Plant License Renewal (Turkey Point 3 & 4) - September 25, 2001
Official Transcript of Proceedings
NUCLEAR REGULATORY COMMISSION
Title: Advisory Committee on Reactor Safeguards
Plant License Renewal Subcommittee
Turkey Point Units 3 and 4 Application
Docket Number: (not applicable)
Location: Rockville, Maryland
Date: Tuesday, September 25, 2001
Work Order No.: NRC-031 Pages 1-272
NEAL R. GROSS AND CO., INC.
Court Reporters and Transcribers
1323 Rhode Island Avenue, N.W.
Washington, D.C. 20005
(202) 234-4433 UNITED STATES OF AMERICA
NUCLEAR REGULATORY COMMISSION
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ADVISORY COMMITTEE ON REACTOR SAFEGUARDS
PLANT LICENSE RENEWAL SUBCOMMITTEE MEETING
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TURKEY POINT UNITS 3 AND 4 APPLICATION
AND RELATED WESTINGHOUSE TOPICAL REPORTS
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TUESDAY
SEPTEMBER 25, 2001
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ROCKVILLE, MARYLAND
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The Subcommittee Meeting was called to
order at the Nuclear Regulatory Commission, Two White
Flint North, Room 2B3, 11545 Rockville Pike, at 8:31
a.m., Dr. Mario V. Bonaca, Chairman, presiding.
PRESENT:
DR. MARIO V. BONACA, Chairman
DR. STEPHEN L. ROSEN, Member
DR. WILLIAM J. SHACK, Member
DR. F. PETER FORD, Member
DR. NOEL F. DUDLEY, ACRS Staff Engineer
I N D E X
AGENDA ITEM PAGE
Opening Remarks by Subcommittee Chairman . . . . . 4
Florida Power and Light Presentation . . . . . . . 5
by Elizabeth Thompson and Steve Hale
Introduction and Overview of SER Related . . . . .74
to Turkey Point License Renewal Application
Presentation by R. Auluck, NRR . . . . . . . . . .74
Presentation by G. Galletti, NRR . . . . . . . . .95
Presentation by B. Thomas, NRR . . . . . . . . . 102
Presentation by M. Khanna, NRR . . . . . . . . . 115
Presentation by J. Davis, NRR. . . . . . . . . . 136
Presentation by C. Munson, NRR . . . . . . . . . 139
Presentation by P. Shemanski, NRR. . . . . . . . 143
Presentation by A. Keim, NRR . . . . . . . . . . 149
Presentation by B. Elliot, NRR . . . . . . . . . 152
P-R-O-C-E-E-D-I-N-G-S
(8:31 a.m.)
CHAIRMAN BONACA: Good morning. The
meeting will now come to order. This is a meeting of
the ACRS Subcommittee on Plant License Renewal. I am
Mario Bonaca, Chairman of the Subcommittee.
ACRS Members and consultants in attendance
are Peter Ford, William Shack, and Stephen Rosen.
The purpose of this meeting is to discuss
the staff's safety evaluation report, with open items,
related to the application for the renewal of the
operating licenses for Units 3 and 4 of the Turkey
Point Nuclear Plant, and associated Westinghouse
Topical Reports.
The Subcommittee will gather information,
analyze relevant issues and facts, and formulate the
proposed positions and actions, as appropriate, for
deliberation by the full committee. Noel Dudley is
the Cognizant ACRS Staff engineer for this meeting.
The rules for participation in today's
meeting have been announced as part of the notice of
this meeting previously published in the Federal
Register on September 11th, 2001.
A transcript of the meeting is being kept
and will be made available as stated in the Federal
Register Notice. It is requested that speakers first
identify themselves and speak with sufficient clarity
and volume so that they can be readily heard.
We have received no written comments or
requests for time to make oral statements from members
of the public regarding today's meeting.
We will now proceed with the meeting --
well, before we do that actually, I would like to make
just a couple of brief announcements. One is that you
all know that one of our members, Graham, had a heart
attack, and he had a second one, I believe, on Friday.
He is in good shape, but certainly could
not join us here. So I gave him our best, and I think
we hope to have him back for the Hatch application.
So, that is one issue.
The second one is John Barton could not
make it. He had some problems with transportation and
things of that kind. He sent us a number of good
comments, and if the applicant and the NRC will be
patient with us, we will try to do justice to his
comments.
And as we walk through the presentations,
we will go through them and where they seem to be
significant, we will talk about them. That may force
me to break the flow of the presentation and go back
to his comments, but I think that is the only way we
can do justice to them.
So with that we will now proceed with the
meeting, and I call upon the Florida Power and Light
Company to begin.
MS. THOMPSON: Good morning. My name is
Liz Thompson, and I am the project manager for Florida
Power and Light. With me here today is Steve Hale,
and he is the licensing and design basis leader for
FPL as well.
We have prepared a presentation to go
through the process that we used for generating the
application, the IPE portion, or excuse me, the IPA
and the TLAA portions, and Steve is going to lead us
through that using the overhead projector.
MR. HALE: Good morning. Like Liz said,
I am Steve Hale, and I am the licensing lead for FPL's
nuclear plants and terms of license renewal. I will
try to keep this as interesting as I can.
The topics identified by the ACRS
Subcommittee that they were interested were to go
through a background, and go through our scoping and
screening process, go into how we performed our aging
management reviews, and then talk about our time
limited aging analyses.
In terms of background, FPL began
strategic planning for license renewal of our nuclear
plants around the 1992 time frame. This followed
issue of the original version of the license renewal
rule.
We have been active in the license renewal
industry groups, like the Westinghouse Owners Group,
the license renewal group, and the NEI task force and
working groups since about 1993.
We began in earnest our IPA and TLAA
efforts in 1999, and we submitted the application in
September of 2000. The safety review requirements and
guidance that we had available to us at that time were
the 10 CFR Part 54, the revised version that was issue
in the mid-1990s.
We had a draft standard review plan for
license renewal, but that has changed drastically. We
tried to keep up with the GALL report. We had
technical reps on the groups at NEI that reviewed the
mechanical, civil structure and electrical sections of
GALL as it was going along.
We had a draft version of the Reg guide,
and we also had available to us NRC position letters
on certain particular issues like consumables and that
sort of thing.
We were active participants on the
development and issue of NEI 95-10, and we
also had as part of the Westinghouse
Owners' Group effort developed some guidelines on how
to do an IPA, as well as review your TLAAs.
In terms of our work process itself, and
namely that scoping, screening, aging management
reviews, and TLAA identification and evaluation, we
piloted our initial procedures in 1996.
And by piloting we actually tried to
produce sample products and that sort of thing, and
then factored in improvements that we could see. We
tried to structure them around the design basis tools
that we had available to us.
We have a controlled electronic database,
and we have design basis documents that were developed
in the late '80s and early '90s, and those were very
useful in performing this process.
We made a number of information trips to
various applicants that were very active in license
renewal at the time.
And then we went back to the one that we
felt more compared -- you know, fairly well with, to
the tools that we had available to us, and we spent a
lot of time reviewing your detailed technical
documents.
Some of the other things that we did was
that we tried as best we could, because it was kind of
a moving target, to factor in lessons learned from a
review of previous applications, looking at REIs, and
REI responses, and looking at resolution of generic
issues.
And we tried to factor those into our
procedures and output documents as best we could. We
did perform all the work in support of our license
renewal application in accordance with our quality
assurance program, and we also chose to have
independent peer review groups, both internal, as well
as external peer review groups, come in and look at
our products and our procedures.
And these were folks from various
applicants, as well as some technical experts in the
field.
DR. SHACK: I was just curious about that.
One of the more contentious issues that always seems
to come up on a license renewal is how you handle the
effect of the environment on fatigue life. And
through the REI resolution, you seem to have come up
with a good solution to that problem.
But I was a little curious as to why you
didn't anticipate that question was going to come up.
It has come up in every license renewal so far, and I
am sort of waiting to see it built into the
application, rather than coming out of an REI.
Well, I think one of the reasons is
because we were the first B-31(1) plant, and we didn't
really know what the issues would be. Now, we did try
to address concerns relative to NEUREG 62-60, which we
did include in our application.
And we tried to address the concerns as we
saw them, and we factored in, in fact, the commitments
regarding the surge line consistent with what ANO had
committed to.
But there was a lot of questions that came
out regarding the pressurizer, which had not been
asked previously, and the GTR, the Westinghouse GTR
that was submitted as a stand alone document for all
Westinghouse plants, had flagged some high fatigue
areas in the pressurizer.
DR. SHACK: That was one of the more
curious things in the thing. They had it flagged, and
for you it was a "no, never mind" thing.
MR. HALE: Right, but we went back and
looked at the pressurizer specifically for Turkey
Point. And I think that is probably where a lot of
those REIs were based on. Whereas, you didn't really
see a lot of that in the previous applicant.
CHAIRMAN BONACA: I have a question that
is more general to the same. Clearly, your
application is somewhat one of a kind again, because
you didn't have final documents, like NEI finalized
documents, or the SRP, or the GALL report.
How different do you think it would be,
this application today, if you had had started from
scratch?
MR. HALE: I think that probably we would
have figured in GALL as much as we could. It is
interesting that you ask that, because we are in the
process of developing the application for St. Lucie
right now, and we are facing that.
We want to try and use the approach that
we took at Turkey Point, but at the same time
integrate what we have available to us in GALL. And
we are doing things like including GALL references in
the component commodity listings.
And where our programs fit within the
bounds of the GALL programs, we are simply going to
say that we are consistent with GALL. So, we are
doing that.
CHAIRMAN BONACA: Okay.
MR. HALE: We see the GALL as the main
area where we can benefit from what is out there.
With regards to scoping, we kind of walk through a
two-stage process. When you go to look at the plant,
our plants define the terms of systems and structures.
So the first step that we wanted to take
is to identify which systems and structures had
portions that were safety related, and we said that
the whole thing was safety related.
And then the next step is that we looked
at the various components that make up that system,
and determine which ones support the functions and
which ones don't.
So we started first in the system and
structure level, and when I say system, we are at the
cooling system, and safety injection system, and our
HR system, and structures, containment and this sort
of thing.
And you can see those results which are
presented, and I believe it is in Section 2.2 of the
application. The purpose of scoping is to identify
systems and structures which are either safety
related, non-safety, which can affect safety related.
And then the five regulations regarding
fire protection, environment qualification, PTS, ATWS,
and station blackout. More safety related, when you
compare the safety related definitions in Part 54,
they are consistent with what we call safety related
in our quality instructions, and consistent with how
we classified safety related components in our plant.
The sources of information that we used in
defining what was safety related -- and again, even if
only a portion of the system was credited, in terms of
-- or had components that were safety related, the
whole thing was considered safety related for future
component scoping.
We used the UFSAR, and we used the tech
specs. We used our license correspondence database.
We have all of our licensing correspondence, both to
and from the FPL and the NRC electronically.
Our design basis documents, and our
component database, and our control design drawings.
And again we reviewed all systems and structures to
determine if there were any safety related components
within them.
For non-safety which can affect safety,
this is probably one of the more challenging portions
of scoping, especially for an older plant, where you
are looking at non-safety related systems which could
potentially affect safety related systems.
Again, we looked at the UFSAR tech specs,
our licensing correspondence files, our DBDs. We have
a section of our design basis documents that walks you
through all the assumptions like for pipe break,
seismic criteria, and that sort of thing that we
source when we are looking at interactions.
Our design drawings, as well as pipe
stress analysis, because you have to go and look at
what portions where you have a boundary, and you
credit an additional piece of pipe in support of that,
and we had to include that pipe in the scope of
license renewal.
We saw two categories. You have a
category of non-safety related system, which actually
performs a function that supports the safety related
system. An example would be a NVAC system on a long
term basis that needs to run to support a safety
related function. And then we had interactions.
MR. ROSEN: Hold on for a minute.
MR. HALE: Yes.
MR. ROSEN: Why wouldn't a system that is
needed to provide functional support for a safety
related system also be safety related?
MR. HALE: The design of Turkey Point
originally in the late '60s and early '70s didn't
classify HVAC systems similar to what you would
classify them today.
Now, control room HVAC is safety related,
but you had some of those heating or cooling
functions, or ventilation functions, that weren't as
clear, in terms of criteria, when Turkey Point was
originally licensed.
We carry a special augmented quality for
those ventilation systems, but they aren't classified
safety related.
MR. ROSEN: They would be classified
safety related, for instance, at St. Lucie, a later
plant?
MR. HALE: Yes. Yes, they are.
MR. ROSEN: Okay. Thank you.
MR. HALE: But when you look at the older
plants HVAC, it is a little different than what you
would see in a newer plant. In terms of license
renewal, they are all in the license renewal.
And the other was in the area of
interactions, where you have a safety related or non-
safety related systems based on assumed failures could
impact the safety related system. So those two
categories are what we looked at.
With regards to the regulated events, we
have a lot of design tools at our disposal, in terms
of determining what is in the scope and what isn't.
Again, we used our UFSAR and tech specs, and licensing
correspondence, DBDS, our component data base, and
design drawings.
But in addition to that, we have a safe
shutdown analysis and a central equipment list with
regard to Appendix R. We have the EQ list as
integrated into our component database.
And for station blackout, we have load
lists, in terms of what is required post-station
blackout in order to support the plant.
Okay. Now that we have identified what
systems and structures are in the scope of license
renewal, we proceed to screening, the purpose of which
is to identify structures and components which require
an aging management review.
We step through this by first looking at
all the components or structural components that make
up the system or structure, and determine whether that
component or structural component supports the
functions of the system or structure.
And then we look at the screening
criteria. Is it passive as defined in the
regulations. You know, performing the intended
function without moving parts or change the
configuration or properties.
And is it subject to replacement based on
qualified life. And we decided in screening that it
made sense to us to segregate the three major
disciplines; mechanical, which is more system oriented
in the structural area, and had very similar
components in each one of the buildings.
And then in the electrical area, based on
the types of components that you have in the
electrical 9C systems, and it was best to take a
different approach there.
So for mechanical systems, we established
valuation boundaries and interfaces, in terms of where
the systems were, and this is that system, and this is
this system. And we made sure that we had everything
picked up.
And then we identified or actually mapped
functions of the system, the license renewal system
intended functions, on to the drawings to establish
what pieces support the various functions.
And then we identified the various
components in that system that support those
functions. After we got that, we have a list of
components that support the system intended functions,
and this is all three scoping criteria.
And then we identified whether they were
passive or not, which is fairly extensive information
in the NEI and standard review plan regarding how you
do that.
And then long lived. We looked to see if
these things were procedurally replaced on a regular
basis, in terms of qualified life. And then after
that, we identified individual component functions.
You know, like pressure boundary, heat
transfer or whatever it might be for that particular
function, or for that particular component.
CHAIRMAN BONACA: I don't know if this is
the right time to ask questions.
MR. HALE: Sure.
CHAIRMAN BONACA: But in the plant level
scoping results, you know, you have tables in the
back, Table 2.2.1., where you do have an
identification of systems or components, and then
structures, but the structures are later.
And we have a number of questions about
the number of systems that were excluded, and I would
like to ask you, first of all, penetration cooling
that was excluded from scope.
MR. HALE: Yes, there is a particular
analysis that was performed at Turkey Point. Our hot
penetrations go to the outside. I mean, we don't have
a building around where the main steam and feed water
blowdown penetrations come out.
And it was an actual analysis, and it is
in the UFSAR, in the structural section, that says
that even without cooling, temperatures will not
exceed 150 degrees.
CHAIRMAN BONACA: Okay.
MR. HALE: And so all of our peer reviews
-- well, that is a good question.
MR. ROSEN: What do you mean by hot
penetrations that don't exceed 150 degrees?
MR. HALE: Well, the area around -- the
concrete around. You know, you have a flute head
inside containment on the steel side, and you have a
main steam pipe that comes out.
So you have an air space around the
penetration, the actual containment penetration proper
in the pipe that comes out. That goes to the outside.
So that space right there is exposed to an outdoor
environment.
MR. ROSEN: What do you mean by high
penetrations?
MR. HALE: Penetrations that are hotter
than 150 degrees.
MS. THOMPSON: Classically -- this is Liz
Thompson speaking. Classically, you would talk about
those as being, for instance, lines that you look at
for high energy evaluations.
MR. HALE: Yes, typically they are your
main steam, feed water, and a blow down lines for a
PWR.
CHAIRMAN BONACA: The next question I had
was -- and actually this came from John Barton, and is
regarding RAD waste building ventilation, and why that
was excluded.
MR. HALE: We have a document basis in the
application regarding RAD waste systems in general.
We basically looked -- our RAD waste building is an
independent building.
The consequences of radioactive, both
liquid and gastrious releases, are so small that we
looked at the scoping criterion under Part 54, and it
is a small fraction of Part 100 limits for all of our
radioactive waste accidents. So we excluded RAD waste
system on that basis.
CHAIRMAN BONACA: And some of this, you
know, I looked at myself, and I could not find a
discussion, however, in the application. I mean, the
results is here in the table, but --
MS. THOMPSON: On the other side of the
table, there is a copy of the application, Steve.
CHAIRMAN BONACA: So there is a
discussion. You don't have to give me -- well, you do
have a discussion.
MR. HALE: I will give you a reference
after we are done.
CHAIRMAN BONACA: Okay.
MR. HALE: We did cover it, I believe, in
the methodology section.
DR. FORD: Could I come back to Steve's
earlier comment about the classification of non-safety
related items, which would affect a safety rating, and
which are not included in your proposal because of the
age of your plant, and which would be included, for
instance, in St. Lucie.
I can understand that maybe there is a
regulation reasoning for this, but is there a physical
justification?
MR. HALE: We just said that they weren't
classified safety related. We have included the HVAC
system in the scope of license renewal, regardless of
classification.
DR. FORD: Okay. So it is not just a
question of putting the rules because of the age of
the plant in one era, and changing them for --
MR. HALE: And there are various
classifications. Typically what we find is that, for
example, we credit the exhaust building exhaust fans.
They are not safety related, but they are credited for
fire protection, and they are credited for station
blackout.
And they also carry an augmented quality.
It doesn't go to the full extent, but they do -- but
they are treated special, and they are controlled
under our QA program.
MR. ROSEN: Can you identify what the
differences are? For example, if today you declared
them safety related. What additional controls and
processes would be applied to those components that
are not now applied?
MR. HALE: Really none, because I think
probably -- because even in new plants the only tech
specs you have are typically associated with charcoal
filter systems.
Well, I take that back. Well, control on
the air-conditioning is one. But in terms of material
control, quality assurance, we maintain a similar
level to safety related for our HVAC systems at Turkey
Point.
So I think it was more of an evolution of
the industry, you know, when you look at the old
plants versus the newer plants. I think the important
thing those is that we have included them all in the
scope, and they have got an aging management review,
and they were determined to be in the scope for the
maintenance rule as well.
CHAIRMAN BONACA: All right.
MR. HALE:
So they are already under observation inspection
and being managed.
CHAIRMAN BONACA: The next question is
that it says on screen wash. Why are screen wash not
in the scope?
MR. HALE: Our screens are, but our screen
wash isn't. And the reason there is that when you
look at the flow rate for intake cooling water, it is
very small as compared to circ water.
We need screen wash for circulating water,
but under accident conditions, our circ water pumps
are not running. So you are looking at a very small
percentage. So we included the screens to preclude
any small debris, and that sort of thing which may be
in the intake.
But we didn't credit the fact that the
screens have to run and you need to rinse this stuff
off of it. And we still have our strainers that are
downstream of that, and which are cleaned periodically
as well.
CHAIRMAN BONACA: So you do have in any
event programs to clean them and to inspect them?
MR. HALE: Oh, yes, but we just didn't
need to credit them for license renewal.
MR. ROSEN: I understand your comment as
to safety related water flows through those screens.
MR. HALE: Yes.
MR. ROSEN: And even after the main pumps
trip.
MR. HALE: Right. But it is such a small
amount that it wouldn't -- that you wouldn't get a
backup to where you would actually block flow in water
cooling.
MR. ROSEN: So the service water system
takes suction from the same bays as the main
circulating water system?
MR. HALE: Right. Right.
MS. THOMPSON: And for clarification, the
safety related service water system at Turkey Point is
called the intake cooling water system. The service
water system at Turkey Point is actually a non-safety
related, like potable, water type of a system just for
clarification.
MR. ROSEN: Thank you again.
CHAIRMAN BONACA: And that is one thing,
that when you read through, you are left with the
question of how come this is not, and then you think
about it and you say, well, I am sure that they have
some programs ongoing now that are not described, even
among existing programs and that are being used to
monitor the systems and this was one.
MR. HALE: Right.
CHAIRMAN BONACA: But to some degree -- I
mean, I guess it is the format of the applications
that we received that it just doesn't provide that
information. It leaves the reader with the impression
that things are not being done.
One question, for example, that was raised
by John Barton that comes later, but I can raise it
now, is that I believe on the fire protection, the
sprinkling systems.
There is a one time test, I believe,
during the last 10 years of the license life -- and
maybe we have to wait until we get there, but is the
testing of wet pipe sprinkler systems starting in the
50th year of operation.
And it leaves us with the question of is
this system never tested before?
MR. HALE: Oh, no. If you look at the
fire protection program description, we have extensive
testing that we do on the fire protection system. The
issue that was raised there was that there was a
particular criteria in NFPA 25 regarding sprinkler
head inspections at year 50.
And so as a result of the staff review,
they had asked us to include that in our commitments,
which we did.
CHAIRMAN BONACA: Yes, and this I think
came up in previous applications.
MR. HALE: Right. Right.
CHAIRMAN BONACA: Okay. I remember now.
Okay. I understand. It is just the impression that
one is left with, is this question, you know. And in
many cases, we know that there is a lot of going on.
But since you are referencing existing
programs, one would expect some mention of that and at
times we don't see it. So --
MR. HALE: The NRC regional inspections --
and I can tell you this much right off. They did a
very detailed review of the programs, and Hibo Wang,
who was the civil rep, can tell you about that.
But they sept a lot of time looking at our
programs, in terms of -- and comparing them against
our AMRs to ensure that our programs are managing the
effects that need to be managed.
CHAIRMAN BONACA: Yes, and if you can be
patient with me, I will go through this list so that
we can get through them under the plant scoping.
MR. HALE: No problem. No problem. There
were three electrical systems. One is a C-Bus
electrical switch gear and closure, the main auxiliary
transformers, and the start-up transformers. And that
was not clear to me why they were excluded from the
scope.
MR. HALE: The C-bus was a bus that we had
installed that was powered from the switch yard, and
it powers non-safety related loads. It was basically
to -- you know, like a feed pump, main feed pumps.
It was really to take some of the load off
the existing plant buses. The auxiliary and start-up
transformer, our assumption was that you have your
diesels, in terms of on-site power supply from a
safety related standpoint.
And you don't need your aux and start-up
transformers for safety, and non-safety, which can
affect safety, and certainly not station blackout.
CHAIRMAN BONACA: But the basic
assumptions in the accident analysis is that you have
also no low power in some cases, right? You would
depend on that. I mean, it is not only that the --
MR. HALE: We don't rely on it, you know,
in terms of our accident analysis, or in any of the
regulated events. And fire protection, the assumption
is that you have to demonstrate that you can handle it
with some loss of off-site power.
CHAIRMAN BONACA: Okay. So you don't
consider them because of that?
MR. HALE: There are components, certain
terms of plant availability. You know, you want your
aux transformer and that sort of thing.
CHAIRMAN BONACA: And then the other thing
that we had on the list here from John Barton is the
off-site communications tower is not in scope, and --
MR. HALE: Well, we have on-site
communications. In fact, after Hurricane Andrew, we
developed 3 or 4 different alternatives on-site. So
it is not required.
CHAIRMAN BONACA: No, this would be off-
site.
MR. HALE: Right, but the off-site one is
not required, in terms of communications.
CHAIRMAN BONACA: Okay. It is not
required?
MR. HALE: No.
CHAIRMAN BONACA: For an emergency plan or
anything?
MR. HALE: Right.
CHAIRMAN BONACA: And finally the switch
yard relay inclosure and the condenser.
MR. HALE: We don't credit the condenser
for any of the scoping criteria, 54.4, nor the switch
yard.
CHAIRMAN BONACA: Okay.
DR. SHACK: Just to continue on the
scoping a little bit. One of the things that we sort
of looked at and suggested in other reviews is do
people look at EOPs, because again this is sort of
discussing equipment that people are relying on.
And just making sure that that equipment
is somehow checked in license renewal, but I noticed
that it is not one of the documents that you look at
here for your scoping study. Are you confident that
everything that you need in your EOPs is somehow
covered here?
MR. HALE: Yes. Yes, we are. One of the
things that we did do was compare our scoping results
against maintenance real scoping results for
consistency, and one of the items under the
maintenance rule is the EOPs.
So we felt confident by doing that
comparison that we could -- that we would capture any
differences that there may be. So that was the main
thing. We found that we didn't really need to go into
the EOPs themselves.
MR. ROSEN: I am taking your answer as you
relied on the maintenance rule scoping for the EOPs.
MR. HALE: Well, we don't -- the EOPs is
not a scoping criteria for license renewal. And we
don't have to check the maintenance rule files as part
of our license renewal scoping. There are differences
between license rules and maintenance rules.
But we did go compare against the
maintenance rule for consistency. It still is not a
criteria under license renewal to do that.
CHAIRMAN BONACA: Okay. I have another
question which probably will go to the staff more than
you, but I think it is about the spent fuel pool. And
I noticed that you included the spent fuel pool
cooling in scope.
MR. HALE: Yes.
CHAIRMAN BONACA: In fact, you identified
for the spent fuel pool system three intended
functions. One is the pressure bundle integrity, and
two is heat transfer, and three is culling.
And so you have a number of components in
scoping, including the cooling of the pumps and so
forth. Now, you do have an emergency makeup system to
that pool outside of the cooling system. Is it tied to
the high pressure injection system or something?
MR. HALE: I am not sure. Do you know,
Liz?
MS. THOMPSON: Well, yes, there are makeup
systems. I am not sure if it is tied to high pressure
injection, but we certainly have that capability.
MR. HALE: We had to upgrade after our
second rerack, and we upgraded our system to a seismic
category one safety related system. We felt that we
were managing the system.
CHAIRMAN BONACA: Well, actually, I feel
that you went beyond the normal scope that we saw
before. I mean, for other plants that we have
reviewed before, the only function identified was
pressure bundling integrity, and then the steel liner
was the only component in scope because there was an
emergency makeup water coming from high pressure
injection.
And I am just questioning why there is
this variability in different applications. Is it
tied to just the design basis? I mean, how come you
have such differences in functions being identified,
and I guess that is a question for the staff.
MR. HALE: Well, I can tell you from my
own experience looking at our two sites that the
original design, for example, at Turkey Point was an
emergency makeup.
But as a result of fuel consolidation in
the spent fuel pits, you go through a upgrade as you
license that. For example, at Turkey Point, we
upgraded the cooling system to seismic category one,
and we replaced the liner with a quarter-inch
stainless steel liner plate which was not there
originally.
Redundancy. I go look at Unit 2, and you
have got a totally redundant system at St. Lucie Unit
2. At Turkey Point, we didn't originally, but it was
upgraded. So I think that has something to do with
it, is based on where various plants are regarding
upgrades that might have taken place through time.
CHAIRMAN BONACA: But I still -- I mean,
I feel at some point, for example, the GALL report
will have to have some base line acceptance of both
functions which are credited for license renewal for
that system, and therefore, the specific components
that come through that scoping and screening process
that identifies those functions.
I mean, I am just uncomfortable about the
difference in scope, particularly the one that has to
do with the inclusion of the cooling system that was
excluded from the previous applications.
MR. KOENICK: This is Steve Koenick with
the staff. You have to look at the licensing basis.
A lot of these other plants, they were required to be
safety related. They did have the boiling and makeup
as a design basis.
So there will be variability like Steve
was saying between the vintage of plants and what they
were designed and licensed to.
CHAIRMAN BONACA: I understand that, but
I certainly wasn't very happy with the exclusion of
the cooling system from scoping and screening in the
previous applications.
But I understood the logic of that. Now
I see an application coming and it goes beyond the
requirements we saw applied before, whatever the
reason may have been.
And I am left with the question in my mind
not regarding this application or the previous one of
why those components should be excluded to start with.
I mean, is there something regarding the
license renewal rule that allows you maybe not to
include things that should be there? You see, that is
really the question, and this is a significant
discrepancy here.
MR. KOENICK: Well, as Steve was saying on
Turkey Point, in order to rerack their pool, I don't
know all the details, but they essentially needed to
upgrade to become safety related.
And other plants, if you look at the
scoping criteria, today they are not safety related
cooling systems. It's not that they are not being
maintained and that there is not programs and
procedures.
But when you look at what the criteria for
license renewal are, these systems on some of the
other plants that you have looked at don't meet that
criteria, and that is the way that they are operating
today.
CHAIRMAN BONACA: But do you feel
comfortable that those systems then are going to be
effective for the next additional 20 years of
operation?
MR. HALE: Yes.
MR. KOENICK: Yes. You know, license
renewal is only looking at select systems that are
based on the scoping criteria that are safety related
or that can in effect fail safety related.
The licensees have programs and
maintenance procedures for all the other systems, too.
It's just that we are taking a particular look at
certain ones for renewal to ensure that the plants
will continue to have the safety margins that they
need.
CHAIRMAN BONACA: Okay. Anyway, I don't
have a problem with your application. I mean, you
went beyond what we have seen before.
MR. HALE: We are very happy.
CHAIRMAN BONACA: And I think you have
certainly recognized the intended functions that I
always thought had to be there. So, that's good. I
have one more question.
