Plant License Renewal (Hatch 1&2) - October 25, 2001
Official Transcript of Proceedings
NUCLEAR REGULATORY COMMISSION
Title: Advisory Committee on Reactor Safeguards
Plant License Renewal Subcommittee
Edwin I. Hatch License Renewal Application
Docket Number: (not applicable)
Location: Rockville, Maryland
Date: Thursday, October 25, 2001
Work Order No.: NRC-081 Pages 1-160
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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EDWIN I. HATCH LICENSE RENEWAL APPLICATION
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THURSDAY
OCTOBER 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. F. PETER FORD, Member
DR. THOMAS S. KRESS, Member
DR. WILLIAM J. SHACK, Member
DR. JOHN BARTON, ACRS Consultant
MR. NOEL F. DUDLEY, ACRS Staff Engineer
STAFF PRESENT:
WILLIAM BURTON, NRR
JAMES DAVIS, NRR
CHRIS GRIMES, NRR
JOHN NAKOSKI, NRR
GENE CARPENTER, NRR
TANYA EATON, NRR
I-N-D-E-X
AGENDA ITEM PAGE
Opening Remarks by Subcommittee Chairman . . . . . 4
Opening Remarks by Chris Grimes, NRR . . . . . . . 5
Presentation by W. Burton on Safety. . . . . . . . 6
Evaluation Report, Closure of Open Items
Presentation by W. Burton on Appeal. . . . . . . 108
Process
Discussion by Subcommittee . . . . . . . . . . . 142
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 Plant License Renewal
Subcommittee.
The other ACRS Members and consultant in
attendance are Peter Ford, Thomas Kress, William
Shack, and John Barton.
The purpose of this meeting is for the
subcommittee to review the Safety Evaluation Report
related to the license renewal of Edwin Hatch Nuclear
Plants, Units 1 and 2.
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. Mr. 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 October 10th, 2001.
A transcript of this 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. At our March 28th, 2001 Subcommittee
meeting, we reviewed the SER with open items.
In a letter to Dr. William Travers,
Executive Director for Operations, issued on April
16th, 2001, the ACRS provided conclusions based on its
review of the SER with open items.
We will now proceed with the meeting, and
I call upon Mr. William Burton of the Office of
Nuclear Regulatory Regulations to begin. Actually,
Mr. Grimes, would you like to have an introductory
statement?
MR. GRIMES: Yes, Dr. Bonaca. First of
all, I would like to thank the ACRS for this
opportunity for the staff to present the results of
the staff's review and resolution of open items.
As you mentioned, Butch Burton, a senior
project manager, who is in charge of the license
renewal review for Hatch, is going to lead the staff's
presentation.
I would also like to introduce John
Nakoski, who is an acting section chief in the license
renewal and standardization branch. I have to leave
shortly to attend to another function for the Division
of Regulatory Improvement Programs.
But we are looking forward to the ACRS
reactions and comments on the staff's resolution of
the open items and the final safety evaluation report.
Mr. Nakoski is going to represent my
interests to make sure that we clearly understand what
issues or what comments the subcommittee would like
for us to address more fully for the full committee on
November 8th. Thank you very much.
And so with that introduction, I will turn
the presentation over to Butch Burton.
MR. BURTON: All right. Thank you, Chris.
I am going to use the remote mike. Is that going to
be all right and can everybody hear okay? Okay. My
name is Butch Burton, and I am the lead project
manager for the staff's review of the Plant Hatch
license renewal application.
I have with me some of the staff reviewers
who performed the review. Not all of them are here
today. So if you have some questions that would
really be addressed by them, I am going to have to
perhaps defer the question until the full committee
meeting.
But most of the reviewers should be here
today. I also have the representatives of Southern
Nuclear here to clarify any items that you may need to
ask of them.
According to the agenda, this is actually
going to be in two parts. The first part as I
understand it that you wanted to do was to go over the
open items that did not go through the appeal process.
So the first part, I was just going to go
through those and what the resolution of those open
items were. And then following the break, I was going
to go through the open items that did go to appeal.
And it was my understanding that for each
of those that you wanted to make sure that you
understood exactly the basis for going to appeal, as
well as the final resolution of each of those items,
and so I will be going through that also.
Okay. First, a little bit of background,
and a lot of this is similar to what I provided during
the previous meetings back in -- what, the March-April
time frame.
Southern Nuclear submitted its application
in late February of last year. As you know, Plant
Hatch is a two unit site, located about 11 miles north
of Baxley, Georgia. They were requesting renewal of
both of the licenses for both of the units.
And for Unit 1, an extension of 20 years
so that it would move from 2014 to 2034; and for Unit
2, from 2018 to 2038. The initial SER was issued in
early February of this year, and we just recently
issued the final SER that I will be talking about
earlier this morning on October 5th.
Just briefly, I wanted to put up the
milestone schedule, and just let you know some of the
activities that have gone on since the last ACRS
meetings, which occurred April 5th.
Since that time, or at that point we had
not gotten or completed all the necessary responses
for all of the open items. So since that meeting, we
have gotten all of the open items, and we have been
working to resolve those, and they are all resolved at
this point.
The staff also issued its final
environmental impact statement in late May, and we
also did the final optional inspection. As you know,
there are two inspections that are normally done, and
then an optional final inspection, and we did do that.
And we got the associated inspection
report, and as I said before, the staff issued its
final SER on October 5th, and following that we got
the regional administrator's letter basically saying
that as a result of the inspections that were done
there were no outstanding issues.
Now, we identified 18 open items during
the staff's review. Of those 18, 12 were resolved
without going through the appeal process, and six were
resolved as a result of going through the appeal
process.
The next couple of slides is just a
laundry list of the open items that were resolved
without appeal, and I am going to be going through
each one of these. Now, if you actually look at the
next two slides, you will actually count -- rather
than 12, you will actually count 13 items.
The reason for that is that one of the
open items, the very last one, 413-1, had two parts to
it. Part A was not appealed and Part B was. So, I
split it up along those lines. So you actually see 13
items on this list.
Okay. The first open item was Open Item
2.3.3.2-1, and it had to do with the screening of
skid-mounted components. The big issue at hand was
should skid-mounted components be subject to an AMR.
These skid-mounted components were
actually associated with the hydrogen recombiners, and
the emergency diesel generators. We had actually gone
through this issue with Oconee earlier, and the final
resolution was that we needed to clearly define the
boundaries between these two components, which were
considered active, and then the associated skid-
mounted components.
And what we recognized was that there were
some skid-mounted components that actually fit the
criteria for being long-lived and passive, and as such
they needed to be -- well, they were already brought
into scope, but also needed to be subject to an AMR.
So after some discussion the final
resolution was that there were some additional
components that were brought within that were subject
to an AMR. As you can see with the recombiners, they
were such things as blower casing, piping, reaction
chamber, and some other things.
And similarly with the diesel, jacket
water cooling, lube oil, and scavenging air. And what
I wanted to make sure that you all understand is that
when we have these scoping issues, when we did decide
that something needed to be brought within scope,
and/or subject to an AMR, there was a whole cadre of
aging management information that had to come with it.
And so in each of the scoping and
screening open items, if they were resolved such that
things had to be brought within scope, or be subject
to AMR, all of the associated aging management
information was brought with it, and the staff
evaluated it.
CHAIRMAN BONACA: I have a question on
this. One is that this was an open item as you
mentioned before on Oconee, and is the guidance --
well, I believe the guidance right now, for example,
in the GALL report is pretty clear about what it
should be.
So with other applications coming through,
does it look like this is going to be again contested
in some other applications, or is it pretty much of a
clear understanding now of what the interpretation is?
MR. BURTON: Well, if you look at the
latest license renewal guidance, the SRP, and all of
that, it is pretty clearly laid out. Once of the
issues as I go through this and I guess you will kind
of find is that the timing of the Plant Hatch
application versus some of the infrastructure work
that the staff was doing, we kind of got caught in
cross-purposes.
But as we reach resolution on some of
those things, we were able to see if it was applicable
to Hatch and be able to resolve it that way. You will
see that with some other items that had to do with
some of the work that we had to do with GALL and
things like that. So that was part of it.
DR. BARTON: I had the same question,
because it seems to me that there is going to be
generic issues that are going to come up, and another
one I think is seismic two over one piping issues.
Now, is the staff going to have to go
through every application and go through the same
arguments? Isn't there some way once a precedence has
been set that the word gets out or something, and
don't come back in and try to argue it, because it
seems to me just a waste of resources to fight the
same issues if the staff is going to say, hey, we are
never going to accept seismic two over one.
And so everybody is going to come in with
the same argument, and we are going to have the same
response. So, you know, let's get on with it.
CHAIRMAN BONACA: And another thing that
I wanted to note in particular for seismic two over
one is that the SER for Hatch contains a discussion
that is very clarifying.
I mean, the logic why an existing high
energy line break, for example, analysis doesn't
provide sufficient understanding of locations that you
have to protect for.
So I think an important question is how is
this information or this guidance being provided to
the licensees. Clearly, an update of GALL may be the
way, but it is important to provide it in a way that
open items on the same issues don't appear again.
Unless, of course, it is an issue that is
highly contested by the industry, and then in that
case we will have to go through to a resolution.
MR. BURTON: I will say that in the
specific case of seismic two over one with Hatch, I
was going to speak not only about the resolution, but
how that actually got played out.
(Brief Interruption.)
CHAIRMAN BONACA: Let me ask another
question about this. Are there any other skid-mounted
systems in the plant that one should look at?
MR. BURTON: Not -- well, I guess --
CHAIRMAN BONACA: Well, I am just saying
that I would like to ask that question.
MR. BAKER: Of the items related to
license renewal, the only ones that came to mine --
MR. DUDLEY: Excuse me, but could you
introduce yourself for the record?
MR. BAKER: Ray Baker with Southern
Nuclear. The hydrogen recombiners skid and the diesel
generator skids represent two major examples of skid-
mounted components that have an overall active nature
associated with them, but which through the
discussions that we had with the staff, we resolved
how to break that down into the parts that required
aging management. There are no others that I am aware
of.
CHAIRMAN BONACA: Okay.
MR. BAKER: And that would reach that
level of the interest.
MR. BURTON: And for your other question
about in general how we deal with these items that
come up, I think Mr. Grimes wanted to speak to that.
MR. GRIMES: Thank you, Butch. Yes, I
would like to first emphasize that we were learning
how to resolve some of these issues, and which
includes renewal guidance.
And parallel with the staff's review of
Hatch and Turkey Point, and the practice that we have
established in it is that I would intend to continue,
as has been illustrated by the demonstration project,
is that as we identify areas where there is still
controversy or sensitivity.
That wherever we can clarify the staff's
expectations, we would send proposed positions to NEI,
and give the industry an opportunity to react to them
on a generic basis, and then augment the improved
renewal guidance either in the form of supplements to
the standard review plan, expectations regarding the
contents of the application, or changes in the style
guides that we have established to try and articulate
a consistent treatment of these issues.
You might recall that the industry
identified five -- what they referred to as dialogue
issues, and those were areas where the industry felt
that there was still an opportunity for improvements
in the process.
Most notably, environment effects of
fatigue is an area where there is ongoing research
activity, and ongoing industry initiatives, and
ongoing staff review.
And in those areas, as we find ways to
clarify the expectations and minimize the extent of
the struggle over finding the right answer on a plant
specific basis, we would intend on capturing those.
I do think that the improved renewal
guidance is probably achieved 95 to 98 percent of the
resolution of controversy over how to do license
renewal, aging management, scoping, and other aspects
of the process.
But there will continue to be areas where
we are trying to find the optimum solution. There
will continue to be areas where there will be
challenges on a plant specific basis, and that just
represents the nature of the emerging issues and
adaptability that will be a part of the process, I
think, on an ongoing basis.
MR. BURTON: And I wanted to add to that,
is that as we do our work with grappling with the
emerging issues, there is always the timing issue
where as things come up you have applications that are
being reviewed at that time, and applications that
have already been reviewed and approved.
So there is also the part of what we do as
part of our process is as we resolve these things, we
have got to see how do we communicate that resolution
to the plants who are so far along that they didn't
have an opportunity necessarily to incorporate it.
And also for those who have already been
or had their license renewed, part of the process that
we follow is that we have to evaluate, well, how does
that impact on them and what needs to be done.
And some of that as well we are going to
bring out with some of the seismic two over ones. So
those are all issues that we as a staff are aware of,
and we try to take into account as we resolve these
things.
MR. GRIMES: Okay. The next open item was
2.3.4.2-1, fire suppression in the radwaste building.
Our fire protection engineer, in her review, did a
thorough review of the fire hazards analysis, and what
some of the commitments were in there.
And comparing that to what had been scoped
in for license renewal, and we found that some of
these fire suppression systems in the radwaste
building according to the fire hazards analysis was
necessary to protect charcoal filters, and some
combustibles, in the dry waste storage area.
And also as a result of one of the
inspections, we also found that there was some cabling
that needed some protection. So as a result of that,
we said, well, we think that needs to be brought into
scope and be subject to an AMR.
And we did some walkdowns during the
scoping inspection, I believe it was, and actually
identified that portion of the system, and exactly
what it was designed to protect.
And in the end we did decide -- the
applicant did decide to bring that into scope, and
make it subject to an AMR. And again all of the
associated aging management information came along
with it.
Now, I just happen to know in this
particular case that as you know, what was done was
once you identified components in scope and subject to
an AMR, you commoditized it. You broke it down into
its material environment combination.
And I know that in this case the staff
that was brought in to scope when it was commoditized,
it didn't really result in anything new, in terms of
aging effects or aging management programs, and things
like that.
The next open item was open item 3.0-1.
This is a standard open item. What it is, it is sort
of a place holder for all of the work that we do with
the FSAR supplement. As we review the FSAR supplement
information, we will find open items, whatever issues
that need to be resolved.
This open item is sort of a catch all,
that when we are satisfied that all of the issues in
the supplement are correctly resolved, then we will
close that out.
There is also a standard license condition
associated with that. Basically, the license
condition says that the FSAR supplement, as it has
been agreed to, needs to be incorporated into the FSAR
at the next available FSAR update, and that is a
standing license condition.
Another standard license condition states
that in the supplement that there are a number of
future activities that are committed to, and so we
also have another standard license condition that says
all of those activities have to be performed before
the end of the current term, another standard license
condition.
And that is two of the three license
conditions that we actually have in this review, and
I will speak to the third one later.
CHAIRMAN BONACA: A number of the closure
of open items result in new one-time inspections, or
some modifications of existing programs, and in some
cases actual changes in site procedures.
And in fact I have some questions on that,
and I think you, John, had some questions on that.
But the question that I have is are these changes
going to be reflected in the FSAR supplement, or how
are these new commitments captured?
I mean, the reason to commitment to the
licensee to update the application, and we discussed
this before. The application stands as is, and it
doesn't have included an amendment to reflect these
changes. Are they going to just sit in the SER, or
what are they going to go?
MR. BURTON: That is a good question, and
I guess in order to answer it, I am going to let
Southern Nuclear talk a little bit about their
commitment tracking process, and then how we as the
staff actually as part of our inspection actually took
a look at that.
MR. BAKER: This is Ray Baker again at
Southern Nuclear. One of the activities that we began
early was to track the commitments that we were making
as a part of the license renewal application review
process.
And we had several stake points in that
process, one of which was the issuance of the final
SER to go through that document again, and identify
any revised commitments or new commitments that had
been made since the previous stake points, and we
capture those in a database.
And for each of those commitments, we have
performed an extensive review process of the existing
site procedures, and we have identified the
procedures, and the procedure steps, where
enhancements will be made, or where we will credit
those activities to satisfy those license renewal
commitments that we have made.
And so we have that process in hand now so
that once the license is issued, we will then go
through a process of actually converting those draft
procedures into the actual implemented site
procedures.
DR. BARTON: I have one additional
question. You have got this in the commitment
tracking system, and I know that people sometimes have
problems with commitment tracking systems, and lose
commitments, and lose track of commitments, et cetera,
et cetera.
Have you also placed each one of these
items in your corrective action system?
MR. BAKER: We have a separate database
besides the actual site commitments matrix, that we
are in the interim managing these commitments until
they are established in the site's commitment tracking
system.
As far as a separate -- our site processes
would not lend themselves to having them in a separate
corrective actions kind of a database.
DR. BARTON: So you have got more than one
corrective action system at the site?
MR. BAKER: There is a corrective actions
process.
DR. BARTON: A corrective actions process?
MR. BAKER: Yes.
DR. BARTON: So it has got many systems or
many fingers to this, and how you track actions?
MR. BAKER: One of the things that you
would do would be to identify conditions that require
correction. So that is a piece of it. And another
part would be the tracking and trending of those
issues.
And so you have some procedures that track
and trend internally, and then you have other
procedures where the tracking and trending would be
performed perhaps at a departmental level, rather than
at the procedural level. Those are all a part of the
corrective actions control for the site.
DR. BARTON: Okay. It just seems to me
that it more complex, and I have seen other plants
where everything goes into one corrective action
system. So I only have to worry about tracking one
place.
MR. BAKER: There is one corrective
actions system, yes, but it is made up of many parts,
yes, sir.
