strong supporting
evidence that that's when corrosion rates were of
enough of a rate that we would say that significant
rates were underway.
If you put that stake in the ground then
in that time frame, you could look back using what I
would just say typical estimates for crack growth
lengths which we know are rough estimates only, but
that's how we picked the time frame of '94 to '96 for
propagating the through-wall and some several years
prior to that for the actual initiation of the crack.
MR. SHACK: You would argue your crack is
much then is much older than Oconee 3, despite its
much longer extent?
MR. LOEHLEIN: Well, these are quite long
cracks, too, in total length. I think that the one at
nozzle 3 is almost 4 inches long, isn't it?
MR. McLAUGHLIN: It's over 4 inches long.
MR. LOEHLEIN: It's over 4 inches long.
Whether they are the oldest or not, you know, I'm not
smart enough to tell you whether that's true. I can
tell you that our post-evidence type of review of
this, the 20-20 hindsight says that signs are out
there that this leak has been there for sometime, and
that it, because of being obscured, went uncorrected
for sometime. So, we believe we had four years of
significant corrosion rates.
MR. BONACA: Since this could happen to
other units and to other nozzles, it seems strange
that we've been so lucky in all the other cracked
nozzles that we caught them all as soon as they
happened. So, I'm trying to understand if, in fact,
there isn't some kind of other mechanism that worked
here somehow -- and, of course, I don't expect an
MR. LOEHLEIN: I have looked at the top of
the head myself, and I know what -- the boric acid, if
it comes from the top, if it runs off and it creates
a path for corrosion, what that will look like. You'll
get these edge effects that are deep and so forth.
You don't see anything like that on this head in this
region. What you see is something that looks very
much like a pool that then worked itself down along
the side of the nozzle and progressed out from there.
Now, we put together in our Root Cause
Report what we think is a plausible explanation of how
it progressed, but we know there will be more work
done on it as time goes on. But, clearly, if you look
at all the facts available -- crack length, the
evidence of boric acid accumulations and how it
increased over the years, and these factors -- it
seems pretty undeniable that the leak has -- it's an
MR. BONACA: I'm not denying that, I'm
only saying that I'm thinking about the other units
and the many indications we found of cracking through-
wall, and I'm just saying it's surprising to me that
in all those cases we always caught them as soon as
they started and so there was no time for it to
develop the erosion and corrosion we have seen here in
this particular one. I wonder simply if there was
some other phenomenon that took place, I don't know
what it would be.
MR. LOEHLEIN: I think if we look at what
we have here from Davis-Besse, we have a lot -- and
you compare it to what's out here in the industry data
-- we have a lot to suggest that we have three
examples right there on the top of our head. We have
nozzle 1 which is like a brand new -- we have a very
small -- I think, above the weld we've got a half-inch
or something crack length. The damage, if you want to
call it, there is so minor we didn't even characterize
it as damage, it's just a little bit of -- you know,
we could take a feeler gauge at nozzle 1 and just sort
of tell that we didn't have a tight fit anymore.
That's kind of minor corrosion that existed at nozzle
Nozzle 2 had a small cavity which
structurally is really nothing. That was obviously
older, the crack length is longer. And we have nozzle
3. Now, by our estimation, nozzle 3 has been leaking
a fair amount for, we think, about four years. You
know, I think if I was going to give a message to the
industry, the advice that's out there is correct, once
you find evidence of a leak you need to fix it right
away because the clock starts to tick then, and four
to six years later you have a significant problem
MR. BONACA: One point that became very
clear from the presentation is that the CRDM
superstructure there really was a major contributor
because it made it very hard to look in. It really
helped accumulation of crystals up there, and I know
you already had a plan to modify that. Is there
something that can be done in this facility to make,
in fact, a modification that makes that area much more
accessible and visible, as a minimum, particularly to
MR. WOOD: We can speak to the B&W design
plants, and you can put additional inspection up there
that allow you to open up that area more, and we
unfortunately had not done that prior to this. And
there are other type units out there where, as you may
know, the insulation is basically sitting on top of
the head, and they'll have to evaluate what, if
anything, they need to do to rectify that. But I
think the Westinghouse plants, which we have a couple
at the Beaver Valley unit, they are much more
accessible. So, fortunately or unfortunately, the B&W
plants are small in numbers, and we were one of the
only ones not to make that modification.
