Plant License Renewal - March 27, 2001
Official Transcript of Proceedings
NUCLEAR REGULATORY COMMISSION
Title: Advisory Committee on Reactor Safeguards
Plant License Renewal Subcommittee
Docket Number: (not applicable)
Location: Rockville, Maryland
Date: Tuesday, March 27, 2001
Work Order No.: NRC-135 Pages 1-311
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
(ACRS)
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PLANT LICENSE RENEWAL SUBCOMMITTEE
MEETING
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TUESDAY,
MARCH 27, 2001
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ROCKVILLE, MARYLAND
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The Subcommittee met at the Nuclear
Regulatory Commission, Two White Flint North, Room
T2B3, 11545 Rockville Pike, at 8:30 a.m., Dr. Mario
V. Bonaca, Chairman, presiding.
COMMITTEE MEMBERS PRESENT:
MARIO V. BONACA Chairman
F. PETER FORD Member
THOMAS S. KRESS Member
COMMITTEE MEMBERS PRESENT: (cont'd)
GRAHAM M. LEITCH Member
WILLIAM J. SHACK Member
ROBERT E. UHRIG Member
ACRS CONSULTANT PRESENT:
JOHN BARTON
ACRS STAFF PRESENT:
SAM DURAISWAMY
ROBERT ELLIOTT
ALSO PRESENT:
HANS ASHAR
RAJ AULUCK
GOUTAM BAGELU
R.D. BAKER
BILL BATEMAN
TAMMY BLOOME
JOSEPH BRAVERMAN
WILLIAM BURTON
GENE CARPENTER
ROBERT CARTER
T.Y. CHANG
PEI-YING CHEN
ALSO PRESENT: (cont'd)
OMESH CHOPRA
MANNY COMAR
H.F. CONRAD
J.F. COSTELLO
AMY CUBBAGE
JAMES DAVIS
JERRY DOZIER
ROBIN DYLE
TANYA M. EATON
BARRY ELLIOT
JOHN FAIR
DONALD FERRARO
GREG GALLETI
HERMAN GRAVES
CHRIS GRIMES
JOHN HANNON
ALLEN HISER
CHUCK HSU
DAVID C. JENG
PETER J. KANG
ANDREA KEIM
ED KLEEH
STEPHEN KOENICK
W. KOO
ALSO PRESENT: (cont'd)
P.T. KUO
SAM LEE
W.C. LIU
YUNG Y. LIU
ROBERT LOFARO
WAYNE LUNCEFORD
JAMES E. LYONS
MICHAEL McNEIL
S.K. MITRA
RICH MORANTE
KEITH NICHMAN
WALLACE NORRIS
K. PARCZEWSKI
ERACH PATEL
PAT PATNAIK
CHARLES R. PIERCE
JAI RAJAN
MUHAMMAD A. RAZZAQUE
KIMBERLEY RICO
K. RIW
JOHN RYCYNA
SYED SHAUKAT
PAUL SHEMANSKI
DAVID SOLORIO
ALSO PRESENT: (cont'd)
SHIU-WING TAM
BRIAN THOMAS
STEVEN G. TONEY
JIT VORA
DOUG WALTERS
I N D E X
AGENDA ITEM PAGE
Opening Remarks. . . . . . . . . . . . . . . . . . 7
Staff Opening Remarks. . . . . . . . . . . . . . . 8
Introduction and Review. . . . . . . . . . . . . .10
Overview of Public Comments. . . . . . . . . . . .14
Changes to Standard Review Plan: Scoping. . . . .15
and Screening Methodology
Changes to Generic Aging Lessons Learned . . . . .36
(GALL) Report, Chapters II and III
Changes to GALL, Chapter IV. . . . . . . . . . . .57
Changes to GALL, Chapters V, VII, and VIII . . . .76
Changes to Gall, Chapter VI. . . . . . . . . . . 105
One-time Inspections, Regulatory Guide,. . . . . 111
NEI 95-10
Changes to NEI 95-10: Industry Guidance . . . . 128
Staff Introduction Concerning BWRVIP . . . . . . 169
Topical Reports Related to License Renewal
BWRVIP 76: Core Shroud Inspection . . . . . . . 274
BWRVIP 41: Jet Pump Assembly Inspection . . . . 278
BWRVIP 26: Top Guide Inspection . . . . . . . . 279
BWRVIP 75: Technical Basis for Revisions to . . 280
Generic Letter 88-01 Inspection Schedules
Discussion . . . . . . . . . . . . . . . . . . . 299
Recess . . . . . . . . . . . . . . . . . . . . . 311
P-R-O-C-E-E-D-I-N-G-S
(8:30 a.m.)
CHAIRMAN BONACA: Good morning. The
meeting will now come to order. This is a meeting
of the ACRS Subcommittee on Plant License Renewal.
I am Mario Bonaca, Chairman of the
subcommittee. The other ACRS members in attendance
are Peter Ford, Thomas Kress, Graham Leitch, William
Shack, and Robert Uhrig. We also have John Barton
attending as a consultant.
The purpose of this meeting is to review
the final drafts of the Standard Review Plan for
License Renewal; the Generic Lessons Learned Report;
the Draft Regulatory Guide DG 1104, Standard Format
and Content for Applications to Renew Nuclear
Powerplant Operating Licenses; and NEI 95-10,
Revision 3, Industry Guideline for Implementing the
Requirements of 10 CFR Part 54, the License Renewal
Rule.
The subcommittee will also review
selected reports of the boiling water reactor vessel
and internal projects associated with the license
renewal. The subcommittee will gather information,
analyze relevant issues and facts, and formulate
proposed position and actions as appropriate for
deliberation by the full committee.
Mr. Sam Duraiswamy is the cognizant ACRS
staff engineer for this meeting. Mr. Rob Elliott,
who is on rotation assignment to the ACRS staff from
NRR, is also present.
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 March 8, 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 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.
We will proceed with the meeting, and I
call upon Mr. Grimes of NRR to begin. Good morning.
MR. GRIMES: Thank you, Dr. Bonaca.
My name is Chris Grimes. I'm the Chief
of the License Renewal and Standardization Branch,
and I want to thank the subcommittee for taking the
time to review the results of the staff's effort to
develop improved license renewal guidance.
As you may recall, we set off to review
license renewal applications for Calvert Cliffs and
Oconee with draft guidance, an industry guide, and a
standard review plan that were untested and
represented a very different way of staff review for
a licensing action.
We accomplished those first two reviews
through perseverance and with a focus on the
objective of Part 54. And through those efforts we
learned substantial lessons in how to improve that
focus and concentrate the staff review.
During the course of the review of the
first two applications, the industry also raised an
issue which they referred to as credit for existing
programs. That is described in a Commission paper,
SECY-99-148. As a result of that issue, and also a
reflection on the lessons learned from the Calvert
Cliffs and Oconee reviews, the staff set out to
develop improved renewal guidance largely in the
form of generic aging lessons learned, a catalog of
the staff's expectations of the attributes of
effective aging management programs.
We've kept the subcommittee and the
committee informed of our efforts as we've gone
through the evolution of trying to develop that
catalog and the improved renewal guidance that goes
along with it, with a focus on achieving
predictability and stability in the license renewal
reviews and to facilitate the future workload that
we anticipate because of the substantial industry
input and interest in license renewal for other
power reactors.
Today's presentation is going to focus
on addressing the way that the staff has responded
to public comments on the improved renewal guidance,
and I call upon Dr. Sam Lee, who is going to provide
the introduction for the staff's presentation.
MR. LEE: Good morning. My name is Sam
Lee of the License Renewal and Standardization
Branch, NRR. And as Chris had indicated, the INPO
license renewal guidance document consists of the
Generic Aging Lessons Learned, the GALL Report,
which is a staff evaluation of aging management
programs, and the SRP, which references the GALL
Report, to focus the staff in areas where programs
should be thoroughly evaluated, and also consists of
the Regulatory Guide which endorses NEI document 95-
10 that provides guidance to the applicants to
prepare their license reapplication.
There has been a significant agency
effort. It involved the office of NRR and the staff
who are conducting the license renewal applications,
and also involved the Office of Research. And Jit
Vora, on my right, he is the team leader from
Research. And the two national labs -- Argonne
National Lab, Yung Liu on my right, he is the
Project Manager from Argonne. And Brookhaven
National Lab, Mr. Morante on my left, he is the
Project Manager from Brookhaven.
This morning we are going to discuss the
changes or significant changes in the document as a
result of public comment when we issued it in
August. Back in August, the GALL Report has a
format that is a double-sided, two-page table kind
of format, and it turns out to be not very easy to
use. So as a result we streamlined the format in
the GAL Report into a one-page table format, and
then we centralized the program evaluation into
Chapter XI of the GALL Report.
We are going to discuss the GALL Report
by structures and systems later on today. We are
going to also discuss the associated changes in the
program also.
The SRP references the GALL Report, so
when the GALL -- when we make a change in the GALL
Report, we make the corresponding or conforming
changes in the SRP. However, in Chapter II of the
SRP, we discuss the scoping. This is separate from
the GALL Report. Okay? So Mr. S.K. Mitra will
discuss the changes in the SRP relating to scope
this morning.
And Dave Solorio is going to discuss the
changes in the Regulatory Guide and NEI 95-10. And
we were asked to discuss the one-time inspections,
and Dave will also do that.
We are preparing a SECY paper to submit
this document to the Commission for approval in
April. And during the interaction with NEI to go
over their comments on these documents, they
identified five items that we should continue
dialogue on. And we will discuss them later on this
morning as they come up in the respective systems.
Another NEI comment is on the -- how
these documents are going to be used. NEI is now
performing a demonstration project which prepares
some sample portions of an application, and they
plan on submitting this to the staff by the end of
April. And we will interact with industry to go
through that document to see how we can work out the
implementation details when all of these documents
get folded into the process.
CHAIRMAN BONACA: Before you move that,
could you expand on the second bullet? I mean,
continue dialogue on these five issues.
MR. LEE: Yes. We're going to talk
about this later on in the later portion.
CHAIRMAN BONACA: Okay. All right.
MR. LEE: Okay? As they come up.
CHAIRMAN BONACA: Okay.
MR. LEE: Basically, this is -- continue
to exchange information with NEI.
MR. GRIMES: Sam, if I may, this --
those five items were issues that were -- that
evolved from industry comments for which there was
some controversy. And rather than take those issues
to appeal, the industry requested that we -- that
they be afforded an opportunity to continue a
dialogue on those subjects, with an expectation that
perhaps improved guidance or improved positions
would be developed for future changes to the
guidelines. And as we get to those topics and the
particular sections that they apply, we will explain
the details.
CHAIRMAN BONACA: Should complex
assemblies be part of that list?
MR. GRIMES: No. I believe that complex
assemblies has been clarified. There may still be
some details to work out, but that issue did not
rise to a level of potential appeal.
CHAIRMAN BONACA: Yes. Because it seems
there is some kind of significant issue in the Hatch
application.
MR. GRIMES: And we expect that we'll be
able to resolve that, but we are continuing to
discuss treatment of complex assemblies on the Hatch
application.
CHAIRMAN BONACA: Okay. Thank you.
MR. LEE: Okay. Is there any more
questions? Okay. Now I'm going to turn it over to
Mr. Steve Koenick to discuss the public comments.
MR. KOENICK: Good morning. I am Steve
Koenick. To my right is Ed Kleeh. I'll give you a
brief overview of the public comments.
We issued four documents, as Sam stated,
on August 31st in Federal Register Notice 65
FR53047. Following that, we had a public workshop
with over 100 participants. We also received
numerous comments on the improved regulatory
guidance documents.
On the third bullet I reference NUREG-
1739, which is the analysis of the public comments.