MR. PIERCE: I just wanted to add one
other thing. This is Chuck Pierce, and I am with
Southern Nuclear as well. To more specifically answer
the question that you had asked earlier, Chairman
Bonaca, the SER supplement, which is a part of what we
send the NRC, was updated to reflect these new
commitments, and what we have resolved with these open
items.
So there was an update made to that
document that will go into our FSAR.
CHAIRMAN BONACA: And that will list, for
example -- well, I don't expect a description, but it
will list the programs that you are committed to?
MR. PIERCE: Yes, and it includes the
final resolution of the commitments made in the open
items.
CHAIRMAN BONACA: Okay. So there is a
place then.
MR. PIERCE: Yes, sir.
CHAIRMAN BONACA: Because that is really
generic to all this license renewal, and not
specifically to Hatch. I mean, I think it is
important that somewhere we have what is that we have
agreed to support license renewal.
And I think that it is up to the location
that there has to be a place where we understand what
the programs are going to be. Some of them are
modifications that can be lost in a SER. So, all
right.
MR. BURTON: Now, having a better
understanding of what they do, now let me talk a
little bit about what the staff did in terms of its
confirmation of all of that.
As they said, what they tried to do was to
capture all of the commitments, and all of the
commitments are identified in the application in the
SER.
And as they said, they capture all of
those commitments in a commitment matrix. So what we
did -- and this was at the very first scoping
inspection, we spent a fair amount of time that week
understanding their system, and taking examples of
commitments as they were incorporated in the matrix at
that point, and seeing how they were tracking them
down to the procedure level.
And in fact we found that they actually
did a very good job in terms of tracking those
commitments, and they actually had red-line strikeouts
of the associated site procedures. And all of that is
documented in, I believe, the first scoping inspection
report.
And actually in that respect, they were
actually ahead of some of the previous applicants, in
terms of their development of that phase of the
process.
Now, it was not complete at that point,
because obviously now that we have the final SER out,
there are more commitments that have been made as a
result of resolving the open items.
All of that was actually before we had
resolved the open items, and so what their process
does is that they are going to go back now once
everything is resolved, and put to bed, and see what
other commitments they have made, and put them in that
tracking system, and run them down to the procedural
level.
But after we took a look at the process,
we were pretty comfortable that they were actually
doing things right there, and we are actually better
than some of the other applicants.
MR. NAKOSKI: Butch, this is John Nakoski.
If I could just add that post-renewed license, that we
do plan to have an inspection procedure that will
specifically go and look at confirmation that the
commitments made have been implemented and met prior
to or about the time the existing license would have
expired.
MR. BURTON: The next open item is 3.1.1-1
had to do with the BWR water chemistry guidelines. We
had developed in the initial license renewal
application, they talked about some of the water
chemistry guidelines that they were going to use, and
they committed to following EPRI 103515.
And in response to an RAI, they noted that
this document was going to be revised to Rev. 2. So
the issue came up, well, we haven't seen that, and we
are not sure what is in it. So we are not sure that
we are going to be comfortable if you move to that
revision.
And that was the basis of the open item.
After some discussions, we realized that the applicant
needs to have flexibility in their water chemistry
program. They have hydrogen water chemistry, and
hydrogen water chemistry with Noble gas chemical
addition.
And as a result of some of the operating
experience, they need to have the flexibility to make
whatever changes that they need to make. But in
response to the open item, because our concern was,
well, how does Rev. 1 differ from Rev. 2, they also
included some of that information.
And in fact when you look at Rev. 2, what
it does is that it does in fact give someone who
implements Rev. 2 a lot more flexibility if they are
using hydrogen water chemistry. They are allowed to
relax some of the limits for chlorides and sulfates,
and things like that.
So after -- again, after looking at all of
that, and realizing that they really do need to have
that flexibility, we said, okay, we are going to close
this out and basically not ask them to stick
necessarily to Rev. 1.
DR. FORD: Can I ask a procedural
question? I agree entirely with our decision there,
but since you haven't reviewed Rev. 2, how is that
-- if you have not reviewed Rev. 2, how can you just
go along and agree with the application?
MR. BURTON: Okay. And let me be clear.
Right now what they are doing is associated with Rev.
1. Rev. 2 at the time -- and I don't know whether the
-- or at what stage of completion that is in. I don't
know if any of you all know that.
But again -- and I guess to some extent
that you may call that a judgment call, and part of it
very much was, well, we need to understand the delta
between the two.
And once we understood it, it really was
just a relaxation of some of the chlorides and
phosphates if you are using hydrogen water chemistry,
because it gives you a big benefit to do that.
We thought that was a good thing. The
other thing that it did was that it also relaxed some
of the monitoring frequencies. I think Rev. 1 says
that you have to monitor for these things daily.
Rev. 2 says, well, you can relax that if
you have got satisfactory trends in some of your
conductivity, and things like that. Oh, okay. Did
you want to add to that?
MR. DYLE: This is Robin Dyle from
Southern Nuclear, Dr. Ford. One of the things that we
did in this process was evaluate for the staff the
differences between Revision 2 and Revision 1, and
provide that to them.
So there was an assessment of Rev. 2. I
think it would be better characterized that they
didn't do a generic review, and to say that it is
applicable to the entire fleet.
But they do understand that the
differences. The one thing between Rev. 1 and Rev. 2
is that there is no change in the action statements,
and the real requirements. There was more guidance on
how to monitor things that should be noted and kept up
with when you are implementing HWC or Noble Metal.
But that has been reviewed as far as what the
differences were and that was provided.
And the documents are available for
generic review also, but it just has not been
submitted that way yet.
MR. BURTON: The next open item was 3.1.3-
1 having to do with diesel fuel oil testing. The open
item was that we had a concern with degradation of the
tank bottoms, and that we thought that it would be
advisable to do a one-time inspection of the tank
bottoms.
One Southern Nuclear informed us of was
that recently they had actually done some excavation
and actually had done just the kind of inspection that
we were looking for on one of the four buried diesels.
I'm sorry, diesel fuel oil storage tanks.
They couldn't bury diesels. Wouldn't that be
something. They are pretty large tanks as I am sure
that you all know. When they looked at the one, they
did not find any significant wall thinning or any kind
of degradation.
And the thought was that these four tanks,
and they are all made of the same material, and they
are all in the same environment, and they have all
been in the same environment for the same period of
time.
So the implication is that if we are not
seeing any significant degradation in the one, that is
probably true for the other three. There was also --
well, actually, when we went on the scoping
inspection, as we did our walk around, we noted the
diesel fire pumps.
They also have fuel oil storage tanks.
However, they are above ground, and easily accessible,
and the same material, and a more benign environment.
So if we were going to see any kind of degradation, we
would see it here before we saw it here. So the
conditions here really bounded these.
DR. BARTON: I have a question. The
buried diesel oil fuel storage things, the tanks, the
four tanks, steel construction, coated or uncoated?
MR. DYLE: The exterior surface is coated.
DR. BARTON: The exterior surface is
coated, and you inspected one of four tanks?
MR. DYLE: Yes.
DR. BARTON: And ultrasonic showed that
you had no loss of wall on the one tank?
MR. DYLE: That's correct.
DR. BARTON: Now, what assurance is there
that -- well, maybe that tank has no deterioration or
no damage to the external coating when it was
installed.
What assurance do you have that when the
other three tanks were put in the ground that there
was no damage done to the external coating, and you
could have some corrosion going on in those tanks.
And that the condition, if you did inspect
them, could be different than in the 1-A tank?
MR. DYLE: I think that what you are
postulating is exactly correct, and is the case for
all construction. That is always a possibility for
buried components; that if there is some construction
related issue that is unique to a specific location,
it could damage that exterior coating, but we have not
observed that.
DR. BARTON: How do you know? Have you
looked at the external coating of those other three
tanks or other four tanks?
MR. DYLE: We have not observed any
consequences, any results of that throughout the plant
in general. When you backfill, you backfill with
clean backfill so that there is not a significant
likelihood of there being damage to the exterior
coating of those tanks.
But your premise is exactly correct, and
no, we have not looked at those. But the assurance
that we are able to provide ourselves is that by
examining that one, a 25 percent sample showed no
damage.
DR. BARTON: Well, I still think that
there could be damage to the other ones that you don't
even know exists. I think the staff should require
additional inspections before closing the site, or
requiring additional inspections somewhere down the
road.
You expected this one because you went in
and had to do some cleaning or something, and if you
had to do some cleaning of the other tanks somewhere
down the road, maybe the requirement ought to be that
you do an ultrasonic inspection of those tanks while
you are doing the cleaning.
I think it is a crap shoot, you know. You
hit one out of four, fine. That's 25 percent, but you
don't know what the condition is of the other three
tanks.
DR. FORD: I have a related question
actually.
MR. BURTON: Okay. Well, go ahead.
DR. FORD: And it is somewhat related to
John's. I am pretty uncomfortable about the idea of
one time inspections when it is applied to a time
dependent degradation mechanism.
DR. BARTON: Yeah, 60 years.
DR. FORD: And especially corrosion, when
if it is uniformly general corrosion, fine. But if it
is localized corrosion, and if you have a bad batch of
oil, with some chloride in the water or whatever it
might be, then it depends on when you do the
inspection as to whether you are going to see any
results.
MR. BURTON: Okay.
DR. FORD: And so it is related to that.
DR. BARTON: Well, you can only do it from
the inside of the tank, and when it comes from the
outside of the tank --
DR. FORD: Right. I was going to speak to
that.
MR. BURTON: Well, let me speak to both.
One of the things that Southern Nuclear has is they
have put in their procedures how to deal with buried
components, and actually I will speak to that in a
little while.
And that is one of the things that we
looked at in our inspection, is how did those
commitments get carried through to the procedural
level.
And the protective coatings program is one
of the aging management programs that they take credit
for. When you go to the implementing procedures at
the site level.
What they say is that any time that things
are being excavated, there is a specific pointer in
there to have their protective coatings people go in
and take a look at the exterior of the status of the
protective coating.
So the aging management program -- the
implementing procedures for the aging management
programs actually will get them to where they do that.
DR. BARTON: Butch, most people have that
in their programs. But, you know, one, when you go
and do that inspection, it is usually when you have a
leak, and then you do the excavation, and then you fix
the leak.
And then you look at adjacent piping, or
tanks, or whatever, and areas of the tank adjacent to
the leak, and you go patch that up also. But that is
a reactive program, and it is usually after you have
a leak and you are chasing a leak.
Now, you want diesel fuel oil leaking? You
know, that's where I am coming from, you know, before
you go and chase the tank or the coating. I know the
procedure, and most people do have that same
procedure, because how else are you going to inspect
all the buried stuff.
And you inspect it when it is leaking, and
you go after it, and you do an inspection of the
coating, and you repair the coating. Otherwise, no
one is going to dig up everything on site and look at
what was buried 20 years ago. I mean, that is not
practical.
DR. SHACK: At the risk of beating this
one to death, how detailed was the ultrasonic
inspection? I would expect a coating failure to lead
to a localized corrosion. I am not too worried about
uniform corrosion of this tank. That's not likely to
be a problem.
DR. BARTON: Right.
MR. BAKER: There were 144 locations that
were probed around the tank, and none of those showed
any reduction in wall thickness.
CHAIRMAN BONACA: Why did you perform this
inspection?
MR. BAKER: It was an opportunity. The
tank was opened and we knew that this was a question
that was of interest, and so we took that as an
opportunity to go take a look and see, just to
convince ourselves.
In general, these one time inspections are
where we don't expect an aging effect to exist to
begin with, but we want to confirm the absence of that
aging effect.
So in that respect, perhaps they are
proactive because it is not inspecting on an
expectation of there being a problem, but to confirm
that perhaps there is not a problem. And so that was
the rationale for what we did here.
MR. BURTON: And actually what Mr. Baker
said, I think that is an important point. I think
from the beginning of license renewal that we tried to
lay out the rules of engagement, I guess you would
want to call it, as it concerns one-time inspections.
And as Mr. Baker said, we generally
expected those kinds of inspections one time in
situations where based on operating experience we
really have not found any evidence of age related
degradation.
But again just if -- well, just to make
sure that we are assuming is correct, or I shouldn't
say we, but assuming what they are assuming is
correct, they will go and do that.
And many times that is associated with
things that have to do with chemistry of some sort.
CHAIRMAN BONACA: I don't understand.
What are the commitments that you have to -- I mean,
the current licensing term, and there is no
commitment?
MR. BURTON: I'm sorry, but say that
again?
CHAIRMAN BONACA: I am trying to
understand for the first 40 years of operation of the
plant.
MR. BURTON: Oh, for the current term.
CHAIRMAN BONACA: There is no commitment
to tracking aging degradation of that tank?
MR. BURTON: I must admit that I am less
familiar with what is currently done. So I don't know
if you all can speak to that.
MR. NAKOSKI: Butch, this is John Nakoski,
and let me just ask -- I guess I am going to ask you
a question here out of turn maybe.
MR. BURTON: Go ahead. I'm ready.
MR. NAKOSKI: Are we taking any credit for
corrective action if there were degradation of a
buried component? Is that part of an aging management
program?
MR. BURTON: Sure.
MR. NAKOSKI: And where they would
increase the scope of the --
MR. BURTON: Yes.
MR. NAKOSKI: Well, consider that as part
of the corrective action program?
MR. BURTON: Yes, absolutely. I am glad
that you said that. If I didn't make it clear before,
let me do it now. The corrective action program --
and this kind of speaks to your question also, but the
corrective action program is an aging management
program.
And what it is, is that when any kind of
problem is identified across any of the systems, their
guidance has to feed that into the corrective action
program, which basically is at an Appendix B level.
And so they implement all of those actions.
DR. BARTON: Is the commitment tracking
system at the same level?
MR. BURTON: In terms of the maintenance
of the commitment tracking?
MR. BAKER: I'm sorry, I was talking to
Chuck. I apologize. Repeat the question.
MR. BURTON: What I was talking about was
the correction actions program, and I was explaining
that it is a separate aging management program, and it
applies across all of license renewal, all of the
systems.
And the way that the process works is that
any time any problems are found anywhere, it gets fed
into the corrective actions process. And what I was
just saying was that that process is really at an
Appendix B level.
MR. BAKER: That's correct.
MR. BURTON: Even for some things that are
not Appendix B.
MR. BAKER: That's correct.
DR. BARTON: The question was is the
commitment tracking system at the Appendix B level
also, or just the corrective actions system?
MR. BAKER: The corrective actions system
is an Appendix B program.
DR. BARTON: And the commitment tracking
is part of that?
MR. BAKER: The commitment tracking is
more of a licensing process I would characterize.
DR. BARTON: So it is really not --
MR. BAKER: I don't believe that it is
subject to QA.
DR. BARTON: That's my problem. You are
using different systems to track things that --
MR. NAKOSKI: This is John Nakoski again
to try to maybe help answer Mr. Barton's question. I
think the point was made earlier that the commitments
are captured in the FSAR.
Further, there is a license condition that
requires -- if I understand right, Butch, and correct
me if I am wrong. But there is a license condition
that requires that those commitments be met before
entering the extended period of operation. That is
really where the FSAR controls the commitments.
DR. BARTON: These commitments that are in
the FSAR?
MR. BURTON: Oh, yes, all the commitments
are ultimately going to be in the FSAR, and controlled
from that point.
MR. NAKOSKI: And like I said further, we
will have an inspection procedure, post-renewed
license, that will go and look at satisfying these
commitments.
MR. BURTON: Okay. Now, all of that is
true, and I think that satisfies at least part of your
question. But it sounds like your concern is that the
entity that they used to track the commitments, the
actual commitment tracking system, which is not
technically part of an aging management program, that
it is buried in the corrective actions program.
And I guess what I need to do is I need to
get some clarification about that and what the level
of accountability is for that.
CHAIRMAN BONACA: It seems to me that --
well, what we are saying is that the one time
inspection would be adequate if we had not concern for
a possible inspection phase issue that may have led to
having coating chipped?
DR. BARTON: Failure of the coating.
DR. FORD: Or localized corrosion, which
may occur the day after you have done an inspection.
MR. BURTON: Right. And of course I want
to address your question, because I don't think that
we really spoke to that. The issue of degradation
from the inside -- and actually you said it already.
I mean, part of the ongoing program
currently, programs currently, is to sample. So if
there is any evidence of degradation, it is caught
fairly early. I am not sure what the frequency is,
but there is guidance for that.
So if there is evidence of degradation,
they jump on it right away, and it gets fed into the
corrective actions program, and is dealt with.
DR. BARTON: Butch, my only point is that
if you are going to go in the future, and if you are
going to inspect other diesel fuel oil tanks for
whatever reason -- you had a reason to inspect the 1-A
tank.
But if you have any reason to go in and
clean and inspect the other ones, do an ultrasonic
inspection, or do an inspection and tests like you did
on the 1-A tank somewhere down the road.
That is what I am looking for to ensure
that there is nothing going on in the other three
tanks. It is the same as if you have a buried pipe
that has a leak.
So you are going to excavate and you are
going to go and repair it. But you are going to also
expose other pieces of this piping. So you would go
and look at that while you had the hole open, all
right?
MR. BURTON: Absolutely.
DR. BARTON: And all I am saying is that
if the opportunity presents itself in the future to do
other fuel oil tank inspections, go do them, and right
now you are letting them off the hook on a one-time
sample of one tank. That's my problem.