MR. LOEHLEIN: And I do think, following
up on what you said, it's important to -- this is
something we couldn't evaluate because at Davis-Besse
all the nozzles that did have leaks were at the top of
the head. But it would be nice to know whether
farther down on the head, if a leak had gone
unattended there, what type of boric acid accumulation
could have developed -- you know, because it's going
to tend to fall off. We're not able to evaluate that,
but it is true, in this region where we were, the
boric acid that would accumulate there would tend to
stay there and provide a ready source for continued --
I mean, the leak itself provides boric acid once it
gets going, but even early on the accumulations of
boric acid from whatever source, whether they come
down from flanges up above or build up from the
popcorn boric acid that isn't removed, regardless, it
stays there because it's relatively there and it's
available when the moisture supply becomes -- you
know, comes from beneath. But all the evidence that
we have here points to corrosion supplied by a
moisture source from below.
MR. FORD: If I could just ask in terms of
time management, if you could conclude in the next
couple of minutes, if that's possible, because I want
to give the staff 20 minutes to do their concluding
statements, then I'd like to spend quarter of an hour
just for us to go around the table and give our
MR. LOEHLEIN: We are very close to the
end here. This was the -- we were just going to
mention some of the ongoing activities we have for
ourselves, which we're still -- a lot of what we're
doing is confirmatory in nature, has to do with us
sending things like boric acid samples out, confirming
that they do indeed contain iron oxide, and the big
thing we have coming, of course, is when we do remove
the area around cavity 3, which Mark talked about, and
we'll study that for evidence, if there is any, of
heavy erosion, and other elements besides corrosion as
a contributor. And, of course, we'll complete the
investigation of nozzle 46, and we plan to stay
involved with the EPRI MRP and see whatever assistance
we can provide to them.
MR. FORD: Thank you very much. John Wood
has some concluding remarks.
MR. WOOD: We're attempted to describe the
discovery, the evaluation, and the root cause of the
degradation recently found at DB. We understand there
is more to be done in regard to the technical issues
and the management aspects, and we're developing the
repairs, as you've probably heard us talk, we're going
to have a meeting tomorrow with the staff to discuss
We understand programs like boric acid
corrosion program and ISI program need to be refocused
to accomplish their goals, and we know the basic steps
we need to take to internalize the event at the site
and to revamp the organization to prevent recurrence.
So, we hope we've given you the information that
you're looking for in putting us on the schedule.
MR. FORD: Thank you very much indeed.
Could I ask the staff to --
MR. KARWOSKI: My name is Ken Karwoski.
A lot of this has already been discussed, but what I'd
like to do is basically just provide you with some of
the generic regulatory actions we've taken in response
to the Davis-Besse findings.
As was previously discussed, the cavity
was identified on or about March 7. What we knew
shortly after that was that there was a history of
boric acid-like deposits on the head for several
cycles, and that the degraded area around nozzle 3 was
associated with a nozzle that had a through-wall
crack. The root cause was being investigated at the
time, and we couldn't rule out whether or not the
corrosion was from the top-down, as a result of the
boric acid deposits from the flange leaks or from the
crack in the nozzle, or some combination of both, and
we're still evaluating the root cause.
Shortly after identifying the cavity, we
began several steps. We issued an Information Notice
about a week later. We also contacted the industry,
NEI, Nuclear Energy Institute, and also the EPRI
Material Reliability Project, and we posed several
questions to them. We asked for the plants that had
completed their Bulletin 01-01 inspections, tell us
were those inspections capable of detecting the type
of degradation observed at Davis-Besse; for the plants
that had not completed their Bulletin 01-01
inspections, what was their justification for
continued operation as a result of the findings, and
also to provide a risk assessment.
The industry conducted a survey and posed
four questions to the various licensees, and I've got
those listed on the slide, and I'll discuss those real
As the industry was doing that survey, the
staff was preparing a bulletin. That bulletin was
issued on March 18, and it requested several different
items. Within 15 days of the bulletin, we requested
licensees to provide the following information: a
summary of the reactor vessel head inspection and
maintenance programs; evaluation of the ability of
those programs to detect degradation similar to what
was observed at Davis-Besse; a description of the
inspection findings; we also asked them for their
plans for their next outage, and also we asked them
for a justification for continued operation.