We received over 1,000 comments, the bulk of which
was from the nuclear industry, with the majority of
those being from NEI.
With the written comments, you see 100
-- over 100 individual comments. The majority of
these comments were with respect to nuclear power as
a whole and the license renewal process to which we
responded to each comment with a description of the
license renewal process. So that's how we
dispositioned those comments. The rest are
articulated in the NUREG, if you have any questions.
If none, why don't I turn it over to the
SRP Chapter II on scoping.
MR. MITRA: Good morning. My name is
S.K. Mitra, and with me from NRR on my left is Greg
Galleti is -- he has contribution regarding scoping.
And on my right is Brian Thomas, also from NRR, and
he contributed on scoping and screening.
Today we'll discuss the changes in
scoping, Chapter II, the standard review plan from
the -- due to the industry comments. As Dr. Lee
previously said, when the GALL changed, it resulted
in a corresponding change in the SRP, and we will
discuss later on as we talk about other GALL
changes. But how that Chapter II of SRP addresses
scoping which is separate from GALL, so in this
slide we are only going to talk about SRPLR Chapter
II, which is scoping.
The first bullet is we incorporated
severe accident management to the source document to
consider scoping. This is done in response to ACRS
letter to Chairman dated November 15, 2000, to add
severe accident management guidelines to SRPLR Table
2.1-1, which is sample listing of potential
information sources for identifying structure,
system, and components within the scope of license
renewal.
The number two bullet is clarify the
focus of scoping review. We clarified in response
to industry comments. The industry took an issue
that we should -- that the industry should only,
under Rule 5421, request to identify the list of SSC
data subject to aging management review, not a list
within the scope of license renewal.
Previously, the previous application,
the industry submitted a list of components that are
within the scope of license renewal. So the change
in the SRPLR will be from -- in the future, the
industry is only going to submit the list which are
in AMR, which is, you know, aging management review.
And the other list will be determined
through the sample in PNID, review of FSAR, and
other plan documents, what SSC are, you know, within
the scope. And during the inspection, the plant --
the list will be available for the inspectors.
CHAIRMAN BONACA: Well, let me ask a
question. I'm trying to understand if I understood.
So the industry wants to have only the results of
the scoping and screening listed in the application?
MR. THOMAS: Yes. If I understand the
industry's comments appropriately, they --
basically, they're saying that the SRP should focus
on the actual expected contents of the application.
And when you look at the rule, it specifically
states that it should just be the structures that
are subject to AMR.
CHAIRMAN BONACA: Yes. I understand
that. I mean, the way we have seen it, there was a
scoping process that said this is -- potentially it
should be in the application.
MR. THOMAS: Right.
CHAIRMAN BONACA: I mean, should be
under the aging management programs. Then you have
a screening process that will cut out a number of
those, because they do not perform the function that
-- the result of it is a list of components which
will be subject to an aging management program.
MR. THOMAS: Right.
CHAIRMAN BONACA: That's what they want
to have in the application?
MR. THOMAS: In the application itself,
yes.
CHAIRMAN BONACA: How do you -- how does
a reviewer understand the process by which the
screening has been applied if you don't know what
the list they started from is?
MR. THOMAS: Well --
CHAIRMAN BONACA: I'm trying to
understand, you know, how you do that. I mean, the
review process is a very important one. I'm saying
this because even the ACRS struggles with the
review, and we are -- you know, since scoping is
important, and how you go through the steps is
important.
MR. THOMAS: Right. There is a review
of the scoping methodology itself that is performed.
And then the review of the application itself is
just focused on the results of that -- of the
implementation of that scoping methodology, which
is, you know, a subordinate list of structures and
components that are subject -- yes, that list is
subordinate to the bigger picture list.
What a reviewer essentially has to do is
what we consider to be a negative review if you
will, and what you're looking for is really what's
been omitted from the scope of structures and
components subject to AMR. What a reviewer then has
to do is just canvass the PNIDs, the FSAR, any other
plant supporting documents, the licensing basis, and
so forth, to determine if there are any additional
items that should have not been omitted from that
list that presents the results of the screening, the
scoping and screening.
CHAIRMAN BONACA: But it seems to me
that this places all of the burden on the staff. I
mean, I have a concern with that, and I would like
to express it now, because I've seen it also in the
Hatch application that we are talking about
tomorrow. If the staff has to ask questions, many,
you know, requests for additional information
saying, "Why didn't you include in scope the
following 27 components?" and then the answer comes
and says, "Oh, of those, 20 are in scope, but you
have to look at them some other way."
And so you keep asking questions, and
you keep having some confirmation or some exceptions
and expirations. At the end, you are making a
statement in the SER that you have -- you have
reasonable confidence that all components that
should be in scope are in scope.
How are you making that statement? I
mean, you have to do a lot of pulling strings to --
you know, I mean, the process it seems to me becomes
some difficult for a reviewer that I'm just
questioning how you're going to be able to make a
statement that says there is reasonable confidence
that all issues in scope are in scope.
MR. THOMAS: It is a very involved
review process, and it's very involved review on the
part of the reviewer. But it forces the reviewer
to, you know, do a thorough evaluation of the
systems and structures and components, and to do
just that, what you said, to prod and probe to see
if there has been any omissions from the screening
results.
MR. GALLETI: Excuse me. This is Greg
Galleti. I'm with the IQPB part of NRR. We're
responsible for the scoping methodology review. The
staff would have two opportunities to review the
scoping methodology in detail.
One would be during the scoping audit
which is performed by the staff reasonably early on
in the process. We would be on-site at the
engineering offices looking at the design
documentation and going through with the cognizant
engineers the specifics of the scoping review,
scoping methodology, and looking at the scoping
results.
In addition, there's a second
opportunity for the staff to go through in detail
and look at the scoping results, and that would be
during the scoping inspection which is performed by
the regional offices. They would go out and do a
more formal review of the results, system walkdown,
things of that nature, to determine if in fact the
scoping was accomplished in accordance with the
methodology put forth.
CHAIRMAN BONACA: I understand that. It
doesn't change the -- yes, sorry.
MEMBER SHACK: Yes. You know, it seems
to me, and I guess we've argued around here, that it
would certainly be helpful to the reviewer to have
these results. What is the major -- is it really
just the burden on the licensee to provide this
list? He's got the list.
CHAIRMAN BONACA: He's got the list,
hopefully. I think I started from somewhere, and --
MR. GALLETI: The list would be
available to us during the audits. Obviously, the
list has been developed by the licensee as part of
their methodology. When we go out to do the audit,
that level of detail would be available to us, and
we would exercise reviewing that information.
MR. GRIMES: This is Chris Grimes. I'd
like to clarify that we can reflect back that it was
the focus of the renewal rule that established that
the application need only provide the results of the
process, and the rule focuses on a process-oriented
screening -- scoping and screening activity for
which the application is specifically told to only
produce the result.
The guidance that we have provided in
the SRP explains to the staff how to go about
testing the results of the process. And,
admittedly, it forces the staff to stop and think
about the insights gained from, in this particular
case, severe accident management guidelines, but
also the FSAR and other source materials for which
the staff then applies its experience and knowledge
in order to go through a process of testing those
results in order to determine whether or not the
staff can identify any structures, systems, or
components that have been omitted. And that's the
way that we have constructed the guidance, is to
explain to the staff how to go about doing that.
As Greg pointed out, during the
methodology review and the scoping inspection, the
staff has an opportunity to look at the underlying
documentation that includes things that were
originally considered and then excluded for whatever
reason. And our safety evaluations have explained
what we found, how we've tested, and how we reach a
conclusion that is framed in terms of the staff
hasn't found anything omitted, and, therefore, there
is reasonable assurance that the result is complete.
And we certainly could consider a new
construct for the rule that would present the front-
end of the process, but that would tend to detract
from the process orientation of the rule.
CHAIRMAN BONACA: Yes. I'd like to note
that the rule -- it's written in a few pages, and
the guidance is written in hundreds and thousands of
pages. And I'm saying there is quite a latitude in
support and documentation to help the processes
which are implied in the application of the rule,
which is the development of the application, the
review, the SCR, and everything else.
So I -- I can't argue now -- and you
may, in fact, have available during your inspection
a full listing and very scrutable. I'm only saying
that it doesn't facilitate, for example, for a
reviewer like myself. I spent time looking at the
Hatch application, and I really was troubled by the
fact that it was hard to pull strings to find how it
went from A to B to C. And I think that documents
should be more scrutable than that. Anyway, that's
my comment here.
MEMBER LEITCH: Wait a minute. I had a
question on the first bullet, if you were getting
ready to move forward. As I understand it, all that
was done as a result of the ACRS comment was that
you added severe accident management guidelines to
Table 2.1.1. That table says sample listing of
potential information sources.
So there's a suggestion that one might
look at severe accident management guidelines. It
leaves me with a question about whether that's
really required or not. In other words, if there is
equipment that is necessary to carry out actions
prescribed in the severe accident management
guidelines, is that equipment required to be in the
scope?
MR. GALLETI: If I could answer that.
This is Greg Galleti again. What is required is
that the application be consistent with the current
licensing basis. To that extent, if there is --
when you review the severe accident management
guideline, if there is equipment in that --
described in that guideline that would be consistent
with the COB, then one would consider that to be
potentially within the scope.
Just because something is in the severe
accident guideline does not necessarily mean that it
must be within the scope of for license renewal.
But, generally, what we have done is we've put, you
know, a rather large listing of potential documents
that would be available to the staff to review
really in preparation for embarking on the scoping
evaluation.
The mandate of the staff is to come up
with a safety determination, based on getting a good
understanding of what the current licensing basis
is. That's a formidable task, and the staff felt it
was appropriate to try to encompass as many
technical documents that pertain to the licensee and
the design of the plant as possible. That's really
the general reason why we felt it was appropriate to
incorporate it there.
MEMBER LEITCH: But doesn't it -- the
severe accident management guidelines are not in the
current licensing basis, are they?
MR. GALLETI: That's correct.
MEMBER LEITCH: So it seems to me it
still begs the question as to whether we're -- what
is our expectation with regard to severe accident
management guidelines.
MR. GALLETI: I think what we've tried
to do is provide the staff with an opportunity
certainly to look at that information to try to
glean some insights as to what would be risk
significant or important SSCs for the purposes of
this plant -- you know, any particular plant.
I think what we've determined is that
the efficacy of the SAM guidelines is really going
to be considered on a site-specific, case-by-case
basis. Again, that's why we had incorporated into
that level of this SRP.
MEMBER LEITCH: And, again, the only
change that was made as a result of that was just
the added listing in this table. There's nothing in
the text that refers to that?
MR. GALLETI: I believe that's true.
MEMBER LEITCH: Okay. Thank you.
MR. MITRA: The last bullet we have --
item which we are having continued dialogue with
NEI. And it's IPE/IPEEE has a source document to
consider for scoping. Since license renewal rule is
deterministic, not probabilistic, the industry
commented that PRA techniques have very limited use
for license renewal scoping.
There is one element -- the review of
individual plant examination, which is IPE, and
individual plant examination of external event,
which is IPEEE, in the SRP. The staff agrees that
license renewal rule is deterministic, but also
feels that the use of IPE and IPEEE does provide
useful insight for current licensing basis.
The dialogue with the industry is still
going on, and hopefully we will have some kind of a
resolution on this.
MR. GRIMES: This is Chris Grimes. I'd
like to expand on that thought in further response
to Dr. Leitch's question. The standard review plan
generally explains to the viewers your source
material as part of this challenge to the results of
scoping and screening, and particularly in the area
of the use of severe accident management guidelines
and IPEs.
The staff has very powerful tools to go
-- to prod into the current licensing basis and to
determine the extent to which there may be systems,
structures, and components that are important to
safety that may not be part of the current licensing
basis.