MR. BURTON: Okay. And I do understand.
I guess what I will ask Southern Nuclear to talk about
is currently what their normal process is. If they go
in to do any work on a tank for whatever reason -- and
I don't want to put words in your mouth, you know, if
you speak to that.
But I think the normal -- I think even
normally now that when you go in to do something --
DR. BARTON: Why don't you ask them what
they do. Don't tell them what they do.
MR. BURTON: You are absolutely right.
DR. BARTON: Yes, I'm good at that.
DR. FORD: The internal corrosion, and to
ask a question. This standard that you have got not
to exceed .1 percent of water, what data was that
based on, and how much margin do you have if you have
maintained that specification? How much margin do you
have?
MR. BURTON: I don't know. Jim, can you
speak to that?
MR. DAVIS: I am Jim Davis. That is
really more for damaging equipment than it is for
damaging the tank. You don't see any damage to a fuel
oil tank because you have got water in it, because the
oil keeps you from corroding. You just don't see the
damage.
DR. FORD: Are the two liquids -- well,
does the water just fall to the bottom?
MR. DAVIS: Water falls to the bottom,
yeah, but you still have a film of oil there, and you
just don't see that damage. I have seen air cushion
vehicles operating in sea water in Vietnam, and the
oil coming out of the gas turbine engines coated the
steel bolts connected to aluminum.
And there was absolutely no corrosion, and
I couldn't believe it, but there was no corrosion.
DR. BARTON: Did you ever see a thousand
gallon fuel oil tank on a boat that has got water in
the fuel oil, and it gets holes in the bottom of the
tank and leaks a thousand gallons of diesel fuel in
the bilge? I have.
MR. DAVIS: Yes, I have seen that.
DR. BARTON: Well, what is different here?
You are telling me that you have got oil protection
coating, and you have got the water, and there is no
corrosion. Well, how come it corrodes in the boat,
and it doesn't corrode in those tanks?
MR. DAVIS: That's sea water, and --
DR. BARTON: I have got sea water in the
tank?
MR. DAVIS: You can, yeah. I mean, you
are right in the ocean.
DR. BARTON: Okay.
MR. DAVIS: But really what I pushed for
and what they actually do in a lot of these instances
that I don't want to take credit for, is there are
well-established methods for determining corrosion of
these tanks, and you normally are more concerned about
corrosion from the soil than you are from the
interior.
DR. FORD: Is it protected as well --
DR. BARTON: No.
MR. DAVIS: And if you own a gas station,
there are certain things that you have to do that the
nuclear industry doesn't do. And I came from the oil
and gas pipeline industry, and pipeline coatings.
And there are very simple techniques that
you can use to determine how good your coatings are.
You know, if you coat a pipe for the Department of
Transportation to transfer oil or gas, you have to
cathodically protect it and coat it.
And you have to do a subpipe to soil
potential survey every year, and that tells you
exactly where you have any problems, but NEI refused
to accept that. And so we put in a provision that
-- and it's not just if you are having a leak.
If you are going in there to make a
change, or you are going in to modify a line when you
look at the coatings, and we have a sub to that on all
of the license renewal applications.
But you can do a coating conductance
measurement, or something like that. A lot of the
utilities actually do that, but they don't want to
take credit for it because they didn't purchase their
rectifier safety related and that causes some
problems. So they are actually doing more than they
are taking credit for.
DR. FORD: I noticed that they say here
that incidents of such leakages is very low. But what
would be the consequence?
MR. DAVIS: Well, they are following EPA
rules. If they have a leak in a fuel oil tank, they
have to clean it up, and that is very, very expensive.
DR. FORD: Well, I was thinking more in
terms of that, but also the safety of the plant.
CHAIRMAN BONACA: Well, you have four
tanks and probably the leakage would be small at the
beginning.
DR. FORD: So we are banging something to
death.
DR. KRESS: Well, this is as to a safety
issue.
DR. BARTON: Well, I think you were about
to ask the licensee what his inspection program would
be?
MR. BURTON: What is his normal practice,
yes. And I don't know if we have the people here to
do that, but if you can talk a little bit about what
is normally done when you go into the tanks and things
like that, and the scope of any follow-up activities
that would apply to other tanks. If any of you all
could speak to that.
MR. BAKER: The ultrasonic examination
that we did -- and again this is Ray Baker, but the
ultrasonic examination would not be a routine thing.
And we took the opportunity to go ahead and do that.
And if a tank was being cleaned, certainly
you would visually observe the condition. You would
note whether there was any localized corrosion on the
interior. And, of course, that just deals with the
interior of the tank.
And as was said, you would not expect to
see anything in there, because there is -- except
perhaps the oil vapor space would be where you might
be likely to see something if there was anything,
because the rest of it would be coated with oil, and
would be very resistant to attack.
The exterior surface would be observed by
our excavation procedure. If you excavated for any
reason -- you were doing a plant modification and it
required exposure of a part of a buried component,
even though there was no leak or anything that had led
you to that excavation, you would still bring in the
coating specialist to check the condition of the
coating. That is excavation for any reason.
MR. BURTON: And if you did find
something, you have processes to deal with that, and
to identify the possible scope of the problem.
MR. BAKER: That's right.
MR. BURTON: And things like that.
MR. BAKER: Correct, and the corrective
actions program is applied across all of our license
renewal programs. So it will assure then that if the
individual program does not have built within it the
tracking and trending, the corrective actions program
assures that it gets tracked and corrected, and
remediated.
DR. BARTON: If I understand you
correctly, if you had to go into another tank for
cleaning somewhere down the road, you would do a
visual of the interior of the tank. That's what I
thought I heard you say.
MR. BAKER: That's correct.
DR. BARTON: Why did you do an ultrasonic
on the 1-A tank?
MR. BAKER: Because we knew that this was
an issue that was being raised and we just wanted to
satisfy ourselves and the staff that what we expected
the result to be was in fact what we found.
And that if we had found something
different, then that piece of operating experience
would have been factored into what we proposed as
appropriate aging management programs.
DR. BARTON: So based on that, you don't
plan on doing anything for the next X number of years
on any of these tanks?
MR. BAKER: Unless operating experience
were to show that there was something going on that we
did not expect to see. And as was indicated, we -- I
think all licensees probably do more than they have
committed to doing just to assure themselves that they
do maintain that equipment.
So if we were to observe anything, the
operating experience is a piece of the equation to
factor in and do self-correction on these programs as
we go through the period of extended operation.
We can't just ignore operating experience
just because we now have the license for an extension.
We continue to see what is happening not only at our
plant, but in the industry.
DR. KRESS: If you had a leak, would you
know about it? Do you have liquid level measurements
in those tanks?
MR. BAKER: It would have to be a pretty
significant leak to observe it right away I think.
But ultimately you would observe it, and as was said,
that would be a pretty big deal. You would be in
trouble with the EPA, and there would be an expensive
process.
DR. BARTON: It would be cheaper to do an
ultrasonic if they ever opened another tank than to
clean up if I had a leak.
MR. BAKER: Yes. And I am not saying that
we would not do that apart from what is committed to,
because I know in other areas of the plant we have
some aggressive programs to do radiography in areas
where we are looking to see if there is wall thinning.
So it is not something that we want to ignore. You're
right.
DR. BARTON: Okay. The reason that I am
being a stickler on this is because I was at a plant
that ended up with tanks leaking, all right? And then
after 30 something years, you know?
So here you are doing a one-time
inspection for 60 years, and then you are saying
everything is hunky-dory, and I am not going to do
anything else, and that is what bothers me. All
right. End of my spiel.
CHAIRMAN BONACA: I have just one more
question. How do we treat this for -- if I remember
for the other applications, they also had one time
inspections.
MR. NAKOSKI: That's true. That's true.
MR. BURTON: I want to -- and I think it
will get to yours, too, because I don't want to let
Dr. Barton's question go just yet, because I
understand where you are coming from in terms of what
it says in the application.
It sounds like we do a one time
inspection--
DR. BARTON: Of one tank.
MR. BURTON: -- of one tank, and the
results were satisfactory, and we don't need to go on.
DR. BARTON: And I won't do anything else
unless I have a leak.
MR. BURTON: Right. I think -- and
probably we need to clarify this in the SERs, is that
-- and when Mr. Baker talked about operating
experience, it is more than just even the operating
experience at that particular plant.
One of the things that -- and it is an
ongoing think that is factored in, is that if there is
any evidence that this commodity group shows evidence
of leakage or any kind of degradation, the license
renewal process factors that knowledge in, whether it
is plant specific operating experience, or industry-
wide operating experience.
And that is an ongoing thing that goes on
now, and will continue to go on into the renewal term.
So your concern that we look at it this one time, and
it is never looked at again, is really not what
happens.
But if we need to clarify that in the SER,
that probably would be beneficial to talk more about
some of the more routine things that go on.
CHAIRMAN BONACA: And also I think you
might want to think about it in terms of -- and this
is in preparation for the presentation for the full
committee, but in terms of the specific definition of
the rule, I would suspect that this is a support
system and this failure could cause safety systems not
to perform.
MR. BURTON: The aging criteria.
CHAIRMAN BONACA: And you went on to look
at it in the context of what would it take to lose
function, which means to empty the tank to the point
where you are really losing inventory, because from
the perspective of the rule, that is really it seems
to me the objective you have.
DR. KRESS: But the question is, is there
a safety concern, and that would be one question.
CHAIRMAN BONACA: And they would be going
into that. So I think that is clearly an issue that
we raise, and want to talk about.
DR. KRESS: If there is no safety concern,
it just seems like it is up to the applicant to deal
with it the way that he wants to.
CHAIRMAN BONACA: Correct.
MR. DAVIS: This is Jim Davis again.
Under the current regulations, they require nothing.
CHAIRMAN BONACA: Well, that's why before
I was asking what is the regulation asking for under
the current --
MR. DAVIS: There is no requirement.
CHAIRMAN BONACA: I was asking before what
do the current regulations require for the current
term, and the answer is --
MR. DAVIS: That there is no requirement.
CHAIRMAN BONACA: -- there is no
requirement. But I think the presumption is that you
would leak oil at a rate that would not -- well, by
the time that it manifests itself, you would still
have sufficient inventory in the four tanks to run
your four diesels for the commitment that you have in
the FSAR.
MR. BAKER: Dr. Bonaca, if I could
clarify. There are two sets of tanks that are of
interest when you are dealing with the emergency
diesel generators. These are the bulk fuel oil
storage tanks.
The day tanks, which are associated with
the immediate operability of the diesel generators,
are above ground and are separate tanks. So these are
just the bulk fuel oil storage.
CHAIRMAN BONACA: Okay.
MR. BURTON: Okay. But we will be
prepared to talk about that a little bit more next
week. The next open item was 3.1.11-1, having to do
with stress corrosion cracking of high-strength bolts.
The issue was that we know that bolting
that has a yield strength below 150 ksi is not really
subject to stress corrosion cracking.
DR. KRESS: Why is that? Does that have
to do with residual stresses?
MR. DAVIS: This is Jim Davis. It is the
microstructure of the material. We know that
materials that have a yield strength above 150 ksi can
be subject to hydrogen embrittlement actually. We
call it stress corrosion, but they can crack just in
moist air.
DR. KRESS: Because they have a very small
micro structure?
MR. DAVIS: Yes. It is probably -- well,
it is a strength issue, and it is related to the
microstructure. So the specifications say a minimum
of 125 ksi yield, and what happened was that we saw
yields in the neighborhood of 175, and made sure that
they met the 125.
And after a lot of study, we found that
anything below 150, really you don't see the cracking
problems.
MR. BURTON: It's great to have a
materials guy around. Thanks.
CHAIRMAN BONACA: Well, with this issue --
well, go ahead.
DR. FORD: May I ask -- well, in this item
you say an approved thread lubricant.
MR. BURTON: I'm sorry, what?
DR. FORD: It says to be lubricated with
an approved thread lubricant. It is not molybdic
sulfite by any chance?
MR. DAVIS: No. That has been found to
cause cracking very definitely. A lot of the cracking
problems were related to the thread lubricant, with
molybdic sulfite decomposed to hydrogen sulfite.
DR. KRESS: So the resolution is or
experience has shown that these particular bolts had
a cracking problem?
MR. BURTON: Right. These bolts are used
across a number of different systems, and what we
found was that when we asked them to go back and look
at some of the procurement data to see what that high
limit was, it wasn't in the documentation.
So what they did was that they went back
and again looked at operating experience and found
that stress corrosion cracking for these bolts, that
they really had not seen it across the industry.
DR. KRESS: And where do they use these
bolts? Are they around the head, or --
MR. DAVIS: They are used everywhere.
There is about 40,000 of them in the plant. They are
used on pumps, valves.
DR. KRESS: And in the primary system they
are used?
MR. DAVIS: They are used in the primary
system, and in the primary system the only place that
I am aware that they are used are in pumps and valves.
Everything else is welded.
CHAIRMAN BONACA: Let me tell you what
makes me a little bit uncomfortable about this. Just
a month ago, we looked at Turkey Point and the same
issues. And they say, oh, yeah, in fact we are
concerned enough that in our procedures we have a
limit of 150 ksi in our positions, and so when you
tork these bolts, you don't go above that.
Now here we are a month later, and we see
a different applicant that says, oh, there is no
issue. Well, I am left with the feeling that we don't
know where this is coming from.
MR. DAVIS: They are two different issues
actually.
CHAIRMAN BONACA: Were they?
MR. DAVIS: Yes. The high strength steel
issue is the yield strength can't be above 150 ksi,
and for A286 bolts, which are a corrosion resistant
fastener, if you tork those above 100 ksi, then you
are going to have stress corrosion problems. Those
are two different issues.
CHAIRMAN BONACA: So two different types
of bolts.
MR. DAVIS: Right.
CHAIRMAN BONACA: Could you explain to me
exactly the difference again?
MR. DAVIS: Well, they had both issues at
Turkey Point, and we raised -- or I raised both
issues, and that is the high strength steel with the
yield strength above 150, and what they did was they
did a license event report review, and found that they
had no operating history of any problems with those
bolts.
With PWRs, there is another issue, and
that is that when you do system pressure tests, you
have to remove the insulation, and inspect the bolts,
and there is a code case N616 that says -- ASME Code
case that says if you have corrosion resistant
fasteners, you don't have to remover the insulation.
And we impose some requirements on heat
treatment and applied stress. For 17 -- and stainless
steel, you have to temper the temperature, or the age
of the temperature above 1100F, and then you won't get
into stress corrosion problems.
With A286, if you apply a preload above a
hundred ksi, you are going to start seeing stress
corrosion cracking.
CHAIRMAN BONACA: So you think it is still
appropriate after the discussion, that it is
appropriate to have Turkey Point have their procedures
stay below 150 ksi?
MR. DAVIS: Yes, that's right, and they
went back and looked at the certified material test
reports to show that either they didn't have any above
150, or that they had no experience with any cracking.
CHAIRMAN BONACA: And I went back to the
Turkey Point, and in the discussion I just could not
pick out the difference, and maybe I should have.
Thank you.
DR. FORD: But the point here is that the
minimum yield -- this is for the specifications,
procurement specifications, with a minimum yield
stress of 105, and there is no upper limit stated. So
they were lucky. They weren't above 150.
MR. DAVIS: Well, actually, there have
been some that are above 150. They have been as high
as 175. When people start seeing cracking problems,
the industry kind of modified that specification and
they are asking -- well, most of the industry, and I
won't say for everybody. But they are saying that
between 105 and 150 yield.
DR. FORD: But for these applications,
would it not be wise to impose it on the
specification?
MR. DAVIS: I think that they already know
that.
DR. FORD: Well, there is a difference in
knowing it and in fact demanding it I would expect.
MR. DAVIS: We could do that, but that's
not really the issue, because there is 40,000
fasteners already installed in that plant, and if we
did a back-fit analysis and remove the antibolts with
a yield strength above 150, we couldn't satisfy the
back-fit requirements under 50.109.
DR. FORD: But if you go into license
renewal in the future, this will occur, and it should
be documented, and in the future you will not or
should not.
MR. BURTON: Well, I think that the
industry is aware of the fact that if they maintain
high strength steel fasteners with a yield strength
above 150 that they can get into trouble.
But that is not the real problem, because
they don't change these fasteners all that often.
They have got 40,000 fasteners in there, and they are
not going to go back and change them.
And unless we do a back-fit analysis and
show that there is a problem, then we can't justify
that. I am aware of two cases where there have been
a problem in the nuclear industry, and that is at
Dresden.
And they had closure studs that were
overly hard, and they had two of them that cracked.
But there has been no other occurrences, but I still
ask the question just to make sure
MR. BURTON: Okay. Thank you, Jim. The
next open item was 3.1.13-1. This open item actually
had three parts to it. The first part -- and we have
actually started to talk about this -- had to do with
buried components.
The license renewal application credited
this for managing aging effects of buried components,
but when you went to the actual write-up in the amp,
it didn't really speak to the buried components.
And so as a result the applicant clarified
that the protective coatings program, that amp, is
really what does the managing. But what happens is
that again, going down to these site procedures, the
site procedures invokes an inspection that is part of
this program.
And part of that inspection is to use
protective coatings personnel to look at the buried
components, and they use the protective coatings
program to do that.