We also requested within 30 days the
completion of their next outage, for the results of
those inspections, and we also asked a broader
question with it, that they provide us an evaluation
of their boric acid corrosion prevention program, and
that response is due 60 days after the date of the
bulletin, so that will be coming in in about another
With respect to the staff activities, the
industry categorized the plants based on the results
of their survey, and they had five categories, and it
really had to do with the extent of the condition on
the top of the head with respect to whether or not
they did a visual examination, how thorough that
visual examination was, was it 100 percent bare metal,
and could they rule out boric acid on top of the head.
Like I said, they categorized, and they
had five categories. We focused on the highest
category which they called "Other". We contacted all
the plants in the "Other" category in order to
understand why they were categorized in that category,
and to get an assessment of whether or not we thought
there were some issues. Several of those plants are
down for an outage now. One of them is coming down
for an outage in a month. Based on our review, we're
still pursuing discussions with one licensee to get
additional information with respect to their
inspection findings last fall.
The NRC is currently contacting plants in
outages. In the 15-day period while we were waiting
for the responses, we wanted to make sure we
understood what plants were planning to do in their
outages, and then what they were finding as a result,
to factor that into any other generic action we may
need to take. We are still conducting those post-
inspection phone calls. To date there have been no
significant findings -- and by significant -- there
may have been minor degradation, and there have been
nozzles with indications, but nothing to the extent of
what was observed at Davis-Besse.
We have started our review of the bulletin
responses. We're categorizing the results similar to
what the industry has done, and we're reviewing those
right now. The categorization basically just provides
a priority for our review. We're focusing on the ones
with the higher ranking and, if we have any additional
issues, we'll pursue them with those licensees.
That's basically all I wanted to say, is
that generically we have been acting and we continue
to do the plant-specific evaluations.
MR. FORD: Thank you very much indeed,
appreciate it. What I'd like to do is I'd like to
ask, from the NEI perspective, Larry, do you have
MR. MATHEWS: We have a brief
presentation, but he covered a lot of it, but there
might be a couple of slides we might go ahead and talk
MR. FORD: Why don't we leave it up to the
two of you as to how you want to give the final --
MR. FORD: If you could take about no
longer than ten minutes, if possible, and then we'll
follow it with, Alex, you, and then Jack, ask you just
to finish off with the staff's perspective.
MS. KING: All the stuff is contained
within your packet.
MR. FORD: Yes, we've seen that. I'm not
too sure I understand it.
MR. MATHEWS: This may be slightly updated
from Al's presentation.
If you look at this, we've tried to do
everything through today, as far as the visual
inspections and known leakage. We've also -- these
are the plants that plan spring outages, and this is
plants less than 30 years EFPY from being equivalent.
We don't have the plants that are way out there on
this graph, but even many of those plants that have
spring outages were doing bare metal inspections of
their heads, if they could not rule out the
possibility, and even the ones that didn't think there
was any way they had any boric acid on top of their
heads, some of those were even doing inspections.
But if you look at the blue open diamonds,
those are the plants that have spring outages and have
to do some kind of inspection per 2001-01. So there's
quite a number of those plants will have looked at
their heads by the end of this spring. I guess they
are kind of -- I started to say "rust" -- red circles,
those are the plants that are scheduled for the fall
outages when they will be doing their inspections, and
then the four green squares that are on cycles that
get them into the Spring of 2003.
MR. FORD: So the take-away message from
this is that the prioritization algorithm you've got
right now seems to work into a first approximation
that should be more definitive after the spring
outages, is that the take-away message?
MR. MATHEWS: We'll fill in all these blue
diamonds at the spring outages, at least from a visual
inspection perspective. And if you look, the red
triangles are all to the left of the graph. There's
a couple of plants with cracking out in the middle,
but as far as I know those plants were not through-
MR. FORD: And the other obvious take-away
message is you'll get a crack eventually, unless you
manage it before.
MR. MATHEWS: Yeah. I hate to say some
plant that has a cold head that on our histogram is
200 years away from being equivalent to Oconee 3 will
MR. FORD: I agree.
MR. MATHEWS: -- but as far as these other
plants, there's a good chance. There's no guarantee,
but at least it's being borne out so far that this may
be a good model, or sort of a good model anyway --
nothing is perfect.
Well, I think he talked about this. Why
don't we put the list up, this is the one with the
plant names. It's in your handout. I think this has
been supplied to the NRC.