And I believe that it's reasonable to
characterize the industry's concern as further
guidance in the standard review plan in terms of how
to use those devices without causing damage, and
that is to unnecessarily challenge the current
licensing basis to be more risk-informed without an
explanation of the process by which risk-informed
changes to the licensing basis should be made.
I believe that the guidance is
reasonable, in terms of the importance of the focus
on maintaining a current licensing basis and simply
selecting from that those systems, structures, and
components that need to be considered for aging
management reviews.
But I do also see an opportunity for us
to draw experience from risk-informed licensing to
further expound the explanation about how to use
risk insights in a constructive way. And that's why
we'll continue a dialogue in this particular area
that may result in additional guidance to the
reviewers in the future and how to challenge the
current licensing basis in a constructive way.
MR. MITRA: That's all we have on
scoping.
MR. BARTON: Is there going to be any
more discussion on the standard review plan in
today's presentation, or is this it?
MR. MITRA: Well, as I said before, that
any changes in GALL have an effect on SRPLR, and we
will discuss along -- the changes with GALL in the
later part of the presentation.
CHAIRMAN BONACA: Any other questions
for --
MR. BARTON: Yes. Mario, I've got a
question, and I don't know if it's timely or
whatever. Section 1 of the SRP, paragraph 1.1.3.2,
it talks about timeliness of the application and
says the licensee must submit an application at
least five years before the license expires. I
don't know whether this paragraph is a "gotcha" from
a licensee and decides late in life that I'm going
to now extend my license, want to extend my license.
And I'm in my fifth year before
expiration, and I submit an application which the
reviewers decide is not "a sufficient application,"
and I have to modify it. It says I have to submit
the modified application with at least five years.
I just wonder whether if you're late in
submitting it and you have to modify it, whether you
can still meet the requirements of the standard
review plan, because the next section says if I
don't do this, the reviewer checks off, "No, I have
not satisfied this requirement," and I get a letter
from the NRC that says my license will expire in
five years. End of story.
And I just wonder whether that's what
this thing really gets you -- is it a real "gotcha"
or is there a way out of this thing? That's the way
I read this.
MR. GRIMES: I'll respond to that
question. The provisions for timeliness are
established by the rule, the guidelines, for the --
to the staff are simply the guidelines on how to
treat the timeliness requirements in the rule.
We've had several requests -- at least a couple of
requests to take exception to the other end of the
time scale, and that is not sooner than 20 years
prior to expiration.
And it really gets to the Administrative
Procedures Act in terms of the timeliness for the
proceedings to occur, which were originally
predicated on an expectation that it would take five
years to complete a review.
I would expect that if an applicant were
to determine late in life that they still want to
apply for license renewal, and they come in with
less than five years to go, that they would be able
to make a case for taking exception to that
requirement, and then the staff would be given
specific guidance on how to treat those specific
cases.
But this statute wasn't intended for the
staff to be backed into a corner on making the
timeliness decision. It's an administrative
requirement for the process.
MR. BARTON: Thank you, Chris.
MEMBER LEITCH: I guess I had a couple
of technical questions in the standard review plan.
I'm a little unclear how we're going to proceed
today. Is this the appropriate time to ask those
questions? Or could they be discussed when we talk
about GALL? You're just talking about a few changes
that have been made to the standard review plan?
MR. GALLETI: Well, to the specific
section of the SRP. If your question relates to
that particular section, I guess we can discuss it
right now.
MEMBER LEITCH: No, it does not. Okay.
MR. LEE: Are your questions relating to
Chapter III of the SRP? This is Sam Lee from NRR.
MEMBER LEITCH: No. They're mainly
Chapter IV, actually.
MR. LEE: Chapter IV? And those -- yes,
what are the questions? Maybe he can help the, you
know, panel, you know, answer that for you when they
come up.
MR. BARTON: If you want to talk about
Chapter III, the comment I've got on Chapter III is
there seems to be a lot of repetition in subsections
of Chapter III. And I don't know what your plan is
with this document to go back and do some more
editing, or if this is the final shot, or whatever,
but I think you could significantly improve this
document just by looking at Section 3.2 and some of
the subsections -- 3.2.2.2 and 3.2.3.2 as an
example.
There is so much repetition I think that
you could kind of take out 90 percent of the
repetition here and still get your point across.
And the same problem occurs in the power
steam and power conversion in Section 3.4. If
you'll look at those sections, I think you can
significantly improve this document by a good
editing job.
MR. GRIMES: Our editors are going to be
sorely disappointed.
CHAIRMAN BONACA: I had just a couple of
questions, too, about Section 3. There are a number
of -- for example, under auxiliary systems, there
are some sections where the section is still there
but at the beginning of it there is a parenthesis
that says, "Program no longer used." And I don't
understand, what does it mean? I mean --
MR. BARTON: 3.3.2.2.6 and 3.3.2.2.8 are
examples of --
CHAIRMAN BONACA: Are examples of --
MR. BARTON: -- our program you say
"Program is not used."
CHAIRMAN BONACA: Yes.
MR. BARTON: Kind of confusing.
MR. LEE: I guess when we come to the
auxiliary system, the panel can explain to us.
CHAIRMAN BONACA: Also, before that, in
a number of other sections, like 3.2.2.2.2 on the
crack initiation and growth due to stress corrosion
cracking, that was in the old document. It's not
there anymore. There are many examples of certain
issues under certain sections that have been totally
eliminated. I'm sure there is a logic behind that.
I would like to understand how you
restructure that eliminated those sections from the
previous draft. In some cases, I mean, I thought
the issue was still there. But I guess the
discussion is gone, so either it has been absorbed
somewhere else and I don't understand where, or it
doesn't belong there and I don't understand why.
So if you will talk to me about that.
MR. LEE: Yes, we'll talk about that
later.
MR. MITRA: Any other questions on
Chapter II SRP? If not, we'll leave the floor for
Mr. Peter Kang for Chapter II and Chapter III
structure.
CHAIRMAN BONACA: As we get ready for
this presentation, there was one more question
regarding the SRP. It would be probably good to
provide it now in case you want to look for an
answer from NRR.
MEMBER LEITCH: It was regarding
Chapter IV, actually. I wasn't sure if we were
coming back to that or not. 4.2.3 related to the
elimination of circumferential weld inspections for
boiling water reactors, and I was just wondering why
we were doing that. Is it very difficult or
impossible to inspect circumferential welds?
It seems like what we're doing here is
saying, well, we've made an analysis and they're
good for 64 effective full power years. And we're
going to improve operator training so that we don't
have any of these low temperature overpressurization
events.
But my question still remains, why not
just look at the welds?
MR. LEE: We'll discuss that later.
MEMBER LEITCH: Okay.
MR. LEE: In Chapter IV of the GALL
Report.
MEMBER LEITCH: That will come up later?
Okay.
MR. LEE: We will do that.
MEMBER LEITCH: Thanks. Okay.
MR. KANG: We are ready to talk to GALL
Chapters II and III.
My name is Peter Kang, K-A-N-G, with the
License Renewal, and --
MR. DAVIS: Jim Davis from Materials and
Chemical Engineering.
MR. COSTELLO: Jim Costello from Office
of Research.
MR. BRAVERMAN: Joe Braverman,
Brookhaven National Lab.
MR. ASHAR: Hans Ashar, Mechanical and
Civil Engineering Branch.
MR. MORANTE: Rich Morante, from
Brookhaven National Lab.
MR. KANG: Okay. For Chapter II, which
is containment structures, and Chapter III,
structure and the component supports, So those two
areas -- chapters we had in -- although there was a
lot of changes, comments on that, but this is the
most -- four most important issues.
The first has been dealt with before.
The first bullet is dealing with managing aging
effects of concrete and steel for inaccessible
areas. In the August version of GALL we required
evaluate the plant-specific programs whenever for
any inaccessible areas. When the conditions in
accessible area may not indicate, then it presents
degradation to some inaccessible area.
Since the industry commented that such a
requirement is over and above 10 CFR 50.55A, which
states, "Licensees shall evaluate the acceptability
of an inaccessible area when conditions exist in an
accessible area that could clearly indicate the
presence of degradation to such inaccessible areas."
So our position was a very stringent,
which is -- obviously, was that you've got to have a
plant-specific whenever you have an inaccessible
area. So staff decided to clarify this aging
management of an inaccessible area.
The latest GALL has revised it to
include specific criteria for, let's say, aging
effects of concrete due to aggressive impact or
corrosion of embedded steel. The applicants should
establish periodic monitoring of below-grade water
chemistry and evaluate whether the below-grade
environment is found to be aggressive.
But then we have a definition of -- or
criteria for aggressiveness -- is based on NUREG-
1611, which is for pH levels and chloride levels and
sulfate. And then --
MEMBER LEITCH: Could you point us to a
specific page on GALL? Do you have that
information?
MR. KANG: Yes. The latest or the
August versions?
MEMBER LEITCH: This is the March 2001
version.
MR. KANG: Oh, the 2001. 2000 is the
August version.
MEMBER LEITCH: No, the latest one.
MR. KANG: Oh, okay. The latest one.
Okay.
This is first -- okay. PWR is in the
front sections, and BWR is in the back. And the PWR
Section 2, Chapter 2A, 1-3, has -- let's see here,
this is -- okay. Aggressive chemical is actually 1-
4.
MEMBER LEITCH: Okay.
MR. KANG: Aggressive chemicals and --
okay. That's for one. And then, four, aging
effects on concrete due to leaching of calcium
hydroxide, this is on A-1-3, the first items on the
bottom, identified as A.1.1-B. That one the
applicant has to establish the leaching is not
significant by evaluating whether the concrete is
exposed to the flowing water.
Even then, you also have the conflict as
to whether -- evaluate whether a conflict is
constructed based on ACR 201.2.R. This is to ensure
the conflict is dense and well-cured and has low
permeabilities.
And then the last one is steel. For
aging effects of steel area of containment due to
corrosion, the concern was this is water on the
containment floor, seeping through cracks in the
concrete floor, or past degraded joint sealants.
So to determine whether loss of material
due to corrosion is significant the applicant
establishes -- there was a list of four items,
whether they -- their concrete meets the requirement
of ACI, and the monitoring of concrete for
penetrating cracks, and also moisture barrier. Is
it constructed or built in accordance with IWE
requirements? And then, also develop a program to
minimize water spillage.
Then, so what we said was if any of
those criteria cannot satisfy, then a plant-specific
management program has to be developed to address
each of those items.
MEMBER LEITCH: So conversely, then, if
all those criteria are satisfied, then no further
action is -- no further evaluation is required.
MR. KANG: Yes, that's correct. Yes.
MEMBER LEITCH: thank you.
MR. KANG: Second bullet. This is on
managing loss of material due to corrosion of
containment of steel elements. In our August
version of GALL, the report described -- what we
said was IWE, with Appendix J and the coating
program -- in other words, you've got to have all
three components together. But industry commented
that Appendix J and the coating should be deleted,
because IWE alone should be -- is acceptable as a
stand-alone program.
MR. BARTON: Excuse me. "IWE" meaning
-- what's IWE?
CHAIRMAN BONACA: What does it stand
for?
MR. KANG: IWE relates to the in-service
inspection of metallic liners and --
AUDIENCE MEMBER: The code.
MR. BARTON: Oh, the code? Okay. All
right. Gotcha. Okay.
MR. KANG: So then staff did that -- we
had a lot of discussions back and forth, especially
pertinent to Appendix J. And the staff could not --
we did not agree to deleting Appendix J and coating
program. However, in the past, the staff has
granted the relief request for a few certain plants
on IWE inspection, on the maintenance of the
protective coating to control corrosion.
So on that basis, the final version has
slightly revised on the coating program. We just
added a statement which says the coating program is
-- if the coating program is credit for the
managing loss of material due to corrosion during
current licensing terms, then you should continue
on.