So there is a linkage between the two
applications, but the staff was a little unclear as to
what the linkage was. So they clarified it.
CHAIRMAN BONACA: And that was brought up
by the clarification in fact now. So is the
commitment only in site procedures, or is it also a
license renewal commitment?
MR. BURTON: The commitment -- well, go
ahead.
MR. BAKER: It is programmatic. It is in
the program, yes, sir.
CHAIRMAN BONACA: In the program?
MR. BURTON: Yes, sir.
CHAIRMAN BONACA: All right.
DR. BARTON: And the words in the SER say
that you will place this in the instruction. My
question is have you already done it?
MR. BURTON: Yes.
MR. BAKER: On that particular one, the
trigger to get the coatings specialist in when buried
components are exposed is already in the site
procedures.
DR. BARTON: And they will be examined by
a protective coating specialist? That is already in
the procedures?
MR. BAKER: The trigger to do that is
already in there, yes, sir.
MR. BURTON: And we will make that change
to say that it has been done.
DR. BARTON: Good, because this looks like
you are going to do it when you go to license
extension.
MR. BURTON: All right. Now --
DR. BARTON: Don't end up. I have another
question with this one. There is a third part to
this, Part C. Are you going to break this up into
three pieces, or are you going to be done with it?
MR. BURTON: No, no, go ahead. Ask your
question.
DR. BARTON: The staff proposed to close
the site and based on the applicant stating the plan
is to inspect portions of PSW piping that is
surrounded by guard piping during an outage during
February of 2002.
Now, I heard what John said, is that they
are going to have tracking, and these guys are going
to do this inspection, et cetera. Are you prepared to
make sure that any outage scope of this February 2nd
thing, that this is already in there?
MR. BURTON: Actually, let me put some
context in there. What happened was that when we went
down for the scoping inspection, there were three
issues associated with this, and we have jumped to the
third issue.
DR. BARTON: This is the third issue.
MR. BURTON: So let me speak to that and
then I will go back to the second one. This has to do
with the plant service water guard pipe. What
happened was that during the scoping inspection, one
of our regional inspectors, going through some of the
diagrams, saw this section of guard pipe, and it just
wasn't discussed at all.
So the question came up should this
component be in scope. So Southern Nuclear went back
and looked at it, and looked at the intended function.
There is absolutely no documentation anywhere of what
this guide pipe is supposed to be for.
So they went through there and asked their
eight questions for the scoping criteria, and found
that it did not have an intended function, and so it
was not put in scope.
The problem is that this guard pipe is
actually welded. It is in the diesel generator
building. I guess it is about a hundred-foot section
or so, and it is welded at each end to the exterior of
the plant service water piping, which is in scope.
So what it does is that it creates an
internal environment that we are not sure what it is.
So again common sense tells you when they welded it
that it is probably just dry air in there, and that
there probably isn't any aging effect associated with
it, but we don't know that for sure.
So what they said they would do is that
during the next outage, they would actually go in and
put in a baroscope or something, and take a look in
there, and see exactly what the environment is.
Again, we don't anticipate any adverse
aging effects. but if they go in and they do find it,
again it gets fed into the corrective active program,
and is dispositioned accordingly.
DR. BARTON: My question is whether it is
already in the outage scope, or is nailed in the
outage scope for the February 202 outage, and has the
NRC confirmed it is in the outage scope? That is my
question.
MR. BURTON: Right now do you guys have it
as part of your plans for the outage?
MR. BAKER: We plan to do it. I can't
speak to whether it is in an outage scope of work
activities, or whether NRC has confirmed that it is
there. But the engineer who is going to be doing that
work is planning on doing that work.
DR. BARTON: The reason that I asked the
question is usually this close to an outage, your
scope is frozen.
MR. BAKER: That's right.
DR. BARTON: And if it is not in there
now, are you going to be able to get it in there, and
has the NRC confirmed that it is in there. That's my
concern.
You made a commitment to do it, and I want
to know if it is in the outage scope, and it is
approved in the outage scope, and the NRC is satisfied
that it is in there.
MR. BAKER: What we should so -- well, we
can call back and ask. I am certain that it is,
because I was just talking with the individual this
week about it again, and he said, yes, that is still
on track, and we intend to do that. So I will get
confirmation on that before the day is over.
DR. BARTON: Thank you.
MR. BURTON: And let me just say from our
end that given the circumstances, we weren't sure
whether we needed to lock this in with a license
commitment, or license condition and that sort of
thing, because they are saying that they are going to
do it in February, which is like the time frame when
we are talking about issuing the renewed license,
again it was another timing issue where things could
be working at cross-purposes.
DR. BARTON: I am just reading what they
said, and I am asking did they do it, and are they
sure it is in here, and are you guys satisfied.
MR. BURTON: Right. And I will say that
on our end our resident inspector, he has it on his
"to do" list togo and check that out when that is
done. So we expect that to be done in February, and
we have the things in place to make sure that it is
done.
DR. BARTON: Thank you.
MR. BURTON: Okay. Now, let me back up to
issue number two. Now, I wasn't sure whether you were
talking about a third part in the first issue or just
the third issue. But it is no problem.
We needed some clarification regarding the
treatment of the RHR heat exchangers. The activities
in the PSW and RHR service water inspection program
apply across a number of components, including heat
exchangers.
There is another aging management program,
and I have an open item associated with that, but it
is the RHR heat exchanger augmented inspection and
testing program, which also speaks to activities
associated with the RHR heat exchanger.
So the issue came up, well, which one does
what. So part of the resolution was that they
clarified this program, and the plant service water
and RHR service water really does more than just a
visual inspection of surfaces.
Whereas, the RHR heat exchanger augmented
inspection testing program is really the primary amp
to deal with components in the RHR system, looking at
internals and things like that.
So they just clarified the scope
difference between the two. Okay. Let's see. The
next open item, the reactor vessel monitoring program.
This is another aging management program. This
program actually is sort of a compilation of three
different things.
There are three parts to it. There is a
fatigue monitoring aspect, which actually is done
through an aging management program called the
component SLIC or transient limit program, CCTLP. It
is done through that, and there is also aspects to it
that are TLAA.
Another aspect of the program are code
required augmented inspections and tests, and that is
done through the ISI program, which is also one of the
aging management programs that they credit.
The third has to do with surveillance
materials testing, and that was the basis of the open
item. The issue here is that there is a BWR VIP 78
for an integrated surveillance program, where they are
trying to work the surveillances across the entire BWR
fleet.
The problem is that when they submitted
the application the staff was in the process of
reviewing this. Now, the current status is that we
finished the review, and I am going to turn to Gene
just to be clear exactly about what the status is of
VIP-78, and its associated implementing document, 86.
If you want to speak to that for a second.
MR. CARPENTER: This is Gene Carpenter.
Basically, the staff has completed the review of the
BWRVIP-78 and the VIP-86 document, which is the
implementation plan.
We are in the process of documenting that
in a safety evaluation report, and that should be on
the street within the next month or so.
MR. BURTON: Thanks. So what we had was
that we had the crediting of a document that hadn't
gone through our review process yet. So what we had
was that we asked them either to commit to that, or if
that doesn't go through, to commit to a plan specific
material surveillance program.
And the open item came out that we need
this to be clear that those will meet Part 54, and the
10 attributes for the aging management programs. So
we needed to get that commitment.
We did get it, and they said we will do
one or the other. Either way, it will meet the
requirements of Part 54, and the 10 attributes, and we
locked them in with a license condition. That is the
third license condition. The first two I already
mentioned having to do with the FSAR supplement, and
this was the third one.
DR. FORD: I am a little bit unsure about
the 78. It was only applicable to the current
licensing period, and they are going to put in a
supplement due in 2002 for the extended period?
MR. CARPENTER: That is correct.
DR. FORD: What are the details of that?
Why is it limited to only the current licensing
period?
MR. CARPENTER: As the VIPs of the
document is presently written, it is for the current
operating term. The reason that it is not at present
for the extended operating period is because the
BWRVIP program takes credit for a variety of plants
surveillance materials.
When the program was initially implemented
or put together by the BWRVIP, they still were not
sure which licensee, which BWR licensees, were going
to be going for a license renewal.
They are in the process at this time of
finalizing which plants will be in the license renewal
period, and they will be able to take advantage of.
This is going to be a somewhat fluid
matrix, because as things change, they need to have
something that is flexible enough, a program that is
flexible enough that will allow for Plant X, Y, Z,
which would be one that they would take credit for,
does not for whatever reason go into the license
renewal period.
They need to be able to be flexible enough
to move to another plant and to make adjustments for
it. So this is something that the staff and the
BWRVIP are working together on to ensure --
DR. FORD: And this relates to the number
of capsule samples at various fluence levels, and
instead of going into the expected fluence for a given
plant in a license renewal period, or is it something
to do with that? I am trying to work out why you need
all these other licensees to --
MR. CARPENTER: Well, it is an integrated
surveillance program, where you have one licensee
pulling its capsules and several other licensees being
able to take advantage of that study.
DR. FORD: So you are studying all the
fluence levels?
MR. CARPENTER: Correct.
DR. FORD: Okay. That is what I was
getting at.
MR. CARPENTER: Yes.
DR. FORD: Okay.
MR. CARPENTER: Robin, did you want to add
something?
MR. DYLE: Yes, Gene, thank you. This is
Robin Dyle of Southern Nuclear. The VIP-78 document
is the technical basis document for why an integrated
surveillance program is appropriate, and how you would
go through and screen for fluence materials and select
the best capsules that would be representative for the
fleet.
And that 86, as Gene correctly
characterizes, is the implementation schedule. We
believed at the time that we put it together that all
those plants would go for license renewal, and for one
reason or another we are not ready to make that
commitment.
And instead of sitting on the
implementation schedule, we put one together for the
current term, and submitted it, and then we will
revise the implementation schedule. The technical
basis won't change.
We have to be able to predict fluence, and
we have to be able to test a range of capsules that
will give an overview of what the fleet behavior is
for vessel embrittlement. So that is the way the
program is put together.
Just as a note, both Hatch units capsules
were going to be pulled as part of the ISP anyway, and
so it doesn't affect Hatch one way or the other. That
is where we currently are.
MR. BURTON: And that is an important
point, and that's why they can make the commitment
that if 78, for whatever reason, doesn't work out,
they can do it themselves.
CHAIRMAN BONACA: Okay. Good.
MR. BURTON: The next open item was
3.1.18-1, having to do with fire protection. There
are actually two issues associated with this. The
first one had to do with the adequacy of system flow
tests to be able to manage aging.
This was another one of these issues that
was being worked at cross-purposes generically, and
what was finally determined was that we did not need
to have system flow tests per se as part of the aging
management program.
It is currently done already and will
continue to be done in the extended term. But what we
do have is that we do have an aging management program
called fire protection activities, which is primarily
inspections.
And so the idea is that those inspections,
as part of the aging management program, along with
the ongoing flow tests, should together be adequate to
manage aging for the fire protection components in the
extended term.
DR. KRESS: Did you inspect just the
heads?
MR. BURTON: The extent of the inspection?
I don't think it was just the heads. I think they
look at the piping and all the way up and down. I
think they look at everything. There are some issues
with the heads which I am going to get to, but yeah.
DR. KRESS: And what did the flow tests
consist of? Do they actually turn these on?
MR. BURTON: Well, what it is -- well, I
do actually have some notes about that. What they
have is what they call an inspectors connection, and
which is at the furtherest end of the system. And
what they do is that they actually just run the flow
all the way through.
DR. KRESS: Run it into a bucket or
something and that tells you how much?
DR. BARTON: Yes, I guess it is a bucket
or something like that.
DR. KRESS: So it is a measure of the flow
rate?
MR. BURTON: Right, and the existence of
the flow, right.
MR. BAKER: At the furtherest point of the
branch connections, right.
MR. BURTON: Right.
DR. KRESS: So what that tells you is that
when you turn the system on that you are going to get
flow?
MR. BURTON: You are going to get flow,
right. Now, the issue --
DR. KRESS: And what does that tell you
about aging; that was my question.
MR. BURTON: Well, that was the question.
Does that really tell you anything about age related
degradation, and the question was that it really
didn't. What you really have to rely on is actually
doing the inspections to see what is actually going
on.
But between that and the flow tests, you
have kind of got everything covered. But, yes, the
actual age related degradation, what we are depending
on and what is being credited for license renewal, are
the inspections as part of the fire protection
activities amp.
DR. KRESS: So my question once again is
how extensive is the inspection, and what all does it
look at, and how often?
MR. BURTON: And I can either speak to
that, or -- oh, Tanya. I'm sorry. You did come back.
MS. EATON: This is Tanya Eaton, NRR, and
I was the fire protection engineer that reviewed the
application. And Jim just told me, as I was out, and
he said that you all were asking questions about the
inspectors flow test, and how that is performed.
I know that -- well, I don't know if Butch
explained this, but usually the most remote connection
from the water supply, and so what they do is -- and
I know, for example, with ANO, their connection was on
the roof of some building somewhere.
And it hydraulically is the most remote
point from the water supply. So when they flow that,
they are able to look at the water to see if there is
any type of corrosion products that are coming from it
or anything.
I don't know that they tested it. That is
not an NFPA requirement. Usually, they are just
trying to ensure that they are getting flow through
the system.
DR. KRESS: How often do they do that?
MS. EATON: I think it is annual. If you
look in NFPA-13 requirements, every year they will do
the inspectors flow test.
DR. FORD: As I read this, it is saying
that you could have a situation of the year 49, for
instance, and you suddenly want to turn on the
sprinkler systems, and you are hoping that nothing has
occurred from a corrosion point of view. And this is
not the time to be assuming no corrosion is going to
occur in 49 years.
CHAIRMAN BONACA: This is the second issue
item.
MR. BURTON: Yes, we are actually getting
into the second issue.
CHAIRMAN BONACA: And that is an
interesting one by the way, Issue Number 2. I just
don't understand -- you know, it seems to me that the
earlier that you perform an inspection the better off
you are.
Now, we understand that the licensee
proposed to perform a one time inspection before 40
years. And the staff said no, and you have to go
NFPA, and the NFPA requires a one time inspection of
50 years.
MS. EATON: It is not one time.
DR. BARTON: It is 50 years.
CHAIRMAN BONACA: Fifty years, because it
says 50 years, and then your intervals. Well, at 60
years, the plant is retired, at least for this
license.
MS. EATON: I can address that. The time
-- well, if you look at the NFPA requirement, it
requires at 50 years of service life of the
components, and if you look at what I think Hatch was
doing in this case, at 40 year operating life, their
suppression system -- I think the sprinklers were
going to be something like 46 or 47 years old.
So at that point when they were testing,
right before they go into renewal, the system was
already going to be 47 years old. And I think
initially that they proposed to do this as a one-time
inspection.
The NFPA 25 requirement is that you do it
at 50 year service life, and then you do it at 10 year
intervals thereafter, and that is what we were trying
to have them do, which was not just to do the one
inspection.
CHAIRMAN BONACA: So at the end of 50
years, you are telling me that 50 years will come
actually after 3 or 4 years in the new licensing
period.
MS. EATON: Right.
CHAIRMAN BONACA: You see, that is not
clear in the SER at all. The SER speaks of 50 years,
and 50 years from the moment of the license, and you
are telling me that actually you are starting the
clock years before.
MS. EATON: When it is installed and
operable, right.
CHAIRMAN BONACA: So for the 50 year --
all right. I think it would be important to have some
clarification in the SER just to specify that that 50
years -- well, because when you read that, you are
saying, well, you give up at 40 years of inspection,
and then you are waiting 10 years longer.
And that way you would have two
inspections than one at, say, 43 years, and the other
one at 53.
MR. BURTON: Right.
MS. EATON: Right.
DR. FORD: When they came up with this
specification, this 50 year business or whatever the
number, they are very large numbers.
MS. EATON: Right.
DR. FORD: What data is --
MS. EATON: I think what NFPA looked at
was that their program, NFPA-25 has programs for the
inspection, testing, and maintenance of fire
suppression teams, and that in most cases it was their
understanding that if you follow those programs that
at your 50, that's when you really need to begin
checking for the type of failures that you might see
due to corrosion.
And with most licensees, we found that
they would commit to NFPA-13, which is the sprinkler
code that requires them to install suppression
systems, and then they will have maintenance procedure
inspections that are in accordance with the NFPA
requirements that they follow. And that is all the
information that I have.
DR. FORD: It just seems an incredibly
long time --
MR. BURTON: Yes, it is a long time.
DR. FORD: -- of being assured that no
corrosion has occurred.
MS. EATON: Right. The NFPA requirements
are also the minimum requirements. It is always up to
whoever the authority having jurisdiction is, which in
this case will be the NRC to say that we require
beyond that for these types of applications.
If we see that there is evidence out there
that shows that there are problems being experienced
in cases of less than 50 year time periods.
DR. FORD: Well, shouldn't the NRC be
applying -- I mean, this thing was done for warehouse
--
MS. EATON: No, NFPA-25 is -- a lot of
industries outside of nuclear use that as guidance for
whatever their particular industry is. And so in the
case for the NRC, if we find that -- well, for nuclear
energies, we think that they should look before 50
years, and we would need evidence to support that from
our perspective.