MR. FORD: It has.
MR. MATHEWS: I guess I'm obligated to
tell you we've received at least two phone calls this
morning to say Watts Bar has found more documentation
and want to be classified in Category 4 instead of
MR. FORD: Can you tell me -- I have
looked at this slide quite a few times -- I have not
the foggiest idea what the take-away message from this
MR. MATHEWS: The take-away message is
that most of the plants out there, almost all of the
plants out there, feel that they have a very good
position that they don't have the kind of boric acid
corrosion going on on top of their heads that has been
experienced at Davis-Besse. Almost all the plants are
in that boat right now.
The plants in the greater-than-30-year
category feel they don't have the source to wet their
head -- all of those.
MR. FORD: And there's no correlation at
all -- they're just looking to scatter those numbers
between boric acid on the head and cracking
susceptibility. Is that the way -- I mean, the
MR. MATHEWS: Oh, okay. The
categorization was based on how people answered those
questions, and the four categories -- maybe we can go
back to that one slide --
We had four questions and they came over
four categories in another. Category 1 plants at
their most recent inspection, they did 100 percent
bare metal inspection, and there was no boric acid on
the head and none coming from above the head.
Category 2 plants, they were doing the
inspection. There was some boric acid accumulation
detected. It was removed and the head inspected and
the source determined and corrected. Those are the
plants that -- you know, they've gone and looked and
they don't have a problem.
Category 3 plants, bare metal inspection
was limited for some reason, or they were not able to
be performed, but they've reviewed the plant history
over the whole life of the plant, and there's no
evidence of leakage coming from above.
Category 4 plants, in limited inspections,
but when they review their history, there may have
been some leakage, but none of it reached the outer
surface of the head -- you know, little seal leak that
-- you know, there's no evidence that the boric acid
got all the way down to the head or anything like
that, or the affected area, if it did get to the head,
was cleaned off.
And then there was the other category
which, for a number of reasons, they may not fit any
of these, or there may have left some boric acid on
the head. Those were the four categories and the
Other group. So, if you look at it, everybody
basically in Category 1, 2, 3 or 4 felt they had a
pretty good story for why they don't have boric acid
on top of their head.
MR. FORD: There's a whole lot of
subsidiary questions to ask on that one, but we're not
going to take the time.
MR. MATHEWS: Okay. Put up the summary
Basically, all the plants of less than ten
years will have inspected by the end of the Spring
2002 outages, and have reasonable assurance that none
of them have been returned to service with significant
corrosion of the head or CRDM leakage. And of the
plants that are left in 30 EFPY, 34 out of 40 of those
plants will have done inspections by the spring. And
then five more in the fall, and then six of them do
make it over into the 2003 time frame.
MR. FORD: I've only got one question.
You're assuming that if you don't see boric acid on
the head, then you have no problems?
MR. MATHEWS: Yes, I guess that's the next
MR. MATHEWS: So far, in the industry, I
think 34 penetrations, leaking penetrations were
detected by visible evidence of boric acid during
visual exams from the top of the head, or could have
been if they weren't masked by other boric acid
deposits. A total of 203 nozzles have been inspected
by NDE, and by that I mean UT or AD-current from
underneath the head at nine plants where the leaks
have been found, and NDE confirmed the through-wall
leaks in all 34 penetrations which showed the visible
evidence, and it did not detect through-wall leaks in
any of the additional 169 penetrations that were
MR. FORD: And yet in the EPRI -- you're
going toward the conclusion that you can manage by
leakage detection, and yet EPRI, in their Boric Acid
Corrosion Manual, say that for these particular head
penetrations you cannot rely on visual detection on
the head for what is happening down at the bottom --
MR. MATHEWS: To quantify that, I would
think that may be true, and that's something we're
looking at -- you know, can you get a cavity down
here. I guess the basic message we're saying right
here is, we don't see any way to get to cavity without
getting something on top of the head simultaneously.
I mean, the stuff --
MR. HUNT: Steve Hunt. As the author of
that statement -- the statement in the Boric Acid
Guidebook is correct, as it stands, that you cannot
see the cavity which is underneath the surface, but
you will be able to see the pile of boric acid
crystals on top that led to the formation of the
cavity, and we're in the process of trying to quantify
that right now.