So that's a slight difference on this
managing loss of material due to corrosion on the
containment steel elements.
MR. BARTON: Does this take care of
corrosion of containment on the exterior of the
steel as well?
MR. DAVIS: No. No, it doesn't. It
only applies to inside.
MR. BARTON: How do you handle exterior
corrosion?
MR. DAVIS: I'm not aware of it being a
problem, but it --
MR. BARTON: How about Oyster Creek's
drywall?
MR. DAVIS: Except Oyster Creek. And
it's not covered by the code.
MR. MORANTE: This is Rich Morante from
Brookhaven. The basic in-service inspection
requirements of IWE would include inspections of the
exterior surface of a steel containment.
MR. KANG: Accessible.
MR. MORANTE: Of the accessible areas of
a steel containment.
MR. BARTON: Accessible areas.
MR. KANG: Accessible areas.
MR. MORANTE: Except that IWE, through
10 CFR 50.55A, which invokes IWE, does require an
evaluation of inaccessible areas if there is
suspicion that there may be degradation there based
on what is seen in an accessible area.
The sand pocket region would fall into
one of those areas that would have to be
specifically reviewed by an applicant, and it is
identified in the GALL tables as an area for review
during license renewal.
MR. BARTON: Thank you.
MR. KANG: Okay. Third bullet. The
third bullet is for managing stress corrosion
cracking and the crevice corrosion for the stainless
steel.
MEMBER SHACK: Can we just back up for
just a second?
MR. KANG: Yes, okay.
MEMBER SHACK: Go through that coatings
program once more. So if they have the coatings
program -- only if they're taking credit for it -- I
mean, that's the thing. A lot of the time -- I see
that in other sections, that they may have the
program but it's only sort of required if they are
asking credit for it. They may try to continue the
program, but if they can live without the credit
then they don't want to sort of commit themselves to
the program, is sort of what I see happening here.
Is that the basic idea?
MR. DAVIS: A number of utilities have
come in and asked for relief from the code
requirements of IWE to use our coatings program
because it's a more intense program. And so they're
doing it in relief of the code requirements.
MEMBER SHACK: Requirements. Oh, okay.
So you don't want to have both.
MR. MORANTE: Well, let's say we're not
required to --
MEMBER SHACK: Required to have both.
MR. DAVIS: A lot of them do both,
actually.
MEMBER SHACK: Right. Yes. But
required to only --
MR. ASHAR: But the earlier applications
like Calvert Cliffs, Oconee, and Hatch that I'm
reviewing now, they all have credited coating
program for corrosion. So far we have seen that.
MR. DAVIS: That's only in containment,
though, not in the coatings program outside of
containment.
MR. ASHAR: Yes.
MR. KANG: All right. The third bullet
-- this is for managing stress corrosion cracking
and the crevice corrosion for stainless steel spent
fuel pool liner issues. Industry commented that
deleting monitoring of a leakage detection system
that was discussed in August version, we had a leak
chase monitoring of leak chase system drain lines
and leak detection sump.
They commented that it should be
replaced with just a water chemistry program as
applicable, aging management program. Their
justification was the water chemistry program
precludes aging effects by maintaining spent fuel
parameters so that the degradation would not occur.
Staff has agreed or concurred that the
water chemistry program could be identified as
applicable aging management program. And then also,
in addition to water chemistry program, staff took
the position reliance solely on controlled water
chemistry does not manage potential degradation from
concrete side of a spent fuel pool liner -- the
other side of a concrete.
So because -- and this is because we --
such degradation we have seen at the one plant. So
-- so and the latest GALL uses -- revised this one
and said uses both a combination of the water
chemistry program and the monitoring of pool water
level to manage the corrosion of a stainless steel
fuel pool liner.
MEMBER LEITCH: So you're talking about
monitoring the pool water level --
MR. KANG: Yes.
MEMBER LEITCH: -- rather than tell-
tales?
MR. KANG: Well --
MEMBER LEITCH: I mean, it would have to
be a pretty gross leakage --
MR. KANG: Right. We --
MEMBER LEITCH: -- pool water level.
MR. KANG: We had a lot of discussions
with industry at the time. When was it? December,
right? And not all industry uses that generic term
such as leak chase, leak chase systems, or -- so we
-- probably more appropriate just to more general --
make it very general, say water level. Go ahead.
MR. DAVIS: Nobody really looks at the
leak chase system to see leakage. They watch water
level. And if the water level starts dropping, then
they go look at the leak chase system and see if
they have a leak. That's what the industry is
telling us their experience is. So we agreed to
that.
CHAIRMAN BONACA: Please.
MEMBER FORD: You must forgive me if
some of my questions are simple, because this is my
first time on this committee. You mentioned just
now inspection of accessible regions. What happened
to the inaccessible regions?
MR. ASHAR: They were the first bullet.
If you see the first bullet that we have, it was
referring to the inaccessible areas. And that is
where we concentrated, because accessible areas are
being covered by the code -- code requirement, IWE.
MEMBER FORD: Okay.
MR. ASHAR: Okay. Inaccessible we were
a little bit concerned about. We said did not --
was not covered in the code, and we had to do
something about it. So the first thing what we have
done was to put some provisions in the regulation,
which is 10 CFR 50.55A, the requirement that if the
weaknesses are found in accessible areas that
indicates degradation of the inaccessible areas,
then they will go and check out what is going on in
an accessible area. That is the way the rule is
written.
Then, in NUREG-1611, we said, "If there
is no evidence in the accessible area, and still
there is corrosion going on, how do we get to the
bottom of that?" And this way in a generic way you
say, "There is no evidence. If the environment and
conditions are such that could give rise to certain
corrosion or degradation in inaccessible areas, that
has to be investigated as a part of the license
renewal."
MEMBER FORD: Okay.
MR. ASHAR: And in order to resolve this
particular item, we had quite a discussion with the
industry on this area. And what we did was it
looked like an open-ended thing for the industry.
So they said, "Identify the areas that you think are
the most susceptible." So we identified two areas.
One was the -- under the -- just over the basement,
and on the top of it, in PWRs particularly, there is
a concrete -- two feet of concrete.
Okay. And we said, "Water always goes
to the top of the -- up to the top, and then if
there is cracking in the concrete, then it can seep
in, and then it can degrade the liner below." That
was one concern.
The second concern that we expressed was
if the chemical constituents of the soil is
aggressive enough, it can degrade the concrete
foundation part. So there are the two areas that we
identified, and then together with industry worked
on the criteria and everything. And we came out
with the criteria that we have in the GALL Report.
MEMBER FORD: Thank you.
MEMBER SHACK: Just on this water
chemistry program for the spent fuel pool liner,
they're arguing basically the temperature is low
enough that if they control the water chemistry they
can manage the cracking of the stainless steel.
MR. DAVIS: That's right.
MEMBER SHACK: And what temperature are
we talking about here, and how stringent are the
controls on the water chemistry?
MR. DAVIS: It's always below about 200
degrees F.
MEMBER SHACK: 200F.
MR. DAVIS: And that's controlled.
MEMBER SHACK: And what controls do they
put on the water chemistry, typically? I mean, it's
not as pure as a BWR, obviously.
MR. DAVIS: It's the regular reactor
vessel, RCS chemistry that --
MEMBER SHACK: Chemistry.
MR. DAVIS: -- guidelines, the EPRI
guidelines. You have the same chemistry in the
spent fuel pool that you have in the RCS.
MEMBER SHACK: RCS. I see. There's no
boron additions, or something? No?
MR. DAVIS: Not in a BWR.
MEMBER SHACK: Not in a BWR.
MR. DAVIS: But since you're
transferring fuel back and forth, you have to have
the same chemistry.
MEMBER UHRIG: If you dump the water and
boron in the fuel pool at all, is it soluble?
MR. DAVIS: In a PWR, you do. In a BWR,
you do not.
MEMBER UHRIG: In the fuel pool.
MR. DAVIS: In the fuel pool.
CHAIRMAN BONACA: This is pretty much
what they do right now, right?
MR. DAVIS: Yes.
CHAIRMAN BONACA: That's all.
MR. KANG: Okay. The last bullet deals
with that -- the August version of GALL included --
we had included cracking of metal component support
members due to vibratory loads and the cyclic
loading. The industry commented that there was --
that this is not a license renewal item and should
be deleted.
Their justification was that, number
one, proper design eliminates or compensates for the
vibrations and the cyclic loadings. And then, also,
what they said was vibration characteristically
leads to cracking in the short period of time on
order of hours or maybe days of operations. Such a
failure is probably early -- also occurs early in
life.
Because of this time period that --
because this time period is short when compared to
the overall plant operating life, cracking will be
identified and corrected to prevent occurrence long
before the period of extended operations. And they
also said that this degradation is very limited in
small -- a small set of components, and there is
corrective as -- as discovered.
The staff has agreed that cracks in the
steel elements component supports caused by
vibratory stress would be developed in a matter of
hours or days.
This timeframe is not consistent -- so
this timeframe is not consistent with the
requirements of the license renewal rule, which
addresses a slow aging process affected by extended
operations. So staff agreed to delete cracking of
metal components from the latest GALL Report.
MEMBER LEITCH: Now, that comment,
again, still applies just to steel structures.
MR. KANG: Yes, supports. Yes.
Component support sections of Chapter III.
CHAIRMAN BONACA: Only support section.
So it doesn't affect your definition, for example,
of complex assemblies that we have seen; for
example, the casing of a structure like fans that --
MR. KANG: This is a Class I and a Class
II and III and small support areas.
MR. MORANTE: Well, I'm not familiar
with the complex structures issue on --
CHAIRMAN BONACA: Well, I'm talking
about, for example, an HVAC fan hanging from some
ceiling out there, and there are structural members
that hold it. Typically, the fan will have some
vibrations in it maybe.
MR. MORANTE: Right. I would expect
that in that case we -- we must keep in mind that
there are certain cases where supports, especially
piping supports, may have been designed considering
cyclic loading. Those are still included in GALL as
-- they need to be addressed as a TLAA.
The areas we're considering here is
where the supports for piping or other structures
were not necessarily designed to withstand any type
of cyclic loading. So the vibratory loading that
might occur would be an unusual event, not a design
basis event.
For the case of the fan support, one
would expect that the design of that supporting
system for a fan that would tend to have a certain
vibratory load would be inherent in the design, and
it should be considered that way. So this would not
really cover that particular case.
CHAIRMAN BONACA: I'm trying to
understand it because I know in the Hatch
application that we will review tomorrow there are a
number of issues to do with passive components of
active systems that should be still within license
renewal, and a list that was disseminated made by
the SCR. And some of those passive components
include casings of HVAC systems as well as frames,
or whatever, supports of active components.
So I just am wondering, you know, when
we begin to cut it so close in the different issues,
and then it becomes hazy, or whether it applies,
whether it doesn't apply.
MR. MORANTE: In the current GALL, in
Chapter IIIB, we do specifically address supports
for components such as fans, probably a vibration
isolator. That's a specific line item in the GALL
tables that are subject to review.
CHAIRMAN BONACA: Okay. So there is --
MR. MORANTE: Whether it exactly covers
the case you're concerned about on Hatch, I couldn't
answer that question.
CHAIRMAN BONACA: We'll talk about it
tomorrow.
MEMBER SHACK: Now, again, are these
anticipatory -- anticipated vibratory loads or
unanticipated vibratory loads we're talking about
here?
MR. ASHAR: I would say unanticipated.
If they are anticipated, they will go into the
analysis or TLAA.
MEMBER SHACK: Well, I mean, I can sort
of envision an anticipated fatigue load I'd handle
in two ways. One, I'd do a cyclic analysis, and the
other one I would say, well, my vibratory loads are
below my threshold, or, therefore, I can run
forever.