I know that there have been studies done
in the fire protection section to look at corrosion
and blockage due to corrosion, and those types of
things. And we were unable to find any cases or we
looked through licensee event reports, inspection
reports.
And there were two studies. One was done
in the '80s, and another in the '90s, and I don't have
the numbers now. But the conclusions reached were
that the licensees were aware that this could be a
problem.
They had programs in place to at it, and
to manage it if it were a problem. It is not just a
license renewal issue. That is more of a current
licensing issue.
CHAIRMAN BONACA: Are these wet pipes or
dry pipes?
MS. EATON: For NFPA-25?
CHAIRMAN BONACA: Yes.
DR. FORD: Carbon steel pipes.
MR. BAKER: Let me clarify. Dr. Bonaca,
this is Ray Baker again. The item that we are talking
about here is an inspection of a -- it is actually a
destructive examination of a closed-head sprinkler.
And that is a separate issue from all of
the other more general fire protection activities,
where you are concerning yourself with corrosion, and
blockage, and these other things.
The specific issue here relative to this
50 years of service testing is to ensure that that
closed head sprinkler will actually actuate, and that
is the thing that NFPA-25 is addressing itself to with
regard to this 50 year service test.
And just to clarify the distinction that
we are not talking about corrosion and those kinds of
things with regard to this sprinkler.
DR. FORD: The stocking --
MR. DAVIS: That is part of the assurance
that we give ourselves with the system flow test at
the furthest branch connection to ensure that
throughout that entire time period we are not
accumulating a corrosion problem that might lead to a
flow blockage situation.
DR. KRESS: It seems like the corrosion
products would accumulate in the head.
DR. BARTON: That's where they will go.
MR. BAKER: Well, on these closed systems,
there is not going to be any flow in those branch
lines.
DR. KRESS: Well, there is static all the
time.
MR. BAKER: Right. Right.
DR. KRESS: Stuff can't get down there.
DR. BARTON: It has a lot of moist carbon
steel, and it is a dry system or --
MR. BAKER: No, it is a wet system.
DR. KRESS: They have little pony puffs
that they can't pull.
DR. BARTON: So you have got air in there,
and water, and you have got some corrosion in the
pipe.
MS. EATON: The NFPA requirement for 25
does require that you test a sample of each type of
sprinkler head that is in the plant. So if they did
find problems, then they would have to go back and
replace those heads.
DR. KRESS: You made a study of NFPA-25 to
assure yourself that it would be applicable to
nuclear, because the issues are protection of
investment versus safety, and I think that NFPA
doesn't look to you for safety does it?
MS. EATON: They do. I think the concept
is that the sprinkler systems are designed similar.
In either case, you don't want to have failure,
whether you are protecting life or equipment.
And especially in the case where you have
safety related equipment. You don't want to have
failures.
DR. KRESS: Yes, but there is a difference
whether you are protecting life or equipment.
DR. BARTON: That's right. There really
is.
MS. EATON: Right. But the systems are
designed the same, and I think that they apply them in
general throughout if you look at the NFPA-25
guidance.
DR. KRESS: But my question is, is that
applicable to nuclear, where chances of an accident is
not just limited to the site, and I would question the
applicability of that to nuclear safety.
DR. BARTON: That's a good point. Is it
Bloomingdale's, or is it Plant Hatch.
DR. KRESS: Is it an insurance issue or is
it something else.
DR. BARTON: That's right.
MR. BURTON: Okay. We will go back and
research that a little bit and get an answer for you.
DR. KRESS: I appreciate it.
MR. BURTON: Thank you, Tanya.
CHAIRMAN BONACA: Let's finish these items
here, and then we will take a break.
MR. DAVIS: I would like to make a comment
on the 50 year life. In a former life, I used to make
fire protection pipe as well.
MR. BURTON: He did it all.
DR. BARTON: No doubt about it.
MR. DAVIS: Actually, what occurs is that
most of these are static and they are always filled
with water. And when you consume -- it drops to an
extremely low value, and there were lots and lots of
studies -- and this is in the '70s that I did this
one, and I am an old guy.
But they really had some good studies and
they projected the corrosion rate, and what they
really recommend is that you don't really disturb the
system too much, because when you put new oxide in
there, it starts to corrosion over again.
All these piping systems were designed to
last 50 years, and still be within a margin of safety
just for the thickness of the pipe.
So they are just plain carbon, carbon
steel pipe. And they last that long, and they did a
lot of corrosion studies to show that they would last
that long. They have a lot of data.
CHAIRMAN BONACA: I would expect also that
if you had a lot of corrosion going on and tests that
you performed once a year, it would show the clogging
of the sprinkler heads at the end of the rods.
DR. KRESS: Except that they don't check
the sprinkler heads as I understand it.
DR. BARTON: They normally just check
flow.
CHAIRMAN BONACA: Just the flow, and as I
was saying, you would have a lot of junk coming out.
DR. KRESS: I don't think so, because I
think they would tap in before you get to the heads.
You wouldn't find out anything about the heads.
CHAIRMAN BONACA: No, I am talking about
the corrosion of the piping.
DR. KRESS: Well, you would find out
whether they had crap in the water, yes.
MR. DAVIS: And we have had plenty of
discussions on this, and what we should do, and
reflecting about maybe putting or changing it as well.
And should we make them if they are going
to go into the pipe, look and see if there is any
corrosion, and I really recommended against that, and
I think the better approach would be to do some
ultrasonic measurements, and not disturb the pipe,
because you are really doing more damage by opening it
up and looking at it, because you are reintroducing
oxygen into it.
DR. KRESS: And then you have a problem as
to where to do the measuring.
MR. DAVIS: Right. And so that's what we
are saying, and saying in GALL -- well, I am not sure
that we have made the change, and that would be to do
ultrasonic measurements for wall thickness and see if
you are losing wall.
DR. FORD: Well, that all makes technical
sense, but where does it appear in the formal
paperwork?
MR. DAVIS: I am not sure that we
addressed it with Hatch, because it was only a couple
of weeks ago that we had a really big meeting, and
discussed this for GALL. Maybe we need to take
another look at that.
MR. BURTON: Well, it is another example
of where some of the ongoing work timing wise gets
cross-purposes. So as we resolve this issue, one of
the things that we have to do is to go back and see,
number one, how does it affect those folks who are
going through license renewal right now, and how does
it affect the people who are getting ready to come in
and maybe far enough along in their application that
they can't really get to it.
And in which case obviously we would go
through an RAI process to get our arms around it. And
then how does it affect folks who perhaps already got
their license, and then you get into the whole back-
fit issue and stuff.
But those are all things that as we get
these emerging issues coming out, how do we address
it, not only -- well, you know, once we have resolved
it, how do we address it for applicants and licensees
at different phrases.
So I don't have an answer for you, but it
is something that the staff is aware of, and that we
try to do for each one of them.
Next, open item 3.1.28-1, RHR heat
exchanger inspection and testing. An issue came up
with how do he provisions in the aging management
program manage aging, or manage damage that may result
from vibration, vibration-induced cracking.
And we asked basically for a lot more
information about their methods, and their
frequencies, and all the things that you see there, in
addition to there was a tube leak in '96, and we
wanted to get a little bit more information about how
that was looked at, and how it was ultimately
dispositioned.
There were some issues with dents and
things like that, and the augmented inspection and
testing program, which I spoke about before, that is
really the main aging management program that deals
not just with the RHR heat exchangers, but all the
components in RHR.
But this one also includes activities that
ultimately between the inspections and all that stuff
will tell you whether or not there is some tube
damage, and whether it is due to vibration or anything
else.
So they provided that additional
information to try and clarify that the actions are in
fact adequate to detect that sort of thing. And then
like I said, they also gave us some additional
information on the operating experience they had
associated with the tube leak.
DR. BARTON: Before you get off of that,
look at the words in the SER. You asked four specific
questions, and the licensee responded, but they didn't
fully answer your question, and yet you signed this
thing off.
The first thing you asked for was to
provide information on inspection methods,
frequencies, acceptance criteria, about bases, et
cetera, et cetera, and they tell you I am going to do
any current testing every 10 years.
MR. BURTON: Right.
DR. BARTON: Well, they didn't say
anything about any acceptance criteria, associated
bases.
MR. BURTON: Okay.
DR. BARTON: And then in Item C, you ask
for inspection criteria, et cetera, et cetera, and
they said, hey, we are going to do general visual
inspections of the RHR heat exchanger every three
operating cycles.
And if you are satisfied with that, that's
fine, but I don't think they answered fully what you
asked for -- A, B, C, and D. They gave you partial
answers. So maybe you are happy, and maybe there is
something that is not in the SER. I don't know.
MR. BURTON: You just hit the nail on the
head. Actually, some of the supporting information
for the bases and stuff was actually in response to an
RAI, and it didn't get transferred into the final SER.
And now that you have said that, it
probably ought to be in there for clarification. But
let me give you the answers.
DR. BARTON: Okay.
MR. BURTON: For the leak testing and the
RHR heat exchange of the tubes and tube sheets, what
they said, and I think this is in the SER, that they
do 10 percent of the operational tubes.
DR. BARTON: Every 10 years, right.
MR. BURTON: Every 10 years. The basis
were test results that they have done on three heat
exchangers, where they found no damage. And they also
have a 5 percent margin, in terms of excess tube
capacity, to take into account when they -- if they
have to do any tube plugging.
And so that is what they used to provide
assurance that they could catch anything between the
intervals.
DR. BARTON: All right.
MR. BURTON: In terms of the general
visual inspection that you talked about -- and again,
for 10 years -- the basis was actually a Sandia Lab
report that recommended --
DR. BARTON: When you say every three
operating cycles, are they on a 24 month cycle?
MR. BAKER: We are going to 24 months.
DR. BARTON: You are going to 24.
MR. BURTON: Yes, every three operating
cycles.
DR. BARTON: Every three operating cycles.
Okay.
MR. BURTON: And shell side every 10
years, with bundle supports and some other things.
That was based on the Sandia Lab report, and again
operating experience.
You know, some satisfactory results from
some previous inspections. But you are right. None
of that got into the SER, and it probably needs to be
included.
DR. BARTON: Thank you.
CHAIRMAN BONACA: And you do have what you
asked for?
MR. BURTON: Yes. Yes, in response to the
RAIs.
DR. BARTON: Well, I just didn't see it,
Butch, and it should be in here I guess.
MR. BURTON: Well, I am going to make a
note of that.
MR. BAKER: Butch, I have that response
here if you need it.
MR. BURTON: Oh, okay. So we will make
sure that we get all of that to the SER. Let's see.
Next. Open Item 3.2.3.1.1-1, having to do with cast
austenitic stainless steel components, CASS
components.
The issue was that we know from the
science that CASS or Cast Austenitic Stainless Steel
components, can be susceptible to a loss of fracture
toughness as a result of thermal and neutron
embrittlement.
We also know that that will come about if
there is evidence of cracking in the components. If
there is no cracking, then you won't see the effect of
the thermal and neutron embrittlement on loss of
fracture toughness.
So the staff said, okay, well, let's do a
one time inspection to see if there are any cracks in
the components. We should ask for that. We did some
additional discussions about that, and in the end we
determined that probably at this point a one time
inspection probably isn't warranted and here is why.
First of all, when you look across the
industry, in terms of operating experience, there
really is no evidence of cracking in these CASS jet
pump assemblies and fuel supports. These are the
components that were under question.
The other portion was that the assembly
welds are already being inspected as part of VIP-41,
and that these welds actually would show evidence of
the aging effect before the CASS components in
question.
So this is sort of the precursor to it.
Once you found it in the welds, then that would direct
you through to the corrective actions process to
perhaps look at this.
But this is where you would find it first.
So based on that, we said, well, it is probably not
appropriate since we have not seen it, and we have a
precursor for it, it is probably not reasonable to ask
for it.
CHAIRMAN BONACA: Well, you have
inspections that would be a precursor to identify
that?
MR. BURTON: Right.
CHAIRMAN BONACA: You do have inspections.
DR. FORD: What is your basis for saying
that, that the assembly welds should be from a timing
component more susceptible in CASS.
MR. BURTON: Okay. We are going to talk
a little bit more about the science, and I --
DR. FORD: Well, it is not the science for
science sake. You are using that as a leader of the
fleet.
MR. BURTON: Yes.
DR. FORD: And I am just questioning what
--
MR. BURTON: Well, I can have perhaps
Robin speak to it or Barry.
MR. DYLE: I can speak to it from the VIP
perspective, and I am not sure who the staff evaluator
was. This is Robin Dyle. Peter, one of the things
that we looked at when we developed VIP-41 was that
the material and those welds are more susceptible to
IGSCC than the CASS material is.
And the inspection program requires all of
that to be inspected, and to do examinations of the
welds, and the wrought material, and that would be a
precursor before we would have to worry about cracking
in the CASS material itself, just by the general
nature of IGSCC and the material properties.
And the only way that you are concerned
about fracture toughness is once you have the
cracking, and so the inspection program -- and about
half the fleet has already done these the best that we
can tell.
And if you are looking at the entire jet
pump assembly in all 20 of them, based on how the
wrought material and the welds are behaving, that
would be a precursor before you would have to worry
about these actual CASS austenitic abusers that are at
the bottom.
That is the way that the program was put
together. The practical side of it is that when you
go down with a camera, and you have got it calibrated
to do an EVT-1 or a VT-1, knowing what the distance is
in the aim, unless you are going to be looking at
these things also jus while you are putting the camera
in place to look so that there will be some -- I
started to say collateral, but that's not the best
term. You want to avoid that term these days.
There will be some additional inspections
that occur that we just actually have not taken credit
for, but we know that it will happen.
And we are confident that what we would
see in the wrought and the welds would be a precursor
to anything being a problem with the CASS austenitic
material.
Also, as we go forward with HWC and open
metal, we can also do things to further minimize
concerns.
DR. FORD: I guess my problem with this
particular one was the statement that because we
haven't seen cracks, you never expect to see a problem
because the parent material being brittle.
And you are leaving aside the fact of how
-- that if you are going to see a crack, then how did
it get there to start with. And there is no reason at
all why you could not have some sub-critical crack
that you have not yet seen.
And to say that in the year 2035 or 2040
that these sort of flux levels, and therefore
fluences, that you wouldn't see some sub-critical
crack growth in the CASS material.
And that's why I was questioning that if
you are going to use the assembly welds, that there
are so many variables which control the initiation and
growth of a crack in a weld --
MR. BURTON: Well, this is hardly -- well,
this is 10 to the 17th.
DR. FORD: I agree with you, Bill.
DR. KRESS: This is mostly thermal don't
you think?
DR. SHACK: I think the embrittlement is
probably neutron. I mean, 10 to the 17th does a
wonderful job in embriddling fahrenheit islands, but
it is not going to produce IASCC in a non-submittal.
DR. FORD: I agree with you. I am just
pushing the questioning, and the assumption that if
you haven't seen a crack now, at this time in its
life, it doesn't mean to say that you are not going to
see it in 10 years. I mean, our industry is bedeviled
by that argument.
MR. CARPENTER: Dr. Ford, this is Gene
Carpenter, and --
CHAIRMAN BONACA: Point A I think was
pretty irrelevant to the answer to some degree, and I
think Point B was the one, because we were looking for
an inspection program. Point B is where the whole
issue is.
I mean, how credible it is that as you
inspect the welds, you will also see cracks in the
CASS components. I don't know, and that is a good
question.
DR. SHACK: You will never see the crack
in a CASS component until it busts. You are probably
better off inspecting the welds.
CHAIRMAN BONACA: Okay. So you are saying
that the welds are only a precursor. Okay. That's
right. You're right.
DR. SHACK: But I probably believe your
argument about IGSCC susceptibility. In Peach Bottom,
where did the fatigue cracks occur? Were they at the
welds, or were they in the elbows? So there is
another mechanism potentially for cracking here
besides IGSCC.
MR. DYLE: Let me be careful -- this is
Robin Dyle again. Let me be careful on how I answer
that since I don't work at Peach Bottom. I think you
are talking about the jet pump riser pipe cracking is?
DR. SHACK: Yes. I don't know. All I
know is that they had a peak problem, and I don't have
any idea where it was.
MR. DYLE: That was in the jet pump riser
pipe and that is wrought material and it is down where
the nozzle is inserted into the vessel, and it is that
elbow. And it was wrought, and so it was a
combination of IGSCC and then fatigue.
These CASS materials are further
downstream, where the defusers sits on the jet pump,
and the jet pump defuser sits on the shroud support,
and actually injects the water into the bottom end
region.
But we have seen cracking in the jet pump
assemblies and the wrought material, and at the weld
locations. Not to date in the CASS material. So we
do have the inspection program that looks at the whole
assembly.
And I believe that the precursor would be
more thorough inspections in that more susceptible
material.
MR. BURTON: Okay. Thank you, Robin. Now
-- oh, I'm sorry. Gene.
MR. CARPENTER: I just wanted to reply to
Dr. Ford's question. Basically, you are right. There
are things that could occur in 10 years that we don't
expect today.
And to address that, we are trying at this
time to put into place a research program to look at
the effects of the radiation embriddlement, et cetera,
on these CASS components.
And I can't tell you that it will be in
place in Fiscal 2002, but it will be in place well
before any of these plants go into the license renewal
term.