MR. HALE: Okay.
CHAIRMAN BONACA: Your Table 2.2.1 is a
list of all of the component mechanical systems, and
then when I got to Table 2.3.2, I find that there is
a very effective, I think, resolution of the renewal
applicant action items coming from the supporting
Westinghouse documentary report.
MR. HALE: Okay.
CHAIRMAN BONACA: And although you did not
reference it in the application; however, you do have
significant discussion into the application and also
in the SER. I could not find the one for the
pressurizer.
MR. HALE: Well, at the time that we
submitted the application, we had two draft SERS. We
had piping and we had supports. So, when we
submitted, we did not have that available to us for
the pressurizer or for the internals. Now, what
happened --
CHAIRMAN BONACA: But you must have used
it, because the SER, all the pressurizers specially
identifies four renewal applicant action items, and
then discusses the reason why or whatever you are
proposing is acceptable.
MR. HALE: As part of our REI process, and
the staff I'm sure will describe this to you, and
maybe this afternoon, but we got REIs relative to the
open items on the pressurizer.
They reviewed our application and in those
cases where the applicant action items weren't
addressed, they asked us in the REI and we responded
to it.
In the case of the internals, they asked
us all 11 of the applicant action items as an REI. So
what you will find is our responses to those in our
REI responses, and it might have been in the reactor
coolant system REI response.
I am not sure about that, and so it was a
combination of considering where they were with the
WCAPs at the time.
CHAIRMAN BONACA: Okay. I understand.
MR. HALE: They all have SERs now, and we
have also done a check where we stand against them,
and we took them either through our application or in
the REI responses.
CHAIRMAN BONACA: Well, I bring it up
because I thought it was an excellent way of
documenting resolutions in an open fashion so that you
understand the true linkage between the supporting
topical reports, and the way they had been used in the
application.
And I liked it so much that when I went to
the pressurizer, I said where is it, and so I
understand now.
MR. HALE: That's good feedback. Thank
you.
CHAIRMAN BONACA: Okay.
MR. HALE: With regards to civil
structural screening, we took a very similar approach
to what we had done in the mechanical area to each
structure. We identified the various structural
components that make up each structure.
One point that we wanted to make is that
the non-current carrying electrical 9-C components,
these are enclosure supports for conduit, and conduit
cable trays were included in the civil structural
area, because they are really structural components.
We looked at the various structural
components that support each of the structure intended
functions, and then we went through the passive, long-
lived checks in the regulations with regard to
screening.
Of course, most of the civil structural
items are passive, and typically they are not replaced
on a regular basis. So most of the stuff comes
through in terms of requiring an aging management
review.
And then we identified the individual
functions of the structural components. In the
electrical 9-C area, for efficiency, it makes a lot
more sense to walk through this in a little different
order.
For example, if I do a download in our
database of electrical components associated with a
480 volt load system, I may get 18,000 components, and
to go through that one when a majority of them are
active, it makes more sense to -- you know, let's look
at the active stuff, and get it out first, and then
look at what we have left.
So we identified all the component
commodity groups, and we identified the functions as
being very similar to approaches taken by previous
applicants. And then we identify the component
commodity groups that were passive.
One point that I wanted to make was that
if it was in the EQ program, we said that it is
subject to replacement based on qualified life, and I
think that's it. Yes, that's it. I'm sorry, I
thought I had another slide on there.
Well, that pretty much takes us through
screening. Did you have any questions regarding
screening?
CHAIRMAN BONACA: Well, actually again I
thought that your tables laid out, 3.2.1., are quite
effective, because you are summarizing in those tables
the function, and the material environment, and
therefore you are going to the scoping and screening,
and it comes through. That's very good.
MR. HALE: And six column tables were
lessons learned from the Oconee. In fact, it came
from our Duke Brothers that indicated that if you had
it all in one table -- and in fact we are thinking of
carrying that forward long term, in terms of
configuration control and management.
CHAIRMAN BONACA: Yes.
MR. HALE: I think that is a good way to
reflect the entire IPA.
CHAIRMAN BONACA: Yes, that's good.
MR. HALE: Now to the aging management
reviews. This is really the purpose as defined in the
regulation for each structural component or component
requiring an aging management review. You demonstrate
the effects of the aging will be adequately managed.
So the intended function would be
maintained consistent with the current license basis
for the extended period of operation. Now, that is a
long definition.
I thought that the best way to go through
this was to talk about the inputs that we utilized for
doing our aging management reviews. I am going to
touch on the technical resources, and talk about the
operating experience reviews that we performed, and
also mention peer reviews that we had done on our
aging management reviews.
CHAIRMAN BONACA: Before you start with
that, I would like to ask you a question.
MR. HALE: Yes.
CHAIRMAN BONACA: Of course, through the
application there is a description of the exposure
that you have to salt air. You do have a pretty
peculiar auxiliary building, right? I mean, you have
no walls there. It is all open.
MR. HALE: The turbine building. The
auxiliary building is enclosed, with the exception of
the CCW area, which has walls, but steel grating for
a roof.
CHAIRMAN BONACA: For those components
which are not enclosed -- I mean, what is the
experience of the past? It is more curiosity than
anything else.
MR. HALE: It is actually pretty good.
What we found is a large bore stainless piping, thin
wall, in the heat affected zones. We have had some
experience with St. Lucie, which in terms of external
stress corrosion cracking, and this is piping in
trenches.
But overall it has been very good. As
part of our aging management review, we walk down all
our systems that were outdoor. I mean, we walked them
all indoor as well, but outdoor we specifically were
looking for certain aging effects, like pitting. You
know, cracking.
We have had 30 years of experience at
Turkey Point, in terms of SSC and that sort of thing,
and so we know where the problems area would be. But
actually it has been pretty good.
There is a couple of isolated areas which
have challenged us, and we have talked about them in
the application.
CHAIRMAN BONACA: Yes.
MR. HALE: Our previous heat traced line
in the CDCS system, where you had insulation, and you
get some leakage or something and it holds it on to
the pipe, we actually had some experience with it.
But overall the performance has been very good.
MR. ROSEN: Let's come back to the
stainless steel piping that was found to have external
stress corrosion cracking. Was that piping that was
wetted continuously or underwater because it was in
trenches?
Were the trenches filled with water, or
was that cracking, do you think, experienced just
because the piping was exposed to salt there?
MR. HALE: No, there was some wetting
involved, and Liz, maybe you can speak a little better
to this. We have not really experienced this at
Turkey Point yet. We experienced it at St. Lucie, but
we made it an assumption for Turkey Point.
MS. THOMPSON: Well, in a trench,
sometimes in a subtropical climate like we have, we
get rains, very hard rains, all at once. And
sometimes you will get some wetting. If nothing else,
you are getting a very moist environment, with some
salt present there from the ocean and the canal water
at the two different sites.
And both are salt water environments, and
what you don't see -- and what is different about
trenches -- is because it has a cover, you don't get
the rinsing effect basically of the rainwater, which
basically in a trench, you know, you would tend to
expect that you may see a little bit higher chloride
concentrations.
And you don't get the rinsing and then the
sun drying from afternoon thunderstorms and stuff like
that that you get in most other areas.
And as Steve mentioned, Turkey Point --
you know, we are dealing with about 30 years of
experience, and at St. Lucie, about 25 years of
experience. And so far that has been all that has
really come up. The rest seems to be a pretty stable
environment for outdoor areas.
MR. HALE: And it was very specific to the
heat affected zone on that thin wall pipe where they
welded it.
MS. THOMPSON: But the stresses of the
heat affected zone, you know, plus a thinner wall,
would tend to cause higher stress and complications.
So it took the combination of all of that before we
have seen anything, and of course those have been
addressed through our correction action program under
our quality assurance program.
MR. ROSEN: How severe was the cracking?
MS. THOMPSON: We had just seen minor
boric acid indications. I mean, nothing from a
leakage perspective or whatever. Early detection, of
course, is what we deal with everywhere.
But we have found it in more than just one
location. So once we found it in one location, then
the next step is to look for applicability, and
expanding out until you confirm that you have really
got your arms around the full scope of the issue.
And so we did see it in more than one location.
MR. ROSEN: And this was at St. Lucie and
not Turkey Point.
MS. THOMPSON: It was at St. Lucie. We
took that experience and applied it to Turkey Point.
We do have a few lines that are somewhat comparable,
although we have not seen the conditions at Turkey
Point.
MR. ROSEN: And can you tell me what
systems at St. Lucie it was experienced in?
MS. THOMPSON: They were ECCS section line
systems. Basically, they are section line to the
piping systems, and we had to work through one train
at a time making repairs, and replacements, and so
forth to address those. So they were definitely
systems of great interest to us.
MR. ROSEN: Thank you.
DR. FORD: On this full page, fairly
recent Mr. Lochbaum, a concerned scientist, sent a
note to Mr. Grimes pointing out that in the last year
in several, in quite a few, in over 10, incidents
where reactors have been shut down prematurely,
unplanned, and probably because of a failure of aging
management programs.
How good do you feel about this programs,
in terms of their ability to see or to detect a
problem before it occurs?
MR. HALE: We are very confident in our
programs. In fact, I think the inspection that was
recently performed upholds that. We look at those and
we factor in any of those failures in consideration of
our own instances.
For example, the V.C. Summer, we looked at
the applicability there to Turkey Point. You know,
they had penetrations, and that's identified as an
open item in the application.
DR. FORD: But these are really all
reactive.
MR. HALE: Well, that penetration issue,
I think there was some recent information that came
out regarding the failure mode that had not been
originally, but we all had plans for reactor vessel
head penetration inspections as part of 97.01.
You know, it's just that -- I think there
was some -- the new information that came out
available, but it is not as if we were ignoring it,
you know. I think that -- well, my perspective on it
is that I have been at FPL for over 30 years.
And I have been at both of these plants,
and I think you pretty much see most everything, or
have seen most everything based on the long term
operations at length.
DR. FORD: Yes. Unfortunately, you always
see something the next day which you didn't predict
the day before. I guess my frustration to a certain
extent about this whole procedure is that I keep
seeing -- for instance, the frequency of inspections,
and the depth of inspections.
It is dependent on how good your
disposition algorithms are, and we keep seeing in all
of these license renewal aging management programs
reference to ASME 11 procedures.
And yet the data upon which those curves,
those disposition curves, are not always good quality,
and they are always being revised. And unfortunately
when you find that we need to revise them after we
have had a fairly catastrophic event.
And maybe this will come out this
afternoon as we are discussing from the NRR
perspective, but do you have any feeling as to where
we are at risk? For instance, baffle bolts right now.
Could you predict when the baffle bolt cracking
occurrence would in fact take place, and what would
the impact be on, for instance, delta-LOCA, or LRF?
MR. HALE: I feel very confident about the
baffle bolt area because we have had an extensive
probing program going on right now as part of the WOG
to address that specifically.
And including safety evaluations
regarding, you know, failures. We were doing -- and
Roger Newton is back there, and he can tell you,
because they pulled theirs at Point Beach and
inspected them.
And George Roble was also there for GANE,
who has done the same. So I feel in terms of the WOG
that we have a good feel for the baffle bolt issue.
With regard to Section 11, where we credited Section
11, at least the mechanical systems, was for Class One
inspections.
Now, we are moving to a risk informed in-
service inspection at Turkey Point. We factored in
things like risk, fatigue, into what we are going to
be looking at.
For example, we are going to look at every
weld in the surge line in the next 10 year interval,
because that is the critical location to Turkey Point.
DR. FORD: Well, that's great. What is
the area of your greatest risk right now?
MR. HALE: Greatest risk?
DR. FORD: Well, you have about 7 or 8
programs that I see listed in your application, but no
details in there about them. How good do you feel
about their worth, and which ones would you want to
upgrade from a risk point of view?
MR. HALE: I feel -- well, what we
described in the application, behind every one of
those on site is what we call our program basis
documents.
DR. FORD: Okay.
MR. HALE: And details specifically how
the plant specific procedures that implement those, as
well as specific enhancements to procedures, in terms
of what we feel that we need to do.
If you look at what is happening in
industry over the last few years, you know that
inconel is an issue. I mean, that seems to be one of
the underlying things behind a lot of these issues
that have been raised.
At St. Lucie, we have a number of inconel
instrument penetrations, and we have had leakage there
before. So we have been following the inconel issue
for some time, and what I have seen through the years
is they started saying, well, it is a bad heat.
And then, oh, here is another one, and
here is another one. But certainly inconel poses a
challenge for all of us, and to me I think that's
where the risk is.
But I think we are learning a whole lot
more over the last couple of years, because the V.C.
Summer event was related to an inconel safe end, I
believe. You know, certainly the penetrations on the
inconel head are all centered inconel.
DR. FORD: I bring it up now because the
information for making those decisions come out of
those three sub-bulleted items there.
MS. THOMPSON: I think an important thing
to note is that the aging management reviews
-- and Steve will get into this a little bit, and
factor in operating experience, both at our plants and
at other plants.
And that is part of an ongoing process
that we always do. Operation of our plants is based
in a defense-in-depth, you know, multiple barriers
type of a concept.
And we have to recognize that those
multiple barriers really are what provide the ultimate
level of safety from redundancy, between systems. You
know, systems backing up other systems.
And the fact that we have and have
included in our aging management program are most of
our early detection processes that we have in place
now under the current term.
And in a couple of cases we have suggested
enhancing those to further cover a broader scope
basically for the renewal term. Those are the
processes that put us in a position where that
operating experience is identified early, and then we
as an individual operator of the plants, as well as an
industry, share that.
And that's where I think we really have
the strength and the safety performance of this
industry. We don't what to let problems get us to the
point where they force us undue shutdowns, unplanned
shutdowns.
And we know that we have to take the right
actions to address those based on not just our own
specific planned experience, but also what we find as
we move forward basically in this industry and
managing these plants.
And a lot of our early detection programs,
from the systems and structures monitoring program,
and to our boric acid programs, are the types of
things -- just to name a couple of examples, that
really put us in that early indication type of a
process that allows us that additional layer of
defense really to ensure our plants are safe.
CHAIRMAN BONACA: And on the other hand,
you might reference to the V.C. Summer issue. They
are more -- and I am not as much troubled by the fact
that you have an inconel problem, and you have some
cracks developing, than about the fact that the
programs which were in place there did not detect
those cracks.
In fact, they didn't see any when the
inspections were performed. And then we had to wait
until the crystals were out, and that's really what is
our concern the most. I mean, these programs are
great in many ways.
I look at it and there is a full life
cycle management here being laid out, and developed in
front of us. You know, the concern is always about
how able are we to detect in the inspections, because
the inspections are many and thorough.
DR. FORD: These are more general
comments, and not specific, as those will come out
this afternoon. But it just concerns me that as an
industry that we tend to go by industry experience,
and by implication is the mean of the experience.
And what we are really interested in is
the first occurrence. For instance, before V.C.
Summer, the day before, we didn't know it was going to
occur. And when it did occur, it was, "oh, shit," and
what are we going to do about it.
And time and time again throughout our
history we have done exactly that, that in large pipes
and BWRs, they are never going to crack, but for
whatever reasons yet they did.
And this is why I have got great suspicion
of these aging management programs which can't see
forward.
CHAIRMAN BONACA: We left behind an issue
on scoping that I would like to get back to, because
I think it is important, and that has to do with the
October 1 issue of known break location line piping.
I guess support by known break location line supports,
seismic. Why are they not in scope?
MR. HALE: The supports are in the scope.
CHAIRMAN BONACA: I understand that. Why
are the segments not in the scope?
MR. HALE: In looking at our licensing
basis regarding high energy line break and flooding,
we felt that we had already accommodated pipe failure
aspects.
Now we are working with the staff right
now and understand the concern they have raised, and
we are in the midst of responding to their open item.
Our feeling is that our current licensing
basis is acceptable based on approved flooding
evaluation and our high energy line item, but we
understand the staff's concern. So we are taking an
additional step, and looking at our plant regarding
the assumptions that are being proposed.
And essentially the assumption is that
aging would change the assumed break locations and
this sort of think for systems containing fluid and
steam. So we are evaluating that.
The supports have always been in the
scope, and another point that I need to raise is that
we have got a number of non-safety related systems
already in the scope, including the piping.
The Turkey Point fire protection brings in
numerous systems in the Aux building that are non-
safety related. So the pipes wouldn't even scope
there.
So we are walking or we are in the midst,
and in fact we are going to work with the staff,
understanding their concerns. And we will probably
identify some additional lines that we will include in
the scope.
CHAIRMAN BONACA: And I am sure that you
will agree that if you had a segment between supports
that is likely to corrode, or whatever, and then fail,
and then fall over into other systems, that would not
be acceptable. You don't disagree with that do you?
We are trying to understand the logic.
This is the second application that we have seen in
which there is this issue. The first one I think had
different connotations there, because they, I believe,
had seismic qualified supports.
And then they were looking more at zones
and you are not here. But try to understand why this
issue is there, and whether or not -- and we will
understand that this afternoon that there will have to
be specific items on the part of the staff for
licensees in this particular area.
MR. HALE: A lot of it has to do with your
current licensing basis. You know, when do you assume
the seismic occurrence. You know, we all went to the
older plants when they went through A-46, and you just
had to show that you had shut down the plant with a
seismic -- a given seismic occurrence.
If you jus say that failure can impact
safety related equipment, period, well, that is a
difference basis behind -- you know, that is saying,
okay, I have got the seismic occurrence, and I have
got the LOCA.
And so if you take the definition,
"affects safely related period," you have to go back
and look at your licensing basis as to what your
assumptions are. Typically most of us don't assume an
earthquake with design basis events.
MR. ROSEN: Notwithstanding all of that,
and going back and looking at the license basis, and
all of that, where we end up on this issue I think is
that we have an unsafety related piping out to a non-
safety related support, where we have the support in
the aging management program, and the aging management
review. But the piping itself, which is the load
carrying member out to that support, is not.
MR. HALE: Well, let me correct that. We
did include piping segments that provide structural
support in the scope for that very reason, because it
is an extension of the support.
What we are talking about here is a non-
safety related line that sits above a safety related
piece of equipment.
MR. ROSEN: Where the non-safety related
line does not provide any kind of structural support.
MR. HALE: Right. We did include the pipe
segments. Remember when I was talking about screening
and stress analysis? We actually took whatever
portion of the piping was credited downstream of the
boundary, as in the scope of licensing. That pipe is
in the scope of licensing.
MS. THOMPSON: I would also like to add
that in addition to what Steve described, which was
the piping segment that is connected to the safety
related portion being considered in the scope, the
support is being considered in the scope.
We also considered protective features,
such as sump pumps and actual protective features for
leakage considerations in the scope as well. So our
difference between the staff's open item and what we
have already considered in our application is actually
very small.
We feel like we understand that, and we
would like to -- you know, we have asked our project
manager if we could actually go through our resolution
on that next week. So we feel like we can move
forward on that.
And for Turkey Point, as I think you all
mentioned earlier, a number of the areas are outdoor
as well, and so the things that are underneath, those
safety related pieces of equipment, are actually
designed for wetted environments.
MR. HALE: Outdoor service.
MS. THOMPSON: Outdoor service. So our
scope tends to be quite small in this area. but we
feel like we can move forward on that. So our delta
is actually a relatively small delta.
And we understand the staff's position,
and we will work forward on that. I think our
difference has been consideration of what we consider
our current licensing basis.
But I think aside from that, we understand
the staff, and we will work forward to resolution.
CHAIRMAN BONACA: Okay.
MR. HALE: Okay. Any other questions? If
not, I would like to go through these three points.
With regards to the AMR technical resources we had
available to us, although only five generic technical
supports were submitted to the NRC for review, the
Westinghouse Owners Group, we generated over 15 of
these generic technical documents.
And it incorporated basically the history
of all of the Westinghouse plants. So we have that
integrated in it, and it pretty much covered every
component that you would have in the power plant.
And certainly in the early '90s, NUMARC,
with EPRI, had the industry reports, which were
submitted to the NRC for review. The B&W tools, I'm
sure you have heard this, all of the owners' groups
have bought those tools that look at the evaluation of
aging effects for non-Class One mechanical systems and
civil structures.
You have to tailor it to your plant. You
know, we did an evaluation which took the tools, and
applied to to Turkey Point. We looked at the Aging
Management Reviews performed by a particular
applicant, and that we felt did a fairly detailed
review of.
We looked at submitted applications in
certain cases, and if you have some unique materials,
you actually get into materials handbooks. We also
have a materials group and a materials lab, and so we
also had at our disposal laboratory results of
analyses that have been formed through the years in
support of corrective actions.
And we are very active in the industry
groups, and so those were the technical resources that
we had at our disposal.
And with regards to operating experience
review -- and I feel that this is one of the strengths
of the aging management reviews that we performed.
Not only did we look at the industry stuff
that was out there, both in the INPO and the NRC, and
how we responded to that, but we also looked at all
the non-conformance reports and condition reports in
our database.
We looked at our event response team
reports. These were teams that are formed after a
major event. License event reports. We looked at all
the FDL metallurgical laboratory reports that we had.
And then we actually -- we were on site,
and so we spent a lot of time with the system and
component engineers in going over our aging management
review results as to what they are actually seeing out
in the field.
We used this as input for identification
of our aging effects, but another positive though is
that it also shows that we are managing aging. If you
are identifying items requiring corrective action, it
says that you are out in the field and you are out
there and actually managing aging of these systems.
So we draw on a fairly extensive database,
in terms of input into our operating experience.
CHAIRMAN BONACA: Did you look at the GALL
report that was being developed at that time?
MR. HALE: Yes. In fact, we were very
active. You know, the industry established technical
review groups -- mechanical, civil structural, and
electrical -- and we have representatives on all three
of those.
In fact, our mechanical lead, he is
probably one of the most knowledgeable of the
mechanical folks in the group. In fact, he is
providing most of the input to upgrades to the B&W
tools right now.
And in addition to all of that, we felt
that it was worthwhile to have independent eyes come
in and look at the results. And not only the results,
but out of procedures, and the way we approached this.
We had license renewal staff members that
actually gone through the process with the NRC review
it. We actually had some ex-NRC and other consultants
come in and look at the way that we had done our aging
management reviews.
We felt that because Framatome had
submitted generic reports, and gone and gotten SERs,
that we wanted to have the technical experts from
Framatome review all of our Class One AMRs.
CHAIRMAN BONACA: Which components were
manufactured by B&W?
MR. HALE: Our reactor vessel, but in
terms of just what are the aging issues associated
with rack cooling components, they had gone through
quite an extensive review of the generic reports for
the B&W plants.
So we felt that the type of aging issues
and that sort of thing were worthwhile to have him
come in and actually review in detail the results and
conclusions we had reached.
And then in the electric/I&C areas, we
actually had our corporate electrical chief, who is
also -- I guess, Liz. that he is an IEEE chair,
actually review our electrical/I&C aging management
review results.
CHAIRMAN BONACA: I had a question, and I
don't know if it fits here, but what is the -- well,
material-wise, what is the basic difference between
Class I piping and non-Class I piping?
MR. HALE: It is essentially the
definition consistent with what we call Quality Group
A, reactor pressure boundary up to the second normally
closed valve.
It's just that you have orifices sometimes
breaking the boundary between Class I and non-Class I.
For example, attached to the reactor coolant system,
and that's why you will see a section in the RCS on
non-Class I.
Well, what I was looking at was the aging
-- the facts to be managed. There were some
differences there. For example, you know, Class I
piping not subject to wear.
And then non-Class I piping subjected to
loss of material by a different means or several
means. And I was just asking in general the
difference in materials.
DR. SHACK: Well, a lot of it is stainless
steel versus carbon steel. So one is essentially
immune to erosion, and the other is going to be
susceptible to erosion.
CHAIRMAN BONACA: But non-Class I piping
has no cladding of any type?
MR. HALE: The Westinghouse plants, the
piping is stainless.
CHAIRMAN BONACA: For non-Class I.
MR. HALE: No. Well, it depends.
Typically systems that are exposed to boric acid are
stainless steel.
CHAIRMAN BONACA: Well, boric acid wastage
-- I mean, you have those for Class I, and need for
chemical control, and starts corrosion and cracking
issues.
So there was just such a difference in the
application between the issue of where, and where
simply there is no monitoring for wear of Class I
components, and were identified by several means on
non-Class I. But I understand, and that is really the
difference in the material.
DR. FORD: Could I ask again a very
generic question. If you look at this slide and the
two previous ones, can you -- and everything is great,
great words.
Can you give an example -- for instance,
for the specific situation of baffle bolt cracking,
there is a physical phenomena. How do you use these
technical tools, the technical resources, the AMR, the
operating experience and the peer reviews, to solve
that particular problem?
And I realize that I am asking you a half-
an-hour talk, but if you could just kind of bulletize
things. What information did you get from these
various resources to come up with a better inspection
program and correction actions for baffle bolts.
MR. HALE: For baffle bolts, the WOG
report, we utilized that.
DR. FORD: Yes, I have got this thing
here, but there is no data shown in this.
MR. HALE: Oh, I understand. You will see
some data that we have presented in our REI responses,
where we have provided more data as they are analyzing
and looking at these various baffle bolts.
But we identified radiation system and
stress corrosion and cracking, stress relaxation. All
these aging effects for the baffle bolts, and this is
based on the experience that we have seen, and also on
expected experience in the future.
So we have established for those bolts
-- that is part of our -- the rack vessel internals
inspection program over and above Section 11. I
believe we are planning to do one early in the renewal
period on Unit 3.
DR. FORD: And inspection process?
MR. HALE: Well, the inspection process
will follow very closely what has been done at the
previous Westinghouse plants, where they have actually
done ultrasonic examinations of the bolting material.
I believe you also -- and, Roger, correct me if I am
wrong, but you actually pulled all the bolts; is that
right, or just the ones that had indications?
MR. NEWTON: At Point Beach?
MR. HALE: Yes.
MR. NEWTON: At Point Beach, we had a
removal program, where we were taking the bolts out
and replacing them with new material, and a --
CHAIRMAN BONACA: Could you come up to a
microphone, please?
MR. NEWTON: Yes. I am Roger Newton, and
I am or was the Chairman of the Westinghouse Owners'
Group on the baffle bolt program. I am also from
Point Beach Nuclear Plant, an older plant, and we did
participate as part of the Westinghouse and EPRI
baffle bolt program.
And as part of that program, we were
looking for actual experience of bolts in nuclear
plants, and Point Beach is one of the older plants. So
we volunteered to do a bolt inspection and replacement
program to add information to the industry.
We have 347 stainless steel bolt material,
and older plants have that, and newer plants have 316
stainless steel bolt material. So there are two
different categories of plants in the Westinghouse
family. I think Turkey Point has 347 don't you?
MR. HALE: I believe so. I would have to
check it out.
MR. NEWTON: You are old enough to have
347. WE did this just to provide information to the
industry on what aging was looking at in this
particular area and to answer questions for the NRC,
and provide a benchmark that at this age and time what
are we seeing.
And as part of the program, we inspected
all of the bolts, and for those bolts that had
indications, we said, well, let's see if we can
replace the pattern, plus the additional bolts that
had indications.
So we ended up replacing -- well, I knew
those numbers by memory at one time, but about 170
some bolts throughout the internals. Most of them did
not have indications because they were in the pattern
that we wanted to replace to.
But we did replace about 50 that had
indications. We found that of those 50 that 9 did
have cracks. We tested almost all of the bolts that
were removed by structurally, and put them in a took
and breaking them to indeed see what their
characteristics were.
All of this information was put together
in a very extensive report and provided to EPRI, which
was also provided to all of the Westinghouse Owners'
Group members. So that's part of the operating
experience for 347.
Similarly, an older plant that had 3/16ths
stainless steel replaced their bolts as well. They
found that for that aged plant that there were no
indications and no failures.
So we have a mark in time with respect to
the bolt behavior in a Westinghouse plant. So that is
part of the operating experience that the industry is
now relying upon.
The MRP program of EPRI is continuing to
pursue the bolting issue, and looking at longer term
effects of aging, and looking at whether voids play a
role in it.
There was an integrated program that will
support all of us out into the future and that pretty
much all of us will take credit for as part of the
Aging Management Program, and deciding what the next
steps are. And so that is somewhat of the operating
history.
DR. FORD: So your aging management
program for Turkey Point is sort of a living document?
MR. HALE: Yes.
DR. FORD: And tomorrow it will change?
MR. HALE: Yes. If you look at the --
right, and because I am a member of the Westinghouse
Owners' Group, we have all this information available
to us either in the WOG technical reports, or
information as brought forward.
So in answer to your question, in terms of
where, the participation in the Westinghouse Owners'
Group is the primary source of information relative to
baffle bolts.
But, yes, if you look at our application,
as well as our response to REIs, you will see that --
and in fact the staff has asked us to submit our
inspection plan, detailed inspection plan, in advance
of performing the inspection.
DR. FORD: And the fact that the distance
rate tends to go on logarithmically with fluence, your
response time to these changes frequency will
increase, or your response frequency will increase?
MR. HALE: Yes.
MR. ROSEN: The response time will go
down.
DR. FORD: Will go down, yes.
MS. THOMPSON: I think that you have to
look at all of these as living programs, and I think
the most current example is the Alloy 600 program,
where when we submitted the application, it was prior
to any of the discoveries that happened at Oconee and
so forth.
And now you look at it, and we are
shutting down one of the units for a scheduled
refueling outage next week, and we have an inspection
that the reactor had planned.
And that will be factored in, and that is
one of the open items. We have responded to the
bulletin. It is going to be a living program. We are
going to incorporate that in, and I think that
particular open item really just becomes a matter of,
yes, this is a living process.
And we just happened to be in the middle
of our licensing process here for renewal, but you
would expect this type of change as items come up.