MR. ASHAR: Exactly.
MEMBER SHACK: If I have an
unanticipated load, it doesn't seem to me to follow
into either one of those.
MR. ASHAR: And then it wouldn't be any
measurement. It will be just like in the current
license what is happening. Same thing will happen
in an extended period of life, and it should be
taken care of.
MEMBER SHACK: When I find that I have
vibratory loads that I didn't anticipate, I mean, I
do something about it, right? I either go out and I
do an analysis, or I --
MR. ASHAR: Yes.
MR. MORANTE: I'd like to address that.
You're correct when you say if the -- if the
vibratory loads are below the endurance limit, then
you can have an infinite number of these cycles.
You're not going to see a problem. So, obviously,
the concern is vibratory loads that would exceed
that level. If you exceed that level, and it's a
true vibratory loading, you're going to generate
millions of cycles in a very short period of time
and are likely to generate a failure locally.
Now, what the industry has said is we
have to deal with that in the hear and now. It's
really not a license renewal issue. It's an
operation -- it's an operating issue. And whether
we're operating in the first 40 years of life, or
years 40 to 60, is irrelevant. We have to address
it when we find this kind of problem, and we
basically looked at it again and said, "Yes, we
agree with you that it doesn't -- it's not really a
slow aging process. It's an operational problem
that you need to address immediately."
So that's the reason for us removing it
here.
MEMBER SHACK: Okay. I mean, I guess
you're right.
MR. DAVIS: It goes into your Appendix
B, Corrective Action Program.
MEMBER SHACK: But, I mean, it is a
cumulative damage process. But in high cycle, the
difference between 60 and 40 is nothing.
MR. MORANTE: Right. If it's going to
happen in a matter of days or a week or so, does it
matter at what point during that 40-year or 60-year
life that it occurs? And that's the basis for
removing the consideration.
MR. KUO: This is P.T. Kuo, License
Renewal and Standardization Branch. If I may
clarify a little bit. This item here only deals
with those supports for the steel structures or
frames or cabinets or -- it is not -- those supports
are not designed for any vibratory motion.
If they are, then it will be designed
according to the fatigue rule that -- that is
described in ASME Code Section 3 or used under the
code requirement. But these are those things that
are not designed according to those rules, not
required to design -- to be designed according to
those rules.
And that the vibration were due to some
unanticipated sources like pump vibrations. We
never expect it, but because of some other reasons
it vibrates, you know, high vibration amplitude.
There are two ways to mitigate those problems. One
is to immediately correct the problems, the problem
source. The other one is that if it vibrates really
with high intensity, you see the result right away.
It doesn't accumulate from 40 to 60.
CHAIRMAN BONACA: Okay. Any other
questions? If not, then I think we need a break.
It's 20 of 10:00. So we will meet again at five of
10:00.
(Whereupon, the proceedings in the
foregoing matter went off the record at
9:40 a.m. and went back on the record at
9:56 a.m.)
CHAIRMAN BONACA: Okay. Let's resume
the meeting now, and we have a presentation on
Chapter IV of the GALL Report.
MR. DOZIER: Yes, sir. Good morning.
My name is Jerry Dozier from the License Renewal and
Standardization Branch. I have Barry Elliot from
Engineering, Omesh Chopra from Argonne National Lab,
and Mike McNeil from Research.
Chapter IV deals with the reactor vessel
internals, the vessel itself, and also the reactor
coolant system. These five bullets represent
examples where public comments were resolved for
repackaging, providing minimal acceptable programs,
providing a real focus of concern, ensuring
relevance and completeness in the GALL Report.
For the first item, that's an example of
repackaging. In the ACRS meeting, we had
considerable discussion about neutron fluence
levels, and what is the threshold for ISCC, or when
does void swelling come into effect. We also had
industry discussions and debates about that
particular issue.
On the one hand, it was an argument of
accounting of materials versus thresholds, or we
could focus on what we really wanted the aging
management program to be. What we really wanted in
this aging management program was to monitor the
most susceptible locations and provide a method for
inspection to detect that mechanism.
And that's what we really wanted, and we
wrote an additional program, and it was consistent
with Calvert Cliffs, that would accept that program.
And if the licensee was willing to do that, then it
would require no further evaluation.
The second one deals with minimal
acceptable programs. Earlier, in the August
edition, we had boric acid corrosion, and we also
credited in-service inspection. NEI goes into --
MEMBER LEITCH: Before you move on to
the second bullet there, where is the -- could you
point me to the section in GALL where the change was
made?
MR. DOZIER: Yes, sir. In Chapter XI,
Program M16 titled "PWR Vessel Internals" is the new
program that was written.
MEMBER LEITCH: Okay. Thank you.
MR. DOZIER: Was there any question?
MEMBER LEITCH: No. I just --
MR. DOZIER: Okay.
MEMBER LEITCH: -- want to know for
reference. That's all.
MR. DOZIER: Yes, sir.
For boric acid corrosion, as we see it
earlier, ISI could be a mechanism also -- could be a
program that could be credited. NEI asked for the
minimal acceptable program. Boric acid corrosion
has been effective in the current term, and we feel
like that it would be effective in the extended term
for controlling boric acid corrosion.
So now in GALL we only have the boric
acid corrosion program monitoring being credited for
the boric acid corrosion.
CHAIRMAN BONACA: The boric acid
corrosion problem, this is a visual program?
MR. DOZIER: Yes, sir. It is a visual
program, whereas in ISI we were also looking at
crediting possibly -- when the -- during the
pressure test, you make it to detect some boric acid
corrosion. If it was in an inaccessible area, or if
it was covered by insulation, we thought that it
might be effective, you know, also for that. For --
CHAIRMAN BONACA: And this is all
components, anything which is effective -- this is
effective boric acid corrosion. I mean, so in
general it doesn't talk about --
MR. ELLIOT: This is not a coupon
program. This is an inspection program of the
actual components.
CHAIRMAN BONACA: Okay. I understand.
All right.
MR. DOZIER: Okay. The next one is an
example of how we got -- we made GALL more focused.
Earlier this was -- this PWSCC was primarily plant-
specific, but now we focused it on for -- for the
Inconel 600 penetrations they are primarily being
adequately managed by the chemistry and ISI program.
However, for the Inconel 182 welds, we
do need a plant-specific evaluation. Now, of
course, in that example, again, we're trying to
focus the licensee really where they need to be in
the -- or what we really want to see in the review
process.
There was also some comments that for --
for some components there were a lot of aging
effects. And sometimes maybe one or two of those
aging effects may not have been really applicable,
and we removed those from the GALL Report. For
example, wear/loss of material for the core support
pads and the guide tubes. Those were really not
significant and we removed them.
Have we removed the component? No.
They are still in there. Just that particular aging
effect was removed.
CHAIRMAN BONACA: Just because we
haven't seen wear or loss of material for core
support pads and guide tube cards? Or why else?
MR. ELLIOT: That's the reason. They've
been looking at it over the years, the industry, and
they -- and they mention it as something they look
for, but they haven't seen anything significant. So
since it was not significant all these years, that
we've decided to remove it and concentrate on the
other aging effects that could affect these
components.
CHAIRMAN BONACA: But you are telling me
they are looking at them. That's why they know that
there isn't. So --
MR. ELLIOT: Right.
CHAIRMAN BONACA: -- I mean, it's a
closed circle. Are they going to stop looking at
them, because --
MR. ELLIOT: No. There's an ISI
program, you know --
CHAIRMAN BONACA: No. I mean -- all
right. So it's not specific -- specifically tied to
license renewal, but it's still -- okay. So there
is not a commitment under license renewal. That's
what you're saying.
MR. ELLIOT: Right.
MR. DOZIER: The last bullet is more of
a completeness issue. One of the -- we had several
comments where NEI would ask for additional
components be added, so that they could be credited.
And we tried to accommodate those requests, so that
it would be easier for the licensee to reference the
GALL Report.
In this case, we are talking about the
CRD head penetration. That was an NEI comment.
Actually, this incore neutron flux monitoring tubes
was a request from Union of Concerned Scientists.
So we tried to accommodate and make GALL as complete
as we could based on those comments.
CHAIRMAN BONACA: Before you move on, if
you could go back to that PWSCC of pressurizer
Inconel 600 penetrations. Now, here the concern you
-- the intent was to focus the program where it's
needed, you said. Okay?
MR. DOZIER: Yes.
CHAIRMAN BONACA: Is there a concern
that when you begin to focus too much you may not --
now you may inadvertently neglect some areas where,
you know, you don't know exactly but it would be --
you know what I'm trying to say?
MR. DOZIER: Okay. Well, the GALL
Report actually is a self-check mechanism in it, and
it -- even though -- say we don't mention an aging
effect. If we don't mean the aging effect, that
does not relieve the licensee to identify that
effect and also report it to us in that application.
He can only take credit for the things that are
enveloped in the GALL Report.
So any -- any other -- that's the good
thing about GALL is that any new aging effects, or
whatever, that may come down the pike, if we have
not addressed them, they will come in as a plant-
specific evaluation.
Barry, I think you --
MR. ELLIOT: Yes. On PWSCC of the
pressurizer, 600 components, what our experience is
today is that the 600 component is-- the limiting
materials are in the upper head. And that's where
we're concentrating our inspections and our efforts.
If we see in the current license that we
need to expand the locations for inspection, then we
would -- we might include the pressurizer. But at
the moment, our experience is that the Inconel 600
type cracking is in the upper head. And so that's
where we're concentrating our effort.
The Inconel 182, of course, is a recent
issue, and it has more -- you know, it is in a lot
more locations, safe-ends, and all over, and that
gets -- and that's why it's plant-specific.
CHAIRMAN BONACA: Okay. I think you
have answered my question. My concern was when you
focus on something, it implies that you know exactly
where to look. Now, you know, these are -- there
are so many applications of this -- different
materials there, and that was the question I was
asking you. And you answered that.
MR. DOZIER: Okay. From Chapter IV, we
had a couple of issues that we were continuing the
NEI dialogue on. One of those dealt with the
operating experience with cracking of small-bore
piping, and the other was management of loss of
preload of reactor vessel internals bolting using
the loose parts monitoring system. And those we are
continuing the dialogue with NEI to come to
resolution on.
MEMBER SHACK: Okay. Can you describe
the issues of contention here?
MR. DOZIER: The first deals with small-
bore piping, and basically they are asking about the
operating experience. They are saying, have we
really got enough operating experience for us to
justify the one-time inspection that we are -- that
we now have in the GALL Report? If you look at some
of the operating experience, they may be because of,
say, a weld defect, or there may be some event-
driven issue.
But our bigger issue is that we feel
like this -- that small-bore piping will be a
concern in the extended period. So, really,
regardless of our operating experience, we probably
still want to pursue the small-bore piping.
And also, there is a -- a materials
research project being performed by EPRI, and we
want to follow that and -- you know, for the
complete resolution of small-bore piping. So I
think that -- in that particular case, it's really
an issue that's -- that's continuing forward, and so
it's one good to keep a dialogue on.
The next deals with loss of preload of
reactor vessel internals bolting. Their contention
is that ISI is good enough. We credited also the
loose parts monitoring system, you know, for this
aging effect. And the real issue is, is ISI good
enough? And we're still exploring that.
Also, with loose parts monitoring, some
of them took -- took loose parts monitoring out of
their tech specs and had -- have not -- have not now
got it even plugged up, or I guess not operating
further. What we don't want GALL to be is a
document that says, "This is the minimum program."
If they don't have a loose parts monitoring system,
of course, they can come up with any plant-specific
ways to monitor that aging effect.
MEMBER SHACK: Well, I thought that's
what GALL was was a minimum program, that this is
what you have to have. If you have anything more,
that's fine and dandy.