DR. FORD: Now, as well as the kinetics
embriddlement, what about sub-critical crack growth?
MR. DYLE: That is part of the program
that we are talking about at this time with our
research department, the Office of Research
Department.
MR. BURTON: And the truth is that we
didn't want to include it in the SER at this point
because it isn't a firm commitment on either side
right now. We expect that it is going to be done with
budgets and things like that at the point that we were
doing the SER.
There was no short commitment for that,
and so we decided not to put it in, but as Gene said,
we expect that to happen.
CHAIRMAN BONACA: Well, you do have a
discussion in the SER regarding that on page 135,
right?
MR. BURTON: Yes. Yes. Right.
CHAIRMAN BONACA: Well, we are running
late, and so for those items, we will just have
confirmation. You know, you asked for confirmation
from the licensee and he gave it to you, and just try
to go fast.
MR. BURTON: For the remaining things?
CHAIRMAN BONACA: No, no.
MR. BURTON: Oh, you are still on this
one? I'm sorry.
CHAIRMAN BONACA: No, I am talking about
on the future items that you are going to present us
with, and which you are asking for a question to them,
and they say yes, and that's what it is, try to go a
little faster.
MR. BURTON: A little faster. Okay.
There is just a couple of more in this portion, and
let me do this a little expeditiously. Open Item
3.6.3.2-1, two items regarding the primary
containment.
The first was that we were a little bit
unclear as to what was being credited to manage aging
in the TORUS, and what they did was that they provided
us with a drawing that showed very clearly the aging
management programs that were being credited, and
there are a number of them.
Basically, and I have jotted it down
because there is no way that I can remember it all,
but what they did was they identified the programs to
manage aging for the TORUS above the water line, and
then there was another set of aging management
programs below the water line, and in the splash zone.
Above the water line, they took credit for
in-service inspections, primary containment leak
testing, protective coatings, and the CCTLP, fatigue
monitoring basically.
Below the water line in the splash zone,
they took credit for water chemistry, and associated
inspections. So they did clarify that, because at
first we weren't sure how it was being done, and in
fact it is being done by a combination of aging
management programs.
So that was the final resolution for Issue
Number 1. For Issue Number 2, this is another example
when we asked this open item, this was being dealt
with as part of GALL, and again timing wise, it was
for kind of cross-purposes.
But in the end this issue was clarified
both in GALL, and Hatch's position is consistent with
that, in that they are going to use performance based
requirements and criteria to ensure that the
penetration leakage and overall containment leakage
doesn't exceed the tech specs limits. That is
consistent with GALL.
DR. BARTON: Well, in the initial item on
the TORUS water level, above and below water level
inspection, as I read the applicant's response, they
say they have taken credit for the protective coating
program for TORUS penetrations above the water line?
MR. BURTON: Yes.
DR. BARTON: I didn't get out of there
what program is covering corrosion below the water
line.
MR. BURTON: Below the water line? Okay.
DR. BARTON: I couldn't find that.
MR. BURTON: Okay. It should be right
there.
MR. DYLE: If you recall, one of the
clarifications that I provided you is that the
protective coatings also should have been applied in
the SER wording to the penetrations below the water
line.
MR. BURTON: Right. That's right.
DR. BARTON: Well, it is not in there now
though.
MR. DYLE: It was not in the SER, but it
is --
MR. BURTON: Yes, the protective coatings.
Right. That's right, and he had already pointed that
out and we will have to take a look at that.
DR. BARTON: Okay. That was my problem
with it.
MR. BURTON: Oh, just with the protective
coatings?
DR. BARTON: Well, to address what program
covers below water line. It is not answered there.
It is not in the current SER, unless I missed it.
MR. BURTON: On page 3-196.
DR. BARTON: Okay. I was looking back
here.
MR. BURTON: That was kind of a summary of
some of the stuff, but it is in the body.
DR. BARTON: It is covered in the body?
MR. BURTON: Yes.
DR. BARTON: Okay.
MR. BURTON: Okay. So I did identify the
aging management programs, and protective coatings was
missed, and we are going to have to include that.
DR. BARTON: Okay.
MR. BURTON: This is the last one of the
open items that did not go to appeal. Open Item
4.1.3-1 had two parts to it. Part (a) did not go to
appeal, and Part (b) did. So I will be talking about
Part (b) after the break.
For Part (a), it had to do with fatigue
analyses, and the issue was -- well, actually, there
were a couple of questions. For the vessel internals,
how was the fatigue analysis found to be acceptable
for the 60 years, for the extended term.
And Section 4 covers TLAAs, and as you
know, disposition of TLAAs, there are three options.
Either you can show that the analyses are already good
for the extended term, and you can project the
analyses or the evaluation to cover the extended term,
or you manage.
It turns out that they clarified that the
fatigue analysis for the internals was projected over
the 60 years, and found to remain below one, and
therefore met the second requirement.
And for the second part of the question,
were there any other coolant pressure boundary
components that were subject to fatigue analysis, and
if so, how was that disposition, and they said that
the -- they clarified that they didn't identify any
other reactor and pressure boundary components that
that would apply to.
And that's it. That was the last of the
open items that we resolved without going through
appeal. Any questions on any of that?
CHAIRMAN BONACA: If not, let's take a
recess for 15 minutes. Let's meet at a quarter-of-11,
and we will review the appeal issues or items.
(Whereupon, at 10:30 a.m., the meeting was
recessed and resumed at 10:45 a.m.)
CHAIRMAN BONACA: Let's start the meeting
again. We have now a presentation on the appeal
process, and then a discussion of the six items
resolved by appeal.
MR. BURTON: Okay. I am going to try and
go through this fairly quickly. But Southern Nuclear
had mentioned that there were a couple of things from
last session that they wanted to clarify, and if you
wanted to go on and do that real quick, Chuck.
MR. PIERCE: Yes, my name is Chuck Pierce.
One item had to do with whether the commitment
tracking program at Plant Hatch was an Appendix B
Program, and I would like to clarify that in fact it
is an Appendix B program, rather than what I said
earlier.
It is audited by our QA organizations, and
falls under Appendix B. The other clarification had
to do with whether the guard pipe inspection
activities that we are planning in the outage
schedule.
Two items here. The action item tracking,
Item 4 of this work, has been generated already. So
it is scheduled in that sense. It falls below the
level that you would see in the outage schedule or the
work schedule, per se.
But it is in fact scheduled by action item
tracking, and then the maintenance work order will be
generated as we get into the time to do that work.
MR. BURTON: Okay. Of course, Dr. Barton
isn't here to hear that, but --
MR. PIERCE: I did mention to Dr. Barton
as he went by about the Appendix B item.
MR. BURTON: Okay. Moving right along
here, I am going to go over the six open items that
did go through appeal. There were two appeal
meetings, one on March 29th at the branch level; and
a second appeal meeting on June 6th at the division
level.
And what I want to do is just go through
this chart very quickly to explain how the process
works. This is a relatively old chart, and I think
some of this may have changed, but I think that the
relevant part is still relevant.
Any time we have a disagreement -- what
did I say?
CHAIRMAN BONACA: Just keep going.
MR. BURTON: All right. When we have a
disagreement, we take it and the first level of appeal
is at the branch level, and we had several of the
items that did that. If we resolve them at the branch
level, great, and we continue on with our business and
close it out.
If we continue to have a disagreement, we
then go to the division level, and that is the next
level of appeal. Again, if it is resolved, which it
was in this case, and so we followed this branch, and
resolved the comments.
And the resolution was established and
implemented in the SER. So that is the branch that we
actually took. If there continued to be a
disagreement at the division level, we would go on and
move to the office level and so on.
But for our work with Hatch, we followed
this patch here, and of course we keep the license
renewal steering committee informed of our progress in
this. So that is how the appeal process works.
CHAIRMAN BONACA: Is this process unique
to the license renewal, or is it a process that is
used in other areas?
MR. NAKOSKI: This is John Nakoski with
NRR. I think this is a typically and fairly informal
process that is used throughout any licensing activity
or licensing action.
Essentially, if the staff and the licensee
can't agree, we apply ever increasing levels of
management attention until we come to a final agency
position that may be in alignment with what the
licensee asks, or it may not.
But having the burden of making a
regulatory decision, once we have gotten our
management to agree we established a regulatory
position and move forward. So I would say that this
is an informal process that has been used typically
throughout all licensing activities.
DR. KRESS: Suppose the lower level staff
that raised the issue in the first place continues to
disagree with the resolution after he gets up to the
higher level?
MR. NAKOSKI: The recourse is that the NRC
-- well, we fully support the right of any individual
on the staff to have a differing professional view or
differing professional opinion, and we will take
appropriate actions consistent with those programs.
DR. KRESS: Okay. Thank you.
MR. BURTON: The first open item, Seismic
2 over 1. We have spoken a little bit about it in the
previous session. The issue is that structures,
systems, and components that have been identified as
seismic 2 over 1, should those be in scope and be
subject to an AMR.
The specifics of what brought this to
light had to do with some piping segments that were
seismically supported, and as a result of being
seismically supported, Southern Nuclear felt that the
associated pipe segments didn't need to be brought
into scope, because with them being seismically
supported, they wouldn't fall during a seismic event.
And we asked them to consider that, and
they considered it to be hypothetical, and the reason
that it is hypothetical is that there has been no
industry experience of piping, whether new or old
piping, that has actually fallen during a seismic
event.
The staff's position was that when you
look at operating experience, we in fact have a lot of
operating experience that shows that pipes have failed
due to age related degradation mechanisms.
And that in that respect, failure of the
piping is not hypothetical, and should be considered
in the scope and be subject to an AMR. There was a
lot of discussion on this issue.
And where we are now is ultimately there
were some additional components that were brought into
scope, and subject to aging management, but as a
result of the discussions, we realized that there is
-- that this is a generic thing that needs to be --
that resolution needs to be incorporated into some of
our guidance documents.
And that's where we are now. What we did
in the short term is we developed -- we are developing
the staff position, but for those plants that were
right after Hatch, which are going through now --
Catabawa, Peach Bottom, Maguire, and some of those --
this is also an issue that needs to be captured.
So the first thing that we did was we
developed a series of both scoping and aging
management RAIs to begin to understand what they put
in scope, and what they didn't, and why.
And then once we understand what is in
scope, exactly how is that to be managed. So in the
short term, we have developed and distributed RAIs so
that we can do that with some of the applicants behind
us.
We also have to look at it as we document
the position and put it in the guidance documents.
Now we have to apply it to the folks who already have
their license, and does it raise to a level -- you
know, go through the whole back fit thing, and see
whether it needs to be addressed there.
So we are trying to capture the whole
thing with the Seismic 2 over 1, and what we are doing
right now is we are actually working on the staff
position.
Next, Open Item 2.3.3.2-2, aging
management review for the housings of active
components. The issue was raised that for active
components the actual housing for those should be
subject to an AMR.
And it actually came into play for four
specific systems; standby gas treatment, control
building, outside structures, and reactor building
HVAC.
Southern Nuclear's position was that what
the staff was asking for was basically to do a piece
parts review, and if you go to the rule and some of
the supporting documentation, what it specifically
calls out are valve housings and pump casings.
It specifically calls those out as
requiring an AMR, and Southern Nuclear's position was
what needs to be done is already identified, and
that's all we need to do.
The staff's position was, no, we see the
valve housings and pump casings as being examples of
what needs to be done, and it needs to be expanded
beyond that to cover other housings for active
components where there may be a pressure boundary
function, and things like that.
So that was the source of the conflict and
why it went to appeal. It went through the first
level of appeal as I recall, and in the end the
resolution was that the housings would be brought into
scope and be -- well, it was already in scope, and be
subject to an AMR.
And again the associated aging management
information was brought with it. But we did recognize
that the issue of the housings, we need to somehow
clarify that in our guidance documents that it is more
than just the valve housings and the pump casings.
CHAIRMAN BONACA: Because this is not the
first time it comes up anyway.
MR. BURTON: Right. Exactly.
CHAIRMAN BONACA: Now, let me understand
one thing. Here you say that it has to be developed
into a guidance, and of course it will be some place
for guidance, and there are guidance documents.
Now, the previous issue of Seismic 2 over
1, you said you are developing a staff position.
MR. BURTON: Right.
CHAIRMAN BONACA: How would that position
be conveyed? Also in guidance documents I would
imagine?
MR. BURTON: Yes, that's right. They
would ultimately be in the guidance documents; in the
SRP, and the Reg Guide, and --
CHAIRMAN BONACA: Well, when you talk
about backfitting to the previous applicants, but I
thought this issue of 2 over 1 already was dealt with?
I mean, it came up before.
MR. BURTON: Yes, and I probably
mischaracterized that. With previous applicants, it
may have been dealt with in other ways. For instance,
I think with ANO, they had actually -- it actually had
its own specific category.
It was -- I can't remember what it was
called. So it may in fact have been dealt with with
previous applicants, but the thing is that part of our
process is that we have to just make sure that it is.
That is the main thing.
CHAIRMAN BONACA: Okay.
MR. BURTON: The next issue is 3.2.2.3-1,
small bore piping. The staff recognized that small
bore piping could be subject to high cycle thermal
fatigue due to either thermal stratification or
turbulent penetration, or it could be susceptible to
intergranular stress corrosion cracking.
So we needed to have that captured in an
aging management program. What Southern Nuclear did
was that they looked at all of their small bore
piping, and looked at it from both a susceptibility
standpoint and a consequence standpoint.
And after going through all the small bore
piping, what they identified was about -- I don't
know, about a 2 foot section of the --
MR. BAKER: Four foot.
MR. BURTON: Four foot -- of the enclosure
for the electrochemical potential sensor. The
enclosure for that seemed to be something that should
be within the scope of this aging management program;
the treated water systems, piping and inspection
program.
And what that does is it is a series of
one-time inspections just to confirm again -- and as
we spoke before, just to confirm that there is no
adverse aging degradation.
So the scope of this aging managing
program was revised to include that portion of the
piping.
MR. BAKER: Butch, could I clarify?
MR. BURTON: Sure.
MR. BAKER: That was always within the
scope of the treated water. We just clarified
explicitly that it was in scope.
MR. BURTON: Right.
CHAIRMAN BONACA: Well, what happens if
you -- the expectation is that you have no cracking
due to -- well, that is a one-time inspection, and you
are really doing that for confirming that the effect
is not taking place.
Should you find that, would these
inspections be expanded to other components; that is,
more piping, or not?
MR. BURTON: Yes, and again, as we had
said before, the corrective actions program captures
any of those kinds of problems, and once it is fed
into the corrective action program --be expanded
CHAIRMAN BONACA: So that will be a
leading indicator?
MR. BURTON: Right.
MR. BAKER: One thing. If you did start
finding some of this cracking, you could actually look
and see what type of a program you need to put in
place to manage it.
So the one time inspections would probably
cease at that point, and you would come up with a
program that managed the cracking for the compliments.
CHAIRMAN BONACA: Well, you are talking if
you need further inspections, or why not.
MR. BAKER: Exactly.
MR. BURTON: That's correct. The next one
was Open Item 3.6.3-1(b), reactor building controlled
in-leakage. At this point in time in the review, what
Southern Nuclear was crediting was maintenance of
individual penetrations to make sure that the
degradation was not so bad that leakage would be a
problem.
The staff's position was that that is fine
for each individual penetration, but you haver to look
at the cumulative effect, even though leakage for
individual penetrations may be acceptable, and when
you look at it on a global basis, we still may not be
able to maintain the in-leakage limits.
So the staff's point of view is, well, we
already do the draw-down test for the standby gas
treatment system, and why don't we credit that as an
overall gross indicator for the entire building that
leakage is being maintained.
Because we recognize that even though it
is okay at the individual component level, globally
there might be a problem. Southern Nuclear felt like
that was overkill, and that basically if we adequately
managed the penetrations that should take care of the
wider in-leakage problem.
Again, they took it to appeal, and when
all was said and done, they did decide that we will
credit it. We are doing it now anyway, and we are
going to continue to do it in the license term, and we
will go on and take credit for it. So that's how that
was done.
CHAIRMAN BONACA: I just have a question
here. Given that you are performing the tests anyway,
you must have had a reason for trying to have it
included in the commitment for license renewal.
MR. BAKER: We believed that the test was
really a very gross test and added nothing to any
assurance relative to aging management. The threshold
for detectability of a leak was probably on the order
of 2 square foot on one unit, and about 4 square foot
on the other unit.
So we felt that that was really not going
to add anything of value. I think the resolution of
it was that in fact, yes, you are doing that test
anyhow, and so there is really no regulatory burden,
and we agreed.
And so we have agreed, and the resolution
of it is that we will do the test. It is a tech spec
requirement as it is.
CHAIRMAN BONACA: And is that the course?
I wasn't aware of that. Okay.
MR. BURTON: Actually, I think this is the
last one. Again, I mentioned to you that open item
4.1.3-1 had two parts to it. Part (a) wasn't
appealed, and I discussed that earlier. Part (b) was
appealed.
This is the next to last one. Pipe break
criteria is a TLAA. The issue was postulated pipe
break locations meet the TLAA criteria, and should be
evaluated as TLAA. Southern Nuclear's position is
that it did not meet the six criteria that were
necessary for it to be a TLAA.