And we will do the right thing and update our programs
accordingly.
MR. HALE: I think the one thing -- and
this has been a good learning process for us all, in
terms of -- well, because the aging effects evaluation
that we have performed, it not only looks at what
experience has happened, but what we would expect to
happen, in terms of aging effects.
So I think that we have improved our
knowledge level, in terms of trying to get at the
issue that you are raising in terms of avoiding the
failure before it occurs. I know that I know a whole
lot more about aging of the plant.
DR. FORD: Thank you very much.
MR. HALE: And one of the things that we
did that I mentioned previously was the development of
our program basis documents. For each program that
you see in the application, we have what we call a
program basis document.
The program basis document provides a
detailed evaluation of the 10 attributes, the summary
of which you see in the application, and we felt early
on that we needed to do this, because if you show the
program to someone, and they say, well, show me the
program, and it may be as many as 10 to 20 procedures
that are being implemented, but you don't have this
umbrella that says this is what defines what the
program is.
And in some cases, you do, but in other
cases, especially some of these non-regulated
programs, it is not as clearly defined. So we felt
that it would be a good idea to have a basis document
which bridges the program described in the application
with actual implementation in the field.
This basis document identifies specific
plant procedures which will implement the inspections,
the walkdowns, or whatever may be involved, and it
also is a place to capture all of our specific program
commitments.
I think as a result of going through this
process, we identified about 80 program commitments,
and it is down at the procedural level as to when we
will do the inspection, and what changes to programs,
and what specific procedures need to be made.
And this was also one of the topics that
the inspection team came down and looked at when they
did the aging management review inspection.
MR. ROSEN: When this kind of a program
requires you to change a procedure, does the procedure
reference back to that this change was as a result of
the aging management review done on the license
renewal?
MR. HALE: Yes, we are going to put a
statement on every procedure that implements that
program that this is a commitment for license renewal,
and we will identify -- because some of the procedures
may be broader than the specific scope related to
license renewal.
And we will highlight the specific steps,
and the specific components that are covered in that
particular procedure for license renewal. So any
change that occurs in the future is going to have to
go through a review process to ensure that it
addresses license renewal.
MR. ROSEN: This is to preserve the
license renewal commitments for the extended period of
operation?
MR. HALE: Yes, because where the rubber
hits the road is in the procedures at the site. With
regards to TLAAs, you have got six criteria that are
specified in 10 CFR 54.3.
We did a fairly extensive review of all of
our current licensing basis documents, and our
licensing correspondence is tech searchable. We
looked at tech specs, and the USFAR, as well as the
DBDs.
We identified potential candidates for
TLAAs, and then we reviewed them against the six
criteria. The methodology is prescribed in NEI 95-10,
and we were consistent with that methodology.
As part of that process, we also looked to
see if there were any exemptions involving TLAAs, and
we did not find any. The TLAAs for Turkey Point as
described in the application, a reactor vessel
irradiation embrittlement, Class I and non-Class I
fatigue, EQ, containment tendon relaxation, and
containment liner fatigue.
And then we had a case of wear/erosion,
where there was a TLAA associated with -- a couple of
cases where there was wear/erosion associated with our
current licensing basis, and then crane fatigue in
some of the major cranes.
With regard to our conclusions, the aging
management programs at Turkey Point we feel are
adequately managing aging effects so that the intended
functions will be maintained consistent with our CLB
for the period of extended operation.
And, secondly, all our TLAAs from Turkey
Point were identified and evaluated, and shown to be
acceptable for the extended period of operation. That
concludes our presentation. Are there any more
questions?
CHAIRMAN BONACA: I have a number of
questions. However, our component are systems
specific, and so we will go through when we go through
the SER. I am sure that you are going to be here for
the rest of the day.
MR. HALE: Yes. Yes, I will be here.
CHAIRMAN BONACA: And so we can ask you to
provide information at that time, and that will be the
best way to do it.
MR. HALE: Okay.
CHAIRMAN BONACA: Thank you. And with
that, I think we should take a break now, and we will
resume the meeting at 20 after 10:00.
(Whereupon, the meeting was recessed at
10:03 a.m., and was resumed at 10:21 a.m.)
CHAIRMAN BONACA: All right. Let's resume
the meeting, and we have now a presentation by NRR of
the Safety Evaluation Report by Mr. Raj Auluck.
DR. AULUCK: Good morning. My name is Raj
Auluck, and I am the project manager for the Turkey
Point license renewal effort, and the purpose of
today's meeting is to brief the subcommittee on the
staff's SER related to the Turkey Point license
renewal application, and to respond to the questions
that the committee members may have.
I will provide an overview of the safety
evaluation report, followed by other staff members
summarizing their research of the review. As the
slide shows, we have a number of staff members
scheduled to speak.
We do not have that many open items, but
for discussion purposes, we have tried to make the
slides complete so that when the appropriate time
comes, you can ask your questions, and we can respond
to your questions.
And most of these staff members have
participated in the NCR, and at this time, I would
also recognize Mr. Steve Koenick, and he is my backup
project manager, and helped prepare the SER also, and
he is getting ready to take on any other future
applications.
As you can see, this is an application
submitted on September 8th, 2000, and this is a little
over a year. It is a three loop Westinghouse,
Pressurized Water Reactor, and a two unit site, and
each is designed for 2300 Megawatts.
Now, the site is shared by two gas and oil
generating units. The plant is located about 25 miles
from Miami in Florida City, the same distance from the
Keys, Key Largo.
The license expires on July 19th of 2012
for Unit 3, and April 24th for Unit 4 -- well, for
Unit 4, April 10, 2013. And they are requesting a 20
year extension to these dates.
DR. ROSEN: So those are typos on the
slide that is Unit 3 and 4?
MR. AULUCK: Yes, correct. It should be
Unit 3 and 4. And for the different applications, we
performed an acceptance review and sent a letter to
the applicant in October, and attached to the letter
was this targeted schedule.
As you can see, we have met most of the
milestones. The next important milestone other than
ACRS meetings is for the applicant to respond to the
open items in the SER.
Now, this schedule is based on our
standard 30 months schedule. Since there is no
hearing -- the hearing proceeding has been closed --
and so this will be changed to 25 months, and we are
in discussion with the applicant, and we will see
where we are.
They have requested with respect to this
schedule an earlier date, and so we are in the process
of discussing that with them and with our staff how to
support any new date.
The SER format follows pretty much the
application for. The difference is that we have in
Chapter 3 all the AMRs and AMPs that are in the
application contain that information in Appendix B and
Appendix C.
And Chapter 1 is the introduction and
general discussion; and Chapter 2 is the structures
and components; and Chapter 3 is the AMRs as I
mentioned; and Chapter 4 is the TLAAs.
As was mentioned by Steve a little
earlier, this is the first PWR and FPL participated in
many industrial groups, and they were an active
participant in the Westinghouse Owners Group.
CHAIRMAN BONACA: It is the First
Westinghouse PWR.
MR. AULUCK: Westinghouse PWR. And the
four Westinghouse Generic Reports were submitted to
the staff for a staff review, and as mentioned
earlier, the reports were not finalized. So the
applicant did not incorporate those Westinghouse
reports by reference.
They addressed all the issues there, and
for the other reports we had several REIs, and all the
applicant items, the action items, were in the report.
But the safety evaluation of these Westinghouse
reports were stand alone documents, which were not
completed at the time of the application.
As far as the staff review, the staff
identified open items,a nd the list is quite short.
The first one is the scoping of seismic II over I
piping systems, which was already discussed earlier,
and we will go over it in more detail in the following
presentations this morning.
There was an open item at Plant Hatch, and
we especially asked the applicant to wait until the
resolution on Hatch is reached, and the staff's
position is clarified, which has been done now.
So now we are in the process of discussing
further the applicant's position on Turkey Point. The
staff's position will be given later on, but it is
very clear that all II over I piping should be within
the scope of license renewal, and we will go from
there.
CHAIRMAN BONACA: What kind of additional
burden does this inclusion of all II over I piping --
for example, for Hatch. I understand this morning
from the presentation that it is not much of a burden
for Turkey Point. It doesn't have much piping.
MR. AULUCK: Well, Hatch probably did some
several walkdowns and they did have to include some
systems which were not previously included.
CHAIRMAN BONACA: No, what I am trying to
understand here is the logic of the applicant, because
this issue is a current issue, and clearly there must
be a significant difference in scope to justify this,
and so we will try to understand the logic.
MR. AULUCK: I think we will have that
later, and it depends on how each plant briefs and
identifies those systems. In the case of Turkey
Point, they went with area approach, and what is
contained there.
If I remember there were 7 or 8 areas only
where they have this potential interaction. So, the
staff is prepared to discuss that this morning.
A second open item is the reactor vessel
head alloy 600 penetration inspection program.
Leaking from the vessel head penetration nozzles has
been identified recently at some plants, and so the
staff is working with them to resolve this issue.
And so our expectation is that whatever
resolution is reached with industry that Turkey Point
will follow that, and we will have a presentation on
this issue also.
CHAIRMAN BONACA: So this is not an open
issue because there is a difference of opinions
between the staff and the licensee, and there is an
emerging event issue that you just are expecting ot
have some commitment from Turkey Point?
MR. AULUCK: I think whatever resolution
is reached between the staff and industry, and Turkey
Point is part of that -- and since we do not know the
resolution of that is, we consider it an open issue.
MS. THOMPSON: I would consider this an
emerging issue, and we have responded to the bulletin,
but of course that just happened very recently.
Whereas, our application and the REI process happened
before the Oconee discovery.
CHAIRMAN BONACA: Yes. I am trying to
understand what the closure means. It will be quite
a while before there is a full resolution of the
technical issues. What is necessary to close this
issue from the perspective of the license renewal?
It seems to me just a commitment to --
MS. THOMPSON: Right. Right.
MR. AULUCK: And so we don't perceive any
problems here, but at this time we are not in a
position --
CHAIRMAN BONACA: No, I understand.
DR. SHACK: Just out of curiosity. You
have an outage coming up. How inspectable is your
plant from a visual point of view? Do you have
insulation on the head?
MS. THOMPSON: Yes. The insulation issue
tends to be more of an issue for the combustion
engineering plants. So Turkey Point being a
Westinghouse plant, there is insulation present, but
we feel like we can perform the inspection.
We are feverishly planning this activity.
Obviously it is something that has just come up
recently and the timing of it, and to try and take
action this quickly truly is a challenge for us to do
at the station.
We have taken one of our main managers off
to the side basically, and he is focusing all of his
attention on trying to get this activity planned to be
ready to go really next week.
So for those plants, just for your
understanding of the type of impact this is, it is not
easy to plan something that is done in a such a high
dose area. Plus, it is relatively costly.
So it is something that we really are very
focused on right now to try to accomplish it at ALARA,
and also in a cost effective manner to be able to get
it done in this period of time.
CHAIRMAN BONACA: This inspection that you
are planning, is it imminent?
MR. AULUCK: In October, I think.
CHAIRMAN BONACA: In October? All right.
I didn't understand that from the SER. I thought that
you advanced your inspection based on the NEI schedule
as shown here, but I didn't realize that you had one
so soon.
MS. THOMPSON: Yes, that is the advanced
schedule. Our refueling outage was scheduled to start
this coming Monday. So we are basically within a week
now of when we would start, and when the head is
removed from the reactor is really our start time for
performing the inspections. So that is the first week
of the outage.
CHAIRMAN BONACA: Okay.
MR. AULUCK: The third item is reactor
vessel underclad cracking. In their application the
applicant indicates that the generic evaluation of
underclad cracks have been extended to 60 years using
fracture mechanics evaluation space on a
representative set of design transients with
occurrences extrapolated over 60 years.
And they also mention that the number of
design cycles and transients are presumed to encompass
the WCAPS 15338 analysis, and this WCAP was submitted
for staff review in March of this year.
So it is undergoing a review, and the
review has been completed, but the SER has not been
issued. The current schedule that the staff
evaluation will be issued by the middle of next month.
CHAIRMAN BONACA: Now, the reactor vessel
was designed and constructed by B&W.
MR. AULUCK: Yes, to Westinghouse
specifications.
CHAIRMAN BONACA: All right. So this
evaluation is being done by Westinghouse, but -- well,
I am trying to understand why wouldn't it be
-- that you would have an B&W evaluation on that.
MR. HALE: Well, B&W fabricated the
vessel, but it was built -- the vessel was built with
Westinghouse specifications.
CHAIRMAN BONACA: Okay.
DR. SHACK: There was a question that I
meant to ask before. Your fatigue management program,
I take it that wasn't a new program for license
renewal. What was the driving force for instituting
that? What problems were you addressing when you
instituted that?
MS. THOMPSON: I think you are referring
to the fatigue or what we call the fatigue monitoring
program. Basically it is a confirmatory program, and
whether you look at the current term or the renewal
term, we are confirming that we are not exceeding the
number of cycles that were assumed for operation.
DR. SHACK: But you had some locations
though that were approaching usage factors of one?
MS. THOMPSON: No, not necessarily. We
had some that were higher as I think all plants do.
Some of the surge lines and so forth that have been
evaluated in some plants you will find some of the
nozzles and spray lines, and so forth, just depending
on the particular plant.
But I think that has been a confirmatory
program to make sure that we are staying within our
design analysis regardless, and to keep track of that.
MR. AULUCK: Okay. The next item is an
open item and is acceptance criteria for field erected
tanks internal inspection. We will have a discussion
on this item later on in the presentation, but this is
a new program used to manage in part aging and effects
of loss of material due to corrosion of the tanks
within the scope of the program.
And this chemistry control program will --
two of these programs will manage corrosion inside the
tanks. At this time, at the time of the staff's
evaluation, the applicant had not developed a program
with acceptance criteria and limiting procedures.
So that is one of the reasons that is an
open item. So as soon as we receive the information,
we will review it and take the next step.
CHAIRMAN BONACA: And this includes all
the other RWST and --
MR. AULUCK: Yes.
CHAIRMAN BONACA: And on the third item
that you had, that is the Westinghouse topical report
being reviewed for the reactor vessel underclad
cracking. When do you expect to have that review
completed?
MR. AULUCK: The middle of October. It is
pretty close. The staff is completing the process of
management review.
CHAIRMAN BONACA: So it seems to me that
the potential for closure of this open item is in the
very short term. What is the understanding that you
have of that?
MR. AULUCK: As I understand, right how
the current scheduled date for a response to the open
items is December 17th. The applicant is targeting
for the end of October or the first week of November.
Around that time. So at least six weeks.
CHAIRMAN BONACA: Okay. Thank you.
MR. AULUCK: And this is a slide on
inspection activities. So far we have performed two
inspections. The first was for a week in may for
scoping, and a two week inspection on the AMRs, split
into one week segments.
This is in addition to the staff audit
done on the scoping in November of last year. I think
that besides --
CHAIRMAN BONACA: So in total you had four
inspections?
MR. AULUCK: Yes, we had four site visits
in four weeks, yes. Once we were there, we discovered
that all the projects developed for license renewal
were under the plant's QA program, as I understand
there were no QA procedures for license renewal.
So they overlooked procedures or
instructions on quality instructions, numbering 5.2
5.3, 5.4, and 5.5. And each of these documents
provide guidance to their engineers and staff members
how to scope the document, and how to scope the
systems, and how to screen the system, and how to
review the AMR.
This is more like a step-by-step, and so
we looked at the application here things were not as
clear and there was a lot of questions from the staff,
and which were answered by redirecting elsewhere in
their applications.
But once we went to the site and looked at
some of those quality instruction procedures, and
taking it step-by-step, it was really helpful. And
then in addition to that there was backup
documentation as Steve mentioned for each program
basis documents. And descriptions for procedures and
assistance.
And they were easily accessible. So these
inspections did not find any major findings, but there
were several minor discrepancies and the drawings were
not consistent with each other, or with different
documents there were some discrepancies.
And then once we told them, they were
reported to the appropriate programs and followed up
on, or they were addressed elsewhere. And the team
did review several documents for the new programs, and
for the existing programs.
With that, if you have no questions that
I can answer, we will then move to the next
presentation.
CHAIRMAN BONACA: We as a committee have
expressed interest in the form and clarify of the
documentation, because it is a complex evaluation, and
it is important to have documents that will be
understandable.
Some of the members of the subcommittee
had an impression that this was a good application
insofar as clarity of the form. What is the
perspective that you have?
MR. AULUCK: I think it is -- I mean, this
is my first -- and I have been involved in project
management of plants, and licensing, and operating for
a long time. But this is my first experience with
license renewal.
And I had worked at Turkey Point maybe 10
years back as the operating director. So I knew a
little bit more about the plant. But they have a good
staff and that might have helped.
The application contents were not as good
as you would expect. An example, when we first
received the application, and it was assigned to
different staff members, and started talking and had
requests for additional information.
So we received more than 300 REI requests
-- and approximately 325 -- and when we started
reviewing them and found that several of them were
simple, then we had several conference calls, and we
found that the information is already available in the
application elsewhere and in different documents.
And as a result of those few meetings and
telephone interactions, we reduced the number without
any new information from 325 down to 215. So once we
go to the site and we see those additional
documentation, and which verifies the application.
And I am sure the next applicant will look
at Turkey Point's REIs and their process procedures,
and follow it and improve on it.
DR. ROSEN: Would you say that the hundred
or so REIs that were really answered in the document,
but the staff didn't find them, that was the result of
the staff's inexperience, or the documents being so
opaque?
MR. AULUCK: I think it was not the
staff's experience, but it was a navigational problem
within the application. The information was not
readily available in the sections that the staff was
looking at.
And it was rational for the applicant to
include that information elsewhere, and sometimes
there is a time factor and only a short time to review
the whole thing, and come up with requests for
additional REIs.
DR. ROSEN: We are always searching for
more ways to be more efficient.
MR. AULUCK: Exactly. And do we have
lessons learned from the different applications? We
are preparing lessons learned for internal use so that
it gives us more time up front to review the
application, and then we will have fewer REIs, and
will improve the process.
DR. ROSEN: Yes, to improve the process,
and no search for blame.
CHAIRMAN BONACA: Now there is a standard
form that pretty much is being proposed between NEI
and the staff, and so on, and so forth. So that is
why we are asking this question. I think we want to
monitor as a committee how this is taking place, and
in-part I think also that when you do review the
application that you have different reviewers, to
which you assign individual chapters, right?
MR. AULUCK: Right.
CHAIRMAN BONACA: And that's why probably
the issues with various problems. There isn't one
person that reads it all and says this is there or
there.
MR. AULUCK: Well, yes, and that's part of
the process.
DR. FORD: I have another question. These
things that we have been talking about have been
navigational and procedural as technical people. When
you look at the application, there is a whole lot of
technical questions that will come up.
Some of them might be minutia and some of
them will be major impacts. How does your staff go
through deciding what they should be really looking at
technically, as opposed to the minutia? And how do
they evaluate that, and how do they get the
information necessary to have an informed review, a
technical review of the application?
MR. AULUCK: Well, I think as a technical
person, they want to feel fully comfortable with what
they are preparing in the safety evaluation, and
whether it is minor or major, they put it in writing.
And if they don't put it in writing, they
will call the project manager or their immediate
supervisor, and say, hey, you know --
DR. FORD: But that does not answer the
question of how do they prioritize what is important
and what is not. For instance, boric acid wastage may
or may not be of higher importance than, for instance,
baffle board cracking, or the other way around.
How do you decide? Is it based on the
formality of a risk-informed analytical approach or
what?
MR. AULUCK: I think there is no priority
basis. I think it is because the information is not
sufficient in the application, and the application is
not sufficient. There is no priority of REIs that
should go first than the other.
MR. KOENICK: For all structures and
components that are within scope, they have to have
full confidence that they can make the findings. So
they have to address that to their satisfaction, and
that's where you get the capabilities of your
reviewers and their supervisors to ensure that they
have done a thorough review and can make the findings
that they need to for every structure and component
that is within the scope.
DR. FORD: I just keep coming back to this
concern I have. We might find a crack in the pressure
vessel and which was not perceived yesterday, and it
was not predicted yesterday, but that would be a major
event.
In your process of when you are looking
through these applications does it go through your
mind how are they managing the program proactively to
decide whether they are going to have a major event
tomorrow?
MR. AULUCK: That will be under the part
of the current license.
MR. KOENICK: You have to go back to what
the fundamental principle of the Commission when they
developed the rule; that you rely on the regulatory
process, and the regulatory process is continuing.
DR. FORD: I guess I am questioning the
approach. I am questioning the technical completeness
of the regulatory process that was developed years ago
and before we had some experience.
MR. ELLIOT: Barry Elliot, Materials and
Chemical Engineering Branch. He is describing the
regulatory process. The best example is the one that
we just finished talking about, which was the reactor
vessel head penetration cracking.
When we originally did the review it was
fine. It met all the requirements that we had
established at that time. That's why it became an
open issue, because it was a new thing.
So the answer to your question is if we
find a new issue, and it is at the time that we are
reviewing the application, it becomes an open issue.
If we have already finished the review, then it is
handled as part of the regular licensing process.
That is our procedure, and you are seeing
it right here on Turkey Point. We are putting it into
effect.
CHAIRMAN BONACA: For example, you may
question why we did not inspect the heads before
because we didn't see any cracks. That is really a
question regarding the current licensing approach to
it, and not really the elements of license renewal,
which is the assurance that the program that you
believe is correct or adequate will be carried over
the period of the license renewal.
And the basis for which you believe it is
going to be effective from 40 to 60 years. So the --
DR. FORD: I can understand the replies,
but I keep coming back to we approved Oconee, and then
we had the embarrassing situation two months later to
have the vessel head penetration cracking, which to
the technical community was no surprise.
CHAIRMAN BONACA: I don't think there is
any expectation that we would not have new events
taking place that would were never seen before. I
mean, there is no doubt in my mind about that.
DR. FORD: I am just questioning the
process.
MR. ELLIOT: We had a vessel head
penetration program before Oconee, and we could argue
all day long how effective it was. But we had it, and
all we are doing now is trying to figure out do we
have to revise it. How much do we have to revise it.
We've had a program, and the issue now is
what do we need to do to revise it, and whatever
answer we come up with will affect Turkey Point, and
will be part of the resolution of the open issue.
DR. FORD: I guess I am on a crusade.
CHAIRMAN BONACA: But I think it is a
significant question that you are asking, and it is a
legitimate question, because it goes to the heart of
how long are you going to run these plants, and we
don't have an answer to that, except that we feel
comfortable evidently with the current process to go
from 40 to 60 years.
But there is no doubt that for components
that there will be surprises coming through, because
they age, and that's why the focus is on long-lived
passive components.
So I think it is a good question that you
have. Unfortunately, I don't think we will be able to
predict all that is going to happen.
MR. AULUCK: Okay. Our next presentation
will be by Greg Galletti, on the scoping and screening
methodology.
MR. GALLETTI: Good morning. My name is
Greg Galletti, and I am with the Division of
Inspection Performance Management Branch of NRR. I am
responsible for the scoping and screening methodology
Review.
What I would like to do is briefly go over
the scoping and screening method with you that we have
performed, and then discuss the one open item on
seismic two over one that we still have currently.
Initially let me start off by saying that
when we do the scoping and screening methodology
review that we really have three goals in mind.
The first goal is primarily to ensure that
the program that is described by the applicant is
comprehensive and detailed enough to ensure that the
requirements of 55.4 are completely covered.
The second goal that we have is to go and
review design documentation and supporting information
that the licensee has developed to ensure that they
have done a comprehensive review to ensure that the
current licensing basis has been considered for the
purposes of the review.
And the third main goal that we come into
this review with is to go and review the implementing
guidance that is provided by the licensee for their
own personnel to try to get an understanding of how
they have implemented the requirements, ensure that
the implementation is consistent across their
engineering staff, to ensure that they have done a
comprehensive and detailed review of the guidance and
the requirements for the performance of the review.
And in doing this three goal tiered
approach, the staff usually uses a two-tiered
approach. This is the approach that we have taken in
the past.
We initially start off with a desktop
review, which is done in-house, where we review the
application in detail, and we also review some of the
background documentation that is provided, such as the
updated safety FSAR.
We would look at any other design
documentation that we would have on the docket that
may be pertinent. The question that had come up
earlier this morning about looking at the EOPs, while
we don't specifically look at the EOPs, we did in fact
look at the Westinghouse ERG, emergency response
guidelines, the parent documentation for the
development of the procedures.
And just to get a better fundamental
understanding of the design of the plant, the
application of mitigation strategies that the licensee
has used, and just to get a better general
understanding of how the plant was designed and is to
be operated. The second --
DR. ROSEN: With respect to that, with the
EOPs and the ERGs, earlier this morning we heard that
it was not a criterion under the license renewal rule
to review equipment used in EOP for aging management.
MR. GALLETTI: That's correct. If you
look at the guidance in NEI 95-10, for example, source
documentation that could be used to support the
scoping and screening methodology, there is a litany
of information that is available to a licensee to use
for that purpose.
It is really left up to the applicant as
to which of those documents best serves them for that
purpose. They may or may not choose to use the ERGs
or the EOPs because there may be some other design
documentation like the maintenance rule scoping, and
there are equipment lists, and which provides the same
level of information, and gives them a reasonable
source for coming up with the conclusions as to what
should be scoped and screened in accordance with 54.4.
So while it is not a firm requirement that
they look at those documents, for the purpose of the
staff's review and getting a fundamental understanding
of the plant, the staff had that information available
to it, and felt that it was appropriate to use that
information.
DR. ROSEN: Well, let's cut to the chase
on this one. What I am concerned about is did the
staff or does the staff have an adequate basis to
conclude that the equipment that operators would use
throughout the extended period of operation for
responding to not normal events, or accidents, would
in fact function and not be degraded by some aging
effect that we have not identified yet?
MR. GALLETTI: Yes. I think that is clear
that the basis for the entire approach as to how we
perform these reviews, and how the application was put
together in the first place.
It is really fundamentally if you look at
the requirements of 54.4, those criterion in the 54.4
must be addressed by the applicant. They must ensure
that the safety equipment is in scope.
They must ensure that non-safety that
could affect the function of that safety is in scope.
By doing so, we ensure that all that equipment that is
necessary for vent mitigation is in fact covered, and
perhaps subject to an aging management review.
And the second tier of the approach that
the staff has used is to actually do an on-site audit
of the documentation and the process implemented by
the applicant.
The on-site audit is typically about a
week long, and generally we have 3 to 5 people on the
staff on the team for the audit. We go through a
detailed review of the design basis documentation that
the applicants have used for the purposes of their
review, and to ensure that the current licensing basis
has been captured.
We go through in very strong detail the
implementing guidance that they have provided to the
staff, and we go through and we use certain samples.
We will sample a couple of systems in detail to ensure
that the implementing guidance as written was actually
performed, and those systems were scrutinized
consistent with that guidance.
And based on the two-tiered approach, the
desktop, as well as the on-site audit, the staff, for
the purposes of the Turkey Point review have concluded
that in general the approach that was taken by the
applicant was consistent with the scoping and
screening methodology that they have described.
It is consistent with the requirements of
54.4, and we believe it is robust and comprehensive
that we had a positive safety finding.
We did have one issue that was brought up that I would
like to discuss in a little bit more detail on the
seismic two over one.
DR. ROSEN: Let me interrupt you again.
Pardon me for making one point, and ask the question
that you said that in your on-site audit that you
looked at the instructions and guidance with the
staff, and found them to be reasonable and
appropriate.
MR. GALLETTI: Right.
DR. ROSEN: But the other piece of getting
a process done correctly is the qualifications of the
people using that guidance, and the training of the
people using that guidance. Did you look at either of
those things?
MR. GALLETTI: The way we captured the
training of the people that were involved in the
review was generally on the on-site inspection, we
will go through as I said certain systems, and we will
go through those systems with the cognizant staff that
was responsible for the review.
So in doing so, we will question them to
understand how they applied the implementing guidance
to ensure that it was consistently applied. We
discussed specifically the training aspects, and how
did you train your people on these implementing
guides.
And in fact the responses have been
generally that the guidance is a quality document. It
is reviewed by each of the staff. There were certain
internal meetings if you will during the development
of this implementing guidance to ensure that the
guidelines were specific and did in fact reflect the
approach that the applicant wanted to take.
So basically through a dialogue with the
staff, the applicant's staff that is, we had a
reasonable assurance that they were well trained.
DR. ROSEN: Did you look into whether this
guidance was included in the engineering support
personnel training programs?
MR. GALLETTI: Not as such, no.
CHAIRMAN BONACA: I think that this is a
good question and it also goes to the NRC stuff. I
mean, how do you -- are the same individuals assigned
to the same areas of different license renewal
applications so that there is experience being built
there, and the learning curve is high?
MR. THOMAS: Maybe I should answer that.
My name is Brian Thomas, and I am in the Division of
Systems Safety Analysis, Plant Systems Branch. And
that division is responsible for the scoping and the
screening of the SSEs that are within the scope of
license renewal.
To the extent that we can, we are forming
a license renewal review team if you will. To the
extent that they are within the resource limitations
and so forth, people are pretty much are assigned to
the same areas.
So we have folks that have expertise in
structures, structural engineering, for example, that
would review the scoping of the SSEs that pertain,
let's say, to the structures, the yard structures, the
containment structures. And similarly we take a
similar approach with the systems.
CHAIRMAN BONACA: Okay. Thank you.
MS. THOMPSON: To address the FTL Turkey
Point specific training, the engineers that
participated in generating the actual license renewal
documents that yielded the application, all received
specific training on the procedures -- they were
called quality instructions as what we refer to them
as -- as part of their job orientation.