MR. ELLIOT: I think industry is arguing
that loose parts monitoring is an additional program
that they don't need for monitoring this aging
effect, and that their concern -- it's our concern,
too -- is that you don't want to put in a program
that monitors a particular aging effect, and that
puts the plant in a less safe condition. Like what
happens if they -- one of the problems, they have
loose parts monitoring. They've shut plants down
looking for things that were not there.
So that we don't want to start that --
down that road again. We've already done it in the
current license, take out the loose parts
monitoring. We don't want to put it back in. You
know, we're discussing that, whether it's necessary
to manage this aging effect using that.
MR. DOZIER: The way it initially got in
there was actually through a Westinghouse topical
report that referenced that was the way they would
do it. So we kind of got the idea from them, and
then as this has grown we've learned more. And,
again, I think the dialogue in this particular case
is a good one to keep going.
MEMBER LEITCH: Can you help me work my
way through here? I'm trying to find out about BWR
circumferential welds. All right? So when I go to
the -- I go to the GALL Report, and A.1.2 is for BWR
vessel shelves, and I guess an intermediate belt
line shell.
MR. ELLIOT: Do you want to take a look
at this?
MEMBER LEITCH: Please, yes.
MR. ELLIOT: Okay. Page 5 -- 4.A.1.5.
MEMBER LEITCH: 4.A.1.5. Okay. And
that's -- is that --
MR. ELLIOT: And it is the vessel shell
-- intermediate belt line shell, belt line welds,
and the aging effect is loss of fraction toughness,
neutron irradiation embrittlement. Do you have
that?
MEMBER LEITCH: Yes. Right.
MR. ELLIOT: In managing neutron
irradiation in BWRs we look at the impact of the
radiation embrittlement on the pressure temperature
limits, on the upper shelf energy, and we look at
the impact of the radiation embrittlement on whether
or not we need to -- a circumferential weld
inspection.
MEMBER LEITCH: Right.
MR. ELLIOT: And under the current
licensing term, we did a review and we determined
that the failure probability for circumferential
welds were so low that we didn't need to include a
circumferential weld inspection, that we could get
along with just the axial weld inspection as like
they would be more susceptible to cracking than --
the radiation embrittlement than the circumferential
weld. And that analysis was done for four years.
MEMBER LEITCH: Right.
MR. ELLIOT: And it assumes certain
radiation embrittlement criteria. Now, as long as
you met that criteria for the 60 years, you would
still satisfy the failure probability evaluation
which was used for the first 40 years. And that's
what this is intended to do is it -- is for the
licensees to show how they meet that neutron
irradiation embrittlement criteria.
MEMBER LEITCH: And there's a discussion
about 64 effective full power years?
MR. ELLIOT: Well, 64 -- okay. What we
did, we did the original evaluation of the BWRVIP
05, which is circumferential weld. They did the
original evaluation for 32 years, effective full
power years. And the ACRS raised the question: is
this a cliff, that if you go past 32 effective full
power years all of a sudden does radiation
embrittlement cause a high increase in failure
probability?
So we asked the VIP to evaluate 64
effective full power years, twice the amount of
time. And they did. And it didn't fall off a
cliff. It was a gradual change in radiation
embrittlement.
For license renewal, we wouldn't be
using the 64 effective full power year criteria. We
would want them to meet -- and our evaluation was
for the 32 effective full power criteria. We would
want them to show that at 48 effective full power
years they could meet the 32 effective full power
criteria.
MEMBER LEITCH: Okay. So 48 effective
full power years for --
MR. ELLIOT: Forty-eight effective full
power is 60 years.
MEMBER LEITCH: -- 60 years.
MR. ELLIOT: Eighty percent, 60 years.
MEMBER LEITCH: Yes. So the reason
we're not requiring inspection of the
circumferential welds is basically even at 60 years,
or 48 effective full power years, they have an
extremely low probability of failure.
MR. ELLIOT: Yes.
MEMBER LEITCH: And plus the fact
there's a requirement to do some additional operator
training to --
MR. ELLIOT: Yes, that's part of -- we
found out that there are certain events that are key
to this that could cause -- that are significant.
As long as they have operator training to preclude
those events, that's like a defense in depth.
MEMBER LEITCH: Are these welds
particularly difficult to inspect?
MR. ELLIOT: Yes. They're --
MEMBER LEITCH: More difficult than the
axial welds or --
MR. ELLIOT: It's a matter of location.
I mean, the axial welds are hard, too. It's -- you
need special equipment for the axial welds also.
MEMBER LEITCH: Okay. Thank you.
MEMBER UHRIG: One question. You
alluded to the 32 years or 48 years.
MR. ELLIOT: Effective full power.
MEMBER UHRIG: Effective full power
years. And given the increased performance in the
last few years of the plants, it's likely that one
of these limits is going to be exceeded before the
license expires. Are you -- how do you -- it's the
license that controls, not the 48 --
MR. ELLIOT: What really controls here
is not the 48 effective full power years or the 32,
whatever. It is neutron fluence. That's what we're
really using here. So as long as the neutron
fluence estimate they use for the evaluation,
whether it's 32 or 48 or whatever, is not exceeded
by the end of the license, then they're adequate.
MEMBER UHRIG: Okay.
MR. ELLIOT: And as long as they monitor
the neutron fluence, which is what they do, and they
stay within their limit, whatever they said is in
their application, they're going to meet the
criteria.
MR. DOZIER: Any further questions for
Chapter IV or -- Dr. Bonaca, I think you had
mentioned some -- maybe some SRP questions for
Section 3.1.
CHAIRMAN BONACA: We had some questions,
yes. If I remember -- well, there were some areas
which were eliminated from the previous draft, like
I can give some examples of one I notice. One was
under -- in management division. That's probably
for the next presentation, right?
MR. DOZIER: Yes.
CHAIRMAN BONACA: Okay. So I'll wait
for that. We talked about the complexity of
performing inspections on welds. And any lessons
learned from the disassemble experience on those
nozzles?
MR. ELLIOT: Well, it says that we used
to be very concerned about Inconel 600. Now we're
really concerned about the welds.
(Laughter.)
In fact, much more concerned about the
welds. And that's reflected here.
CHAIRMAN BONACA: Well, I'm more
concerned about the inspections, actually. I mean
--
MR. ELLIOT: Right.
CHAIRMAN BONACA: -- it says that, you
know, here you have full inspections and --
MR. ELLIOT: Right.
CHAIRMAN BONACA: -- you see nothing,
and then you have a crack, and then you inspect
again and you find --
MR. ELLIOT: Right.
CHAIRMAN BONACA: Which it seems to me
the whole aging and, in general, license renewal is
predicated on inspecting, seeing, and fixing. And
so that's why I asked the question I guess.
MR. ELLIOT: Yes. I mean, whatever we
work out in the current term for the Inconel 182, I
mean, will carry forward into the license renewal
term for inspection.
CHAIRMAN BONACA: Okay. Thank you.
MR. ELLIOT: Okay. Thank you very much.
MEMBER LEITCH: Excuse me. I had
another question. I guess -- excuse me for jumping
around here, but this concerns the generic safety
issue, and I guess the issue is basically there's a
concern that the effects of the reactor coolant
environment on the fatigue life of components were
not adequately addressed in the code of record. I'm
referring here to the -- to page 4.3-2 of the SER.
And I guess my comment is that it seems
like 40 years is at the margin, and I'm wondering
how we can justify 60 years. Is that --
MR. ELLIOT: Okay. First, I'm not the
fatigue expert. The fatigue expert is John Fair,
and he can answer this question a lot better. But
what I will say is that -- that as far as GALL is
concerned, fatigue is a TLAA and it has to be
evaluated by each plant. And that's how we handle
it for GALL, because we are concerned that they
could exceed the limit between -- during the
operating term.
MR. CHOPRA: I just wanted to add one --
that GALL requires them to address for all Class I
components to address the effect of environment on
fatigue.
MR. KUO: This is P.T. Kuo, License
Renewal and Standardization Branch again. The
fatigue issue will be addressed in Chapter IV of the
GALL Report. That is the TLAA, and you will see
some generic programs in Chapter X of GALL.
MEMBER LEITCH: In Chapter which?
MR. KUO: Chapter X.
MEMBER LEITCH: Chapter X.
MR. KUO: Yes.
MEMBER LEITCH: And we're going to
discuss that a little later today?
MR. KUO: Right.
MEMBER LEITCH: Okay. Thank you.
MR. KUO: You're welcome.
MR. DOZIER: Thank you.
MR. KLEEH: Good morning. My name is
Edmund Kleeh, and I'm representing the License
Renewal Branch. On my right is Mr. James Davis, and
on my left is Mr. Crockett Petney, and we also have
Chris Parchuski, all from the NRR, Division of
Engineering.
I would like to present the first four
changes or items on this slide, which indicate the
flavor of the changes between the August and current
versions of GALL for Chapter V.
The first item is that water chemistry
adequately manages transgranular stress corrosion
cracking in the containment spray and safety
injection systems of a PWR. Stress corrosion
cracking for stainless steel components exposed to
borated water can occur at temperatures below 200
degrees Fahrenheit only if containments like
sulphites, sulphates, and chlorides are present in
the water.
Stress corrosion cracking does not occur
if water chemistry controls the level of those
containments below stated levels.
You have previously addressed the change
in the SRP Section 3.2.2.2. There was a renumbering
of that section of the SRP, and the particular
section that you're talking about was deleted
because there was no further evaluation of stress
corrosion cracking in regard to the safety injection
tanks and the refueling water tanks, because the
one-time inspection was no longer required.
CHAIRMAN BONACA: Okay. I understand.
Okay. So it's the elimination of those chapters.
That's what I imagined, but I wasn't clear there.
So the elimination was due to the fact that the
concern is gone; you don't have to address it
specifically anymore.
MR. KUO: Right.
CHAIRMAN BONACA: That's why you don't
have that.
MR. KUO: Right.
MR. LEE: This is Sam Lee. That's what
we meant when we changed the GALL Report. We just
made the conforming changes in the SRP. So when you
see the SRP, some of the things have disappeared,
because they have disappeared from GALL.
CHAIRMAN BONACA: Yes. What about the
other issue of those headings where there is a full
description of the program, but then in parentheses
there is written program no longer --
MR. LEE: You'll hear that. We're going
to discuss that later.
MEMBER LEITCH: Does the water chemistry
program, in addition to prescribing steady state
limits, also discuss actions for excursions, say,
unexpected chloride intrusion or --
MR. KLEEH: What I would think would
happen here is that the water chemistry is a program
-- is an existing program. So the plant -- the
licensee would address that under Appendix -- or 10
CFR 50, Appendix B, for any corrective actions that
had to be taken. It's an existing program, so it
will be addressed in that manner.
MEMBER LEITCH: Okay.
MR. KLEEH: The next item is that
general corrosion causes loss of material for carbon
steel components in air but not for stainless steel
components exposed to water systems. Pitting and
crevice corrosion of carbon steel require an aqueous
environment, with their aggressiveness dependent on
local chemistry conditions like oxygen levels and
component configuration.
And also, general corrosion is a
thinning of a metal surface due to chemical attack
on aggressive environment, but stainless steel
components are not susceptible to it unless
containments are present. This was just a
conforming change that we made to GALL Chapter V.
The third item is that filters are
considered short-lived components. They are
typically replaced based on performance conditioning
monitoring, which indicates the end of each of their
qualified lives. They may excluded on a plant-
specific basis from aging management review under 10
CFR Part 5421.
And not to further elaborate on it, but
this was also -- there was also a deletion here in
SRP.
And the last item is management of
external surfaces of carbon steel components is
plant-specific. Only service Level I coatings are
in scope of the aging management program for
monitoring and maintenance of coatings. The
intended function of a component is not affected by
the degradation of its service Level II and III
coatings.