MR. SHACK: I guess that's my question,
the 34 leaking penetrations, are they all sort of like
at Oconee 3, or do you see very small amounts of boric
acid, or have we had any significant amount of boric
MS. KING: Most of them have been similar
to the initial deposits identified at Oconee.
MR. MATHEWS: As I recall, even the ones
where it was a weld crack that didn't go into the tube
at all, it was the same sort of stuff -- you know, a
little bit of accumulation on top, not any massive
amounts of boric acid buildup anywhere.
Anybody in the audience remember any?
No, I didn't think so.
MR. KRESS: The NDE results, would they
have found the cavity, if it had been there?
MR. MATHEWS: They were not typically
designed to look for that kind of thing. They were
looking for flaws, and the leakage path stuff that was
shown by Davis-Besse showing the lack of hard contact
between the penetration in the head bore was something
that just kind of popped out after-the-fact as they
were reviewing some -- not Davis-Besse -- but as
Framatome was reviewing data, and going back and
taking a look at it.
Cavities, no. The NDE that we have used
to date could not detect the cavity. The best it
could do is tell you that there is a lack of hard
metal contact, if you're using the right techniques
and looking at it in the right way. But as far as is
it 2 mls or quarter of a mile, I don't think we could
tell the difference with these techniques. But that
is not to say we are not working on or looking into is
there -- are there techniques out there that could be
used to detect how far away the carbon steel is or to
actually measure any wastage. We don't know where
we're going with that right now, but it's certainly
something we're looking into.
Other than the ones at Davis-Besse, the 31
nozzles, there's been no evidence of any significant
corrosion, I think we know that.
MR. FORD: I'd just underline as a fact,
we'd better understand why.
MR. MATHEWS: Yes.
MR. FORD: Okay. Thanks so much, indeed.
MR. MARION: Alex Marion, NEI. just a
couple points I'd like to make. The industry is
extremely concerned about the Davis-Besse experience.
We are, quite frankly, anxious to obtain a copy of the
final root cause analysis, and we're also interested
in getting a copy of the NRC's augmented Inspection
Team Report. As that information is made available,
we'll integrate it into the program, as Larry touched
on during his presentation.
This Thursday, we're having a meeting with
the industry chief nuclear officers. This topic is on
the agenda. Mike Cockman (phonetic) is one of the
executive sponsors of the MRP, is planning to give the
We've additionally had conversations with
INPO, the Institute of Nuclear Power Operations, to
get a sense of what they can do relative to some of
the programmatic activities in boric acid corrosion,
et cetera. So we're going to be doing some additional
enhancements as time goes on.
Let me just speak briefly to the policy
issue that the NRC staff identified this morning about
continuing to rely on detection of leakage versus some
other form of nondestructive examinations.
We had a meeting of the PWR, Pressurized
Water Reactor Materials Management Program Committee
-- if I got that right -- the executive steering group
that over sees the MRP and the steam generator
projects at EPRI, and at a meeting in March they gave
a recommendation to the technical staff that visual
examination alone is not effective as a long-term
So, as we're getting the results of the
spring outages and we're getting the results of the
Davis-Besse experience, we're going to try to pull all
that together into a cohesive long-term program.
Lastly, I want to let you know that we are
going to be updating our survey results and sending
them to the NRC at the completion of the spring
outages, which will likely be in the June time frame,
I would think, June-July time frame.
And, finally, I'd like to thank you for
the opportunity to discuss the industry activities on
these two important bulletins, and we'll be more than
happy to brief the subcommittee and the full ACRS in
the future as we move forward with the NRC in trying
to understand the implications of this problem.
MR. FORD: Thank you so much.
MR. STROSNIDER: Jack Strosnider, of the
staff. You've heard a lot of information this
afternoon. I guess there was a suggestion at the
beginning of this that I was going to summarize it,
which might be a little ambitious. But I think it's
always worth looking at these issues in terms of the
NRC's performance goals and just reflecting on that
for a minute. The first of those goals, and the most
important, is maintaining safety.
The Davis-Besse degradation of the reactor
vessel head is a very significant issue, everybody
recognizes that significant degradation of the reactor
coolant pressure boundary.