And there was a specific group of people
that developed those documents, and then more of an
overview and understanding of the concepts and bases,
and how those would be applied in a long term basis
from a commitment management perspective, as well as
a configuration control perspective, the engineering
technical personnel training program also included
sections that were specifically dealing with license
renewal.
And we have done that a couple of times
already, and plan to continue to do that, particularly
upon issuance of a renewed license favorable decision
there.
DR. ROSEN: Well, thank you. That's
helpful. Now, I understand what you said is that you
have included the license renewal process, as well as
those things that come out of the process that will
have to be carried forward for the life of the -- for
the extended life of the plant in the engineering
support training program, so that it gets built into
the infrastructure of the engineering organization as
an ongoing matter.
MR. GALLETTI: Absolutely. That's
correct.
MR. GALLETTI: If there is no other
questions on the scope and screening review itself, I
did want to discuss specifically the seismic two over
one issue.
CHAIRMAN BONACA: And then after that I
have questions regarding 2 or 3 systems, and why they
were not included, and I will ask those questions
after you.
MR. GALLETTI: Sure. I think that Brian
will cover that as part of the scoping results
section. As was brought up earlier today, the one
open issue that we do currently have is characterized
as seismic two over one.
And really for the purposes of the review
the staff is looking at this in terms of a little bit
broader. It is really the application of the 54.482
requirement for inclusion of non-safety related SSCs
whose failure could in fact impact a safety related
SSC from performing its function.
As you know the genesis of this issue
really came out of the Hatch review, where some
questions were asked on some auxiliary systems, and
whether or not certain segments of piping were in
scope or not scoped.
As a result of that staff review and
working with the licensee, several key issues came
out. Generally for the application of 54.482, the
staff would consider any non-safety SSC whose failure
could impact a safety SSC as potentially within the
scope.
What a licensee or applicant would have to
do is really first of all identify what are their
safety related SSCs, and then take in essence a
spacious approach to determine what other components
and systems structures within that vicinity could in
fact impact those SSCs.
Once that is determined, then they would
have to do a credible job of reviewing what sorts of
failures could these non-safety related SSCs have that
could potentially impact those safety related SSCs.
With that fundamentally laid out the staff
really came up with two options for applicants. In
doing this review, they have the ability to either
take credit for certain mitigative features if they
could show through analysis that those features in
fact would mitigate the effects of the failures of the
non-safety SSEs that they are trying to credit.
A good example would be if a non-safety
related pipe were to break and leak, or spill fluid on
a safety related component, if there was some sort of
shielding or mitigative feature that they could show
could in fact ensure the safe function of that
component, then we would consider that mitigative
feature could be brought into scope.
And not necessarily requiring inclusion of
the piping segment. The other alternative if they
cannot show that that mitigative feature is sufficient
to protect that safety related function, the actual
segment itself would be brought into scope.
I think that is consistent with the staff
policy as we have developed it, and now it is a matter
of going to each of the applicants and making sure
they understand that general approach is the approach
that the staff is trying to provide people.
CHAIRMAN BONACA: But this is an approach
as you said has been standing for a while.
MR. GALLETTI: Yes, certainly since the
Hatch review.
CHAIRMAN BONACA: And you have in some
specific cases where you have in fact mitigated
protection of the component that you are concerned
about.
DR. SHACK: This didn't seem to arise in
three of the applications that you have approved
already. Is that because of differences in their
licensing basis or just the way that they have
interpreted it? Have they interpreted it closer to
what you have interpreted it?
MR. GALLETTI: I think it is probably a
combination of those two things really. It's how
certain systems in the plant are credited in their
design basis as to whether or not they are performing
a safety related function or not.
But then once that is actually determined,
reviewing the non-safety equipment that could impact
that needs to be done by those applicants as well.
Now, in the past, I think what we found is
that in certain cases it was clear that this was a
question raised by the staff and then in response
those applicants did something.
In other cases, they were more proactive,
and as part of the application that level of detail
was provided. But it is something as a result of the
Hatch review that we are actually going back and
revisiting some dialogue with those previous
applicants to understand and clarify that.
CHAIRMAN BONACA: Now, for Hatch, the
supports were seismic highly qualified are?
MR. GALLETTI: Yes, sir.
CHAIRMAN BONACA: And for Turkey Point,
are they seismic highly qualified?
MR. GALLETTI: I don't think so, but could
you answer that.
MR. HALE: They are non-safety related,
but we are a fairly low seismic area, and we have
demonstrated that the supports can hold up the
structural components under seismic loading.
MR. GALLETTI: I think the key issue here
is for the supports themselves. The applicant may be
able to credit those supports for mitigating a seismic
event. But there are other mechanisms in play here
that may render that non-safety related piping to
fail.
And that seismic support may not provide
the mitigative feature that is necessary to handle
that particular failure. So other mitigative features
may have to come into play, such as shielding, splash
guards, pipe restraints, and other mitigative features
would have to also be considered.
And in addition the mitigative features
that are already in the plant may in fact not be
sufficient to ensure that failure of these non-safety
related components would not render a safety system
inoperable.
Therefore, regardless of what mitigative
feature you do have, you may in fact still need to
include that segment of piping.
CHAIRMAN BONACA: Is this issue a generic
issue just because of two different plants with really
different kinds of issues still to do with two over
one, and is NEI involved as a part of this resolution
representing the industry?
I mean, is it an open issue for the
industry, or is it just specific to the application
itself?
MR. GALLETTI: I wish Kris was here. I
don't get involved with the NEI discussions.
CHAIRMAN BONACA: This is a plant specific
as of now?
MS. THOMPSON: Well, it is on the list of
remaining open items with respect to the GALL being
issued for the industry, and I believe there was a
steering committee meeting last week, and a
demonstration meeting a week or two before that when
it was raised as one of the items on the list.
MR. GALLETTI: I think it is fair to say
that there is certainly generic interest in the
industry as to how this issue is going to be handled
and resolved, and how it has been handled and
resolved.
MR. HALE: There is a list of what we call
issues for ongoing dialogue between NEI and the staff,
both associated with the SER. Well, not the SER, but
the standard review plan, and the GALL, and two over
one is one of those.
And to get a better handle on guidance and
the approach, and trying to get a little more
consistent approach, especially with the older plants.
DR. ROSEN: What is the Turkey Point
design basis earthquake? You said it was low seismic?
MR. HALE: Yes.
DR. ROSEN: And what is it?
MS. THOMPSON: It's about .15G if I
recall. It is very low.
MR. HALE: Yes, .15 horizonal, and .1
vertical.
MS. THOMPSON: We are the lowest in the
country.
DR. ROSEN: I don't think so.
MS. THOMPSON: Well, I thought we were.
Perhaps not.
MR. GALLETTI: So again as you have heard,
we are going to have some additional dialogue with the
applicant next week to try to better understand their
resolution or proposed resolution to that issue.
MR. THOMAS: As I mentioned before, DSSA
is responsible for the review of the scoping and
screening, and the results of that review in
accordance with the applicable regulations.
Basically, what I have before you is just
a slide that captures the scope of our review. Our
review -- let me say that the review team that I spoke
of consists of about 11 individuals, each with their
specific areas of specialty.
Now, I spoke before of the team if you
will, and let me add that that review process could
get complicated because of the addition of new team
members, and utilization of staff for various reviews
outside of the license renewal review.
But to the extent that we can, we try to
keep some consistency across our applications so that
there is consistency in the focus on the issues that
are addressed.
For example, the fire protection, or the
seismic two over one issue. In this review of the
Turkey Point application, certainly it was much less
of a navigational challenge than the Hatch. And when
I heard Raj say that the review resulted in a number
of REIs following some interaction with -- several
interactions with the licensee.
And it turned out that a lot of the REIs
were just a matter of providing clarification. But
basically the licensee took the approach of -- took a
system approach and a structural approach if you will
also, where systems, and compliments, and the related
structures were decompartmentalized if you will.
So it was not a very complicated
application to follow. It was a matter of looking at
a particular system, and getting a complete listing of
all the SSEs within that system, including the
commodities.
Now, there are some areas -- and a lot of
our REIs have to do with clarification or with regard
to some other commodity groups. For example, the
review of the office building, for example, and the
containment building, there were REIs that had to do
with fire retardant components, fire doors, et cetera,
et cetera, and fire barriers.
Those types of complimentaries resided
under another section, titled, "Fire Rated
Assemblies." So in terms of the navigation of a few,
it wasn't very involved after we got some
clarification from the licensee.
But basically we used the FSAR, the tech
specs, and any licensing correspondence as stated
earlier by the licensee, and specifically there were
design drawings that accompanied the application.
And the design drawings highlighted and
the -- well, let me back up a second. The FSAR and
the application, there were high points between those,
and so it was not from that standpoint. It was a
fairly simple review.
But the design drawings highlighted the
extent of the systems to the system boundaries, and
they were easily read. We really had no major
problems in the review process.
As you can see, we basically reviewed --
well, these just highlighted the major systems that
were reviewed by the DSSA, and reviewed the reactor
coolant systems, and the engineering safety feature
systems, and what is presented here is just some
examples of the systems.
But what I have given you is a count of
the number of systems involved in the review, and all
together there was 43 systems, and I want to say --
no, I'm sorry, 37 systems and 16 structures, separate
structural facilities, that was reviewed.
Raj mentioned that we had something on the
order of 300 REIs, and then that is whittled down to
like 200, and I think we ended up with maybe about 30
of those REIs.
So as you can see altogether, initially I
think we had something on the order of 60 REIs. So
half of our REIs were more of the clarification
concern than anything else.
And in the end we really had no major open
items. Still to come though is how the seismic total
one item is resolved, and I heard a question before
about what sort of additional burden that will impose
on the staff.
As was mentioned before, because they took
a spacial approach if you will, and because they took
a functional approach, which is as we have seen in
previous reviews, like with the Oconee and Talbot
plants, if the approaches to identify an area, and
identify the safety related systems in that area, and
identify the non-safety related systems that are in
that area that are believed to be within the
proximity, that if there is a failure, will infringe
upon the functional capability of the safety related
system, then that I think would not be much of a
burden.
But the burden of a follow-on review then
would be much reduced, and that is all that I have.
MR. AULUCK: Any questions?
CHAIRMAN BONACA: Thank you. If we have
any questions, we will raise them as we move through
the systems.
MR. AULUCK: Next is Meena Khanna.
MS. KHANNA: Good morning. My name is
Meena Khanna, and I work in the Division of
Engineering, Materials and Chemical Engineering
Branch. Basically I will be presenting the first
three sections of the Turkey Point license renewal
application.
I would like to start by just telling you
basically the staff and GE that we have got two
reviews that we conduct; one is on the systems, and
with the system review, what we do is we just try to
verify that the applicant has adequately identified
all the aging effects, and has adequately identified
the aging management programs to manage these aging
effects.
The second review is of the aging
management programs, and Ms. Keim will discuss that
later in Section 3.8. She will discuss the process
that we actually go through in reviewing the aging
management programs.
And I will go ahead and start with the
common aging management programs. Section 3.1 of the
application included a description of the common aging
management programs.
Again, Ms. Keim will also address the
common aging management programs in Section 3.8.
However, the three that we reviewed under common aging
management programs include the chemistry control
program, and the FPL quality assurance program, and
the systems and structures monitoring program. We
will go into details again in Section 3.8.
CHAIRMAN BONACA: Let me try to understand
this. This is part of what they missed in the
application as existing aging management programs.
MS. KHANNA: Exactly.
CHAIRMAN BONACA: And you are pulling out
these three right now in this presentation.
MS. KHANNA: Right. Let me just say that
when we call them a common aging management program,
that is basically an aging management program that is
going to apply to two or more systems or components.
CHAIRMAN BONACA: I see.
MS. KHANNA: So these three have actually
been identified as those aging management programs
that will apply --
CHAIRMAN BONACA: I understand.
MS. KHANNA: And there were no open items
that were found with either one of these three common
aging management programs. However, there is one
confirmatory action item, and that is in regards to
the quality assurance program, and that is just a
minor SER supplement that is needed and Andrea will
discuss that later.
Now, let's go to Section 3.2, the reactor
coolant system. I would like to acknowledge Alan
Hiser. He was actually the lead for the reactor
coolant system. I am going to go ahead and present it
for him.
The components of the reactor coolant
systems include the reactor coolant piping, Class 1
and non-Class 1 components; the regenerative and
excess letdown heat exchangers, pressurizers, reactor
vessels, reactor vessel internals, reactor coolant
pumps, and steam generators.
CHAIRMAN BONACA: Now, are these all
existing programs? I don't think so. There are some
reactor vessel internal inspections which are new
problems, right?
MS. KHANNA: These are actually the
systems. The aging management programs, they are
handled in Section 3.8, and there is a reactor vessel
internals inspection there, and that will be covered
later.
Notes of interest include Florida Power
and Lights AMR results were compared to the following
topical reports. The first one was WCAP-14574 on
pressurizers; and WCAP-14575 on piping; WCAP-14577 on
reactor vessel internals.
However, the staff noted that the FPL did
not incorporate the topical report results by
reference. And I would note that I believe there was
a question that I believe, Mr. Bonaca, you had asked
earlier about the reactor vessel internals WCAP.
CHAIRMAN BONACA: Yes.
MS. KHANNA: And jus to clear it up, we
did have REIs that went out on the reactor vessel
internals action items, and the applicant adequately
identified them. We are satisfied with all their
responses and that was -- and they were noted, all the
findings were noted in our response, or in their
response.
CHAIRMAN BONACA: Well, my question was
regarding the pressurizer.
MS. KHANNA: Okay. Right.
CHAIRMAN BONACA: And there the SER finds
at least four of the applicant action items -- well,
I mean, the pressurizer, while topical, has maybe 10
applicant action items.
MS. KHANNA: Right.
CHAIRMAN BONACA: And the SER identifies
four as being applicable to Florida.
MS. KHANNA: Right, to Turkey Point.
CHAIRMAN BONACA: To Turkey Point, and I
was left searching around for where the others are
being discussed in the application. Well, not in the
application, but in the SER.
MS. KHANNA: In the SER, right.
CHAIRMAN BONACA: And where they are
discussed is in the REI response on the reactor
cooling system.
CHAIRMAN BONACA: Well, some of them are
considered non-applicable, and I don't understand why
they were not applicable in all cases.
MS. KHANNA: Well, we have got Alan Hiser
here. Alan, would you like to talk on that? We are
talking about the pressurizers, the topical report on
the pressurizers. There were four action items that
were not addressed.
MR. AULUCK: There were four addressed and
six were not addressed and the question is whether
they were applicable at Turkey Point.
CHAIRMAN BONACA: Well, I was left with
searching around for those that were not addressed,
and having to trust the judgment that says these are
not applicable.
DR. FORD: And with the exact equivalent
question for the internals, too. There are 11 action
items in the internals program, and that is exactly
the same question.
CHAIRMAN BONACA: That's right. And some
of those in the report for the pressurizer were
convincing. Now suddenly they disappear for Turkey
Point, and the statement says these are not
applicable. So I just don't understand. I couldn't
find --
MR. HISER: I will have to get you an
answer on this. The lead reviewer on that is not here
right now.
MR. HALE: If I could offer at least from
our perspective that it's not that the applicant
action items were not applicable. The applicant
action items were already addressed in the
application, and the reviewer who did the pressurizer
review recognized, and only asked us those that
apparently weren't covered in the application.
But we have addressed all of the applicant
action items either in the LRA -- I mean, it wasn't
because we had the list. It's just that we had
already covered the applicant action item in the aging
management review that we had performed.
I can give you an example of one. It is
Applicant Action Item 3.2.2.1-2, which was covering
commitments regarding the boric acid waste
surveillance program.
Well, we had already covered that in our
table, and we had already covered that in Appendix B
with the boric acid waste surveillance program. So,
in the case of the pressurizer, at least in the
interface that we had with the staff reviewer, he
recognizes that some of that stuff was already picked
up in the application.
So he only asked us those REIs, those
applicant action items that weren't covered or weren't
readily identifiable. Now, in the case of the
internals, we got a letter with all of the applicant
action items listed, and requested a response from us.
CHAIRMAN BONACA: Okay. That is probably
the explanation for that. The text was not clear.
The text says that during the staff review of the
pressurizers, the staff determined that four of the
applicant action items summarized in the staff SER and
WCAP were applicable to the AMR for Turkey Point, and
the staff requested an explanation on this. And
that's why the others are not so.
MR. HALE: Right. They may have concluded
that because it was already in the application.
CHAIRMAN BONACA: It is just simply left
me with no answers to the others, and the answer may
be right in the application. I agree with that, but
it wasn't clear.
MR. HISER: I believe in the internals
topical report that we did list the 11 action items
and the specific responses.
DR. FORD: Okay. And were the responses
to those quantitative, because in that WCAP-14574, the
reactor vessel internal one, it is continually
referenced to the ASME 11 code as to what the
frequency of the inspections would be.
It is a beautiful criteria on what an
aging management program should specify with data, but
in the response to the REIs on Turkey Point were the
response quantitative? Do you understand my question?
MR. HISER: Yes. I believe in some cases
they were, in terms of the inspection program
activities. In some areas the details on the programs
are still being developed through industry, and MRP
programs, and those kinds of activities.
So the quanitativeness isn't really there
at this point.
DR. FORD: Now, are we fairly sure as an
industry that we are collecting the relevant data?
MR. HISER: We are monitoring everything
that is going on with the industry. We have periodic
public meetings with the MRP to discuss the status of
their program, and what their plans are.
At this point the programs are proceeding
--
DR. FORD: In a timely manner?
MR. HISER: Yes, in a timely manner.
DR. FORD: Well, it wasn't a statement.
It was a question.
MR. HISER: Yes. At this point, yes. We
are satisfied with the scope, and status, and plans in
the program.
DR. FORD: And do we know how to define
timely in relation to the effect on some risk informed
basis, like a delta-LOCA? If we have a failure event
occurring, which of the ones out of that list of
components are going to give you a real heartache?
And are we in the expected time period
going to get the data to come up with what renewed
frequency should be for inspection?
MR. HISER: Well, I think that of the
items that are listed there that the main activity is
in the reactor vessel internals area, and the industry
program timeliness is tied to plants entering the
license renewal period. And the plants having
programs in place as they enter into that period.
MR. ELLIOT: This is Barry Elliot. The
reactor vessel's internal program, there are two parts
to the program. There is the research part of the
program, and then there is the inspection part of the
program.
The inspection part of the program is a
commitment by them to do inspections of limiting
locations in the reactor vessel internals, once during
the first 10 year interval, and the other unit during
the second 10 years of the extra period.
So they have to have their research
results to meet that schedule, and they will have it
to meet that schedule. That is the plan and that is
how we have written up the program.
DR. FORD: But these in your intervals,
Barry, are based on --
MR. ELLIOT: Well, you asked whether or
not it will be in time. The time needed for the data
is in year 41 of the operating cycle of the plant
operation. That is the program.
They will inspect the first unit in year
41 according to whatever the research results are from
the research program. The second unit will get
inspected in the next 10 years of the operating
period.
It will use the results of the research
program, plus whatever the results are from the first
10 year first unit. Now, that is the plan today.
When we get research results, and if it
shows that there is an immediate problem, then we
won't do it in year 41. We might have to do it in
2002 or 2003. But that is the current plan.
DR. FORD: I can understand the reason,
that you have to have a date to go into this.
MR. ELLIOT: Right.
DR. FORD: You can't just say we will
wait.
MR. ELLIOT: Right.
DR. FORD: You have to draw a line in the
stand if you like.
MR. ELLIOT: Right.
DR. FORD: But what concerns me is that
there is surely enough data in the technical community
right now to say -- and especially for the older
plants with the higher fluence level, that a 10 year
period is nowhere adequate enough.
MR. ELLIOT: Well, that is going to be the
results of the research programs, and to look at all
the data, and to come up with an answer for that
question. You have to look at everything, and that is
one of the issues that I am sure the program will look
at.
DR. FORD: Obviously we are getting into
a great big technical argument of, yes, you do; and,
no, you don't, but in terms of delta-LOCA as a
parameter to prioritize where you should be putting
your money to come up with this data in a timely
fashion, have they gone through that sort of analysis?
MR. HISER: I don't think it has been
looked at in a risk-informed sort of mode. It has
been more of a deterministic mode, where aging
mechanisms, and combinations of materials and
environments have been identified as potentially
requiring additional attention.
And the industry programs are looking at
the parameters that would be involved and determining
when and under what conditions the mechanisms could
become important. And then developing inspection
tools that would be effective in managing those
mechanisms for those materials for these components.
DR. FORD: I guess that this goes way
beyond Turkey Point, Mario, and specifically it does
relate to Lochbaum's assertion that relicensing
programs and the data from which they are based are
not adequate.
CHAIRMAN BONACA: Well, I believe that the
examples that Lochbaum made, 8 or 10 were related to
active components that wouldn't really even fall in
the scope of relicensing if I understand, if I
remember that.
And again, however, I don't think that
license renewal insofar as the process we are
implementing there is to review the life cycle
management, and the procedures is going to have all
the details of what needs to be done in the program
right now.
What we need to have is a commitment by
the licensee that he recognizes the issue, and he has
prepared himself to deal with the issue, and that
through the corrective action program he has, he has
performed those actions that are considered by the
requirements to be appropriate.
And that will be different when we get
there than they are today most likely. I mean, just
because we will know about it. Now, I think the only
place where we can have some discomfort is where some
issues that may not ever be experienced, and then make
them up.
But again that will have to be dealt with
at that time, and will be part of the core licensing
interaction within the staff and the NRC, and not
necessarily of the license renewal, because that would
become part of the license renewal.
MR. HISER: And we have tried in
particular in the reactor vessel internals area to try
to crystal ball some of the issues that may come up,
and that we don't think are an issue for 40 years, but
could with fluences increasing, and exposure times
increasing, they may become important.
And right now the data for relevant
conditions isn't sufficient to tell us that we
definitely would have a problem, or we definitely do
not have a problem. So the industry is trying to
collect the data that would help them to determine the
potential problem, and then propose appropriate
management schemes.
DR. FORD: I have another question, and I
don't know who to ask, but on steam generators, we
have been talking about future events. But there have
been problems, and I think it was in one of the WCAP
documents that was saying that we were safe from many
of the cracking problems because we monitor the oxygen
and the chloride contents, et cetera.
Well, it is not really oxygen that you are
interested in. It is corrosion potential, and you can
high corrosion potential from copper from condensers
on the secondary side, and at Indian Point we did have
cracking of the vessel because of copper coming from
the condensers.
Now, does that come into these programs
and into these GE management programs?
MS. KHANNA: There is a steam generator
integrity program that adequately addresses that.
DR. FORD: Then it is just the steam
generators that are on this slide then?
MR. HISER: Right. Steam generators is
one of the components of the RCS. However, there is
an aging management program that specifically is
called a steam generator integrity program, and that
adequately identifies that.
DR. FORD: That specific item is watched
for copper tube flux within the --
MS. KHANNA: Could you guys answer that?
MR. HISER: Well, for one thing, when we
replaced the steam generators, we replaced all the
condenser tubing with titanium. All of our feed water
heaters are stainless tube now. So we minimize copper
as an additional preventive action.
And we do sludge lancing and all that
stuff related to ensuring tube integrity is
incorporated into the steam generator integrity
programming, as well as our current testing of the
tubes.
And you see that both in your chemistry
control program and in the steam generator integrity
program.
MS. KHANNA: Okay. Great. I will go back
to the review. The second note of interest that we
noted for the reactor coolant system is that the
reactor vessel had penetration nozzle cracking was
managed by the reactor vessel had the 600 penetration
inspection program.
There will be a presentation made on the
Ally 600 penetration inspection program. There was an
open issue also identified on CRDMs, and that will
picked up in a later discussion in Section 3.8.
So basically there were no open items in
regards to the reactor core systems. We will go to
Section 3.3, engineering safety features. The ESF
systems include emergency containment cooling systems,
the containment spray, the containment isolation, the
safety injection, residual heat removal, emergency
containment filtration, and containment post-accident
monitoring and control.
The staff found that the applicant
adequately addressed all the aging effects for each of
the components and the systems of the ESF, and also we
also found that the aging management programs to be
appropriately addressed for each of those aging
effects as well.
So we also found no aging -- I'm sorry, no
open items with the ESF.
CHAIRMAN BONACA: The containment
monitoring and radiation protection system, that does
not have an aging management program for it?
MS. KHANNA: Right. There were no aging
effects found to require an aging management program.
CHAIRMAN BONACA: And could you explain
more on that? So there were no aging effects found
for that?
MS. KHANNA: Right. The applicant didn't
identify any aging effects, and we found -- well, what
we do is we use the GALL report and we compare the
results. And if we found that they had adequately
identified the aging effects --
CHAIRMAN BONACA: Well, this was a
question from John Barton. What you are saying is
that it was in scope, but you found no aging effects
that would justify a management program?
MS. KHANNA: Right, that's correct.
CHAIRMAN BONACA: John thought that they
were not in scope, and they are in scope. All right.
MS. KHANNA: But they were identified as
being in scope, and so we went ahead and reviewed it,
and it is in scope.
CHAIRMAN BONACA: And there was another
question here from Mr. Barton regarding the MSIV.
There are two different designs for the reserve tanks
that are used to operate the MSIVs, and on Unit 4
there are reserve tanks that are used or they are
simply accumulated that are used.
And those are in the scope of license
renewal. For Unit 3, there are bottles. I mean,
bottles that are used for the safety function.
MR. HALE: That's right.
CHAIRMAN BONACA: So if I understand it,
you do have reserve tanks that are used for normal
operation?
MR. HALE: The MSIV normal operation is
just basically instrument error. What these are, the
air accumulators on Unit 4 and the nitrogen bottles on
Unit 3, are under certain accident scenarios, if you
assume leakage of the actuator, and you have an equal
DP, or a no DP across the MSIVs, it could come back
open again.
So we provided a back up source to
instrument error for the MSIVs. Now, with regards to
--
CHAIRMAN BONACA: Okay. For Unit 4, they
are treated different?
MR. HALE: They are different. It was
kind of a decision that was made for Unit 4 to go with
something that didn't need to be replaced
periodically. The bottles are monitored for pressure
and they are replaced periodically.
Whereas, the air accumulators on Unit 4
are just an in-line tank. So what was the question?
CHAIRMAN BONACA: The question is that you
do have the instrument accumulative tanks for Unit 4
are in fact subject to an AMR.
MR. HALE: Right.
CHAIRMAN BONACA: While for Unit 3, you
took the position that the bottles are not long term,
and they are replaced.
MR. HALE: Right. They are replaced on a
-- the pressure is monitored, and they are replaced
periodically.
CHAIRMAN BONACA: And how is it monitored?
MR. HALE: Actually, there is tech spec
requirements that they be maintained at a certain
pressure level, and if it drops below that for
whatever reasons -- you know, testing, leakage,
whatever it might be -- they are monitored and
replaced.
So we considered those replaced
periodically and as such didn't require an aging
management review.
CHAIRMAN BONACA: And the monitoring is a
periodic monitoring with tech specs?
MR. HALE: Yes. We are required to
maintain a certain pressure.
CHAIRMAN BONACA: Okay. All right.
DR. ROSEN: When you say periodic
monitoring, what do you mean?
MR. HALE: Whatever the requirement is,
but they are stipulated that we have to maintain a
certain amount.
DR. ROSEN: Well, does somebody go out and
look at these bottles every four hours or something
like that?
MR. HALE: There is pressure indication.
DR. ROSEN: In the control room?
CHAIRMAN BONACA: In the control room, no.
MS. THOMPSON: I don't know if it is in
the control room.
MR. HALE: I would have to look at the
drawings.
MS. THOMPSON: They are monitored
relatively frequently, and we are not talking about
once every 18 months or something. They are on
regular operator rounds.
CHAIRMAN BONACA: All right.
MR. HALE: The same question was raised in
our REIs and we got a response to that as well, which
summarizes I think some of the specifics that you are
asking for.
CHAIRMAN BONACA: All right.
MR. AULUCK: Next we will go to the
auxiliary systems, and James Davis will cover that.
MR. DAVIS: There are 15 systems on the
auxiliary systems that we looked at. We thought that
the application was very good this time. The best one
that I have seen so far.
We had a number of REIs, and they were
fairly simple. They basically were that the words
didn't match the tables, and things like that, and we
just cleared those up very quickly. There were no
real surprises. So we ended up with no open items.
Are there any questions on these systems?
If not, on steam and power conversion systems, these
included the main steam and turbine generators, and
feedwater and blowdown, and the auxiliary feedwater
and condensate storage.
And there were no show stoppers here.
They were just conditional REIs, but they basically
were to just clarify the text and the tables again.
And there are no open items here.
CHAIRMAN BONACA: I would like to go back
just a second. I had a question about that there is
a discussion in the SER regarding inaccessible
locations, the pressurizer, the pressure vessel, and
steam generators, and vessel internals.
And I would like to have a better
understanding of how that is being dealt with in
inaccessible locations in the pressurizer, the
pressure vessel internals, and steam generators.
MR. AULUCK: In the inaccessible areas,
they go look at the accessible areas for possible
clues, and then follow it up in the inaccessible
areas.
CHAIRMAN BONACA: Well, assume that you
have a clue and it may be something that is in an
inaccessible area.
MR. HALE: Well, I think we saw quite
disparity in how previous applicants have addressed
this. We have had some applicants say that there are
no inaccessible areas in the power plant, and with the
right amount of money or whatever, you can always make
something accessible.
We took the perspective that with
inaccessible areas, if something is not readily
visible, and something where you would have to take
extraordinary measures in order to see things.