Are there any questions on the items
that I've covered?
MEMBER FORD: I have a question. You
made some very definitive statements on the first
two bullets as to when you are going to or not get
localized corrosion, stress corrosion, pitting,
etcetera. Unfortunately, we know from history that
you are always bitten in the future by such an
occurrence. You've changed something in material or
the environment which you did not anticipate.
How are those unanticipated changes
covered in this whole process? And, again, I'm
talking from lack of knowledge.
MR. KLEEH: I'll let James Davis answer
that question.
MR. DAVIS: That, again, goes into your
Appendix B, Corrective Action Program.
MEMBER FORD: Okay.
MR. DAVIS: So you deal with it as an --
MEMBER FORD: So the whole process is
compliant enough that you can take into account
these unanticipated things in the future.
MR. DAVIS: Yes, that's the purpose of
the Appendix B program is when you have an unusual
occurrence, then you take corrective action.
MEMBER FORD: Okay.
MR. DAVIS: You analyze the situation,
determine why it occurred, and then you correct it
with your corrective action program.
MR. GRIMES: This is Chris Grimes. I'd
like to add to that that the requirements for the
renewed license also provide that the -- this
revised licensing basis, for which there is
significant industry sensitivity to the extent of
the commitments for these aging management programs,
it provides the boundaries upon which Appendix B
operates because if the design has changed, or if
the environment has changed, or if the assumptions
associated with the effectiveness of the aging
management programs somehow are changed in the
future, then the renewed license demands that those
changes be addressed in terms of their impact on the
licensing basis.
So if we're bitten somehow in the
future, it would be our expectation that the
licensing basis would be maintained by these
departures being addressed with respect to the
effectiveness of aging management.
MR. DAVIS: Event-driven occurrences are
included from this license renewal and from GALL.
So if it's some event that occurs, you don't
consider it in GALL, like a spill or something like
that.
MEMBER FORD: Well, I wasn't talking
about things like spills or other things like that.
I was talking about major systemic problems, like we
didn't know that core cracking would occur until it
occurred.
MR. DAVIS: That's right.
MEMBER FORD: And now that -- in the
hind events, we know why it occurred, but we didn't
know at time zero.
MR. KLEEH: That concludes the
presentation on these first four items. The next
items on this slide and the one on the following
slide will be presented by Kimberley Rico.
MS. RICO: Hi. My name is Kimberley
Rico. I'm with the License Renewal Branch. The
fifth bullet on the screen is an issue raised by NEI
concerning biofouling and the buildup of deposits.
And it -- the issue of whether flow was an active
function, and we determined that biofouling affects
both flow performance and pressure boundary
integrity. But flow performance is considered an
active function covered under the current licensing
basis and should not be included within the scope of
license renewal.
However, biofouling causes loss of
material, which affects the pressure boundary, and
this passive function requires aging management. So
however -- in order not to contradict the license
renewal issue Number 98-105, which states that the
heat transfer function for heat exchangers is within
the scope of license renewal. So biofouling was
kept in for the heat exchanger tubes for buildup of
deposits.
The last bullet on the screen is we
added an alternative AMP to the Chapter XI for the
buried piping. NEI was concerned with the current
program that we had, followed the NACE standards,
and we didn't want the NACE standards which aren't
currently required to become the standard, that we
wanted to give them an alternative program.
And that was one of the purposes of GALL
was that eventually it would be multiple AMPs for
certain aging effects. And so we created a new AMP
-- M34 and buried piping tanks and inspection.
MEMBER LEITCH: On that biofouling
issue, just -- I'm still thinking about that a
little bit. You said that you did include
biofouling as an aging management program?
MS. RICO: Yes. We kept biofouling as
an aging mechanism, but we -- the effect is loss of
material.
MEMBER LEITCH: Not heat transfer.
MS. RICO: Well, in the heat exchanger
tubes we kept buildup of deposit, the restriction of
flow, as the aging effect mechanism for the -- only
the heat exchanger tubes.
MEMBER LEITCH: Okay. But does that --
did you think about plants that are now experiencing
asiatic clams in their cooling water systems?
There's growing concern about asiatic clams.
MR. DAVIS: The zebra mussels probably.
MEMBER LEITCH: The zebra mussels, yes.
MR. DAVIS: Generic Letter 89-13
addresses service water fouling, and in that one of
the ways they suggest that you control or monitor
fouling is by measuring the efficiency of your heat
exchangers. And you can tell very quickly if you're
having a problem either from fouling or from zebra
mussels.
MR. BARTON: That's covered by existing
programs, right?
MR. DAVIS: That's an existing program.
MEMBER LEITCH: Okay. So that's
excluded from the aging management, then.
MR. GRIMES: This is Chris Grimes. And
I hope you won't think I'm overly trite, but we did
have some difficulty trying to draw this fine
distinction between what are active functions and
what are passive functions. And quite candidly, the
performance monitoring -- those things that get to
flow and heat exchanger efficiency, they are much
more palatable if you think of them in terms of the
active system demands and performance and system
reliability.
And so for our purpose we focused on
aging effects. Heat transfer is not an aging
effect. Heat transfer is more related to system
performance that is challenged on a fairly frequent
basis. But we couldn't extend that logic to the --
so far as to say that crud buildup doesn't have some
impact on loss of material, which is an aging
effect. So that was -- that's the focus of GALL.
And it is a rather subtle and fine distinction, and
it's not really easy to articulate.
MEMBER LEITCH: Yes. Another concern
that I had in that area, the plant, as you think out
in terms of the forebay and dredging considerations,
and all that type of thing which, you know, that --
that is -- like silt building up in the intake is a
function that develops over a long period of time.
And I don't know whether that would be an active or
a passive type of thing. I guess that's one of
those things that's kind of on the cusp as well.
MR. GRIMES: That's correct. And we
would -- you know, if the reviewers look at the --
at this distinction, and they test it with operating
experience. And to the extent that we have delved
into the area of the impacts of zebra mussels and
other impacts on system performance, we still have
to step back and say, yes, but to what extent are
these things -- aging effects -- age related? And I
think that we've been fairly sensitive to making
that fine distinction.
And we still have to -- we still have
the system performance tests and the active features
that provide protection in the future in the event
that we find some long-term impact going on that
needs to be addressed.
MEMBER LEITCH: Yes. Thanks.
MEMBER SHACK: Just coming back to this
last bullet again, in the earlier version of GALL
you had the NACE program as an acceptable aging
management program.
MR. DAVIS: That's right.
MEMBER SHACK: What you did then was
create another new -- I mean, a plant could have
always come in with a plant-specific alternative.
You just created a new generic management program,
presumably based on some fairly typical plans, is
that --
MR. DAVIS: What we did was we basically
did what Calvert Cliffs and Hatch and ANO and Turkey
Point proposed, and that is when they go in to do
maintenance they're going to dig up the pipe and
they'll examine the coatings at this point.
Whereas, when I originally wrote it, I put the NACE
standards of cathodic protection and coating.
Nobody really does that, and they don't want to take
credit for the rectifiers, because they're not --
they weren't purchase safety-related. So that
causes a problem for them.
So we -- rather than fight about it, we
agreed with NEI that we would offer either
alternative. In the case of Oconee, they have 11-
foot diameter pipes, and they actually are going to
inspect from the inside of the pipe. And that's
about 80 percent of their buried pipe is 11-foot
diameter pipe. So that wasn't put into GALL because
we thought that was an unusual occurrence. But they
can also propose any other program that they want
when they come in.
CHAIRMAN BONACA: This is AM34. That's
the one he quoted. Okay.
MS. RICO: And the last change to GALL
was the addition of a selective leaching program.
Some materials were added that NEI had asked for
that are used in plants, and selective leaching was
identified as the aging mechanism. And we created
selective leaching, which was modeled off of Oconee.
And those were all the significant
changes that were made to V, VII, and VIII.
Now, for the NEI continued dialogue
items, the first one is concerned with bolting, and
NEI feels that the aging effect and mechanism of
crack initiation and growth due to cyclic loading
and stress corrosion cracking for carbon steel
closure bolting and high pressure or high
temperature systems is not necessary. And I'll let
Jim Davis further --
MR. DAVIS: It's the issue of the 150
yield strength. If it's up over 150 yield strength,
those bolts will crack in air. And we've raised
this with every utility so far, and they want us to
take that out of GALL. But we're not going to.
(Laughter.)
MR. BARTON: End of dialogue.
(Laughter.)
The decision has been made.
MR. GRIMES: This is Chris Grimes. I
want to emphasize that dialogue will continue.
(Laughter.)
MS. RICO: And the second item is
concerned with additional requirements above the
NFPA commitments. And I'll let Tanya Eaton from the
Plant Systems Branch just briefly go over what these
two additional requirements are.
MS. EATON: Hi. I'm Tanya Eaton.
Basically, the concern that we had was that there
was a requirement in GALL for fire protection
systems that inspections should be performed to
monitor through internal inspections. NFPA does not
have requirements that currently require licensees
or anybody that has a fire suppression system to go
in and look at the pipe and to trend changes over
time to the diameter which could affect the wall
thickness and eventually affect the pressure
differences in the system.
And so in order to meet the requirements
of GALL you have to go beyond what's currently in
the NFPA codes.
MR. BARTON: So where are you on this
one?
MS. EATON: We're still -- I don't know
if NEI -- what NEI's position is. We haven't spoken
to them in a while. So it's my understanding that
we are just going to continue dialogue.
MR. BARTON: Okay.
CHAIRMAN BONACA: That's in one of the
open issues of Hatch, still open somewhat. Well,
that's more because of the particular area of the
fire protection, not the specific issue.
MR. GRIMES: That's correct.
CHAIRMAN BONACA: Okay.
MR. GRIMES: Arkansas and Hatch were
both challenged by fire protection scoping issues.
CHAIRMAN BONACA: Yes.
MR. GRIMES: But the issue that Tanya
described is basically our expectations about
monitoring programs that would be relied on for
aging management with respect to the pressure
boundary which is -- as Tanya explained, our
expectation goes beyond what NFPA currently
requires, or NFPA code currently requires.
CHAIRMAN BONACA: Okay.
MS. RICO: Are there any further
questions?
MR. BARTON: Yes. Chapter VII -- are
you covering VII?
MS. RICO: Yes.
MR. BARTON: D.2 in VII, compressed air
systems. If you look at the scope in that section
it does not cover the pressurized air receivers,
which are usually carbon steel tanks and corrode and
get full of moisture and operators forget to bow
them down, and la-di-da, la-di-da. Where are they
covered with respect to age managing and corrosion?
MS. RICO: I'm not sure on that one.
MR. DAVIS: I think if there's moist air
in there it's covered.
MR. BARTON: It's not covered in D.2.
So where is it covered?
MR. DAVIS: Okay. I'll have to look.
I'm not sure.
MR. GRIMES: We'll find that, because
I'm sure that the -- I remember the question coming
up about the treatment of receivers, but I can't
recall specifically where they're --
MR. BARTON: Okay. I didn't see it in
the current documents in D.
MR. LEE: Yes. We will check that. One
of the things that we have is GALL is not a scoping
document. So if it is not in GALL, then the
applicant had to address it on a plant-specific
basis. It was in fact within the scope, last we
knew, for that plant.
MR. GRIMES: This is Chris Grimes.
MR. BARTON: I'm not comfortable with
that answer.
MR. GRIMES: This is Chris Grimes.
Sam's explanation is that GALL tries to treat all
systems, structures, and components in a very broad
way.
MR. BARTON: Right.
MR. GRIMES: And so my expectation is
that somewhere that's an explanation on the
treatment of receivers in an air-handling system.
MR. BARTON: Okay.