Whereas, the staff said, look, in our
guidance documents it says very clearly that this is
to be a TLAA. The cumulative usage factor, which is
tied up in the identification of break locations, it
is a TLAA, and the associated break locations should
be also.
So that was the basis of the open item.
Again, when all was said and done, the applicant did
revise the application to identify or to address the
postulated pipe breaks, and the locations are going to
be monitored using this component SLIC or transient
limit program, the CCTLP. So that was the resolution
on that.
The final was environmentally assisted
fatigue, and I am sure that you all know more about
this than --
DR. SHACK: Could we just go back to that
for a second?
MR. BURTON: Oh, sure.
DR. SHACK: On the pipe break, I thought
the idea was that you would look at pipe break
locations again in light of any aging mechanisms that
would be going on. Not just fatigue.
MR. BURTON: Yes, that's true. Now, let
me say up front that I cannot get into it to any deep
extent. Our reviewer is not here, and we will see
what we can do to answer your question, but I may need
to table it.
MR. BAKER: The pipe break locations that
we are dealing with here specifically are those
outlined and which provide or basically says that for
a class one boundary, if you have pipe break, or you
have locations that have a CUF greater than .1, it
would be a 3-1 evaluations, and predicted values of
greater than .1, you would specifically consider that
a pipe break location and deal with it appropriately
within the 3-1 space.
Now, that is the specific issue that is
being dealt with here. If we are not dealing with
IGSCC, or any other fatigue issues -- and of course
there is general fatigue.
DR. SHACK: Suppose I had a carpet steel
align that I would suspect could be susceptible to
FAC. Could I then postulate breaks due to FAC, or is
it just fatigue still?
MR. BAKER: We would deal with the fact
issue separately, or as a separate --
DR. SHACK: But that is in your fact
control, and so there is no need to postulate, okay,
I blew the fact control.
MR. BAKER: Right.
DR. SHACK: And I have a burst anyway, and
that is not addressed.
MR. BAKER: Correct.
MR. DYLE: Bill, this is Robin Dyle. Just
for one clarification. This goes back a long time
that says that when you are designing the pipe
restraints how are you going to select the location to
look at, and the staff determined in the branch
technical position, that anyplace the CUF exceeded .1,
and so it was originally a somewhat arbitrary
location, and just identify where you would assess the
pipe break location.
DR. SHACK: It didn't apply when you
thought the principal aging mechanism was fatigue.
MR. DYLE: Right.
DR. SHACK: And you have new aging
mechanisms.
MR. DYLE: Yes, and so the issue here was
whether that should be treated as a TLAA or not, and
not whether any of those locations was the only issue
to be dealt with. It was just whether it needed to be
a TLAA or not.
And the argument that we had put forth was
that since it was a design parameter, and not really
-- this evaluation didn't manage cracking, it was just
an old design parameter. That was our argument for
why it wasn't a TLAA.
But the staff disagreed with that, and as
Butch said, the staff member is no here to address
that.
MR. BURTON: Is that something that you
perhaps want to discuss more about next week?
DR. SHACK: Yes, that is a topic that
interests me, is that why should I only postulate the
break space and not the fatigue.
CHAIRMAN BONACA: Yes, because that is
really what it does, and it would monitor for fatigue.
MR. BURTON: The last item was
environmentally assisted fatigue, and as I said, you
all have dealt with this ad nauseam I know.
DR. SHACK: You always love it, ad
nauseam.
MR. BURTON: We love it. Thank you, sir,
may I have another. The issue was that the staff's
position was that the applicant should assess the
locations identified in this new reg, considering the
applicable environmental fatigue correlations in these
other two new regs.
As you all know, environmentally assisted
fatigue has a long and torturous history. A lot of
documentation. The bottom line was that Southern
Nuclear had data that was coming from Susquehanna, and
was basically saying that this is applicable to Hatch.
Our staff reviewer had some questions
about that, the applicability, and felt that it would
be more prudent to actually have things in place to
actually monitor and collect data at Hatch as regards
the environmentally assisted fatigue as recommended in
these documents, in terms of locations and fatigue
factors.
In the end, after our discussion, the
applicant did commit to evaluating the six locations,
and it was actually incorporated into again the
component SLC or transient limit program, aging
management program.
So they have committed to actually
collecting that data at those locations. That was the
last open item, and the last couple of things is that
I wanted to again identify the three license
conditions that we have with the review.
DR. SHACK: Before you get into that can
I bring up one more issue in the SER.
MR. BURTON: Sure.
DR. SHACK: It is on page 3-62, discussing
FAC. And it says basically that water chemistry
control can be achieved by reducing the oxygen content
in the water environment. Such a water chemistry
control program to mitigate the aging effects
attributable to FAC is not implemented in the Plant
Hatch units.
I would argue that typically one would
mitigate FAC by adding oxygen, and not by reducing it,
and I just had a question for Hatch. Do they maintain
such a remittable oxygen level?
MR. BAKER: We have to have oxygen comply
with the code.
DR. SHACK: Is that in the BWR
environmental -- well, the water chem specs. What do
you maintain, 20 PPD or 15 PPD? And that is part of
the EPRI water chem specs?
MR. DYLE: The normal situation --
DR. SHACK: But you ought to correct that
statement in the SER.
MR. BURTON: Okay. Clarify that a little
bit more. All right. Let me write this down just in
case.
(Brief Pause.)
MR. BURTON: Okay. All right. Just a
summary of the three license conditions. We already
talked about them. One is the standard license
condition that says that the FSAR supplement should be
incorporated into the FSAR at the next update of the
FSAR.
And that is required by 50.71(e); and the
other one, the second standard license condition is
that all the future actions that were identified in
the FSAR supplement should be completed before the
beginning of the extended term.
And finally the third one was what we
talked about before, that they should inform the NRC
regarding whether they are going to use the integrated
surveillance program associated with BWRVIP-78, or if
they are going to use a plant specific program, and
identify those actions.
So we tied those three things to a license
condition. And then finally the bottom line
conclusion after the staff's review is that the staff
believes that the applicant has met all the
requirements of license renewal as required by 54.29.
And specifically actions have been
identified, and have been or will be taken, either
present actions or future actions, such that there is
reasonable assurance that the activities will continue
to be conducted in accordance with the current
licensing basis.
And again the guidance documents say,
bottom line, what we are trying to do is to maintain
the licensing basis in the same manner and to the same
extent in the future, in the renewal term, as it is
being maintained now.
And we have reasonable assurance that they
are taking the actions to do that. Also, the
applicable requirements of 10 CFR Part 51, which is
the environmental piece of the review, have been
satisfied.
And finally matters raised under 10 CFR
2.758, which is hearings and all of that, have been
addressed. There were no hearings, no petitions to
intervene, or any of that stuff.
So we feel that as a result of the review
that we have covered the safety review, and we have
covered the environmental review, and there were no
intervenors or other issues raised.
But that they have all been satisfied, and
on that basis, we feel like that they can get their
license. As I said, we have also gotten the
confirmation from the regions, in terms of some of the
follow up inspections.
We got some clarification for Dr. Barton
about the level of quality for the commitments, for
the commitment matrix. So hopefully we are satisfied
there. So we recommend that they should get their
license.
CHAIRMAN BONACA: And since we are talking
about an appeal process, I think I read somewhere or
I read some comments maybe from NEI that the appeal
process is not working as it should, or something like
that. Is everybody happy about the appeal process?
MR. NAKOSKI: This is John Nakoski, and if
I could just say something about that. NEI has
proposed or submitted a proposed appeal process just
recently that we have not completed our review on.
We will work towards an appeal process
that improves the fairness or perceived fairness on
the part of NEI, and other stakeholders, and the
efficiency of the process.
And at this point, I don't think that
there is a whole lot more that we can say about that.
CHAIRMAN BONACA: Well, I think we were
asking some questions on --
MR. BAKER: Dr. Bonaca, one other quick
item. I just wanted to mention that the NRC has been
or has encouraged through the working group or through
the steering committee a lessons learned process.
And as a result of that encouragement of
lessons learned process, the industry as a whole has
-- well, when we have identified things that we think
could be improved, has made recommendations to the
NRC, and the NRC has been very open about considering
those recommendations, and this is just another one of
those type items.
MR. BURTON: And let me add that just as
John had mentioned before, I think people have the
impression that Hatch is the first one to go through
the appeal process, and my understanding is that that
is not true.
Some of the other applicants have, and it
wasn't as formalized as what I just showed you. So
Hatch is the one who has really gone through the more
formalized system, and it was our first testing of it.
And just like anything else, we found
areas where it could be improved, and Southern Nuclear
has transmitted some of their suggestions about that,
but that, just like everything else in this whole
license renewal effort, we have a whole lessons
learned process, and how do we take those lessons
learned and incorporate them, and try to do things
better.
And again because this was the first -- it
wasn't the first appeal process, but it was the first
one that really went through the technical aspects as
I tried to show you.
CHAIRMAN BONACA: My question was more
directed at understanding the difference between an
appeal, a formal appeal process, and the normal
process that takes place in an engineering environment
where you have levels of management that should be
involved in decisions, but certainly should not bypass
the technical people and the technical input.
And so I am sure that the appeal process
is not a process designed to bypass technical
insights.
MR. NAKOSKI: This is John Nakoski again.
I agree with you that it is not the purpose of the
appeal process to bypass the technical decisions by
escalating it to higher levels of management.
CHAIRMAN BONACA: Which I would expect
would happen anyway. So that's why I was intrigued a
little bit by the process itself.
MR. BURTON: One of the things that we
have tried to do with license renewal is to try and
make it as visible and transparent as possible,
because as you know, we have several pillars that we
try to meet.
One has to do with public confidence in
our processes and stuff like that. So we feel like
the more that we can clearly show how we do our
business, then the better that is going to be able to
instill confidence with our stakeholders.
So what you are saying is true. I mean,
even before you get on the diagram, there is a whole
lot of interaction that has gone -- that is done at
the reviewer level, and even at that level it involves
a lot of section chief interaction, the first level
supervisory action.
And if we just reach an impasse where our
views are just diametrically opposed, and we just
don't seem to be making any progress, then we have to
get the first level of management -- and not just at
the NRC, but also the applicant's management involved,
too.
And at that first branch level, and it is
not just the NRC who is making this decision. It is
also the applicant.
MR. NAKOSKI: Butch, let me interrupt here
at this point and say that this is not unique to
license renewal. This is essentially the same process
that we would use anytime there is a disagreement
between the staff and an applicant on a licensing
action.
In license renewal, like Butch was saying,
we want to make this -- we want to put this in front
of the public, as this is the process that we use in
this space so that you are aware of the activities and
actions going on that may appear to be behind the
scenes.
But we are being open and up front about
it, and these discussions go on. We are telling you
that they go on, and this is the steps that you need
to go through, the licensee or the applicant would go
through, if they disagree with us.
The bottom line is that we have the burden
to make the regulatory decision, and we are going to
provide the public with the information that we based
our decisions on.
MR. BURTON: And also I should clarify
that what it says on that diagram, it says
stakeholders. There are more stakeholders than just
as and the applicant, and the process allows for any
stakeholder who has an issue or a question that they
feel needs to be brought up. We have a process to do
that. And again all to instill public confidence.
MR. NAKOSKI: And I guess I would add
fairness.
MR. BURTON: Right.
CHAIRMAN BONACA: Some of these
resolutions -- for example, seismic 2 over 1, the
discussion in the SER as I said during this meeting is
quite -- is defined. It provides a lot of information
about the reasons why. So that's good.
In some of the cases, you know, it is more
that the applicant decided to just go along with it,
for example, and do the test, and it doesn't mean that
they are going to be happy about what the resolution
is. And they simply said fine.
Is there any additional work being done on
these issues on a generic basis or not, or is it a
closed item? I guess where I am going is that when I
look at seismic 2 over 1, you have a very convincing
explanation of why aging will bring potentially some
fractures in locations that are not really covered by
a normal break analysis and so on and so forth, and
that makes sense. So you have a solid technical basis
to argue from, and I think the issue can be put to
rest.
MR. NAKOSKI: Mario, I think I would
answer that in a generic sense. We would look at the
resolution of these open items for generic
implications moving forward, and take the lessons
learned from that review and apply them to future
applicants.
If in the case of the standby gas
treatment system draw down test, we made a
determination that it was generically applicable, we
would look at incorporating that into generic
guidance.
And I am not presupposing the position,
but I am just stating a premise. If we determined
that it was generically applicable, we would
incorporate that into generic guidance that we have
developed.
MR. BURTON: And also to understand that
there is -- that operating experience plays a big part
in this whole thing. In the case of the end-leakage,
and what we were saying is that you are maintaining
the individual penetrations, but we are not sure
whether that is enough on a global perspective.
Operating experience as we go along, as
they implement management of the penetrations, and do
the confirmatory draw down test, we may in fact see --
well, that is kind of a bad example, because you have
got to do it anyway.
But operating experience in general, and
let me try to be more general about it, if we find
that something really isn't having a real benefit and
it is an unnecessary regulatory burden and all that
stuff, now this goes beyond license renewal.
You always have the normal 50.59 process
to try and provide justification, but we probably
don't need to do this anymore.
CHAIRMAN BONACA: Are any of these issues
still open with NEI? I know that you are looking at
a number of generic issues with NEI.
DR. BARTON: Well, one that I am aware of
was the housings and ventilation, et cetera, et
cetera, where if applicants said, hey, NEI Appendix
whatever kind of excludes this, but it really doesn't,
that there is an issue there.
CHAIRMAN BONACA: That's right.
DR. BARTON: There is an issue there with
the NEI guidance. That somehow has to get closed in
or closed out here as a factor.
MR. DYLE: That's exactly correct. I am
a member of the NEI working group, and Ray Baker next
to me is a member of the NEI task force. What NEI
does is that they take each of these issues that we
have as open items, and they look at them, and we also
make a decision on whether they are generically
applicable or not, or whether they need to be pursed
with further discussions with the NRC.
And some of these issues are likely to be
discussed further with the NRC staff on a generic
level as we move through time. What happens in the
real world here is that when an issue like seismic 2
over 1 comes up, the plants that have just submitted
haven't -- you know, they were faced with that issue,
and as were us, as those plants were making
submittals.
So you may very well see open items and
issues with those plants that are currently going
through, and the plants coming in next year after
that, there should be enough time to where these
issues sort of get some legs to them, and the staff
and the industry can come to some agreement on how
this should be pursued in the future.
MR. NAKOSKI: Mario, if I could, I would
just like to take a minute here and go over what I see
are the issues that we need to emphasize when we meet
with the full committee. I think I have identified
four topics that you all would like to hear discussed.
The first one is the inspection of buried
components, particularly fuel oil storage tanks. And
really I think the focus of that is on what is the
safety implication of that, and how that relates to
the rule. So I think, Butch, if we could focus on
that.
DR. KRESS: There was another part of that
that you might want to think about, and that is for
the codings of various typings and things. I think
that the commitment was that whenever they excavate
and uncover these in an inspection, that is kind of a
lose type of commitment.
I don't know that they will ever excavate
and uncover those, and --
DR. BARTON: Well, you see, the problem
that you have got with that, Tom, is that if you don't
commit to do an inspection when you are doing an
excavation, or you are chasing a leak, how else do you
inspect buried -- because there is so much stuff that
is buried in the site that there is no program that
really makes much sense to go and randomly dig holes,
because these holes -- you have got to shore them, and
depending on what your soil condition is -- the Oyster
Creek excavation was a million dollar excavation.
DR. KRESS: So you are telling met that is
really the only practical alternative?
DR. BARTON: Yes, on the coated buried
stuff, yeah. I mean, it is hard to swallow, but --
DR. KRESS: Is there no other way to do it
besides excavating?
DR. BARTON: Well, there is -- well, I
guess not. I guess you can run things in pipes and
stuff, and look, but --
DR. SHACK: Well, you can put UT and look
at it from the inside, but since it is a localized
corrosion --
MR. NAKOSKI: And you might even miss it.
I mean, it is such a localized --
DR. KRESS: Somebody mentioned measuring
electrical potential?
MR. NAKOSKI: Well, let me keep us focused
here if I could. It really is when does it become a
safety concern, and you are going to have to have some
substantial degradation in a buried component before
it is going to impact the ability of most of this
stuff to do its safety function.
So if we stay focused on that, what they
are proposing -- and correct me again if I am wrong,
but I think that's why the staff included what they
are proposing is sufficient.
CHAIRMAN BONACA: Well, that is exactly
right. On the tanks probably that is the right
answer, and to go back to the scope of license
renewal.
MR. NAKOSKI: Right. And I would even
argue that having a similar experience with Mr. Barton
at Oyster Creek on service water piping, it would have
had to have been a substantial degradation of that
piping before it impacted the ability of that piping
to perform its safety function.
CHAIRMAN BONACA: Okay.
And if I could, the next item that I
thought that I heard that we wanted to talk further
about is the applicability of NFPA-25 and nuclear
power plants raised by Dr. Kress.
DR. KRESS: Right.
MR. NAKOSKI: And commitment tracking
raised by Mr. Barton regarding the level of quality.
We got a feedback that that was an Appendix B program.
And I am not sure, John, but with that in mind do we
-- do you think we need to talk about that further?