Certainly there are observation techniques
that you can utilize, such as t.v. cameras on -- you
now, remote, very tiny t.v. cameras. In fact, we are
going to utilize some of that in our head penetration
visual inspection.
So I think that the aging management
review pretty much stands on its own. The programs
that we credit, if we see something, then we would be
obligated to go look at these other areas if it was
applicable. But in terms of how we define
inaccessible --
CHAIRMAN BONACA: I wasn't in effect
asking about your obligation. Of course, you do have
to fill a commitment. I would reach the same judgment
that any inaccessible area can be made accessible if
you have to, and if you have indications.
MR. HALE: Right.
CHAIRMAN BONACA: One thing that comes
through the application and the SER are some questions
regarding looking at operator experience. And there
are issues that may prompt you to say that I don't
have any problem, but there may be something.
You have been looking also at other power
plants in the Westinghouse Owners Group, right?
MR. HALE: Right. Yes. As part of each
one of those GTRs that were mentioned, and not just
the ones were submitted, but also the other ones that
we used as source information, it was basically an
integrated look at all the experience for those
particular components on the Westinghouse plants.
So we did that, and we also have our
sister plants, or our other plants up at St. Lucie.
So we have got a broad database to draw on, and we did
an extensive review of our operating experience as
well.
As you have seen, we actually used
experience which may have happened at St. Lucie and
Turkey Point.
CHAIRMAN BONACA: Okay. Thank you.
That's all I needed.
MR. MUNSON: I am Cliff Munson and I am in
the civil engineering group. We reviewed the
structures and structural component section. The
applicant divided it into two groups. The first group
was containment, and then the second group was other
structures.
And they further divided these two groups
into commodities and environments. So they have steel
in air, and steel in fluid, concrete, and we looked at
the aging effects that were identified by the
applicant to make sure that they included all the
applicable aging effects.
The three aging effects that they
identified for the steel and concrete groups were loss
of material, cracking, and change of material
properties.
And for the containment structure, post-
tensioning, they also identified loss of pre-stress.
For the miscellaneous structure component, they
identified loss of seal, as well as loss of material.
We didn't have any open items. I have
reviewed all of the applications up to date, and this
was very easy to follow. We were able to find pretty
much everything we looked for, and they had
-- I think they thoroughly covered the aging
mechanisms that would lead to these aging effects.
And I thought it was an excellent job that
they did.
CHAIRMAN BONACA: I have a question
regarding the in-take structure. There is no
management, aging management of this structure, and
there are a lot of systems or components attached to
the structure that in fact do have an aging management
program.
And I really wondered why -- and also John
Barton faxed me a comment about that, that there is no
aging management program of the in-take structure.
MR. MUNSON: Okay. Is Arnold Lee here?
MR. LEE: Yes.
MR. MUNSON: Can you address his question?
MR. LEE: What was your question again?
DR. DUDLEY: Come to the mike, please.
MR. LEE: I am Arnold Lee.
CHAIRMAN BONACA: In reading the
application and the SER, clearly there are a number of
systems or components which are attached to this
structure which are important to safety which are part
of the aging management program, but there is no aging
management program for the structure itself.
MR. LEE: There is no aging management
program for the structure. It is for the steel.
MR. MUNSON: For the in-take structure.
CHAIRMAN BONACA: For the in-take
structure. Could you explain a little bit why that
is?
MR. LEE: Maybe I didn't understand the
question. Could you repeat it again?
CHAIRMAN BONACA: Yes. Let me just go
through some notes here.
MR. LEE: There are a number of aging
management programs to cover the aging effect, and
there is a structural monitoring program, a systems
structural monitoring program.
CHAIRMAN BONACA: And that covers also the
in-take structure?
MR. LEE: I have to look into that. I
have to check whether that indeed would manage the
aging effect for the in-take structure.
CHAIRMAN BONACA: I would like to have you
find that out.
MR. LEE: Yes, I can find out.
MR. HALE: If you look at the application,
Table 3.6-13, I am not sure the question that he is
raising, but we highlight the systems and structures
monitoring program for structural steel, anchorages,
and embedments.
CHAIRMAN BONACA: And again the table is
what?
MR. HALE: It is 3.6-13, which is the in-
take structure, and it lists all the component
commodity groups which require an aging management
review on page 3.6-85. So I am not sure what the --
CHAIRMAN BONACA: So, okay. You do have
it. I believe the question was -- or the one from Joe
Barton -- related to the structure itself that
supports so many of these components here. For
example, the instrument rack and frames.
MR. HALE: Right.
CHAIRMAN BONACA: And the question he had
was regarding the actual grid structure.
MR. HALE: Well, reinforced concrete,
foundation, beams, columns, walls, floor slabs,
systems and structure of monitoring program.
CHAIRMAN BONACA: Okay. So it is under
that, and you have a visual inspection program to look
at spaulding and things of that kind.
MR. HALE: Yes.
CHAIRMAN BONACA: All right. So you do
have it then.
MR. AULUCK: Okay. Next we will cover the
electrical portion of the review.
MR. SHEMANSKI: My name is Paul Shemanski,
and I am with the Division of Engineering, Electrical
Branch, and basically for the electrical and
instrumentation, and control section, Section 3.7,
there were three groups of equipment that were
identified for an aging management review.
These included basically insulated cables
and connections, uninsulated ground conductors, and
there were 22 electrical penetration assemblies.
These are non-EQ penetration assemblies.
There are additional penetration
assemblies in the plant, but they are treated under
the EQ evaluation. They are evaluated as a time limit
of aging analysis.
There were no open items. However, there
were two items of interest. The first one deals with
non-EQ medium voltage cables that may be subject to
significant moisture. The moisture would come in
basically for cables that are in conduits, cable
trenches, duct banks, underground vaults, or direct
buried installations.
And at Turkey Point, they have a unique
design. These cables are designed with a lead sheath
around the insulation that basically prevents the
ingress of moisture, and the moisture would be the
phenomena that would be the result of a failure in
these cables if moisture gets in and it is subjected
to a long term exposure.
And also energized at the same time, you
could get an effect called water traying. That's
where the insulation basically breaks down and it
ultimately could lead to cable failure.
This goes back to the Davis-Besse event
back in October of 1998, I believe. However, because
of their unique design at Turkey Point, with the
alleged sheath around the cable insulation, basically
that precludes any moisture ingress.
So as a result there was no aging
management program required for these medium voltage
cables. And this second item of interest was the fact
that in response to a staff request for additional
information, the applicant developed an aging
management program for non-EQ cables, connections, and
penetrations.
And these are the components that may be
subjected to a localized adverse environment caused by
increased radiation or temperature. These components
will be inspected every 10 years. It is basically a
visual type inspection, looking for degradation of the
cable outer jacket, and looking for discoloration,
cable cracking, and that type of thing.
The program that they proposed, as I
mentioned, it is a new program, and it is consistent
with the cable aging management programs that we have
described for non-EQ cables.
CHAIRMAN BONACA: Let me ask you a
question now. Does it mean that this program here is
also looking at those cables were said are already
protected by this lead sheath?
MR. SHEMANSKI: No.
CHAIRMAN BONACA: It is not?
MR. SHEMANSKI: We have three separate
programs deigned in goal. One of them looks
specifically at medium voltage cables.
CHAIRMAN BONACA: That's right.
MR. SHEMANSKI: And that one, because
those are typically inaccessible, a visual inspection
would not work. So those cables will be tested every
10 years, starting at year 40, and then year 50, to
give you two data points.
Because of their unique design here with
the lead sheath, there was no need for them to enter
a cable aging management program. The theory is that
water should not get into the insulation based on the
design of these cables.
The cable aging management program they
did propose, those are for non-EQ cables, inside
containment primarily subject to localized adverse
environments from radiation and temperature. And that
program is consistent with the way they have been
described in-goal.
CHAIRMAN BONACA: A member of the
subcommittee who is here raised a question regarding
the first bullet here, the one protected by a lead
sheath. I mean, he was asking the prudency of going
all the way to 60 years without looking at those
cables.
I mean, how comfortable are we that this
design is so consistent that it will last the 60 years
without even looking at it?
MR. SHEMANSKI: Well, these cables are
periodically energized and I believe they do periodic
measure tests on them. But I think the bottom line is
that these cables are very robust. They brought in a
sample of several of these cables, and again they are
medium voltage cables.
Medium voltage cables are anywhere from
2,000 to 15,000 volts. So by their very nature, they
are very thick. The one that they brought in a sample
of, the cable diameter must have been one inch in
diameter, and maybe 1-1/2 inches, and the alleged
sheath was quite sizeable. I forget, but it may be
nearly a quarter of an inch thick.
So it is pretty inconceivable that you
would get degradation of that alleged sheath even at
60 years, I think.
CHAIRMAN BONACA: And do you have
significant industry experience with those?
MR. SHEMANSKI: Well, the interesting
thing about it is that Florida Power and Light's
transmission and distribution standards outside of the
power plants, because we are subject to ground water,
standardize an alleged sheath cabling specifically to
ensure reliability of our underground cables in our
housing, commercial industry, and that sort of thing.
So we have a lot of experience with it,
and that got carried over into our power plants as a
standard design. So that particular feature is
specifically pointed towards a reliability for cable
that may be subject to moisture. We have a lot of
experience.
CHAIRMAN BONACA: Of course, with 45 years
passing, and then you went to look at it, you would
certainly go back and --
MR. SHEMANSKI: Well, we have had a lot of
T&D installations in for even longer than that.
CHAIRMAN BONACA: I understand that, but
I am trying to again develop the thought process
behind license renewal, which is that you would go
back with your corrective action program, and if
necessary, you would have to address it for problems.
So to the best of our knowledge and
understanding of the technology right now, you don't
see the need for that?
MR. SHEMANSKI: No, not at this point.
CHAIRMAN BONACA: All right. Thank you.
MR. AULUCK: Next we will have aging
management programs, new programs and existing
programs.
CHAIRMAN BONACA: These are all one-time
inspections?
MR. AULUCK: Yes.
MS. KEIM: My name is Andrea Keim, and I
am from the Division of Engineering, Materials and
Chemical Engineering Branch. I am here to discuss
their aging management programs.
I guess we will go back and start with the
three common ones that they have listed, which were
the chemistry control program, the quality assurance
program, and their systems, structures, and monitoring
program.
The staff evaluates all the aging
management programs using their tenant tributes, or
elements that are referenced in the standard review
plan.
We use these elements to determine if the
intended functions of these structures, systems, and
components, will be maintained consistent with the
current licensing basis for the extended operation.
And after going over the first three, the
common ones, there were no open items determined under
these programs, although there is a confirmatory
action item in regards to the FSER supplement for the
QA program.
There may be other issues with the FSAR
supplement due to the REI responses that may need to
be updated to ensure that the programs are
sufficiently -- that the program description is
sufficient in the FSAR supplement.
DR. FORD: Andrea, I heard Mario just say
that these are really one inspection?
MS. KEIM: Excuse me?
DR. FORD: Only one inspection is made on
these?
CHAIRMAN BONACA: It is a one time
inspection.
DR. FORD: A one time inspection?
MS. KEIM: I am talking first about the --
these are the aging management programs. Each one has
different frequencies.
DR. FORD: Oh, okay. So it is not just
once?
MS. KEIM: Yes. No. I just wanted first
to go back to really the three ones that they have
listed as common aging management programs.
CHAIRMAN BONACA: I understand that, but
I am saying that what is listed in Appendix B, these
seven programs are one-time inspections.
MS. KEIM: Some are and some are not. It
depends on the frequency listed.
CHAIRMAN BONACA: Well, I went through
them, and all of them say one-time inspection, and if
you find something, then you do more.
MR. HALE: I believe the auxiliary feed
water steam piping inspection is not a one-time
inspection. And the galvanic I believe is not, and
the reactor --
MR. ELLIOT: The reactor vessel internals
is not a one-time inspection.
MR. HALE: Right.
MR. ELLIOT: We are doing one on each
unit.
MR. HALE: But I know that the auxiliary
feed water steam pipe --
CHAIRMAN BONACA: One time for each unit.
Yes, that is the one time for each unit, but I am
saying that with the others, I went over them, and I
was trying to understand which ones are one time
inspections.
The reason why we had the philosophy that
we discussed before, a one-time inspection is an
inspection performed where you do not believe that you
are going to have an aging problem developing.
So you do it just to confirm that you have
confidence that you will not have that problem. Of
course, now if you find that your expectation was
optimistic, then you put in a program.
And so that's why I think it is important,
and I want to look at them to convince myself that
they are confirmatory in fact, and that we don't
expect to have any problems in those areas.
And that's why I would like to ask those
questions about the fact that they are one-time
inspections, and they are different from the others.
MR. ELLIOT: The only one I can answer is
the reactor vessel internal inspection and the small
bore piping, those are both one-time inspections, and
the reactor vessel, in terms of one time of each unit.
And the small bore piping inspection is a
one-time inspection, and it is a volumetric inspection
of the critical locations. And so these are for
unanticipated cracks. We have not seen cracks on
these small bores yet.
And it is intended to look volumetrically
to see if we do have cracks. So that is within the
scope of what you just described. I can't answer for
the rest of them. I can only answer for those two.
MR. HALE: But your interpretation is
correct. In those cases where we had a one-time
inspection, it is usually to verify whether something
is occurring or not, because we don't know.
CHAIRMAN BONACA: All right.
MR. HALE: Our tools tell us that we
should have an aging effect, but we haven't seen it in
our operating experience. So it is a one-time
inspection.
The auxiliary feed water steam piping
though I know is one that we have or are going to have
periodic inspections for, and I think if you read the
description you will see that.
But the one time inspection is one of the
reasons why most of these are new programs, because
they are verification, and we have not had the
operating experience, and it is one of the reasons why
it is a new one that we haven't done yet if you want
to look at it that way.
Now, the steam piping inspection program,
based on some recent operating experience, we have
identified the need to go out and look at not only
internal, but the external surfaces of that piping,
and we are doing that now.
But in terms of a formal program, we
wanted to formalize it under license renewal.
CHAIRMAN BONACA: You are correct. The
second one is not a one-time. So I was wrong.
DR. FORD: But in general the rationale is
that you will inspect these in 30 years or 35 years,
or whatever it might be.
MR. HALE: We would use it as information.
One of the issues that the industry has right now is
galvanic corrosion in treated water systems. The do's
say you have it, but we have not experienced it.
So galvanic susceptibility, we want to go
and look at -- I mean, we certainly have experienced
it in salt water systems and those where you have a
high electrolyte process there.
So some of these we have not seen the
experience, but we are going to go and inspect, and
see if we see anything. If we do, then we will commit
to additional inspections. We don't expect to find
anything, with the exception of that one.
CHAIRMAN BONACA: And again I am not
questioning whether or not it is a problem. It's just
that typically I always look for the one-time
inspections because to me when I read that, it is
telling me that you do not inspect to see a problem.
You are just doing it to confirm that.
And if you in the verbiage you say that
you are expected to find it, and then you decide what
to do then, then a one-time inspection is not good
enough. That may be simplistic, but we had some
understanding of that some time ago.
MS. KEIM: At this point, I am going to
hand it over to Cliff Munson, who is going to discuss
the field erected tanks and internal inspection
program, which does have an open item.
And after that, Jim Davis is going to
discuss the galvanic corrosion susceptibility
inspection program, which doesn't have an open item,
but we wanted to highlight that program for you.
CHAIRMAN BONACA: Since there are a number
of potential questions here coming over the next
couple of presentations, and that might take some
time, I think we should break now and take a recess
for lunch.
I think we will gain some time in the
afternoon, particularly in the discussion here, and so
we should still stay on schedule. We will take an
hour for lunch, and resume the meeting at 1:15.
MR. MUNSON: I must wanted to cover one
thing briefly.
CHAIRMAN BONACA: Okay.
MR. MUNSON: It is just a five minute
thing.
DR. ROSEN: Will that release you for the
rest of the afternoon?
MR. MUNSON: Yes.
CHAIRMAN BONACA: Go ahead.
MR. MUNSON: This is one of the new aging
management programs and it is a one-time inspection of
these three tanks, and these are carbon steel coated
tanks, and this is a new program, and so they have not
developed any program requirements, in terms of the
visual inspection.
And they have not developed acceptance
criteria, and also the application was not clear on
what previous operating experience there was.
So we asked for an REI on this, and they
came back with some operating experience on the
condensate storage tank and they actually recoated
both of the tanks, one in '83 and the other one in
'91, because of significant corrosion or degradating
of the coating.
So we weren't clear if the demineralized
water source tanks or the refueling water source tanks
had been inspected. So that also was part of the open
item on this one.
So we have not yet accepted this as a one
time inspection of the condensate storage tanks. We
are waiting for additional information.
CHAIRMAN BONACA: Okay. Let's break, and
we will come back at 1:15.
(Whereupon, at 12:15 p.m., a luncheon
recess was taken.)
A-F-T-E-R-N-O-O-N S-E-S-S-I-O-N
(1:14 p.m.)
CHAIRMAN BONACA: All right. The meeting
is called to order, and we will continue with the
presentations by the staff.
MR. AULUCK: We will continue with the
aging management programs. Andrea.
MS. KEIM: We were discussing the seven
new aging management programs, and Cliff Munson had
gone over the field erected tanks, and internal
inspection program with the open item, and now Jim
Davis is going to discuss the galvanic corrosion
susceptibility inspection program.
MR. DAVIS: What they have done is they
have identified a number of locations where basically
you have carbon steel to the stainless steel
connection. We have no history of any problems with
galvanic corrosion in these areas.
But they are going to do a one-time
inspection just to verify that they are not having any
problems.
CHAIRMAN BONACA: On all of these
components?
MR. DAVIS: These are all the component
systems that were selected to be looked at.
CHAIRMAN BONACA: Now, regarding the fuel
tanks, I believe there is an open item on those?
MS. KEIM: Yes.
CHAIRMAN BONACA: Could you --
MS. KEIM: The field director tanks.
MR. AULUCK: Oh, the field director tanks
are what you are talking about?
MS. KEIM: Yes. Can you show that slide
back up again.
(Brief Pause.)
MS. KEIM: And that one had to do with the
acceptance criteria.
CHAIRMAN BONACA: Oh, yes, I remember
that.
MR. AULUCK: They had not developed the
acceptance criteria or limiting procedures.
CHAIRMAN BONACA: And so all the 10
elements are not fully defined, and that's what we are
waiting for.
MR. AULUCK: Right.
CHAIRMAN BONACA: Okay. Thank you.
MR. DAVIS: Well, I missed my shot at the
small bore piping inspection program before, but now
that I have got an opening here with the galvanic
program, I will take a crack at it from that point of
view.
It is our old friend, the one-time
inspection program, and galvanic corrosion
susceptibility strikes me as a place where a one-time
corrosion program is useful. You know, I can go in,
and I can see the damage, and I can characterize
damage. It is sort of visible.
When I look at the small bore piping
program -- and until I have a crack, there is nothing
to find. I can have fatigue damage accumulating, and
I am not going to see squat in my one-time inspection.
And I am not sure that -- well, that one
just doesn't strike me as the place where a one-time
inspection tells me a whole lot.
MR. AULUCK: Well, with a volumetric
inspection, you will learn something.
MR. DAVIS: I will learn something, but I
really won't learn -- well, I will learn that I have
a crack, but a fairly high fatigue damage without
initiating a crack, and not see anything.
There is a much higher threshold there
before you get visible damage, and in a case of
galvanic corrosion case and the process is going on,
I would expect -- well, it is really a cumulative
process and I would expect to see something.
And it strikes me again as something where
a one-time inspection is useful. I am not so sure
that I see it, although the staff likes the one-time
inspection for the small bore piping.
MR. ELLIOT: Well, on the small bore
piping, it is for piping that we have not seen a
problem. We have not really seen a thermal fatigue
problem, and we have not seen a stress corrosion
cracking problem.
DR. SHACK: So it specifically excludes
all the lines like we have seen int he B&W?
MR. ELLIOT: That's right. It excludes
all of those. If we have seen a cracking problem,
like the Oconee HPI lines, those have a regular
inspection program associated with that.
The purpose of the one-time small bore
inspection is for small bore that we have not had a
problem with, but we could have a problem for either
stress corrosion cracking in a boiler, let's say, or
a thermal fatigue problem potential for a PWR.
And the one time inspection is looking for
whether there is a cracking problem associated with
those types of mechanisms. Now, it's granted that if
you do more than one that you are going to get more
data, but you have to look at it as where are we going
to expend the resources to do inspections.
What we are saying is that we don't expect
those, for anything to happen here, but just to be a
little on the careful side, we are going to do the
inspection.
DR. SHACK: So you really are almost
excluding the lines where you have seen problems.
MR. ELLIOT: Right. The lines that we do
have problems, we have the HPCI program.
DR. FORD: Would you mind going back to
page 20, and just run down that list of the new aging
programs just to confirm those. I understand that
small bore piping is not a one-time?
MR. ELLIOT: No, it is. It is.
CHAIRMAN BONACA: The only one that is not
a one-time inspection is the second one and the second
to the last one.
DR. SHACK: Well, now that we have brought
this slide back, I can go to the reactor vessel
internal inspection. We are going to work our way
right back to the beginning of your presentation.
The question that I had here was with VT1,
and our friends with boiling water reactors have had
lots of experience looking for cracks and have decided
that VT1 isn't good enough to see cracks. They go to
a VT1 enhanced.
MR. ELLIOT: Right.
DR. SHACK: So these guys are doing VT1
and ultrasonic, and I can justify to myself, okay,
maybe I really can't see a whole lot with VT1, but
they are going to do ultrasonic on the baffle bolt,
and that is the most susceptible component, and I can
live with it.
As I read the SER though, it seems to buy
off on the VT1. If I saw a rationale like that in the
SER, then it is good enough for that reason, and I
think I would buy it. I didn't like the SER where it
seemed to indicate that VT1 was really good enough to
see stress corrosion cracks.
MR. ELLIOT: That is a good point. In the
past we did have VT1 enhanced, and I noticed that in
this one we didn't -- that Turkey Point didn't commit
to do that.
DR. SHACK: But they did commit to do the
ultrasonic?
MR. ELLIOT: Right. Right. That was for
the baffle floor bolt. This will be proven out in
essence, and --
DR. SHACK: Well, haven't you already
proved it in BWR? I mean, GE didn't jump to VT1
enhanced because they loved doing it. They found out
that they couldn't see cracks.
MR. ELLIOT: But Turkey Point said that
their experience was that they could see cracks. That
was the basis of what their experience was.
DR. SHACK: Well, he has a lot more
experience looking for cracks in internals than BWRs.
MR. ELLIOT: Well, we will take that into
consideration.
MR. HALE: I think also one of the things
that we should mention, too, is that with a PWR that
you are dealing with a controlled chemistry, and with
a BWR it is similar to, say, a secondary steam jet,
from the standpoint of the controlled chemistry in a
PWR.
The chemistry control is not exposed to
some of the issues that you were raising before, such
as copper and reactor vessel, and --
DR. SHACK: Well, it is still a question
of whether I can see a stress corrosion crack with
VT1, or I have to go to a higher resolution. I don't
have a problem because you guys are doing ultrasonic,
but it is just the more generic kind of thing that the
notion of whether VT1 would be acceptable to see
cracks that I have sort of objected to.
MR. HALE: Well, there are a couple of
things that I would like to clarify. The stress
corrosion cracking we are managing with a chemistry
controlled program.
DR. SHACK: Well, I should say IASCC.
MR. HALE: IASCC. Our leading indicator
is the baffle bolts. That is the area, and it is
fluence related. So we are using that as the primary
indicator, and we are looking at that first.
DR. SHACK: Well, my comment was more
addressed to the staff.
MR. ELLIOT: We understand your comment,
but if they find cracks in the baffle bolts, then they
have to look someplace else. And if it requires an
enhanced VT1, then that is what they are going to have
to use.
They are going to have to prove to us that
they are capable of detecting those type of flaws. I
mean, that is ultimately where you have to head here.
MR. DAVIS: In general, the way we have
been going is that you want to substitute a VT exam
for a volumetric exam? We have been requiring
utilities to resolve a one mil fire with a visual
exam.
DR. SHACK: Right.
MR. DAVIS: Which is an enhanced.
DR. SHACK: Which is an enhanced, right.
But I don't know why you just don't say that here for
the RVI program. If you said one mil against a gray
background, I'm a happy man.
MR. DAVIS: Okay.
MR. ELLIOT: Okay. I did not write the
SER. You are putting the cart before the horse
because we have not looked at the baffle form bolts
yet. When we do that, and we see a problem, or if we
see a problem, then this becomes something that we
will have to consider.
CHAIRMAN BONACA: Well, Barry, we are --
MR. ELLIOT: You are talking about a
visual examination for baffle bolts, and that is what
we have been doing in the past. Where this crack
occurs is at the shank and where it joins the head.
And in looking at the head, you are not going to see
this crack.
DR. SHACK: Right. Which is why the UT is
so important.
MR. ELLIOT: Right.
DR. SHACK: And I am happy with the UT.
As I said, the UT is what saves the day as far as I am
concerned as far as really making this acceptable.
It's just the notion that I am then going to look with
the baffle bolt as my leading component, and if I then
want to look somewhere else for cracking, I would
argue that I would need the VT1 enhanced rather than
VT1.
But you are right. Once you find cracks
in the baffle bolts, it might be a new ball game.
MR. ELLIOT: And we appreciate your
comments, and Turkey Point does, too.
DR. SHACK: I have made my point.
CHAIRMAN BONACA: No, no, I am just
puzzled because I remember slightly the discussion,
but I don't remember exactly what was said regarding
just visual. What you are saying is that if it leaves
the impression that VT1 is adequate, then that is not
the right impression.
DR. SHACK: That's what I am saying.
CHAIRMAN BONACA: Although it would be an
issue for the SER, but not necessarily for the
application.
DR. SHACK: Right.
MS. KEIM: Moving on to the existing aging
management programs, and aging encompassed all these
programs. We are going to really just highlight the
Alloy 600 program, head penetrations, which is going
to be Barry Elliot discussing that.
MR. ELLIOT: We sort of discussed this
program earlier in the morning. The reactor vessel
head alloy 600 program, the program that is currently
in the application is based on generic letter 97-01,
and in this sense, it is part of your question of the
regulatory process, too.
And that is that 97-01 was concerned about
cracks in the nozzles themselves, axial cracks in the
nozzles themselves, and that was what we were
concerned about when we put out generic letter 97-01.
The industry responded to that concern and
set up a program, and the program was leakage
detection, and then volumetric inspection of selected
components in selected facilities.
And Turkey Point, in their application,
complied with that basic program. And that is what
this slide says. Recently we had problems at Oconee,
and they weren't the nozzle axial cracks. They were
circumferential cracks associated with the J-groove
weld, and the heat affected zone, a different
mechanism than we had previously seen.
So we put out a bulletin asking industry
to respond to this mechanism, and industry has
responded, and the staff is evaluating the response,
and we will formulate with industry a resolution of
the issue.
I just want to make one thing clear to
you. The NRC does not solve the problems themselves.
We resolve the problem through industry, and that is
the process here.
We set up a process to resolve this
problem, and the process for license renewal is to set
up the processes within license renewal so that the
issue doesn't get lost. It just stays within the
application.
And in this case, because this is a new
issue, the process is to have an open item and then to
have a licensee to commit to whatever the program is
that the industry develops for solving the issue in
the bulletin. And that is where we are on this issue.
CHAIRMAN BONACA: Any questions?
DR. FORD: I just find it very hard to
swallow when you say that it is not within NRC's
perview. I think the NRC has got to take a leadership
aspect.
MR. ELLIOT: Let me just say that the NRC
takes the initiative to identify the problem, and then
we identify the problem in a way so that industry
should understand where we are coming from, and what
we think the problem is, and then we expect to propose
solutions to us.
And if we don't like the solution, we say
it is not good and we need another rock. And this is
the regulatory process. Now, we have research here,
and our research is not intended to solve all the
problems.
It is intended to look into what the
industry is proposing to see if it is proposing
something that we can live with, and that is how our
research fits in here. There is sort of more of a
confirmatory aspect.
Now, there are areas where our research
has been not confirmatory. I will tell you that with
the reactor vessel, the embrittlement, it was our
research. It really wasn't industry research.
And with respect to the axial cracks in the nozzles,
that wasn't the NRC. That was the industry.
They proposed it and we went back and
forth for a couple of years before we got a program
that we thought was a good program, and the same thing
is going to happen with the bulletin.
It is not going to come out next week, the
answer, but the industry has proposed something and we
are evaluating it, and we are going to resolve the
issue.
CHAIRMAN BONACA: Any more comments? All
right.
MS. KEIM: Next will be TLAAs.
MR. ELLIOT: Okay. I am going to be
talking about reactor vessel radiation embrittlement,
and under metal fatigue, there is a fatigue issue
related to the vessel, and I will talk about that.
Paul Shemanski will talk about
environmental qualification of the electrical
equipment. There is a whole list of all of the TLAAs
up there. All the others don't have open issues. The
three that we are going to talk about have the open
issues. I'm done.
DR. SHACK: Barry, why was leak-before-
break for RCS system piping a TLAA?
MR. ELLIOT: That's because of the cast
stainless steel basically, is that -- you know, when
they originally did the evaluation did they have
saturation or not. And then we have to look and see
if there is saturation, and how it impacts the leak-
before-break evaluation.
Okay. On the reactor vessel, radiation
embrittlement, there are three parts of the analysis.
There is the pressurized thermal shock analysis, the
charpy upper shelf energy, and the pressure
temperature limits.
They are all related to neutron and
radiation embrittlement. The pressurized thermal
shock evaluation is done in accordance with our --
with the rule, 10 CFR 50.61, which establishes a
methodology for determining the amount of radiation
embrittlement, and it establishes screening criteria.