Ken Karwoski went through fairly quickly
what we've done with regard to the bulletin we put
out, but I'd just like to point out that if you look
at both our interaction with the industry and the
actions they took and the information they provided
and the bulletin we put out, it was in a very short
time frame. If you look at how long it typically
takes to get these out, you'll see that the
significance of this issue was certainly recognized.
In addition, we're casting a wide net in
that bulletin and also in our responses. Without a
well defined root cause, we have to take that
conservative approach. So, for example, a plant has
had seal or flange leaks, but is low susceptibility,
if they can't show that those leaks haven't reached
the head or that they've taken some action, we'll
probably be talking to them, and we expect that it's
going to take a lot of digging into these responses,
but we're talking on the order of weeks before we
identify what plants we might need to follow up on.
Having said that with regard to the Davis-
Besse degradation, we need to make sure we don't lose
sight of the control rod drive penetration cracking,
which is also a significant issue. There may be some
relation, but in and of itself it's significant.
And we summarized the results of the
inspections done in response to last year's bulletin.
Based on what we've seen, we think that the actions
being taken are dealing with that issue in the short-
term, but as we pointed out, this issue will not go
away. It's going to be more broad-spread, and we need
to have that long-term program put in place in order
to maintain safety in the long-run, which brings me to
the next performance objective of increasing
efficiency and effectiveness.
Until we get that long-term program in
place, frankly, we're being pretty inefficient because
we're dealing with all these issues on plant-specific
basis, and that takes resources for the NRC and the
industry. So we certainly have a motivation to do
that as quickly as possible. And to be frank, I think
we have lost some ground because the industry and NRC
-- we had to deal with the Davis-Besse issue when it
came up, and that's had some impact.
We had hoped to be here at this meeting
providing the committee some of the technical basis
for that long-term program, and we're not there yet.
We need to come back with that. And until we do that,
we're going to be paying the price of spending more
resources on a plant-specific basis and probably with
more conservative decisions than might be necessary
until we can get all that technical basis laid out.
So we do need to come back to the committee with that,
and we need to do that for our own good.
With regard to reducing unnecessary
burden, there's going to be necessary burden
associated with this issue. The industry recognizes
that. They are putting the resources into it, and NRC
as well, so I think everybody recognizes they are
going to have to do what's necessary to deal with
Finally, with regard to public confidence,
there is a lot of interest in this issue. Our public
meetings have been well attended. We've had a lot of
questions. I would just point to the Web site where
we're getting a lot of positive feedback in terms of
the information that's there and trying to keep people
onboard with what we're doing. So, I think in the
short-term we're dealing with the issues. We've got
this longer-term activity that we do need to get
underway and we need to make progress on.
MR. FORD: Thank you. If I could finish
off by just going around to my colleagues and asking
them to just give a very brief synopsis of their
thoughts at this stage, and also some information that
we can give to the presenters for Thursday, when we
have a two-hour presentation to the full ACRS -- in
other words, what's keeping you awake at night.
MR. BONACA: Well, just two observations.
One is, you know, there have been 34 leaking
penetrations and, of those, one of them has shown
significant wastage on the outside. The others
haven't. We concluded somewhat in the conversation
that most likely it is because it is a very old one.
I don't think we should jump to conclusions. There
may be some degradation mechanism. He has suggested
possible impingement, I don't know. I'm not
postulating anything, just simple I think we need to
understand what made this different from the others.
And the second observation I would like to
make is that right now the whole program on CRDM
cracking is focused on essentially building a schedule
based on the vulnerability of the units, and then do
visual or UT measurement for detection, that
detection. Yet, we have learned from the Davis-Besse
event that they had indirect indications -- you know,
the containment had cooler clogging, containment
radiation, monitor and filter clogging, and then plate
out of boric acid on cold surfaces, and I really
wonder if, in fact, the unit shouldn't have simple
observation program internally as part of this that
says let's monitor this indication, that was
significant for Davis-Besse, so that will give us an
indication as a minimum that something beyond the
cracking is occurring, which is essentially a
significant leak as they had at Davis-Besse, I don't
think is a burden and probably just part of normal
observation in walk-downs and things of that kind.
I think it would be appropriate because I think for
Davis-Besse they provided significant indication
that's a lesson learned. That's all.
MR. FORD: Tom.
MR. KRESS: I would like to second
everything he said, plus add one other. We saw a
chart of the thickness of -- the mapping of the cavity
was obtained some way, and it seems to me like it's
possible to inspect for cavity as well as the cracks.