DR. BARTON: I think what you need to
describe to the rest of the committee is how are some
of these commitments, or promises, or whatever you
want to call them, how is it assured that they are
implemented in programs, and how does the NRC make
sure that these things get closed. I think that
process should be described to the full committee.
MR. NAKOSKI: Have you got that?
MR. BURTON: Yes, I've got it, and perhaps
revise the SER to give a little more information on
how that is done as part of the methodology section.
DR. BARTON: That's fine.
MR. NAKOSKI: And then the last one is
related to the pipe break TLAA raised by Mr. Shack,
and I think the fundamental question you had was why
are we only considering the postulated pipe break only
for fatigue, rather than looking at the other
mechanisms.
DR. SHACK: Yes. Once you decide that a
piping system is susceptible to other kinds of damage,
why not pick those as candidates for a pipe break.
MR. NAKOSKI: Okay. And those were the
four issues. I mean, you had talked about some other
SER updates, but I don't think that those necessarily
need to be discussed. Was there anything else that
the subcommittee wants to add?
CHAIRMAN BONACA: Let me do the following
now. First of all, I am going to go around the table
and first of all ask the members if they have any
further questions for Mr. Burton?
DR. SHACK: Just a quick one. I stepped
out and maybe it was addressed, but one of the unique
features of Hatch is the core shroud repair, and it is
sort of almost not mentioned anywhere. It is going to
be covered by the VIP program, and is that VIP-76 that
discusses that?
MR. BAKER: The shroud repair was actually
done under VIP-02.
DR. SHACK: It is not referenced at all in
the SER.
MR. BAKER: Right. The reason for that is
that VIP-01 was the original inspection criteria, and
the VIP-02 was the repair criteria, and VIP-07 was the
reinspection criteria, and VIP-63 was the vertical
weld inspection criteria.
We rolled all of those into one document
now, which is VIP-76. So, 76 is referenced, and there
is not a staff SE yet on it, but this is a compilation
of the other four VIP documents for which there are
Ses.
So we have rolled them all into one
document, and so now an owner goes to one place to
figure what to do with everything on the shroud. The
shroud reinspection frequency is consistent with what
the original designer called for, which is what was
specified in VIP-02.
And what the staff reviewed and approved
when they did the review of the shroud repair itself.
CHAIRMAN BONACA: Okay. Any other
questions for Mr. Burton? If not, thank you for a
very informative presentation.
MR. BURTON: Thank you.
CHAIRMAN BONACA: And then what I would
like to do is two things. One is to go around the
table and get views from the members, and your
observations. And also suggestions -- you know, we
have to draft a letter report on what are the
important points. You may give me that information
later by E-mail if you want.
MR. BURTON: Excuse me, but am I to assume
that I need not go over all of the open items next
week?
CHAIRMAN BONACA: Well, wait a minute, and
then after that I would like to go around the table
and suggest what we are going to have in the
presentation two weeks from today, whenever it is
going to be.
So with that, I will start with Mr.
Barton, our guest consultant here. What do you think?
DR. BARTON: As far as the -- let me start
with the items for the full ACRS meeting. John picked
up several of them that I had on my list. I think one
thing, Butch, that as far as -- and you don't have
this much time in a full meeting, but you are going to
talk about open items and appeals issues.
What I would recommend that you do is to
have the list of items, but differentiate between
those that were closed, and the applicant said, yeah,
we agree with the NRC's position. So those are really
simple, right?
But then there are some where there is
some action required or whatever. There are two
different categories of how these open items were
handled, and I think you can save a lot of time by
just whipping through all of those where they say this
is the NRC's position and we are going to do it.
Also, I think you need to have some
discussion on the appeal process, and decisions and
resolutions, and actions that are yet required to
close appeal issues, and discuss the process you now
have, and what John mentioned -- and I wasn't aware of
NEI proposing a change.
So I think the full committee ought to
hear how this appeal process is all about, and what it
is all about, and what items are still required for
those issues that are -- to close those issues that
have been appealed.
Another one is -- well, Mario talked about
part of this also, I think, the handling of the
generic type components, the seismic 2 over 1 and fuel
tanks, and how will these things be handled in the
future so that they don't keep cropping up when you
talk about guidance documents or whatever.
And skid-mounted equipment, and housings
for HVAC, and those kinds of issues that will keep
coming up, and explanations to the committee, and some
of those crept up during this discussion with Hatch,
and how were they resolved here, and what do you guys
plan to do with these things down the road. That's
about it.
CHAIRMAN BONACA: Any other thoughts in
general with the application, and realizing that this
is the final presentation to the committee, and after
that, hopefully we are going to write a letter after.
DR. BARTON: Well, based on what I heard
today, there is no burning issues that I have got that
should prohibit this thing from proceeding down the
path of granting them the extension. I mean, we
talked about a lot of issues today, but I think they
are all going to get resolved to the satisfaction of
the ACRS.
CHAIRMAN BONACA: Okay. Tom.
DR. KRESS: My issues were pretty well
covered by the list he had back here, and with respect
to what ought to be presented other than those at the
meeting, I don't think you have a lot of time to go
over all these open issues.
And what I would do is I would list them
and hand them out, and say you guys can read these and
read what the issue was, and how it was resolved.
But I wouldn't spend a lot of time going
over them. I think the main committee is going to put
some sort of an ACRS position on whether the license
renewal review process was sufficient. So if it were
me, I would think about talking about here is the
review and the things that we did, and here is how
many RAIs we had, and here is how many open items we
had.
It would be very general. It would be
almost one slide that tries to convince the full
committee that this was a comprehensive review, and
that we went over the review, and the screening, and
the scoping process, and we questioned why these
things weren't in scope and that sort of stuff.
Just as a flavor of what you did so that
you can be sure that the full committee thinks it was
a comprehensive and thorough review, and that would be
my only real recommendation.
DR. BARTON: That's a good point, because
I think that the committee felt that this was a tough
application and hard to follow. That's a good point,
Tom.
MR. BURTON: Can I say one thing? I think
that is very good. That would actually bring up
something that happened at the previous meetings, and
--
CHAIRMAN BONACA: It doesn't matter.
That's fine.
MR. BURTON: That's okay?
CHAIRMAN BONACA: Yes. In fact, I support
totally Dr. Kress' comments because if you look at the
way that we format the letter -- you know, you can go
back to the Arkansas letter in the spring.
We are trying to address scoping and
screening being adequate, and we are making a judgment
on what you did, and I think it is important that you
give us that feeling that your judgment, that your
evaluation, was thorough and you feel good about that.
And second are the aging effects properly
defined, and are the programs appropriate. So we are
attempting to pass a judgment on those terms.
DR. KRESS: And with respect to that, I
would -- you know, we really didn't get it here, but
I would add some comment about what aging programs
were already in place, and what new ones had to be put
in place as a result of license renewal, and not going
into any detail.
CHAIRMAN BONACA: In fact, I think it
would be very helpful if the existing programs and the
enhanced programs, and I believe there are several of
those, or five of those, and the new programs.
And the fourth thing would be the
modifications due to closed items, because there were,
I believe, one new or two new one-time inspections,
and one of them is part of another program, and it
gives us a sense of what took place, and what specific
commitments are for the site.
And the other thing that I guess that I am
continuing here is that the other thing that I think
would be important is that often times -- and I
realize that you have a limited amount of time.
But a lot of issues are -- well, for
example, you have in TLAAs, you have certain analysis
that you do. But then you have in other programs
certain things that support.
For example, in the vessel, you have an
inspection of the materials, and so on and so forth,
and it would be good that those pieces are well-
integrated and the programs are supporting in fact
analysis, and just some suggestions in that case.
And again keep the general message to the
full committee regarding the whole application,
because that is really what we are going to write
about. And again some element may come from the
previous letter or previous report that you made to
us.
For example, there is clearly an interest
in BWRVIPs. I mean, they are supporting other
comments.
DR. KRESS: With respect to the appeal
process, the full committee may not be so much
interested in the process itself. I think what they
are interested in is that they have a general concern
that quite often the technical staff gets overridden
by upper management without due consideration of all
of the technical elements that go into their decision.
And I think the full committee would like
some reassurance that that is not the case, and that
the process doesn't just do that to it. So rather
than just looking at the four processes and what they
are, get some assurance that there is due
consideration given to the staff's technical views.
MR. BURTON: Because the elements of the
appeal process are expected from a working engineering
organization, and so therefore why do you need a
formal one?
That's why I think that undoubtedly is an
transparent one, but I think that is in the interest
of the committee. Peter, I will let you raise your
issues. I was going to talk about CASS, because the
conversation at the end left me uneasy, if nothing
else, because I am not an expert in materials.
DR. FORD: Well, I have two concerns. One
is CASS and the justification for one-time
inspections, and you are qualifying or inspecting is
not necessarily a time dependent degradation
mechanism, and so therefore it is very dependent upon
when you do that one-time inspection.
And I don't follow the justification, and
there is the question of tanks, which is not really a
big safety issue as I understand it, and the fire
protection system I would imagine would be a
significant safety impact.
And I follow the corrosion argument that
if you leave it there and don't open it up, you are
not going to have too much corrosion. I can
understand that, but I don't see any control of that.
And the 50 year thing, that just makes no sense at all
to me.
CHAIRMAN BONACA: Let me just say that we
have gone through a one-time inspection concept a long
time, and the expectation of the ACRS has always been
that it is confirmatory of an aging mechanism that is
expected to be, or it is not expected to be there.
So it is applied to an aging mechanism
that it is possible and expected to be there I think
is inappropriate. So that is the way we always
understood it.
So now the only reason why I felt
comfortable enough was a listing of some supporting
statements, because this morning the pipe was designed
to a thickness that would be in fact supportive of 50
years of operation.
Now, if in fact there is a design, that
should have taken into account the corrosion, because
that is the only degradation mechanism that I could
think of. But I think it is valuable to raise it as
an issue, and so we can discuss it.
DR. FORD: And it goes beyond just Hatch.
CHAIRMAN BONACA: It is central to -- if
you look at most of the new programs, there are one-
time inspections, and so they are central to the whole
license renewal process.
DR. KRESS: I think that this is a generic
license renewal question, and shouldn't impact
anything having to do with Hatch. And like Butch
says, it is an ongoing thing maybe -- well, I think
the staff considers it resolved, and that one-time
inspections are considered okay.
DR. FORD: Well, that is what worries me.
Somehow or another it gets into the law that it has
passed once, and therefore it is okay.
CHAIRMAN BONACA: Well, in my mind, I have
always considered it as what you want to do to
prevent, recognizing that a lot of things is going to
happen and you are going to react to it.
So really it is being proactive on the
issues that you understand may be there, versus to be
ready to be effectively reactive should they happen.
Of course, reactiveness also -- that when you accept
that, you imply that you can survive the event.
I mean, you accept that it could happen
because it still would not be a major seismic event,
and that sometimes is difficult to distinguish. But
what I am saying is that there is an expectation in
license renewal that these plants will not have in
fact new degradation mechanisms.
I mean, that's going to happen, and it is
just life, and that we would be proactive enough to at
least take care of what we understand today.
DR. FORD: The other issue I had was the
CASS situation, and how you are going to manage that.
I can follow the argument, but I don't necessarily
technically agree with it, about using the degradation
of the associated weld as a precursor to the cracking
and possible failure of the CASS.
I don't necessarily agree with that, but
that's an academic point of view as you said, and the
whole thing will depend to a certain extent on
upcoming data. But I am open, as usual, to academic
discussion.
CHAIRMAN BONACA: Well, we identified in
the beginning four items that would be -- that you
will discuss in the committee that were brought up at
the beginning, and we can include these two also, and
that makes six.
DR. FORD: I don't now how it can be
presented at the ACRS meeting in a meaningful level.
I mean, they are open only for technical discussion.
CHAIRMAN BONACA: Well, they in the CASS
situation, they can simply state the position that
they are taking, the one that says that we will
perform the inspections of welds.
DR. KRESS: And then as usual, we can
discuss it ad infinitum.
CHAIRMAN BONACA: Well, the one-time
inspection also. We have the specific one on the
fire, and I think we should raise that issue.
DR. SHACK: Is it the notion that you are
going to use a lead component as a surrogate for other
components that you are objecting to?
DR. FORD: Yes.
DR. SHACK: Is that because --
DR. FORD: The kinetics of what is
happening in that component --
DR. SHACK: So you don't believe that a
weld is more susceptible to IGSCC than CASS stainless?
DR. FORD: Not necessarily, because we
don't have the data to disprove it.
DR. SHACK: Well, GE did a lot of data on
Tom Devine, and critical --
DR. FORD: But that was 20 years ago.
DR. SHACK: I know, but --
DR. FORD: And it certainly wasn't under
radiation conditions, even though there was a low
flux.
MR. BAKER: But radiation doesn't seem to
be something that is going to change it.
DR. SHACK: Well, we will have a technical
disagreement on it.
DR. FORD: But my point is that we have
been bitten time and time again by this presumption
that we know what is happening when we don't know what
is happening. It is a concern.
MR. BAKER: Peter, if I could, just one
thing, and I won't be here, but what the staff could
discuss is the safety implications. And again there
are other things that go into the plant to ensure that
there is not a safety issue related to that.
You have daily jet pump surveillance, and
other things, and so from a safety perspective that is
a whole other issue.
DR. FORD: Well, if you had to categorize
things, you would do it by that sort of thing, and I
would put fire protection over the tank for this one-
time inspection. And this one here, I would go along
and state maybe it is an academic exercise, and it is
not a big issue as far as PRAs.
And another thing I have got to mention is
-- and again this should not be brought up at the ACRS
meeting, but just for the record, I do have a problem
with some of the disposition curves that are being
used for the BWRs in general.
There is a huge scatter of disposition
curves, and we are not going to resolve that, and that
will not be resolved in the short term. But again I
am pinning my hopes on the statement that I keep
hearing, that these are all living documents, and they
will be revised.
But I don't want us to get into the trap
of it has been passed once, and therefore it is the
bible. It is not the bible.
MR. BURTON: I do want to say one thing,
because as I am listening to it, it is clear that one
of the broad topics that I need to discuss is how the
process allows for change, and new data, and emerging
issues, and things like that, and it would fall into
that category.
DR. FORD: And CASS is --
MR. BURTON: Yes, in several of these
things.
CHAIRMAN BONACA: And there is a
distinction between license renewal and current
existing problems.
MR. DYLE: Just a comment, Butch, that
might help you pull that information together. The
VIP provides on a semi-annual basis the inspection
results across the entire fleet, and to the staff for
review to see what is going on. So that is ongoing
and documented, and we can respond to that.
MR. BURTON: How often was that?
MR. DYLE: Semi-annually. And after each
outage season, we compile the stuff, and then forward
it to Gene.
CHAIRMAN BONACA: I think that is one of
the strengths by the way, and we noted that in our
interim letter that the fact that you have so many
power plants into a program, and even if one new event
occurs, it will occur once, and then you will know
that it is possible in the whole fleet.
So therefore you are reactive to that one,
but you can be proactive on the other units. So there
is a big strength coming from that.
DR. BARTON: Well, Mario, has the
committee made a statement regarding the BWRVIP
program, which I think is a pretty good program. Have
you guys already gone on record on that?
CHAIRMAN BONACA: Yes.
DR. BARTON: Okay.
DR. KRESS: I thought it was a good
program.
DR. FORD: And that is a jolly good idea.
It is a question about change. Again, I am thinking
about it from a public perception, and reading the
proceedings of the ACRS meeting. There are people out
there who have got concerns on some of these issues.
CHAIRMAN BONACA: Bill.
DR. SHACK: I think everybody has sort of
raised the issues that I think need to be brought up
at the committee. I will say that I liked this safety
evaluation report. I thought you made a fairly good
case that we should renew their license, and better
than their license renewal application did. The staff
saves them again, huh?
CHAIRMAN BONACA: It was very good. I
think we gave you so much that you must be totally
confused, and you have to spend now every day until 11
o'clock at night putting things together.
MR. BURTON: I'll be busy. I think it
would be beneficial because it came up several times
today to talk about the corrective actions program as
part of the whole -- again, change process, because I
know that came up several times. And if I can talk
about it up front, I think that would probably be
helpful.
CHAIRMAN BONACA: Indeed, and you can talk
about that and how does the whole thing get together,
and I think it is important, but again my suggestion
would be that you go on the topics that Dr. Ford
highlighted, and then the second part would be more
like some concluding statements on those portions of
the application that refer or that are essential for
license renewal.
MR. BURTON: Okay.
CHAIRMAN BONACA: Including some -- well,
maybe bring up data on the BWRVIPs, because when we
look at them, they weren't reviewed most of them. Now
we know they were being close to being completed, and
if there is additional information that you can
provide us with that, that's fine, and tell us. But
don't go into detail, but just simply when you think
the SER would be completed.
MR. BURTON: We have an interface meeting
every week, and we have a sheet that gives the status
of not just VIP, but all the topical reports, and I
will just put that on there. No problem.
CHAIRMAN BONACA: With that, are there any
other comments or questions from the members of the
public or the applicant? If not, the meeting is
adjourned.
(Whereupon, at 11:52 a.m., the meeting was
concluded.)
Page Last Reviewed/Updated Tuesday, August 16, 2016
Page Last Reviewed/Updated Tuesday, August 16, 2016