In the case for Turkey Point, they did the
evaluation in accordance with the rule, the screening
criteria, and the limiting material for their vessel
is a circumferential weld in the belt line, and the
screening criteria is 300, and the RPPTS value they
calculated was 297.4.
So they don't have a lot of margin. So
they have to keep track of the fluence and make sure
that it doesn't increase the value of the RPPTS above
the screening criteria.
DR. SHACK: Do they have flexibility? Do
they have a low leakage core ready?
MR. ELLIOT: I would have to ask someone
else.
MR. HALE: Yes, we have a low leakage
core.
DR. SHACK: And that is actually taken
into account when you calculate your 297.4?
MS. THOMPSON: I don't believe we have for
all the future years. We have been operating with a
low leaking core for a number of years, but I think
that calculation has some conservatism in it, but we
do have a low leakage core installed.
But I don't believe we have credited it in
the calculations.
DR. ROSEN: You see, that is the problem
with this, I think, and that is that you have got 48
effective full-power years on a 68 year license, and
that is 80 percent capacity factor.
But plants are running in the 90 percent
capacity factors, and so if you run 90 percent, you
are going -- well, will you end up with higher than
297.4?
MR. ELLIOT: The critical issue here is
not the effective full power. It is the fluence. If
you look on our SER --
DR. ROSEN: Well, more fluence comes from
more operation.
MR. ELLIOT: Yes, and so that is what they
have to reach. They have to keep within that target
fluence. They have a target fluence and at the end
of 60 years, they have to stay below 4.5 times 10 to
the 19th. I think that is the number in the SER.
DR. ROSEN: Yes. But the point is that
they are going to get the 48 effective full-power
years long before they get the 60 years total at 90
percent capacity factors, which typically everybody is
running.
MR. ELLIOT: But as long as their fluence
stays -- the accumulated neutron fluence stays below
4.5, it doesn't matter whether it is 48, or 49, or 50
effective full power years.
It is the neutron fluence which is the
issue, and as long as they keep track of that neutron
fluence, and they measure what they are getting,
versus what they planned on getting, to get the 4.5,
then they will be fine.
MS. THOMPSON: We have completed almost 30
years of operation on the two units, and unfortunately
in the earlier years at the Turkey Point operation, we
did not have that higher capacity factor.
So we actually didn't pick up that much in
the way of BFPY. Nowadays, we do operate above 90
percent, and I don't recall the exact assumption that
was made for the remaining life of the unit, but it
was well into the 90 percents to come up with a
projection of 48 being the bounding for end of life.
DR. ROSEN: So for your first 30 years,
you add 70 percent capacity factor, and that would be
21 EFPY; and for the next 30 years, you have 90
percent, and that would be 27 more. So that is your
48; 21 and 27.
MS. THOMPSON: And that is pretty close to
where we were. We just switch from 19 EFPY to
P-T curves in our technical specifications.
DR. ROSEN: So it is going to be a close-
run thing down at the end is what I am saying.
MS. THOMPSON: And these curves actually
go in our technical specifications, and basically they
stay in compliance with our technical specifications,
and we have to stay within that 48 EFPY.
DR. ROSEN: All right. So I have voiced
my concerns about how close it is going to be before
you get to the end of the 60 years in terms of
fluence.
CHAIRMAN BONACA: Well, I don't think
typically that for this calculation that low leakage
is being considered in it. With low leakage, the
radiation is so low.
MR. HALE: You have to realize there is
some margin in the fluence number, too.
DR. ROSEN: Well, I would like to get to
the margin question. That is where I am really
heading. When you talk about 297.4 versus a 300
degree screening criteria, where are the uncertainties
in this calculation? Is it 3 percent?
MR. ELLIOT: We threw in a margin of 56
degrees. That is part of the calculation.
MS. THOMPSON: That is a lot.
MR. ELLIOT: That is taking into account
uncertainties in chemistry, fluence, and the
calculation procedure. We threw that in. That is
part of the procedure. There is an uncertainty in the
procedure.
DR. SHACK: They build the margin or they
build the uncertainty into their acceptance rather
than calculate it out separately.
MR. ELLIOT: Right. It is all calculated
as part of the calculation, exactly. Okay. Charpy
upper shelf energy. 10 CFR, Append G, has
requirements for Charpy upper shelf energy, and it
must stay above 50 foot pounds, and if you go below 50
foot pounds, you have to supplement the analysis.
Well, Turkey Point is one of the plants
that went below 50 foot pounds. They went below 50
foot pounds a long time ago. In the first 40 year
license, they provided an analysis, and basically all
they have done in the 60 year license is updated the
analysis to 60 years. And that is basically what they
have done here.
Pressure temperature limits are done
according to Reg Guide 1.99 Rev. 2. Again, it is a
transition temperature shift that we are concerned
about in the pressure temperature limits. They have
submitted curves for approval for 32 effective full
power years, and we have reviewed those curves and
they are fine.
They gave us another set of curves for 48,
and they did not submit them for approval, but it is
just a matter of calculating it so they can actually
do that.
And one of the issues here of interest is
that they didn't use the chemistry factor ratio
adjustment. If you have surveillance data, the
procedure describes how you are supposed to use the
surveillance data.
They didn't do it, and so we are just
telling them here that you should do it. Now, it
turns out that what they did was conservative for the
data that they have now.
They are going to be withdrawing I don't
know when, but they are going to be withdrawing
another capsule. They could get another data point.
This is one of the plants that actually has the right
material in the capsules.
So they can actual measure the amount of
embrittlement for their vessels, and when they pull
that capsule, we are just telling them that when you
do it that you need to use the ratio adjustment
factor.
Now, it turns out as I said that this is
a benefit for them in this case so far, and based upon
the data, they could have had even a lower value than
297.4, or they could have had even a less conservative
if they had followed or had used their ratio
adjustment.
They are not supposed to use a ratio
adjustment unless the data is credible. We have
criteria. So they followed the reg guide and the data
was not credible, and so they did what they were
supposed to do.
But it is potential that when you get new
surveillance data that it could change. The data
could become what we call credible according to the
criteria, and then they would have to use the --
instead of using the chemistry factor they used, they
would have to use a different chemistry factor.
That's the point there.
The second point of interest is that
normally we think of the belt liners between the
intermediate shell and the lower shell, those are the
shell courses.
But what happened is that with the longer
life, all of a sudden we have a new shell course that
is starting to get a large amount of radiation, and
right now it is not limiting, but you still have to
monitor it.
And that is this circumferential weld
between the nozzle belt line and the intermediate
shell.
CHAIRMAN BONACA: So it is not limiting
now?
MR. ELLIOT: It is not limiting now, but
fluences change. They change some geometries or
whatever, core geometries, and if they do that, and
they have to do a reevaluation, then they should also
look at this other weld.
And we have looked at it based upon what
they have told us, and it is not limiting. According
to the PTS rule, if you change core geometry
significantly, you have to do a reevaluation. If they
have to do a reevaluation, we would like them to look
at this other weld also.
DR. ROSEN: I was puzzled by the
statements in the application on page 4.2-5 on
pressure temperature limits. It is in Section 4.2.3.,
and it is about the need for a separate license
amendment which specifically requests approval of the
48 EFPY prior to expiration of the proposed 32 EFPY.
MR. ELLIOT: Do you want me to explain
that?
DR. ROSEN: Yes.
MR. ELLIOT: Okay. We give out -- what
happened is that it is a tech spec. Pressure
temperature limits are in the technical
specifications. We only approve the curves for 32
effective full power years.
So they can only operate this plant with
those tech specs until 32 effective full power years.
If they want to operate this plant beyond 32 effective
full power years, they have to put a new tech spec in
that is applicable for a greater period of time.
And they are going to have to put in a new
set of pressure temperature load for that greater
period of time. They have not asked us for that, and
we have to approve their tech specs. That is where
the amendment comes in. We have to approve the tech
spec amendment.
DR. ROSEN: Prior to 32 EFPY.
MR. ELLIOT: Right, because the 32 will
run out.
MR. ELLIOT: And you are out about 21 or
so now?
MS. THOMPSON: Yes, in that vicinity.
DR. ROSEN: So you have time.
MS. THOMPSON: We have plenty of time.
DR. ROSEN: You have plenty of time, 10 or
12 years. But this license renewal extension, or
whatever you want to call it, although it could be
granted, will in fact not give you that full term
until you get this changed, too.
MS. THOMPSON: That's correct.
DR. ROSEN: Why don't you get it changed
now?
MS. THOMPSON: It was a conscientious
decision that we made for some of the reasons that
Barry has illustrated. Those P-T curves that were
submitted that go to 32 EFPY actually are based on
calculations that consider the fluence associated with
48 EFPY.
We elected to make them applicable for the
current term only because we needed that tech spec
amendment approved prior to this renewal application
in order to continue operating.
Our past curves were only go through 19
EFPY, and we just thought that proceeding down that
path would be a more efficient process for us to do at
the time, and that we would take it as a second step
to move through to get the 48 EFPY.
DR. ROSEN: Let me see if I understand
what you just said. You have got a tech spec change
already approved to take you beyond 19.
MS. THOMPSON: Right, which we needed to
continue operation even today.
DR. ROSEN: So you have that, and now you
are in for a license renewal out to 60 years total
time, 48 EFPY. But you are not asking for this change
at the same time, and I still don't understand why.
MS. THOMPSON: Not at this time, but
between now and 32 EFPY, we have the opportunity for
removal of additional specimens for analysis of that.
We can potentially improve those curves and give the
operators more margin.
If not, we have performed the analysis,
and we know what the answer is based on this data, and
it is the same as we are operating to right now. So
we know that we are in an acceptable position, but we
may be able to put ourselves in a better position.
And so we decided to take it on an incremental basis.
MR. HALE: I think it is important to note
that even new plants when they are licensed, in some
cases were licensed with 5 year curves, or 10 year
curves, and the reason is that as you move out in
time, the more restrictive the curves become from an
operational standpoint.
So sometimes you choose, well, we are
licensed for 5 years, and before we reach the
expiration of that, we will submit a license amendment
for 10 years, and it starts narrowing down.
And you can impose, because you have got
also your concerns over maintaining subcooling margin
below, and also MPSH on the reactor coolant pumps.
So even new plants when they are licensed
aren't necessarily licensed for 40 years for their P-T
curves.
DR. ROSEN: So you are keeping the highway
as wide as you can and for as long as you can by doing
this?
MR. ELLIOT: Right. And then it was a
timing issue like Liz said. After we had submitted
the license renewal application, we needed to change
the P-T curves because we were reaching our EFPY limit
on those P-T curves.
So rather than tieing up our approval of
those to the 48 EFPY, we decided to go in with a 32
EFPY with a license amendment that was in process and
parallel with the license renewal application.
DR. ROSEN: Okay. Thanks a lot.
MR. ELLIOT: Okay. The next issue is
metal fatigue, and that normally is John Fair, and
Mark Hartsmen issue, but I have an open issue here.
And the open issue is WCAP-15338.
DR. SHACK: You get all the vessel stuff
anyway.
MR. ELLIOT: Right. So this is the vessel
stuff, and in 1970 the industry discovered that for
course grain forgivings, that if you had a height and
heat input submerged on CLD that you could under beat
cracks under the CLD.
The cracks generally are very, very small.
They are on the order of a 10th of an inch, and really
cannot be detected by ultrasonic inspection. The way
this was discovered was from nozzle dropouts, and they
could actually visually see the cracks.
This was an issue in the '70s and it is a
fatigue issue, in the sense that you have existing
cracks and over a certain amount of time they are
fatigued and grow.
And the question is do they grow to a
large enough size that the integrity of the vessel is
in question. So the industry in the early '70s did an
analysis for 32 effective full power years.
And now we have license renewal, and so
the industry has to come up with another analysis that
has 60 years. It is still a fatigue issue, and we
went through this one time before with Oconee, and I
don't know if you remember that, but I think it is
Unit 1 that has forgings.
And that was a B&W analysis, and this is
the Westinghouse analysis that we are reviewing now.
We have not finished the analysis. The analysis
originally was submitted, and they used an air
environment for fatigue crack growth.
We didn't like that. We wanted them to
use the water environment, which is a little more
conservative. And we also wanted them to look at what
PTS events could impact Turkey Point, and they did
that.
They did everything that we have asked,
and they resubmitted it, and we are reviewing it. It
has gone through a lot of review, and I think as you
said, Raj, you expect it to be done by --
MR. AULUCK: The middle of next month.
MR. ELLIOT: -- the middle of next month,
and that's where we stand. That takes care of
everything that I have to say, and now it is Paul's
turn.
MR. AULUCK: The last slide is
environmental qualification.
MR. SHEMANSKI: I'm Paul Shemanski,
environmental qualification on electrical equipment.
There are no open items; however, we have two items of
interest.
The first one deals with the
classification of how the EQ TLAA was done by the
applicant. When they evaluated EQ as a TLAA, they
used 10 CFR 5421(c)(1)(i), and that basically means
that the analyses remain valid for the period of
extended operation.
Now, we disagreed with that classification
because the staff believes that the reanalysis that
were done, the way that we interpret that is that the
analyses have been projected to the end of the period
of extended operation.
Basically what they did was they extended
the qualified life of these electrical components from
40 to 60 years. They did a thermal analysis and
radiation analysis,and we believe that if you look at
the rule that that constitutes Paragraph
54.21(c)(1)(ii).
It turns out that it is not a big deal
because it has nothing to do technically with the
results that they obtained. It is just a difference
of what they classify and what the staff classified as
the evaluation that was done for the EQ TLAA.
So again there was no effect on the
technical adequacy of their evaluations. Just that
they decided to classify these as (i), and we believe
they should have been classified as (ii). So, no big
deal.
The second item of interest deals with the
wear cycle aging effect on various motors, and in
particular Westinghouse and Joy. These are
containment cooler and filtration motors, and
containment spray pump motors.
When we looked at the EQ evaluation that
the applicant did, we noted that they did not
adequately address the wear cycle aging effect. That
is the start/stop cycles.
These are large motors, and when you turn
them on there are significant electrical stresses on
the windings, and mechanical stresses on various
portions of the motor, like the bearing and shaft.
Anyway, we had a discussion with the
applicant, and they went back and determined that over
the 60 year plant life that they would not exceed
1,000 start/stop cycles.
And they did some further research and
found that a EPRI power plant electrical document that
claims that motors of this type are good for 35,000 to
50,000 start/stop cycles.
So the fact that they only anticipate only
1,000 cycles for 60 years, it looks like they have a
tremendous amount of margin in there. So we accepted
the evaluation and the bottom line is that they are
going to go into their EQ file for their particular
motors.
And they put the EPRI reference document
in there so when people look at it in the future they
will have assurance that the wear cycle aging effect
is minimal. That's it.
CHAIRMAN BONACA: Now, on GSI 168, they
are committed -- what is the commitment that they
made?
MR. SHEMANSKI: Basically to follow the
resolution of GSI 168 and the staff in both NRR and
the Office of Research, are working on the options for
resolution on GSI 168, and so they basically in
essence committed whatever out of GSI 168, and they
would comply with it.
CHAIRMAN BONACA: Any other questions?
Okay. Thank you. So, I think we have completed this
portion of the application.
MR. AULUCK: Is there any action item for
the staff to follow up?
CHAIRMAN BONACA: Well, I heard that
insofar as the application is concerned -- and the
application is quite specific. I mean, it has
ultrasonic in addition to the VT1 in that location,
and that is adequate enough.
Are there any other issues that you feel
should be action items for the staff?
DR. DUDLEY: I think at the end of the
meeting we will need to describe and discuss what you
would like to hear at the full committee meeting.
CHAIRMAN BONACA: I would like to do that
after we hear about the Westinghouse Topical Reports.
All right. With that then, why don't we move into the
presentation of the Westinghouse supporting documents.
I had a question generally. For the B&W
plants, we have the B&W topical report also about
vessels.
MR. ELLIOT: Yes.
CHAIRMAN BONACA: For the Westinghouse
plants, we do not have that.
MR. ELLIOT: No. Well, we will let
Westinghouse speak for themselves here, but let me
just explain to you. The Westinghouse plants, they
didn't build any of the vessels. They are built by
Babcock and Wilcox, and Combustion Engineering.
CHAIRMAN BONACA: Okay. That's what I
thought actually, but I wasn't sure. It was more
curiosity than anything else.
MR. HALE: I think one other point, too,
is that you have got a much wider variety of plants in
reactor vessel designs, two loops, three loops, four
loops, and different power levels.
And we in the WOG had a difficult time
coming up with a generic report on a reactor vessel.
It was pretty high level and so it had to get a
little more specific.
CHAIRMAN BONACA: All right. We do have
handouts for those right, for the vessels? Yes.
MR. ELLIOT: The Westinghouse Owners Group
life cycle management license renewal program
submitted four topical reports for NRC review. They
were Class I piping and associated pressure boundary
components; reactor vessel internals, pressuring the
reactor coolant systems.
The Westinghouse Owners Group people are
here. I know that one of them, Charlie Mayer, is
here; also from the staff here is John Fair, Frank
Rubelick, Mark Hartsmen, Arnold Lee, Hibo Wang, and
Mohammed Razuk.
I just wanted to explain to you how I laid
this out so you know where I am going. I divided it
into three little sections; what was in the
application, and which is the first part, and I will
go through what is in each WCAP.
And then I have a page or a page-and-a-
half of our staff evaluation, and then a final
conclusion. So we will start with what is in the
application.
And in every case I identified what are
the materials that we are talking about here, and then
what are the aging effects that were identified as
being applicable for these materials and these
components.
And then what are the aging management
programs for those materials, and again effects, and
then if there are any TLAAs, and that's how --
CHAIRMAN BONACA: Actually, they really
followed the license renewal formal literally for each
critical component.
MR. ELLIOT: Yes, they did. Well, let me
preference this. They did a pretty good job
considering where they were. They were in the dark.
I mean, a lot of the other B&W stuff were developed as
they were the doing the Oconee application. So they
had the advantage of hearing a lot of the issues as we
were developing them.
In the case of the WOG, a lot of these
topical reports were developed before we even had
applications. So they were going in the dark, and
they were trying to figure out what the issues were.
So what you are going to hear is that we
had a lot of open issues and a lot of action items,
but that's because of the way that they were operating
in the dark here without any previous application to
go by.
And then when I go through the applicant
action items, the ones are -- you are going to hear a
lot of the same ones. We discussed Oconee, and Hatch,
and it is the same set of issues.
CHAIRMAN BONACA: I would like to ask that
as far as you know is there any plan on the part of
the WOG to go back to those four topicals and
disposition some of these issues given now that they
have experience on the applications themselves?
MR. ELLIOT: Well, all the items were
answered by the applicant.
CHAIRMAN BONACA: I understand.
MR. ELLIOT: So they have included in
their application, somewhere in their application,
they have addressed all these issues. Like the small
bore piping, and the reactor vessel internals program,
and the fatigue issues.
Those are all applicant action items that
we addressed that were highlighted during the previous
applications, and they are being carried out here in
their applicant action items for the topical reports.
CHAIRMAN BONACA: Well, what I meant to
say is that given what they know now, it could be more
dispositioning writing the topical reports, rather
than left to the applicants, and that could be
convenient to the future applicants.
MR. ELLIOT: Can I just answer that?
CHAIRMAN BONACA: Yes.
MR. ELLIOT: I hope that we are going to
have GALL. I hope they are going to implement GALL,
and if they implement GALL correctly, and they just
say they meet GALL, and where they don't meet GALL.
CHAIRMAN BONACA: I understand.
MR. ELLIOT: And my preference would be
that the --
MS. THOMPSON: I think the answer is that
the WOG does not plan on going back and revising those
and to address those, and there is a couple of reasons
for that.
One is that as Steve had mentioned earlier
that there is quite a broad spread of design
information that is applicable to various different
components in the Westinghouse class, versus some of
the other NSSS suppliers.
The second reason is that looking at the
industry and the staff's resources, we are focused
largely on individual applications now, and if we were
to put something else on the table for the staff
review, we realize that would also take away from
their ability to deal with the applications on their
table.
So I think it is a balancing act there,
and I believe that each applicant will probably be
able to address these open items.
MR. HALE: Now, we are also -- the WOG is
taking our response and preparing information for all
the Westinghouse plants, and they will have that
available as a source of information that here is the
way that Turkey Point addressed this issue, and they
will have that information available.
CHAIRMAN BONACA: Okay.
MR. ELLIOT: All right. The slide is
self-explanatory. The piping and fittings, and value
bodies, and bonnets and casings are all stainless
steel, and the reactor coolant bolting are alloy
steel; and the valve bolting are carbon steel, alloy
steel, and stainless steel.
The aging effects identified are fatigue
related cracking, corrosion of external surfaces
caused by leakage of borated water; and reduction of
fracture toughness due to thermal aging of cast
stainless steel.
And loss of material caused by wear of the
reactor coolant pumps and values bolted closure
elements; loss of bolting preload caused by stress
relaxation of bolted closures. That is what is
identified as the aging effects.
Now, to manage those aging effects, the
WCAP takes credit for in-service inspection and test
requirements of ASME Code, Section XI, and ASME/ANSI
operation and maintenance standards to manage the
aging effect of wear.
And in-service inspection requirements of
Section XI to manage stress relaxation. The
commitments of applicants and licensees to NRC Generic
Letter 88-05, to manage corrosion caused by borated
water leakage.
And they also would like to have taken
credit for analysis methods and inspection
requirements to manage fatigue related cracking.
And to identify analysis methods and
inspection requirements to manage the reduction in
fracture toughness due to thermal aging. The WCAP-
14575 identifies TLAAs as fatigue and leak-before-
break evaluations. That is the piping WCAP.
The next WCAP is reactor vessel internals,
and the reactor vessel internals are stainless steel
and nickel based alloys. The aging effects are
identified as reduction of fracture toughness due to
neutron irradiation of high neutron fluence
components.
And irradiation-assisted stress corrosion
cracking of high neutron fluence components; and the
irradiation creep of baffle/former and barrel/former
bolts.
A combination of stress relaxation and
high-cycle fatigue for preloaded components; and wear
of components that experience axial sliding and
components that constitute the interface between
structural components; and void swelling of high
neutron fluence components.
The WCAP for these aging effects, the
programs are four; for fracture toughness and
radiation stress corrosion, cracking, and void
swelling.
They take credit for the in-service
inspection of the ASME code, and the results from the
PWR materials reliability project. That is a program
that is going on now, and that is to develop
inspection criteria, and inspection methods, for these
aging effects.
And I think they also take credit for the
in-service inspection requirements of ASME Code,
Section XI, of accessible surfaces of PWR core support
structures, excluding the baffle/former, and
barrel/former bolts, to manage stress relaxation, and
wear of keys, inserts, and pins, or they want to take
credit for noise monitorings as a way for doing the
examination.
Ultrasonic and eddy current examination is
proposed per responses to I&ED Bulletin 88-09 to
manage the wear of the bottom mount instrument tube
flux thimbles.
And augmented ultrasonic examination is
recommended for baffle/former and barrel/former bolts
to manage the aging effects of these components.
And they would like to take credit for in-
service inspection requirements of ASME Code, Section
XI, as a fatigue management program. And then for the
internals, the only --
DR. ROSEN: Slow down.
DR. FORD: I have a question. What you
are doing is just recording what is in these various
documents.
MR. ELLIOT: Yes. Later on I am going to
tell you what we agree on and what we don't. I
haven't told you that yet.
DR. FORD: Oh, okay. Fine.
MR. ELLIOT: WCAP-14575 identifies fatigue
as a TLAA. And the next WCAP is the pressurizer, and
there is a whole list of a lot of different materials
and components in the pressurizer.
These are pretty interesting components.
It has got case and stainless steel, and in case they
have alloy steel bolts and alloy steel forgings; and
they also have Inconel 182/82, as well as stainless
steel in some components.
DR. SHACK: Is that a vintage thing, that
the early ones were done with stainless steel butters,
and then somebody decided to put some improvements in?
MR. ELLIOT: I don't know that much about
the design of Westinghouse. I know that some have --
in the case of Turkey Point, they have stainless steel
instead of the 82/182.
And there are some that have the 82/182.
It is a vintage question and I asked Westinghouse
that, and the answer was vintages, if they have an
answer.
DR. SHACK: And Framatome has always stuck
to stainless steel.
MR. ELLIOT: Right. But in the
pressurizer report, they have a list of which ones
have --
DR. SHACK: Oh, they do?
MR. ELLIOT: Yes. I saw that in the WCAP
when I read it. So in the WCAP, it has a list of
which ones have 82 and which have stainless steel.
And these are the materials. The aging
effects offer fatigue related cracking, and primary
water stress corrosion cracking of Inconel 82/182 weld
metal and sensitized stainless steel safe ends.
The WCAP takes to managing these aging
effects is the in-service inspection requirements to
ASME Code, Section XI, and a fatigue management
program to manage fatigue.
And then the in-service inspection
requirements of Section 11 to manage primary water
stress corrosion cracking of Inconel 82/182 weld
material, and sensitized stainless steel safe ends.
And then the TLAA -- the only TLAA is fatigue.
The last WCAP is the WCAP on reactor
coolant system supports, and we are talking about
steel components and concrete embedments
. The aging effects for these components
are loss of material and decrease of strength of steel
components resulting from aggressive chemical attach
and corrosion.
The loss of material and decrease of
strength of concrete embedments resulting from
aggressive chemical attach and corrosion. And then
stress corrosion cracking of bolting.
The aging program to manage these aging
effects are in-service inspection requirements of ASME
Code, Section XI, and leakage identification walkdowns
to manage aggressive chemical attach and corrosion for
steel components.
And then in-service inspection to American
Concrete Institute 349 Code, and leakage
identification walkdowns to manage aggressive chemical
attach and corrosion for concrete embedments.
In-service inspection requirements of ASME
Code, Section XI, to manage stress corrosion cracking
of bolting.
And the WCAP indicates that there were
plant specific action items; that the applicant must
identify program necessary to ensure proper preload is
maintained; and the applicant must address the effects
of irradiation on concrete components; and the
applicant must address inaccessible areas.
The only TLAA here was WCAP-14422, which
identified fatigue. That is what was in the summary
of what was in the application. I am not going to go
through with the entire staff evaluation, but just the
areas that I think are important.
The first one is the WCAP on Class I
piping and associated pressure boundary piping. We
set out applicant action items. We wanted the
applicant to evaluate the impact of halogens in
insulation on stress corrosion cracking of stainless
steel piping.
That is one of the things that was missing
and that we thought was not enough description of how
it was going to be done. So that is a plant specific
license application item.
We have guidance in that area, Reg Guide
1.36, for non-metallic thermal insulation for
stainless steel components. We also wanted them to
perform a volumetric inspection of small bore piping
that is susceptible to stress corrosion cracking or
unanticipated thermal fatigue resulting from thermal
stratification or turbulent penetration.
In the past, we have accepted both a
deterministic evaluation or a risk-informed evaluation
to identify the locations for the small bore
volumetric inspection. In the case of Turkey Point,
they did a risk-informed evaluation.
And the area we think it was needed was to
evaluate the susceptibility of cast stainless steel
piping to thermal embrittlement. Since the issue of
this particular WCAP, EPRI has put out a report which
highlights the criteria, and this criteria is based
upon Oregon test data, and the staff has reviewed the
EPRI document, and it is EPRI TR106092.
And in a letter dated May 19th of 2000
from Chris Grimes to EPRI, we have established
criteria now for evaluating all cast stainless steel
to thermal embrittlement.
And we want all the applicants to evaluate
their material using that criteria. Now, remember
that I talked about the TLAAs. We want them to
perform a plant specific fatigue evaluation.
We didn't accept the total methodology
that was in the WCAP. So this is a plant specific
action item. And then we wanted them to do a plant
specific leak-before-break analysis assessment to
assessment margins.
The criteria for this leak-before-break
analysis is contained in NUREG 10-61, and the TLAA
issue here is thermal embrittlement of cast stainless
steel.
DR. FORD: Okay. Barry, on the subsequent
ones, you have picked out some significant issues.
MR. ELLIOT: Right.
DR. FORD: What was the quantitative basis
for saying that those are significant?
MR. ELLIOT: It is the ones that I like to
talk about.
CHAIRMAN BONACA: But why did you choose
these?
MR. ELLIOT: Because there are some issues
in here that -- well, there are 10. I mean, I could
read all 10 of them, and you could read all 10 of
them, and I looked at all 10 of them and I said these
are the most significant ones to me.
Now, there are some that are most
significant. They are all significant or else they
wouldn't be in there. There are three that I consider
administrative, in the sense that you bound the
report, and do you have an FSAR, and there are a whole
bunch of those.
And then there is a couple that I thought
were less significant and so I didn't put them in
here. And you can go through the list just like I
can, and if you think there is one in here that you
want me to talk about, go right ahead.
DR. FORD: I recognize about the
procedural ones, but I have to put myself in the
position of being one of the utilities, whoever it
might be. And they have all these address this, that,
and what have you.
MR. ELLIOT: They have to address them
all.
DR. FORD: Well, they have restricted time
and manpower and how do they allocate that in terms of
prioritization?
MR. ELLIOT: They have to do all 10. They
have to do every single one. They have to answer
every single one. I am only doing 10 because I am
standing in front of you now here and I think these
are technical issues that I think that are pretty
important that I want to highlight for you. That's
why.
I just want to highlight the important
technical issues for this committee, and I could go
read them all, but that would not be highlighting
them. I want to highlight the important ones. I
think these are very important.
DR. FORD: And did you have a good reason
for highlighting them?
MR. ELLIOT: Yes.