And I think that ought to be part of the process of
the inspection. There ought to be something -- and we
heard that they are thinking about things, but that
ought to be part of it, inspect for a cavity as well
as for cracks.
MR. FORD: Steve.
MR. ROSEN: I'm looking down the road
quite a way and thinking about the time when Davis-
Besse has repaired its head or bought a new one or
somehow gone back into operation, but there are other
damage that needs to be repaired besides the physical
damage, and it was alluded to, I think, by the Davis-
Besse people, in particular, thinking about it in
terms of the precursor decision not to improve reactor
vessel head access, and then later on the lack of a
questioning attitude that Mario referred to with
regard to the performance of the containment coolers
and the radiation monitor filters, which is a weakness
that has important impacts on the corrective action
program and attributes for the corrective action
program, that lack of questioning attitude. So, the
corrective action program needs to have a look, and
I'm sure that Davis-Besse will be working on that.
And if you have a weakness in the
corrective action program, you need to be thinking
broadly about safety culture in the plant because it's
such an important piece of -- the corrective action
program is such an important piece of the safety
culture. So, those broader questions occur to me as
I think about this, and in the long-term future of
Davis-Besse and focusing on the macroscopic rather
than the microscopic.
MR. FORD: John.
MR. SIEBER: Well, I agree with Mario, and
also Steve, on the issue of inspecting for excavations
in the head, so to speak. Since the policy right now
is to rely on leakage rather than volumetric
examinations, I don't think that you could imply that
there is a way to detect cavities by what licensees
are now doing. I'm not also familiar with directly a
volumetric examination of the head, how you would do
it by looking through the nozzle because of that
interface there. You just can't get across the
I think the decision of leakage versus
volumetric still needs to be made, but I think that I
would prefer the staff to tell us what decision they
come to rather than we suggest to them what way they
ought to go because I think there is a case that says
leakage measurement may be good enough for this kind
One thing that I feel -- I thought all the
presentations were very good. I believe, however,
that there were a number of hypotheses involved in
what causes this, the root cause analysis, and so
forth, and we end up with perhaps a difference of
opinion or, in my own case, maybe a different opinion
versus time as we go along, that tells me that there
ought to be a greater reconciliation with the
hypothetical causes of things and physical
observations versus the body of scientific data that's
out there. And the reason that is is to try to
confirm the validity of the hypotheses that's applied
to why didn't I observe this, why did this occur, and
so forth down the line. I would like to see a little
bit more rigor in this process as we go along, so that
we really understand what's going on and we can say
truthfully, as scientists and engineers, that this is
reasonable based on the body of corrosion data, for
example, that's out there. And so I would have liked
to have seen a little bit more meat on the bones in
that area. Otherwise, I'm pretty well convinced that
NEI and EPRI and the MRP are dedicated to resolving
the issue. I see the licensees acting responsibly
with regard to at least the first bulletin. The
answer to the second one probably isn't due in yet,
except for maybe the 15-day response, but I'm
heartened by the fact that licensees are doing that,
the staff is paying attention and putting this as a
high priority and the industry groups are doing the
So, those are basically my thoughts at
this point in time.
MR. KRESS: Let me comment for just a
moment on my comment on looking for wastage directly.
You surely would get leakage if you had that extent of
wastage, but you can't take that in the negative sense
and say, okay, I've got leakage, I've got wastage.
You can do that with a crack. So, you need a way, I
say, in the program to decide whether or not you have
wastage, and you can't do it with leakage. That could
be an indicator that you've got it, but it is not an
extent as it is with cracks. If you've got the
leakage, you pretty well know you've got cracks. That
was the nature of my comment.
MR. SIEBER: Yeah, and I think there is a
way to use leakage as a way of determining whether
wastage is occurring or not.
MR. KRESS: I don't think so, that's my
MR. SIEBER: Well, the rivers of iron
coming down the side, to me, tells me there's wastage
MR. KRESS: That may be. You may have a
MR. SIEBER: When everything turns brown
MR. KRESS: I think it's too late, maybe.
MR. SIEBER: -- in nuclear, that's iron.
MR. LEITCH: I guess one comment I'd like
to make, although I'm not familiar with Davis-Besse
and it's always easy to jump to conclusions, I'd like
to echo my concern that there seems to be a lack of a
questioning attitude. It looks as though there's a
number of opportunities that were missed that could
have, if not prevented this, certainly have prevented
it from getting as far as it got.