CHAIRMAN BONACA: Are you telling the
licensee that the others are not important?
MR. ELLIOT: No, they are all important
and every one is significant, but these are the
highlighted ones.
DR. FORD: I hate to be pushing on this,
but it is one of the things that I am getting
frustrated about. I have yet to see any numbers in
any of these things, and I have yet to see a number or
a data point.
I haven't seen one data point in the five
months that I have been on this committee, and it is
frustrating. And I have no idea what the margin of
safety is, how much you can push that margin of safety
based on fact. I haven't seen it.
And that's why I asked you why do you think
quantitatively why these are important.
MR. ELLIOT: Because I don't want to see
halogens on the stainless steel components.
DR. FORD: Sure.
MR. ELLIOT: And I think that is an
important thing that the applicant should take care
of. I think that small bore piping -- I can't depend
upon a leak-before-break there. So I have got to have
something and I want to have some kind of inspection.
And the cast stainless steel, we have a
lot of data there, and we want to make sure that data
gets implemented as part of the aging management
programs.
DR. FORD: Let me ask another question.
When the staff reviews these LRAs do they in fact see
data?
MR. ELLIOT: We see programs. We only see
data if we ask for the data. We see programs, and we
see aging effects, and they have to meet the rule.
The licensee has three parts to meet in
the rule. They have to have a scoping to show that
all of the components are within scope. That the
plants are in scope, and they have to define the aging
effects, and they don't have to have quantities there.
They just have to postulate aging effects
based upon their experience on what aging effects are.
DR. FORD: I come from a different world,
but I fail to see how any regulatory body can make any
definitive statement unless you see data.
DR. SHACK: But he does. I mean, as he
said, the EPRI report is what he does the cast
stainless steel on. And they have reviewed the EPRI
report and accepted it, and it has got the data.
But they are saying is that the Turkey
Point people have to commit to using the data analysis
method to do it. They don't have to see the data over
and over again.
MR. ELLIOT: We have data for thermal and
brittle cast stainless steel. We know where it
saturates, and we set up criteria so that we know what
is susceptible and what is not susceptible.
We simplify it. We don't go and say go
tell us what is susceptible. We say use this criteria
here and tell us what is susceptible.
DR. SHACK: I suppose they could come back
in and argue with me.
MR. ELLIOT: They certainly could.
CHAIRMAN BONACA: I really think a couple
of things. One is clearly license renewal documents
at the end is nothing else but a series of management
commitments in the areas where a need for managing
aging effects have been identified.
Now, those commitments are then translated
into very specifics for reports about what kind of
techniques, what kind of locations, what kind of
issues, and so on and so forth.
So you can go down to the specifics in
each one of them, and it doesn't happen at this level
because those commitments are already in existing
topical reports, and in core licensing basis, and so
on and so forth.
However, I would say -- and we discussed
this briefly with some of you during the break -- it
is frustrating to a reviewer maybe when one looks at
an application or a self-evaluation report on a
license renewal.
And I thought that probably it would be
worthwhile to have in SERs like a 3 or 4 page
description of this logic of what really the intent of
the license renewal work is. It is the establishment
of commitments, and how that merges together with the
current CLB and commitments that exist.
Because I think that would provide some
explanation, and it could be almost like three pages,
a boiler plate description, that is used in front of
every SER so that the reader comes in and has an
understanding that the world doesn't start and end
here.
I think that there has to be some
explanation somewhere, because if you pick up the SER,
and you read it through, you don't get that kind of
feeling, and I know that we have gone with questions,
each one of us, to Mr. Grimes on how do you do this,
and he has explained it to us many times. So we are
slowly learning and appeasing our frustration I guess
that way.
But I think just the communication issue
of what the license renewal application is supposed to
do in addition to the core relicensing commitments.
DR. ROSEN: Let's talk about frustration
again. This is one of the things that you talked
about and this was brought up on the circumferential
weld, the 297 degrees.
And the answer was we got 56 degrees of
uncertainly or margin, and so to think about 56
degrees and added to 241, and you get your 297. That
sounds like a lot, but you really have to do an
absolute temperature before you realize if you are
going to do any kind of assessment like that.
So when you do it in absolute temperature
terms, it is really not that much. It is about 8
percent.
MR. ELLIOT: Well, the 56 is an
engineering number.
DR. ROSEN: Well, that is my frustration.
I have no clue how you got the 106 degrees as being
adequate as an uncertainty in this case.
MR. ELLIOT: We use the least squares
method of evaluation. We have two values that go into
it that, and we have the uncertainty in the initial RT
NDT, which is what you start from, and then we have an
uncertainty in the shift in reference temperature.
WE combine those two using the least
squares method, and we come up with a margin term.
That is how we develop it. If you read the preamble
to our safety evaluation, it describes all of that.
We describe that in the safety evaluation in that
section.
DR. ROSEN: But I don't see the data.
MR. ELLIOT: Excuse me, hold it. The data
was the data that we used to develop Reg Guide 1.99
Rev. 2. It is all the surveillance data that we have
accumulated to make that Reg Guide.
There is hundreds of data points. That
was originally reviewed I'm sure by the ACRS at one
time or another, and endorsed that Reg Guide, and that
margin term comes from that Reg Guide. So that is not
a license renewal issue. That was an issue of the Reg
Guide.
DR. ROSEN: I have not seen the data. You
see, I'm not bound by what the ACRS did in the past.
MR. ELLIOT: Well, if you already looked
at it, it is a Reg Guide, Reg Guide 1.99 Rev. 2, and
there is an analysis the staff did based on the data
to find out how in margin term what was to be
included.
DR. ROSEN: I can't conclude sitting here
without having done all of that, that because it is so
close to the screening criteria, that that amount of
margin that you built in is in fact soundly based.
What if I were to take it myself and do
the analysis over, and I got 65 degrees of margin
instead of 56. Then they would be over the screening
criteria. Then what would have happened? Tell me
what the next step would be.
MR. ELLIOT: If they were over the
screening criteria, the rules say what you have to do.
But in all likelihood they would not be sitting here
now.
DR. ROSEN: What is that that they would
have to do if they were over the screening criteria?
MR. ELLIOT: The Reg Guide says you have
to have a supplementary analysis to be done to show
that PTS is not a concern. There is a supplementary,
and you have to look at your plant specific PTS
events, and how you could mitigate those PTS events.
And you have to do a whole basic
probablistic fraction mechanics evaluation to show us
that you could meet the criteria. We have another
criteria, another Reg Guide, where we have established
a criteria that we would have to meet with this other
if they go over the screening criteria, and you could
argue with that.
But that was reviewed by the Commission,
and we put it on SECE 82-465, and if they meet that
criteria for a PTS event, failure frequency, we would
accept that.
DR. ROSEN: We have not done that many of
these little license renewals yet, Mario, but can you
help me understand how close the other people, the
other licensees, have been to the screening criteria
for the circumferential weld? Is this the closest one
we have seen?
CHAIRMAN BONACA: No, they are pretty
close.
MR. ELLIOT: I will answer that. Most of
them are not close. Oconee was very close. One of
the Oconee units --
DR. ROSEN: Most of them are not close?
MR. ELLIOT: Yes, most of them have not
been close. Oconee was very close. One of the Oconee
units was like 2 or 3 degrees. It was like this. It
was very close. It was not a circumferential. It was
an axial.
DR. ROSEN: You have to remember that the
300 degrees was set up by sort of a bounding analysis
for the PTS events. So it has the conservatism built
in. I mean, it is a probablistic fracture mechanics
analysis, but it is a bounding probablistic fracture
mechanics fracture analysis.
And what you would do when you hit the
screening criterion is to do a plant specific, and
Barry said probablistic fracture analysis. So there
really is a fair amount of margin built into the 300.
It was intended to be a bounding generic analysis.
CHAIRMAN BONACA: This is really a
screening criteria.
MR. ELLIOT: Yes, it is a screening
criteria on whether you have to do a plant specific
evaluation. That's all it is. It is a screening
criteria to determine whether or not you have to do a
plant specific evaluation.
If you are below the screening criteria,
we think that you have -- because of the way that we
set up the curve or the analysis, you have adequate
margin.
DR. DUDLEY: Now, would you have done that
for all of the licensees for 40 years?
MR. ELLIOT: That screening criteria that
I am talking about is done based upon fraction
mechanics and it is not done for any amount of years.
It is done or based upon fraction mechanics, and
postulated transients for BWRs.
This was a generic issue, and it was
resolved in SECE 82-465, and this is how we got to
this screening criteria. This was looked at for
years, and this is how we resolved it.
MS. THOMPSON: Barry, if I could add, I
believe that the methodology, the uncertainty terms,
the stipulation of what constitutes data that can be
used and so forth, is all under 50-61 if I am not
mistaken; 10 CFR 50-61 is it?
MR. ELLIOT: That is the rule that governs
the criteria, and what you do above the criteria.
MS. THOMPSON: It is quite explicit
actually in the process that we follow for analyzing
the data, and the staff typically does a confirmatory
analysis really to come up essentially with the same
values.
And if we were not able to meet the
screening criteria, then we would go through staff
review again for the subsequent analysis that would be
done, and basically those are really stipulated by
regulation at this point. I believe it is 50-61 if I
recall correctly.
MR. ELLIOT: And the staff has done the
review of their analysis?
MR. ELLIOT: We reviewed their PTS's in
accordance with 10 CFR 50.61, and they meet it, and
are satisfied that they are under the screening
criteria of 297.4. We wrote it up in the SER.
DR. SHACK: No, I think he is saying to
you do you check their calculations?
MR. ELLIOT: Yes, we check their
calculations.
MR. HALE: In fact, if you are interested,
we summarized all those calculations in the REI
response.
MS. THOMPSON: There is a specific REI on
this particular item, and typically --
DR. ROSEN: Could you give me a reference
to it? Not now, but later?
MS. THOMPSON: Yes, absolutely.
MR. ELLIOT: And the reviewer checks the
calculation. I want you to understand that we just
don't say to you -- well, this is not a hard
calculation. For our reviewers, this is what we do.
We check out calculations.
This is a very important issue for us, and
so we don't want them to go over the screening
criteria. So we check that. We have to check the
pressure limits and that requires an embrittlement
calculation. We check that.
Upper shelf energy evaluations, and if it
says above 50 foot pounds -- and in this case it
doesn't matter because they are below it.
But if a plant says they are above 50 foot pounds, we
check it. We get to check their margin calculation if
it is below 50 foot pounds.
DR. SHACK: Right.
DR. ROSEN: And here again I presume that
one of the parameters in this regulation, in the Reg
Guide and database, is fluence?
MR. ELLIOT: Yes, definitely. Our Reg
Guide for radiation transition temperature shift is a
function of neutron fluence, and the amount of copper,
and the amount of nickel.
DR. ROSEN: So if any of those shift by
any amount --
MR. ELLIOT: Well, cooper and nickel
should not shift. That is what they fabricated it
with.
CHAIRMAN BONACA: But fluence can change?
MR. ELLIOT: Built into the rule is a
stipulating that if you change the basis design of the
core so that the neutron fluence changes
significantly, they have got to come back and tell us
the recalculation all over again.
It is built into the rule. It even
specifies the accuracy to which they have to calculate
the fluence.
CHAIRMAN BONACA: Right.
DR. SHACK: But the copper and nickel --
MR. ELLIOT: Well, the copper and nickel
is another issue. The copper and nickel was a problem
for a long time, and we put out a generic letter, 92-
01, and then we put out a 92-01 supplement, and then
I think we now have it pretty good.
We know that copper and nickel for all the
vessels in the United States, and that data is in the
reactor vessel integrity database, and it is on the
NRC home page. Well, not home page, but one of those
things, and you can get to it.
DR. ROSEN: So let me understand this. If
this number had been submitted by the applicant as
299.4 instead of 297.4, it would have said the same?
MR. ELLIOT: That's right.
DR. ROSEN: And if he had said it was
299.9, it would have said the same thing?
MR. ELLIOT: No, we have to calculate it,
recalculate it at 299.9.
DR. ROSEN: And they were okay.
DR. SHACK: It is just like ASME code
calculation. If the allowable stress is 50 KSI, and
you come in at 14.9, you are golden. If you come in
at 15.1, you have a problem.
CHAIRMAN BONACA: Well, the screenings say
you have to do specific calculations.
DR. ROSEN: Well, we have specific numbers
that people have to hit all the time, and there are
various rules and codes, and we have essentially built
the margins into those acceptability limits.
I mean, that is the real secret. Nobody
believes that you calculate the numbers that
accurately, but you have put the margin into the
acceptance limit. And I got a little excited when I
saw numbers, Peter, and then I said, wait a minute, I
must have read that wrong.
MR. ELLIOT: This is one of the areas
where we actually have numbers.
DR. ROSEN: But then I realized very
quickly that I didn't have any numbers. I just had
answers. I didn't have any rationale for them.
DR. DUDLEY: On NUREG 15.11, that has a
database in it?
MR. ELLIOT: No, it doesn't This is not
the database. NUREG 15.11 is the status report. That
is the status report on all the reactor vessels in the
United States with respect to upper shelf energy, and
PTS.
The actual database -- no, that's not it.
The database is controlled -- I have to go to Oak
Ridge. Oak Ridge has the entire database. And by the
way, they are looking at whether or not they should
revise all of this. This is all commercial reactive
data that was in 1982.
DR. ROSEN: What if they revise all of
this and now the database only supports 295?
MR. ELLIOT: Then we have a lot of plants
that are going to have to do something.
DR. DUDLEY: There is an ongoing research
project in the Office of Research where they are
reevaluating the PTS screening criteria.
MR. ELLIOT: That's right.
DR. DUDLEY: And they are attempting to
identify all the uncertainties of the numbers that go
into the calculation, and the assumptions for the
scenarios that would get you into the PTS event, and
wrap those into a single program which comes out with
a probability of reactor vessel failure, and the
associated uncertainties.
DR. ROSEN: But look at the margins for
lower shelf and intermediate shelf. It is Unit 4 to
use the worst case at Turkey Point, and under the best
case Turkey Point is 64.7 degrees on the lower shelf,
and it has a screening criteria of 270 degrees. You
have an enormous amount of margin.
MR. ELLIOT: Right, because it has very
little copper.
DR. ROSEN: But then when you go to the
circumferential weld, it is this tiny little thing.
DR. SHACK: It wasn't a good idea to add
copper to the weld.
CHAIRMAN BONACA: But if you look at the
technical foundation of the criteria used to make the
judgment, you get comfortable about the conservatism
built into the calculation. I mean, the confidence
level of the vessel ability to withstand the PTS, this
big transient, given that criteria, it is so high.
MR. ELLIOT: Well, it is very low. The
failure probability is low.
DR. ROSEN: Well, I am way out of my depth
in materials and metallurgy. That's where I rely on
Dr. Ford to have the requisite level of confidence.
CHAIRMAN BONACA: Well, if you take any
one of those bullets there and you go to the
references that support the application, you will find
a lot of numbers.
In fact, you lose yourself into those, and
then soon enough you commit suicide probably if you
want to read them all because there is so much there.
So there is plenty of technical information.
DR. ROSEN: But, Mario, my sense of this
application is that there is a very broad degree of
conservatism and good engineering practice, and
prudence in this application.
In this one area, it looks like it skins
right up against the criteria. It as close as one
could go realistically, without having to do a whole
lot of different things.
CHAIRMAN BONACA: But you have to look at
it and it is not intended to be my judgment of fail
safe criteria. This actually is a determination of
whether or not you do some more homework or not.
DR. ROSEN: And so if you wanted to be
conservative, and if you were, for example, at a
national laboratory, one could say that we did it at
this calculation and it comes out to 297.4, and that
is pretty close to the screening criteria, and so we
are going to do a plant specific analysis in addition
and submit it, just so you get a sense of what the
real answer is.
MR. ELLIOT: Well, we already did that,
and that's how we got the 300. That's how we did
that. We did a lot of probability studies on
transients and fracture mechanics evaluation, and that
is how we got the 300 and the 270 screening criteria.
DR. DUDLEY: And as I remember, your
margin criteria was based on the relationship to the
event being less than 10 to the minus 6th probability.
MR. ELLIOT: Well, less than 10 to the
minus 6th was the probability of failure we were
looking for of the vessel, and then we threw that --
the mean value came out to be like 210 or something
like that for all the studies.
And so we threw the 56 in and it came to
260, and then we had another study for the
circumferentials and that is how we did it. This had
a tremendous database of analysis to get the screening
criteria.
And the analysis had margins in it to get
to the 5 times 10 to the minus 6 failure probability,
and that's how we got the screening criteria.
DR. SHACK: Putting it into PRA terms,
think of it as the difference between the containment
design pressure and the containment failure pressure.
CHAIRMAN BONACA: Yes, I would say that
there is even more margin there.
DR. SHACK: And in fact a lot of times you
will end up with a containment design pressure, like
60, and you hit 59.7, and the main steam line break or
large break --
DR. ROSEN: In some plants, you hit 36.
DR. SHACK: They still breathe easy when
they hit 59.7.
DR. ROSEN: SECE 82.465 has got the
background on how to select this circumferential weld
for screening.
MR. ELLIOT: No, that is the background
for the PTS rule. If you want to know how to do the
calculation, it is Regulatory Guide 1.99 Rev. 2. But
it is also in the rule. And Reg Guide 1.99 Rev. 2 has
also been implemented into the rule itself, which is
10 CFR 50.61.
DR. FORD: All right. Can we get back to
Turkey Point? On the 11 renewal applicant action
items, I recognize that the old REIs was done before
this came out as I understand it.
Looking back on it do you think that the
REIs took into account those 11 action items? I think
Al said there had been some REIs on many of those
items; is that correct?
MR. ELLIOT: Yes. The applicant responded
to these items, and I looked it up because I wanted to
make sure, is Turkey Point SER, Section 3.2.5.2, has
a discussion on the applicant action items for the
reactor vessel internals.
CHAIRMAN BONACA: What section is that?
MR. ELLIOT: SER Section 3.2.5.2, and that
is for the internals.
MR. HALE: The REI response letter was
L2000176, and it was REI 3.2.5-4, and all 11 applicant
action items are in that response.
DR. DUDLEY: Could you provide us with a
copy of that?
MR. ELLIOT: Of what?
DR. DUDLEY: Of the REI response?
MR. ELLIOT: I can get you a copy.
DR. SHACK: I have a question. Will all
of those be on a CD some day with the application?
DR. SHACK: Does anybody know?
MR. KOENICK: No, there is no requirement
to update the application once we grant the license.
DR. SHACK: So anybody in the public who
wanted to do this would have to track them down
through ADAMS?
CHAIRMAN BONACA: Or call and get a copy.
MR. ELLIOT: All right. Continuing on.
There were 11 renewal action items for the reactor
vessel internals WCAP. I highlighted four of them
here.
We want to evaluate the synergistic
effects of thermal aging and neutron embriddlement on
fracture toughness of cast austenitic stainless steel.
The staff's issue on this -- and we have talked to you
in the past about this, is that we want them to
identify the limiting locations for inspection, and
then utilized information from the MRP program on
reactor vessel internal identify the inspection
methods and the criteria.
That is our position, and that is also the
same position we have for avoid swelling, cracking,
and loss of fracture toughness. And another issue
that we would like to address on a plant specific
basis was their baffle/former and baffle bolting page
degradation.
The staff's position here is volumetric
inspection of the junction of the bolt heads of the
shank is the important place to look for cracks.
Visual inspection won't be adequate and you need a
volumetric, and MRP is developing an industry program
for this issue.
And then as far as the internals, we need
a plant specific to achieve evaluation. For the
pressurizer, there were 10 renewal applicant action
items, and I highlighted only two of them here.
Perform plant specific fatigue evaluation,
including insurges and outsurges and other transient
lows not included in the current licensing basis.
And then evaluate the potential for
bolting to develop stress corrosion cracking. Our
position here is that bolting is susceptible to stress
corrosion cracking when the bolting is fabricated,
producing a yield stress graded at 150 KSI.
And whether there is excessive torquing of
the bolts, an introduction of contaminants and
lubricants.
CHAIRMAN BONACA: And then for Turkey
Point, you have accepted.
MR. ELLIOT: Yes. They claim that they
have procedures to prevent excessive torquing, and
they control their lubricants, and that is the basis
for our accepting the bolting.
CHAIRMAN BONACA: That's right.
MR. ELLIOT: And then there are 16 renewal
applicant action items for the reactor vessel
supports. I didn't highlight anything here. If there
is something that you would like to talk about, we
have people who did the review here. Are there any
issues that you would like to highlight?
CHAIRMAN BONACA: Well, the top bullet
under pressurizer, that is actually counting -- I
mean, looking at actual transients, right?
MR. ELLIOT: Yes, actual transients.
Mark, and then John, did the fatigue part of the
evaluation.
MR. FAIR: Yes. This is John Fair with
the Mechanical Engineering Branch. What they have
done on Turkey Point is that they have a fatigue
monitoring program, and what they are monitoring is
that the design transients that they assumed in the
original analysis do not get exceeded in the period of
extended operations. So they did not go back and
recalculate anything.
MR. ELLIOT: And our conclusion is that
upon completion of all renewal applicant action items
the license renewal applicants who reference the WOG
reports adequately demonstrate that the aging of the
components within the scope of the WOG report can be
managed so that there is a reasonable assurance that
the components will perform their intended function in
accordance with the current licensing basis during the
period of extended operation. That is our finding for
license renewal.
DR. ROSEN: What are these 16 renewal
applicant action items? Are they administrative kinds
of things?
MR. ELLIOT: No.
DR. ROSEN: Will you characterize them for
me?
MR. ELLIOT: There are technical issues
that we want them to address when they submit an aging
management program for a reactor coolant support over
and above what is in the WCAP.
DR. ROSEN: Could you pull an example out
for me? What are we talking about here?
MR. ELLIOT: Well, we have a lot of them.
We have had the 10 here and the 16 there, and 12
there, and so on.
DR. ROSEN: I am trying to get a sense if
these are overwhelming issues?
MR. ELLIOT: No, I don't think they are
overwhelming. We have reports here. Hai Bo here is
the reviewer of the WCAP and wrote the action items.
So he can give you some insight.
DR. ROSEN: And I had the pleasure of
reading it as well.
MR. WANG: My name is Hai Bo Wang from the
License Renewal Branch. I reviewed the WCAP, but I
didn't review the application from Turkey Point. What
Turkey Point did, I don't know.
The original draft SER had nine action
items, and six open items, and my concern was
generated to all the work numbers. And we converted
all the open items to action items as well.
For instance, the WCAP has pictures for
all the components support reactor vessel, and we have
five reactor vessel support configurations.
DR. ROSEN: Now, Hai Bo, what you are
talking about is your review of the WCAP?
MR. WANG: Yes.
DR. ROSEN: But my question was what are
the 16 renewal applicant action items relative to that
WCAP for Turkey Point?
MR. WANG: Well, I have no idea what the
renewal action items do. I did not read the Turkey
Point application.
MR. HALE: The reactor coolant supports,
we had a draft SER at the time that we submitted the
application. So we summarized how Turkey Point
addressed the open items and applicant action items,
all 15 I guess, in the application for that one,
because we had a draft SER.
So you will find that in the tables in
Chapter 2.
DR. ROSEN: So I look at Chapter 2 of your
application, and I find those action items, and what
you are just saying, Barry, in this slide --
MR. ELLIOT: I am telling you what my
review of the WCAP is. This is a slide that says that
we reviewed the WCAP and this is what we found. It
has nothing to do with Turkey Point.
DR. ROSEN: Then Hibo is telling me about
these things, about one action item.
MR. ELLIOT: And there are about 14 or 15
action items. They are not all like that. There was
one issue that I looked up, and there is an issue on
strain aging on there. There are other issues, and
you just have to look at them.
The reviewer looked at issues, and said
these are issues that I don't see you answered in this
WCAP.
DR. ROSEN: And FPL has answered them in
the application.
MR. ELLIOT: Right.
DR. ROSEN: And those 16 applicant action
items are not open items?
MR. ELLIOT: Right. We are satisfied with
their answer.
DR. ROSEN: And specific ones that Barry
was saying, you know, that Westinghouse identified
temporal embriddlement and strain aging as two of the
degradation mechanisms that could affect the support.
They ruled out temporal embriddlement on
a generic basis because the temperatures were too
high, and the applicant had to address whether a
strain aging could affect his reactor supports.
MR. WANG: But in the WCAP, they never
mentioned -- they didn't say nothing about strain
aging.
MR. ELLIOT: So this whole thing here is
the staff's review of the WCAP and our evaluation of
the WCAP, and where we think the applicant must
supplement the information in the WCAP.
And they have supplemented it, and we have
reviewed it, and not only that, we have reviewed their
reactor coolant system support as part of some
program, and found it acceptable, and that's what you
heard this morning.
DR. ROSEN: Well, the supports were
reviewed when the plant was licensed, I assume?
MR. ELLIOT: No, they were reviewed as
part of the license renewal, all within the scope of
license renewal. So they had to be reviewed for their
aging effects, and for their aging management
programs.
MS. THOMPSON: I would like to just
emphasize that for Turkey Point that we did not
incorporate by reference these particular generic
technical reports.
We simply addressed -- we performed our
own aging management reviews, and provided that
information in the application, and then these reviews
were in process at the time.
So as part of our application, we tried to
anticipate questions that may come from the staff, and
we addressed those open items or applicant action
items that were available to us at the time in our
application, really in anticipation of potential
questions from the staff.
And for those that were not on the table
at the time that we submitted, we addressed those
through REIs. But our aging management review really
stands on its own merits, and has been reviewed by the
staff.
CHAIRMAN BONACA: Let me say if you had to
perform the application today, you would take all nine
items on the pressurizer, and address them
individually, just as you did in this table here.
2.3.3., and have a total correspondence between the
topical report that supports it and the application.
MS. THOMPSON: Yes.
CHAIRMAN BONACA: So there was that kind
of mishmash, and it was because you didn't have
available all those questions at that time.
MR. ELLIOT: We are finished.
CHAIRMAN BONACA: All right. Why don't we
take a break right now, and then come back at 3:15 and
talk about the application. I think we have to talk
briefly about Westinghouse Topical Reports and our
judgment, and we had specific reviewers assigned to
some of them. So let's take a break right now.
(Whereupon, at 3:05 p.m., the meeting was
recessed, and was resumed at 3:25 p.m.)
CHAIRMAN BONACA: Okay. The meeting is
called back to order, and what we need to do now is
two things. One, to go around the table for the
members of the subcommittee and provide their views,
if there is any additional view in additional to what
they already provided regarding, first, the Turkey
Point application.
And then separately we will talk about the
WOG documents, and again provide views on those. Once
we have done those two things, we will talk about what
we are going to do, and the issue is this application
was pretty clear, and pretty thorough.
We have seen four open items, of which
really only one it seems to me is a true open item.
It is very likely that they are closed in the very
short term. In the past, when we had situations like
this, we did not write an interim letter.
And when the final SER came weeks or just
a couple of months after the interim SER, and so we
pointed out to the Commission that we in fact did not
write an interim letter because of that reason.
And we would then write a letter when the
final SER comes to us. And then we will discuss that,
and then at that point we will talk also about whether
or not we need to write a separate letter on the WOG
documents, considering that the application from
Florida Power did not include reliance or reference to
those documents.
And those documents may not be used by
other applicants in the future because they may use
simply our report. So we will decide on all these
things, and let's go around the table, first of all,
regarding the applications from Florida Power for
Turkey Point.
I would like to have your views and
anything new that you may have to what you have
already provided with your question and answers.
DR. ROSEN: Well, I have nothing in
addition to those, although I would just like to kick
them off to make sure that we know what the points are
that I think were interesting or important.
First, of course, is the question of the
proximity of the calculated RT PTS to the screening
criteria, and how we handle that, or if we handle that
in the letter, or even in discussion with the
committee, or if the committee chooses to make any
kind of reference to that to the commission, I don't
know.
That is all to be determined, but at least
that is a subject matter from my point of view. The
other thing that I thought was interesting is that in
talking to the staff and thinking about the large term
nature of license renewal, and the need to retain the
corporate knowledge of the applicant, and the fact
that the staff had not looked into the engineering
support personnel training program with regard to
license renewal, was sort of illuminating to me.
Now, the licensee did clearly in their
remarks, they said that they had dealt with that, and
I think probably what they are doing is appropriate.
But the staff hadn't tumbled to that, and I rather
think INPO hasn't.
If you go all the way back to the INPO
documents, and I used to know their numbers, but I
have forgotten them now, that define the requirements
for engineering support personnel training programs,
I will bet you that there is not much about license
renewal in them.
So if we can successfully do something to
help that get embedded in the industry's training
programs for engineers, that will be good for
everybody.
Another point that I made and followed up
a little bit on in the discussions was the fact that
I didn't get a lot of clarity in how equipment used in
the emergency operating procedures, and the emergency
review guidelines was in fact covered by the staff, in
terms of proper scoping and screening, and aging
management reviews. Maybe it is because it went by
too fast, but --
CHAIRMAN BONACA: You mean the use of
ERGs?
DR. ROSEN: ERGs and the daughter, EOPs,
that come from the ERGs, and whenever you put
something in an EOP, an operator is going to look at
this during this severe accident, and you need to
think about is that thing that he is going to look at,
is it in scope?
CHAIRMAN BONACA: You have to realize that
the EOPs and ERGs is an issue that we raised, and
specifically the staff had put in their reference to
the scoping process EOPs as a document to check for
additional information, although by the license
renewal rule it is not in scope really specifically.
DR. ROSEN: Why is that? I don't
understand why it is not in scope.
CHAIRMAN BONACA: And the NEI agreed to
that, and then NEI agreed and they put it as a
reference in their reference attachment in the NEI
document.