It's always difficult, and I certainly
sympathize with the plant people, it's always
difficult to look at a couple different points and say
there's a lack of a questioning attitude, but yet from
the data that's been presented here, it seems to me
that that is something that may be an issue there.
Can't say definitively that it is, I'm just not that
familiar with it, but certainly there's a couple of
data points here that would seem to suggest that.
The other thing that I would like to have
heard about, and I guess it's still future, is just
what is the final vision for how Davis-Besse is going
to be returned to service. We alluded to just --
there was a very brief allusion to a drilling
operation there and fixing it, but what is the nature
of the final inspection of the head going to be? In
other words, are we going to get a good solid bare
metal inspection of this head, are those modifications
that were suggested in 1990, or whatever it was, to
facilitate future inspection of the head, are those
modifications going to be installed at this time? And
I know those issues are still under discussion and
some of them just cannot be answered at the moment,
but what I'm saying is that's an area where I'm
curious about just what are the next steps.
Included in that perhaps is this issue --
and, again, it was just briefly referred to and,
again, I think it's a subject of another meeting --
about the thickness of the stainless steel cladding
and that it would have been able to withstand 5,000
pounds or something like that. And my question there
was is that the actual stainless cladding, or was that
the design stainless cladding, are the two the same,
is there a nominal thickness or an actual thickness
MR. SIEBER: How many cracks are in it.
MR. LEITCH: Yeah, right. But it seems to
me that this was coming very, very close in spite of
those calculations, at least my gut seems to tell me
that it was coming very close to being a very
I guess the other questions relate more to
the rest of the industry. I see plants in categories
-- I'm not sure I remember the categorization numbers
-- 3, 4 and Other, I guess -- and, again, this is
something that I know is in progress and is a very
current subject and is being worked on, but it sounds
as though there's a great number of plants that, for
one reason or another, cannot make a really good bare
metal inspection of the entire head. I guess I'm
wondering how, if that is the case, how are they
satisfying the general design criteria that says
that's what we're supposed to do.
I guess, as I say, all these things are
future and still under discussion, but my questions
were not so much with what was presented today, but
where do we go from here.
MR. FORD: Bill?
MR. SHACK: You've said so much, I'm not
sure there's anything left to say except I probably
disagree with my friend, Dr. Kress, and probably
disagree with you, but we'll discuss that later at
Like Mario, I'm still puzzled by the 33
and the 1, and I certainly agree with Steve and
Graham, there does seem to be a problem with the
questioning attitude here, maybe in particular, for
this particular case. It seems to that both the staff
and the industry are making progress in addressing the
issue, so we'll just have to wait and see what
MR. FORD: The thing that keeps me awake,
I guess, is the same as we've all alluded to, is the
root cause and the way the hypothesis is going -- this
is for the degradation issue -- is that any axial
crack could give you degradation, according to the
hypothesis that we've got right now, and we don't have
a clear algorithm to say why we'll get excessive
degradation at this plant and not at these others, and
in terms of the annulus size or the temperature or
whatever it might be. We don't have that algorithm and
we'd better have that algorithm fairly quickly.
So, a good root cause -- quantitative,
predictive root cause analysis backed up by, as you
say, Jack, information from literature and from
Another thing that keeps me awake is,
well, okay, then, what's the risk associated with
this? We haven't heard -- I know there have been
published some risk analyses, but we didn't see any
today. I suspect that's what might, if it can be made
available in time, might interest, for instance,
George Asposkolocaz (phonetic) and Dana Powers, who
will be available on Thursday and who are not here
today. Those are the things that would keep me awake
and which I would like some clarification on.
Apart from the management aspect, I am
absolutely convinced on both bulletins we are moving
forward as quickly as we can. We'd love to see it
moving forward faster. We'd love to see better
communications, if that's necessary, between all the
parties in this huge matrix organization, if not
industry, but those are management questions, not
things that we can solve here.
On that point, if anybody has any
questions on what we should be discussing in the short
time we have, two hours on Thursday, come and chat
Well, on that basis, thank you very much,
everybody. It's been very interesting. This is now
(Whereupon, at 6:15 p.m., the joint
Subcommittee meeting was concluded.)