Now, we also recommended that severe
accident guidelines be included as a reference
document, and the staff endorsed that, and NEI did not
as far as I can tell, because they feel it is a
voluntary program and that kind of stuff.
DR. ROSEN: You mean SAMSA is voluntary,
but license renewal is not voluntary. I mean, it is
voluntary on their part, but the staff doesn't have to
grant it.
CHAIRMAN BONACA: Well, the EOPs, they
have agreed to look into this, and so I don't know.
We may ask them to address this issue with them next
week during the full committee meeting, and just
simply tell us how they look at them.
DR. SHACK: I thought the commitment that
we got from the staff today was probably as much as we
could get without changing the rules. If you really
want it to define that part of the scope, then I think
you almost have to change the rule.
And it sounds to me like they were sort of
doing the best that they could and whatever arm
twisting --
DR. ROSEN: The staff has to do that, but
we don't have to. We can comment to the Commission on
that.
DR. SHACK: Well, we can comment, and I
think we said that we didn't need a rule change.
DR. ROSEN: And I think that we probably
don't.
CHAIRMAN BONACA: Especially if you take
the Westinghouse ERGs. I mean, they go far from your
design basis. I mean, they look at the possibility of
all kinds of scenarios. So that is an issue that we
have to tackle.
DR. ROSEN: But I have this pristine
clarity and insight that comes from not being involved
so much, and it seems to me that things an operator
might rely on during a severe accident late in the
life of a plant, the 58th year, what a work, and we
ought to have a lot of confidence in all of this.
That's all I am saying.
CHAIRMAN BONACA: And we wrote two letters
in which we put our position and recommendations to
the Commission, and they were endorsed, but endorsed
that these documents would be guidance that they would
look at, and not endorsed as a change to the rule to
explicitly incorporate those documents. So it would
be important to understand how the staff is using them
at all.
DR. ROSEN: Well, you asked me what I
thought after listening to the subcommittee.
CHAIRMAN BONACA: Well, actually, you are
picking things up fast. You already have covered two
past letters in a row with that issue, because we
really brought it out.
DR. ROSEN: So those are the three things.
CHAIRMAN BONACA: Great. Thank you.
Going around the table. Peter.
DR. FORD: I just feel myself capable of
answering the questions about degradation loads. I
liked the Turkey Point LRA, and I think that the staff
identified all of those EOPs that required modifying,
et cetera.
So I don't doubt that the regulations will
be met, which is all that is required at this stage.
My big problem, however, is that I have not seen any
data that addresses the kinetics of that degradation.
And that impacts on two broader issues
which is outside the Turkey Point application, and
that is the validity of once only inspections. The
phenomena that we had identified on the inspections at
Turkey Point, they are defensible.
But for the ones that require multiple
inspections -- internals and the other phenomena --
they depend very much on the accuracy and the
completeness of the various disposition relationships.
That is, degradation versus time, et cetera.
And unfortunately the data that we have in
the industry as a whole you increasingly find, and
especially as far as cracking is concerned, is not
adequate, and is of poor quality, and sometimes
irrelevant.
And that is more of an industry problem,
and it is completely outside the Turkey Point
application, and is something that industry is going
to have to tackle.
CHAIRMAN BONACA: Yes, that issue would
truly be affecting also aging in the current licensing
area.
DR. FORD: Absolutely.
CHAIRMAN BONACA: Okay. Bill.
DR. SHACK: I thought that this was a good
license renewal application, and I liked the table
format. I thought that the electronic version was
quite useful.
And I am not sure that there is any way to
get around the thing, but there is a certain amount of
jumping. You think they are talking about the reactor
vessel head penetration here in this section, but it
is really just mentioned here and it is discussed over
there.
And you are about to conclude that the
discussion is totally inadequate until you realize
that you are looking in the wrong place.
DR. ROSEN: You pop the hyerlink and --
DR. SHACK: And on the electronic version,
you pop the hyperlink and you get to the right place.
And in the paper version, you kind of look
and say, oh, my god, and you are getting ready to send
off a nasty-o-gram, and you stumble on the real
discussion somewhere else. And I think that is
inevitable in something as large and as massive as
these things.
The only technical quibble I had was with
this thing on the VT1, and again, I think we have
discussed with the BWR VIP that you really need
enhanced inspections to IASCC or SCC, and although I
don't see a problem here because they have got the
ultrasonic for the baffle bolts --
CHAIRMAN BONACA: This is the one for
cracks?
DR. SHACK: Yes, cracks in the internals.
CHAIRMAN BONACA: And concerning the SER.
DR. SHACK: Yes, and if the SER said we
didn't like this, but it is okay, then I could buy
that. But when the SER sort of implies that this is
fine and dandy, I am less happy.
CHAIRMAN BONACA: And that is probably
something we will mention in the letter, and as a
minimum, was a note that we don't believe that --
DR. SHACK: Well, the staff doesn't
either. I mean, any time they are really serious
about it, they have asked for enhanced VT1.
CHAIRMAN BONACA: Any other comments? All
right. I reviewed this and clearly in the perspective
of the others, it was a good application.
I mean, for me, it was visibly easy to
follow, and I liked some of those tables that allow
you to see under 5 or 6 columns, and the component,
and whether it is in scope, and the environmental
conditions, and the aging effects, and the function.
And for an interested person that wants to
look at it -- and I don't know who would be interested
outside, but still that could be -- that would be a
useful format.
And I thought that it was quite complete,
and I thought that the scoping was effective. In
fact, I found in some cases that the scoping went
beyond what I had seen before. For example, the spent
fuel pool.
There was an effort to define the
functions that were complete and covered more ground
than other applicants had done before in my judgment.
The screening was also appropriate, and I
think the definition of functions was quite thorough.
I thought the discussion of environment and aging, or
aging effects was good also. I thought the programs
were significant.
And again the points that Peter made as to
that were absolutely valid, and that really speaks of
how currently we operate these plants. So it is true
also for this operating plant.
I agree with the findings of the staff.
I think that of the four open items that only one is
an open item truly. It still troubles me that it is
a repeat. I think that it probably in-part is tied to
the licensing basis of the specific plant, and how
they define things, and is probably beyond my
understanding right now of why it is a repeat issue
that comes again.
But in general I thought it was a good
application. I do believe again that this power plant
in my judgment is a better plant now because it has a
detailed series of commitments and an analysis of this
type.
And that's why I think it is so important
about the point that Steve was making before, that the
plant is trying to train the personnel to understand
what they have, and the commitments that they have,
and what they have learned from it. This is important
for everybody concerned.
So before we talk about the WOG reports,
we had a situation before where we reviewed an SER and
found that it was completely readable and we
understood it, and also the application we understood,
and we had very few open items.
And we made a decision then not to write
a letter, and the reason is that we got the final SER
in no time after that, and so we just simply wrote a
letter for the final SER.
And we have a choice right now. We can
choose to do the same for this application, or to
simply write a full report next week. I would like to
hear from you guys on what you would like to do.
DR. ROSEN: Well, let me ask you a
question in-turn. What is the timing for the final
SER? They said they were moving it up, and working
with the staff now to try to --
CHAIRMAN BONACA: The earliest is
December, or in January, and we would be writing a
letter in the February or March time frame.
DR. ROSEN: That is the schedule we
anticipated. It says May now, right?
MS. THOMPSON: We have asked the staff to
look at a March of next year decision point for our
renewed license.
DR. ROSEN: So that would be February, and
our letter would be at least a month before that, and
so we are talking about writing something now in
October, and we might have another letter in March.
CHAIRMAN BONACA: Well, the value of an
interim letter has always been that if we had
something that we wanted to communicate -- like, for
example, we don't like something, or you should do
something else.
DR. ROSEN: Well, specific to this
license, and we want to communicate something in
general, or generic, yes; but if we had something
specific to this license --
CHAIRMAN BONACA: Well, I don't think we
do very much. So my recommendation would be to go to
the full committee and tell them that we are not going
to write a letter at this time, and the most we could
do would be to send a very brief note saying that we
have chosen not to write a letter because of the
quality of the application and a few open items.
DR. ROSEN: I think that would be better,
is to write a brief letter that says that, but also
says some things like in our letter which we expect in
the first quarter of 2002, we may have some comments
about or that could lead to general improvements that
came up during the review of the Turkey Point
application that could lead to some generic
improvements in the process, or something like that.
DR. DUDLEY: Just from the staff's
viewpoint, I would rather leave that as an option of
something that we can do, because as soon as we put it
in writing to the EDO or the Comission, it almost
becomes a have to do.
CHAIRMAN BONACA: Yes. Well, my
suggestion is that we don't write a letter.
DR. ROSEN: Okay.
CHAIRMAN BONACA: And then we will decide
if we write a brief piece of information, or as we did
for Arkansas when I wrote the letter for that, we
chose not to write a letter and because, and we
pointed out the reasons.
DR. ROSEN: And were the reasons technical
or logistical. In this case, they are logistical.
CHAIRMAN BONACA: It was mostly for
Arkansas that we felt that the application was very
good, and complete, and were very few open items.
DR. ROSEN: Isn't that where we are here?
DR. SHACK: Yes.
DR. ROSEN: So we would say the same thing
in this case. We would write a letter that says the
applicant's application is very good, complete, and
there are a few open items, and we expect a final
letter very shortly.
CHAIRMAN BONACA: Well, no. Noel has said
no, and --
DR. ROSEN: Well, I think we should write
a letter and it should be a brief one.
CHAIRMAN BONACA: Well, we will talk about
it next week with the full committee. We will bring
it up and decide.
DR. ROSEN: Well, notwithstanding Noel's
comment to the contrary, I think I would signal the
fact that it is a learning process for us as well, and
as part of this discussion that we have perhaps found
some things that we could lay on the table that could
either help the staff in the way they review
applications, or the applicants and in the way they
put them together.
CHAIRMAN BONACA: Okay. So, we will bring
that recommendation up to the committee, and the
committee may decide to do something otherwise. Now,
the second issue is the Westinghouse Owners Group
Reports.
We have specific assignments on those
reports, and I can speak about the pressurizer one,
and I reviewed it in detail, and I felt that it was a
good report in several ways. One was a description of
all the types of pressurizers that are in the
Westinghouse family.
And I think that was quite descriptive of
components, and the environment, and the face, and the
materials, and really had a form that was a typical
license renewal form all the way through.
I liked very much the form where we got
together the WOG report with the SER in front of it,
and the SER specifically listed in the back portion
the renewal applicant's action items. It was very
explicit.
And there was a linkage between those and
what the WOG said. So the WOG said only three action
items for the individual licensees, and the staff
said, no, we disagree with that. We have nine action
items, and they put them forth clearly.
And I liked the fact that in the back
there was a full listing for the request for
additional information and answers to those. So
within the report, I believe there was a full feeling
for the interaction that took place between the WOG,
the staff, and the conclusions.
And that when I looked at this document,
and I looked at how it is being used to support
something like Turkey Point, especially Turkey Point
by relying on it and including it for reference, I
thought it would be very well supported, in the sense
that it becomes like an integral part of that.
So I thought it was a good document. I
could not pass judgment on every single aging effects.
I am not an expert on materials so that I could do
that, but it seemed reasonable based on what I have
seen in the GALL report before.
DR. SHACK: Except for that confusing
section in the pressurizer where they talk about the
erosion of stainless steel components, and then sort
of in the next sentence decides that it is really not,
and I can't figure out the logic, although I agree
with the conclusions.
CHAIRMAN BONACA: This is the issue where
the staff felt there was confusion?
DR. SHACK: Right, the staff felt it was
confusing, and I was confused.
CHAIRMAN BONACA: Well, I thought that I
understood what they were saying or where they were
going.
DR. SHACK: Well, I understood where they
got to, but what I didn't understand is how they got
there. But that's okay.
CHAIRMAN BONACA: That's interesting that
you are bringing that up, because I thought it was the
staff.
DR. SHACK: It is on page 55.
CHAIRMAN BONACA: All right.
DR. SHACK: They have the potential to
cause erosion, and then the next sentence says only
one component is considered to have flow conditions
that have the potential for erosion. So the next
sentence contradicts the previous sentence. But the
conclusion, when it is all said and done, is something
that I would agree with.
CHAIRMAN BONACA: And at the bottom it
says that only one is considered to have flow
conditions that have the potential for erosion.
DR. SHACK: They all have it and then it
says only one has it.
CHAIRMAN BONACA: Because only one has the
flow condition that could justify erosion. The others
are not faced by that flow condition.
DR. SHACK: And several are exposed to
fluid flows that have the potential for causing
erosion. If you understand it, that's fine, because
I am a bit confused.
CHAIRMAN BONACA: Well, anyway, that was
my feedback on the pressurized items. And now the
other reports.
DR. SHACK: Well, I looked at the pressure
boundary, and I thought they were good reports, and as
you said, I really like this format where we get
everything. And that is the usual difficulty here, is
that the REIs are off somewhere in ADAMS, and all you
see are references to REI 3.5.4.2., and you have no
idea what is in there.
CHAIRMAN BONACA: That's right.
DR. SHACK: Now, I was a little puzzled by
some of the things that seemed to be open issues here,
and then Barry clarified that by saying that I had not
quite appreciated just the time frame that this was
all done.
CHAIRMAN BONACA: Yes.
DR. SHACK: And no doubt that things would
be a little different if they were doing them after
the benefit of a couple of license renewals. But I
think they will turn out to be quite useful, although
as I said, maybe GALL is even a better way to
reference things, but this is still a very useful
overall technical package.
DR. FORD: Okay. I did the reactor
internals. I also liked the report. I have a few
comments that I liked. For instance, the general
layout, and the fact that Table 2.2 clearly listed
those parts and subcomponents needing aging management
reviews.
I disagree that the hold down springs, for
instance, don't need a review, but maybe there is a
good regulatory reason for that. But that is a minor
item.
I would also disagree with the fact that
on page 4.1 that cracking and material degradation due
to corrosion and stress corrosion cracking is
insignificant. That was written before the Oconee
incident, and I assume that would no longer be a
believable statement.
And I am assuming that no one would take
that as the gospel at this time. And I particularly
liked the fact that this would be used as template.
I liked the Tables 4.1 through 4.8, which lay out the
criteria that should be covered in an aging management
program attributes.
They were clear and gave examples for the
various components or phenomena -- radiation, stress
corrosion cracking, et cetera, and which obviously
would be plant specific.
And as I stated before, even though
someone said there is data in here, there is not one
data point in this whole report. I would love to see
some supporting data in any aging management program
that would support what the margin is, and how this
program is going to ensure within that project. But
the report I liked very much.
CHAIRMAN BONACA: But I am sure that the
report must have referenced some activities.
DR. FORD: Oh, it does, and the report
gives a lot of --
CHAIRMAN BONACA: It has to be planned on
existing activities.
DR. FORD: Absolutely. >From a
readability point of view, we have a million-and-one
documents pushed in front of us. It would be nice to
see, if only two pages, the state of the art, with a
couple of graphs in there showing where the data
relates to the disposition curves if you are going to
use that for an ASME Section XI inspection.
But these sure give the idea that there
are some data to back up these inspection results
which are being given in these Tables 4.1 through 4.8.
CHAIRMAN BONACA: So we covered the
pressurizer, and the internals, and you reviewed which
one, Bill?
DR. SHACK: The boundary components and
supports?
DR. ROSEN: Yes. I thought this was an
excellent document. It has these pictures in it of
the support and pictures of the various support
configurations. This happens to be one of the best
ones, but this is a steam generated support
configuration four, and reactor coolant pumps support
configuration six.
So I just happened to have that one, and
this is a picture of your plant, and then there is a
table that tells you which plants have which
configurations.
And then there is another table that tells
you which plants are built to which code standards,
and just a compilation of all of that must have been
a mammoth task. I thought it was very well done.
DR. SHACK: It would have been very nice
to have the --
DR. ROSEN: So this table, Table 2.2-2,
primary components support configuration
classifications for all the plants, and which tells
you what configuration of all of the configurations of
what each plant has for the reactor vessel, and what
configuration it has for the RCPs, et cetera.
And so you can find the plant and go
across there, and if you have enough patience, you can
get a mental picture of what all the supports look
like for each plant.
CHAIRMAN BONACA: And so I even know the
size of your pressurizer.
DR. ROSEN: It is bigger than most isn't
it? All the others are 84 and ours is a hundred. But
it is very descriptive, and I must say that I
hesitated to read it, bring a PRA type operating guy,
and I finally brought myself to look at it, and it
wasn't all that bad after all.
CHAIRMAN BONACA: So the question I have
for you is we have three choices. If we don't write
a letter on Turkey Point at this meeting, should we
write a letter on these supporting documents now?
And the second option will be to write a
separate letter when we are writing also the letter,
the final letter for Turkey Point; and the third one
is to do what we have done before, although the staff
does not like it.
And that is to incorporate comments on
these documents at the time at which we write a letter
for Turkey Point. That is the way that we did it for
Oconee, and referencing the case, the B&W genetic
documents.
And also we have done it for Hatch, where
we referenced the BWR documents, and also for Calvert
Cliffs, where we referenced to see the documents.
DR. SHACK: Well, again, these things are
not going to be revised. The SERs are done, and as
far as I can see the only incentive for writing a
letter is if there is something that you disagree
with. And I haven't got anything.
CHAIRMAN BONACA: So my suggestion is to
just leave them behind and talk about them when we
reference or write a letter on Turkey Point.
DR. ROSEN: Isn't here another piece of
support for leaving them behind and not doing too much
with these Westinghouse Topicals, and Turkey Point did
not use them, or at least directly.
They explained how they did, but they
didn't officially reference them. So I think to pull
a letter out of our hat on the topicals at this point
doesn't make sense.
CHAIRMAN BONACA: I agree with that. So
we have a recommendation to bring it to the committee,
and what I would like to do is the following. I would
like to talk now about what is going to happen next
week.
We have two hours on the agenda, I
believe, and I think we need a presentation by the
applicant.
DR. DUDLEY: The staff.
CHAIRMAN BONACA: We need a presentation
by the staff and to focus on open items, and really a
summary of the report.
DR. DUDLEY: Could the staff address some
of the questions that have been raised here about
concerns?
DR. ROSEN: That would be excellent, as
that was the whole purpose of the subcommittee meeting
wasn't it? Was to let the staff know what we think of
the application and of their review? So that if there
are any questions, they can come back to the full
committee and perhaps dispatch them.
DR. FORD: Could I just ask a question?
What are we going to do about these documents?
CHAIRMAN BONACA: Right now we are not
going to write a letter on those. We are going to
comment on those probably when we write the final
letter on Turkey Point.
DR. FORD: Bill, you just said that these
are not going to be revised.
(Discussion off mike.)
MR. NEWTON: My name is Roger Newton, and
I am also Chairman of the Westinghouse Owners Group
License Renewal Working Group, and so I am here to
answer any questions that you may have concerning the
GTRs.
And we can talk a little bit about how we
envision them being used on Turkey Point, and that was
kind of the first plant to use them, and as was
mentioned here, they didn't have the full SERs and the
action items on them.
I would expect the next generation of
plants would use them more discreetly, and
specifically address the licensee action items like
you talked about here.
And the purpose is to define and simplify
the review for the NRC, and define what the applicant
should be looking at, and that is his guide.
Now, Turkey Point still has to do a full
evaluation, but he has a cookbook to compare himself
to to see if he has missed anything, or if he found
anything that is different.
And that's why every first action item was
to say how are you bounded by the WCAP and SER, and if
you find something different, you are obligated to
then identify it, and to deal with it.
And with respect to update in the GTRs,
this is an ongoing issue within the Westinghouse
Owners Group as to how much we should do in that area.
Right now we have asked Westinghouse that any time
something new comes up to put it in the folder related
to that GTR.
And if those issues become big enough, or
value enough at some time in the future we may say,
yes, it is time to do another revision. And would we
take that revision through the NRC to get an augmented
SER on it, or would we just publish it, those are all
items down the road that we would decide what is worth
doing.
And maybe it would be a joint decision
between us and the NRC as to whether it is worth doing
or not. But those are things that are -- I am just
making sure that we do maintain this.
And if something does come up, we try to
make sure that our members are aware of what it is so
that they can factor it in to their reviews. So, this
is not a finished product, and the report is well-
defined, but just the management of the issue for the
long term, and we plan to keep our eye on each of
those areas as part of our responsibility to our
members.
CHAIRMAN BONACA: Thank you.
DR. DUDLEY: I did have a chance to go
through and identify those items that were raised and
that the staff may want to speak to next week.
CHAIRMAN BONACA: And they are?
DR. DUDLEY: The concern about the
proximity of the RT PTS to the screening criteria;
retention of corporate knowledge in the engineering
training program.
MR. AULUCK: This is for the engineering
personnel preparing the application; is that what you
are talking about?
DR. ROSEN: Well, yes. And how also that
information is transferred to the ongoing staff once
the license renewal is approved.
DR. DUDLEY: Also, clarifying how the
committee's recommendations about using EOPs in the
screening process and how that has been worked into
the guidance.
MR. KOENICK: Noel, we need to go back.
I know that we have talked about that at past
meetings, and we may have written you a letter on
that, because the main thing was in deciding the scope
the primary path to maintain safety, that is defined
by your safety related equipment.
And the EOPs include that safety related
equipment that you rely upon for success. But then it
goes on and credits additional means to achieve, more
or less like second or third ways of achieving that.
And it may rely on equipment that is not
safety related, and it gives them other options. But
the scope of the rule is set up to ensure that we wold
have a path, a guaranteed path more or less to achieve
that safe condition.
And so we are trying to maintain that
current licensing basis and to ensure that that path
will be there. And the EOPs were included as a
reference document, along with others, as a source
that if you feel that is a good place to go to get
information, and to double-check your other screening
and scoping type of stuff that you have done, it is a
possible source document.
But it is not a requirement that
everything that is included in the EOPs being in the
scope of a license renewal.
CHAIRMAN BONACA: And right now it is a
source document, and which the answer is not as
written which is in the EOP is going to be in the
scope of license renewal.
MR. KOENICK: Correct, and doesn't need to
be.
CHAIRMAN BONACA: But the EOPs we are
looking at because we wanted to make sure that you
would find some piece of equipment very important to
safety that had been otherwise not considered, just
like you look at the TLAAs and VIPs.
MR. HALE: Just for my own benefit, are
these items being characterized as an issue with the
Turkey Point application?
CHAIRMAN BONACA: This one?
MR. HALE: No, just any of these that --
CHAIRMAN BONACA: No.
MR. HALE: So these are just recommended
enhancements?
CHAIRMAN BONACA: With the EOPS, we have
recommended them before, and the staff came back and
said that they considered them. And we debated within
this committee whether we wanted to go all the way to
the Commission and ask for a change to the rule, and
we decided that it was not appropriate.
And as far as training, again it is a way
for us to learn a little bit what is happening, and it
is a good question for the staff of utilities, who is
likely to ask that question again.
MR. HALE: But the item is for the staff
to be looking at applicant training.
DR. ROSEN: And maybe somebody would walk
the copy down to INPO at some point.
MR. AULUCK: But the question does not
relate to qualification of engineering personnel at
Turkey Point, or their training, or imparting
knowledge to other plant or site personnel at Turkey
Point, right?
CHAIRMAN BONACA: No.
MR. AULUCK: It is a generic question.
CHAIRMAN BONACA: That's correct.
MR. NEWTON: Can I comment on both items?
Again, my name is Roger Newton, and one of my earlier
hats in the Westinghouse Owners Group was I was the
first chairman for the group that developed the
emergency operator response guidelines, which the EOPs
are derived from.
A few have studied those guidelines and
they deal with the accidents, and the design basis
accidents, but they also deal with multiple accidents
so far down the probability chain, and they go into
the plant and say is there anything available that
could deal with those.
So when you go down the risk aspects of
what you may be using, it is pretty far down the risk
chain of some of these things that the EOPs or the
ERGs call on.
So that was one aspect that -- and when we
talked about trying to eliminate things from a risk
standpoint and the license renewal rule, the NRC threw
it out. That was primarily the concern over where the
emergency operator procedures may go.
And the other aspect was that the
maintenance rule did include the EOPs from a
maintenance reliability standpoint, and properly
relates them of risk in the maintenance rule.
So I think the NRC felt that the EOPs were
adequately covered in the maintenance rule, but it was
something that the license renewal did not have to
address, just like active components.
So that was kind of evaluated and whether
it should be in the scope of license renewal, and that
was talked about and at that time judged to be already
covered adequately.
DR. ROSEN: Now that you say that again,
Roger, I remember that is what the staff presenter
said, that he thought that the maintenance rule
covered that adequately, and that may be all you have
to say.
CHAIRMAN BONACA: The reason why we raised
the issue was because the concern we had was that you
may have a component, like a pump, and the maintenance
rule says it is important, and therefore, you are
looking at the active component under the maintenance
rule.
MR. NEWTON: Well, the maintenance rule
looks at the performance of whatever it is intended to
do from an active standpoint. Does it supply
electricity, or water, or whatever it may be way down
the road.
So it covers both the active components,
as well as what is needed to support getting it there,
too. The second item, Steve, that I would like to
address is the ESP program.
The ESP program is the training of
engineering support personnel for your current
licensing basis. And in your current licensing basis,
does that include license renewal, or the aging
effects of the plant includes everything else.
I would expect that once a plant gets a
renewed license, and he has to manage the license
renewal and the requirements for the long term under
this new license, what he will have to do on how to
manage that will be rolled into the ESP programs at
that time.
But to do it now wouldn't make sense
because there is no regulatory requirement to address
it.
DR. ROSEN: Well, I agree a hundred
percent with the timing, but my point was that I fully
expect Turkey Point's license will be amended to
provide them with an extended period of operation. I
don't think that is much in doubt.
And so they night as well get on with
working on what they do to the ESP at this point, and
also communicate to INPO that ESP guidance documents
ought to include another bullet under the engineering
support personnel training program that says for
plants that have obtained license renewal, and here
are the things that they should add to this program.
MR. NEWTON: For example, when you make
mods to the plants now, you have checks for fire
protection, and for EQ, and for everything. There is
likely to be a check for is this important to license
renewal. It does make sense to put that into Turkey
Point now, but once they get their license, it should
be there, and ESP should cover that.
DR. ROSEN: Right. I agree with that.
CHAIRMAN BONACA: All right.
DR. DUDLEY: There are two or three more
items that I would like to throw out as possible
discussions. One was Dr. Ford's concern about
multiple inspections, depending on variables such as
crack growth, where there is no data available.
DR. FORD: There may well be data
available, but not clearly relevant.
MR. KOENICK: Are you asking us to address
that at the next meeting?
DR. FORD: No, I don't think so.
CHAIRMAN BONACA: Well, you can raise the
issue again, but to ask the staff to address it, we
will have to ask for some formal --
DR. FORD: No, I am not asking for that.
My opinion about this application has not changed.
It's fine. It's just that from a systemic point of
view, I would like to see a brighter picture.
CHAIRMAN BONACA: I think it would be
important that you raise the issue again at the full
committee, and it is an issue that you have to bring
up if you feel concerned about that, but I don't think
the staff should address it out of the blue as part of
the license application, and I don't think that is
appropriate, because it would single out the
application as one that has these issues, and that is
not the case.
MR. AULUCK: And to keep the focus on the
application.
DR. DUDLEY: There was Dr. Shack's issue
about the VT1 for PWRs and the acceptability of that.
CHAIRMAN BONACA: It is important because
this has not to do with the application, but with the
SER.
MR. KOENICK: What I understood that to be
was that the SER wasn't clear.
DR. SHACK: The SER accepted it, and I can
understand accepting the license renewal application
because again they are going to do UT and it doesn't
really matter too much whether the VT1 is effective or
not. The UT is really the thing that is going to do
the job.
I didn't like the SER because there was no
reservation there that VT1 without some enhancement
would be able to in fact protect cracking, which is
the case that you have always made in accepting the
BWR VIP documents, for example.
MR. KOENICK: So it sounds like we need to
clarify the SER.
DR. SHACK: Yes, and I have no problem
with the application.
MR. KOENICK: We just need to address what
we are going to do with the SER.
CHAIRMAN BONACA: We don't need a
presentation on that.
DR. SHACK: Well, one of you may need to
address it next week.
MR. COUCH: Well, we will go back and look
at the SER write-up, and take it as an action to go
and look at the SER write-up to make sure that it is
clear that we are crediting the UT.
MR. AULUCK: And that can be done at the
final SER, but not for next week.
DR. DUDLEY: And then next week a
presentation on the open items, with emphasis on the
two over one.
CHAIRMAN BONACA: Now, I think what we
would like to do now is we should have a presentation
by the staff, including also a brief presentation on
the four WOGs reports, and then I will have maybe 15
minutes in which to provide a presentation to the full
committee on the reason why we are recommending that
we don't have a letter at this time, and that it is
the conclusion of this subcommittee that it is a good
application, and we will plan to write a report.
All right. I think we have it. Any other
comments by the members or suggestions for next week's
meeting? If not, any other comments from the staff or
public?
MR. AULUCK: I have a comment. On the
engineering staff training of personnel, and the EOPs,
since we already talked about that, do you still want
us to cover that next week?
DR. ROSEN: You can talk to Galletti, and
he knows about it.
CHAIRMAN BONACA: I think you can mention
that since a member of the subcommittee raised the
issue, EOPs are utilized solely as a source of
information and state the facts. So if there are no
other comments or questions, we will adjourn the
meeting now.
(Whereupon, the meeting was recessed at
4:20 p.m.)
Page Last Reviewed/Updated Tuesday, August 16, 2016
Page Last Reviewed/Updated Tuesday, August 16, 2016