MR. GRIMES: Correct? And a compressed
air system. And so even though it might be
difficult to find, we would expect that somewhere
there's an explanation and we'll research that.
MR. BARTON: Thank you, Chris.
Chapter VIII, steam and power conversion
systems. In 8.E, you talk about a condensate system
and you refer to condensate storage tanks, and
material mentioned in that section only deals with
carbon steel condensate storage tanks. My question
is: what about plants that have aluminum condensate
storage tanks? Where are they covered?
I know you've got to care about aluminum
storage tanks because I have personal experience
that the bottoms rot out. And I don't see that
covered any place.
MR. DAVIS: I don't think we covered
that, but I could check into that, too.
MR. BARTON: Well, I think you need to
look at that.
CHAIRMAN BONACA: That's an important
point.
MR. GRIMES: I know we can find
receivers, but we may have to confess that aluminum
storage tanks would be treated on a plant-specific
basis until we've got some further experience with
them.
MR. BARTON: I know one place where
you've got some real experience with them.
MS. RICO: And then, as for the SRP,
your comment earlier about Section 3.3 on the -- in
parentheses at the beginning of I think it's 3.3.2.6
and 8, the program no longer is in use. That was --
I had tried to keep the numbering system the same.
So like when you encountered earlier
when something -- a program went missing from one
version to the next, that was kind of my way of
making it so that you knew what happened to this
program, that it just didn't disappear off the face
of the earth. But we will end up just taking those
out and just renumbering them. But that explains
why that is in there.
CHAIRMAN BONACA: Okay. Just pursuing
again the issue that John Barton brought up. You
may have, in fact, some components out there which
are not covered by the current guidance. Aluminum
storage tanks appear to be some of those.
In those cases, you will have an
expectation that there will be a plant-specific
program addressing the material, the environment,
and the aging effects.
MR. GRIMES: That's correct.
CHAIRMAN BONACA: Okay.
MR. GRIMES: We tried to treat -- GALL
attempted to catalog everything we've been able to
find so far. And I'm -- I'm sure you'll be able to
think of other examples of unique component
environment configurations that perhaps we haven't
treated, and they simply didn't come up in the
process of our cataloguing. That does not relieve
the applicant from the responsibility of capturing
them in scope and then treating the applicable aging
effects.
CHAIRMAN BONACA: I imagine that at a
later time will be included in GALL as lessons
learned?
MR. GRIMES: That's correct. As a
matter of fact, it's the -- industry has stressed
the importance of their expectation that as future
lessons are learned that there will be an
opportunity to further improve the guidance.
CHAIRMAN BONACA: Yes. I have a general
question about GALL. I can ask it anytime, so I'll
ask it now. Which is, you know, GALL provides a
real baseline and really gives a lot of comfort when
you look at it, because although things may have
been missed, but there is a significant meeting of
the industry and the NRC and the whole experiences
brought there.
And I'm still surprised at some of the
applications, including the one we are going to see
tomorrow, and the SCRs contain very little reference
to GALL. I'm sure GALL has been extensively used to
make judgments, and, you know, I was surprised that,
for example, in the SCR we are going to review
tomorrow there is very little reference to GALL.
And I just -- with respect to time,
there will be more of that because, again, a
reference to GALL is something that says -- like it
is there and is acceptable and will be helpful.
MR. GRIMES: The simplest explanation is
that we have a pact, and that pact is that so long
as GALL is still evolving, and it does not represent
an approved tool, then it will be used carefully by
both the industry and the NRC. And so the lack of
approval on the document means that we use very
carefully, and we do not reference it -- either the
applicants or the NRC -- until it has reached a
stage of maturity and approval that we can say it is
now an official agency document that can be
referenced.
The fundamental objective of this
demonstration project that the industry has
undertaken is to find ways to maximize the utility
of GALL as a reference in order to simplify the
process. The staff is similarly motivated to be
able to reference GALL as a device that represents
an official position relative to these matters.
And we're here today to seek your
endorsement, in your capacity as an advisory
committee to the Commission, to get the Commission
to put a blessing on it that makes it an official
document that can be referenced.
CHAIRMAN BONACA: And I understand and
that's great, because it lessens my concern. I
think with the time I will expect and hope that
there will be much more reference, you know, when it
is a finalized document. But, still, right now --
for example, I notice many requests for additional
information where you went back and forth, and then
finally the answer was, "Well, we did this because
that's in GALL." And the staff responded by saying,
"Ah, great. So we accept it."
I mean, so still now, already now, GALL
represents a significant baselining for discussion
and agreement. And so, okay, I understand it is not
final yet. Is this going to be -- is this supposed
to be the last draft we get before it is approved in
the final form?
MR. GRIMES: We're going to talk about
that at the conclusion of meeting.
CHAIRMAN BONACA: Okay. Because I'm
beginning to wonder now. We don't --
MR. GRIMES: We would like this to be
the last draft before we go to the Commission for
approval to proceed and use it as an official
position. But as you've pointed out, there's still
some room for further improvements, and I hope that
at the conclusion of the meeting we can convince you
that, as we've tried to convince the industry, that
the dialogue will continue and opportunities for
future improvements will be there for subsequent
revisions and additions.
We would like this to be the final
draft, so that we can take this guidance to the
Commission for approval.
CHAIRMAN BONACA: How does the industry
feel about that? Because I see a lot of issues here
which are continued dialogue items.
MR. GRIMES: I think that the -- well,
I'll let the industry speak for itself when they
come up to talk about their contribution with
Revision 3 to NEI 95-10. But I think that the
industry is as anxious as we are to take advantage
of what's been accomplished so far, which we think
is fairly substantial.
If you'll, you know, keep in perspective
that we're here explaining a resolution of what we
consider to be some of the key controversies that
came up in the comments. But we've incorporated the
results of about 1,000 comments for which we've very
carefully gone through and documented in the
companion NUREG report how we've treated each of the
comments.
CHAIRMAN BONACA: Thank you.
MS. RICO: Now S.K. Mitra will come up
and discuss Chapter VI.
MR. LEE: I guess before S.K. comes up,
Dr. Leitch before had a question on the fatigue,
environmental effects on fatigue. I have John Fair
from the NRR staff. He can answer your question if
you still have a question on that. This is, I
guess, SRP 4.3.
MEMBER LEITCH: Yes, that's where my
question was. I guess my question specifically
related to the verbiage on -- I'm referring to the
SRP now, page 4.3-2 and 4.3-3, speaking about the
resolution of the generic safety issue and the
statement that the effects of reactor coolant
environment on the fatigue life of components were
not adequately addressed in the code of record;
particularly, the concluding paragraph indicates the
potential for an increase in the frequency of pipe
leaks as plant continues to operate.
That is speaking now about the
conclusion of paragraph 4.3.1.2. Thus, the staff
concluded that licensees are to address the effects
of coolant environment on component fatigue life as
aging management programs are formulated in support
of license renewal.
MR. GRIMES: This is Chris Grimes. I'd
like to introduce John's explanation by making --
closing the circle in terms of the -- the associated
generic safety issue is GSI 190. It was the issue
that was intended to extend from GSI 168 on fatigue
environmental effects for 40 years.
And what you read was the conclusion of
GSI 190, and actually I think it's also important to
recognize that even though the industry did not
specifically identify this as a potential appeal
issue warranting further dialogue, I think it is
their expectation that this is an issue that has an
ongoing dialogue that will continue in the future
and may result in future changes to this guidance.
But with that, I'll let John explain the
details.
MR. FAIR: Yes. I'm sorry. I'm John
Fair with NRR. I missed the crux of the question
you had on this.
MEMBER LEITCH: Well, it just left me
with an unsettled feeling. I guess someplace in
here, I'm not sure I can find the sentence right
now, but it seems like -- I had the impression that
40 years was kind of at the margin. And on that
basis, I was wondering how we could proceed with 60
years.
MR. FAIR: Okay. Originally, this issue
was looked at for both 40 and 60 years, and we had
an evaluation of a sample of components at a number
of powerplants. And what we found, that in most
plants we could do an evaluation, remove
conservatism with the new environmental curves and
show they were okay for most of the locations.
But in addition to the evaluation of
these locations, we also had an auxiliary risk
assessment, and it showed that the risk was not
significant. And, therefore, we couldn't justify
the backfit to the current operating plants.
So the basis -- the real basis of why we
didn't have a problem with current operating plants
was, one, we did an evaluation of high fatigue usage
factors at most of these -- at a sample of plants,
showed most of the locations were acceptable even
considering environment for the 40 years.
There are some cases we couldn't show it
was good for 40 years, but we suspect that with more
detailed information, which the licensee has
available to them, they could probably show these
other locations were okay for 40 years.
And, in addition, we had the risk
assessment showing it was not risk-significant
enough to warrant a backfit. When we made the
conclusion for 60 years, we said there's a
likelihood that we'd have more problems at 60 years,
obviously, with 20 years additional time. It would
be more difficult to show that these locations were
acceptable.
And we did a follow-on risk assessment
in this GSI 190, and that follow-on risk assessment
showed that there was an increase in leakage
potential for these locations, even though the risk
was not high. And on that basis, we concluded we
should do something for license renewal because of
the potential for increased leakages.
So it was basically we couldn't justify
a backfit to the current operating plants based on
the risk assessment and the evaluation we had
performed. So --
MR. GRIMES: I would like -- if I could,
I need to correct a misstatement I made before, that
the precedent to GSI 190 was GSI 166, not 168. And
I'd like to add that although we cannot backfit the
design of all the fatigue analysis, we're
approaching this from the standpoint of the
environment is an aging -- is applicable to the
aging effects associated with the fatigue analysis.
Therefore, we believe that it's within
the scope of the renewed license to address how that
affect is going to be treated. And John prepared
the guidance for the Generic Aging Lessons Learned
Report that explains our expectation on how that
will be treated.
MEMBER LEITCH: Okay. I guess -- is
that found -- that most of the locations would have
a CUF of less than the ASME code limit of one for 40
years. I guess that's the troubling statement, I
guess, that I -- I'm trying to find the right
sentence here. Just bear with me a second here.
I guess at one point here it says,
"However, because the staff was less certain that
sufficient excessive conservatisms in the original
fatigue calculations could be removed to account for
an additional 20 years of operation for renewal, the
staff recommended in SECY" -- number such -- "that
samples should be evaluated considering
environmental effects for license renewal."
So I guess maybe I'm just not sure what
you have done as far as this issue is concerned. Is
additional inspection required or --
MR. FAIR: No. In license renewal for
the plants that have gone through license renewal
thus far, they have taken the locations that we
originally studied --
MEMBER LEITCH: Okay.
MR. FAIR: -- the six locations, and
they've done their own assessment considering
environmental effects. And in most cases -- again,
in most cases, not all cases, they are able to show
there's not a problem. For the cases where there's
a concern, which right now it looks like mostly a
concern on the surge line, they're going to do some
monitoring in the extended period of operation.
MEMBER LEITCH: Okay. Okay. I think
that answers my question. Thank you.
MR. KUO: If I may add, the fatigue
program that I was talking about earlier in Chapter
X is in Chapter X, M1. The program is M1.
MEMBER LEITCH: M1?
MR. KUO: Yes.
MEMBER LEITCH: Thank you.
MR. KUO: You're welcome.
MR. MITRA: I'm S.K. Mitra again,
Project Manager, License Renewal. With me today, on
my right, is Bob Lofaro from Brookhaven National
Lab; and on my left, Mr. Jit Vora from Office of
Research; and Paul Shemanski from NRR.
Today's topic is Chapter VI, Electrical,
and we are going to talk about the changes from the
August version due to the public comments.
The first bullet is consolidated boric
acid corrosion programs. The borated water leakage
surveillance for a non-acute electrical connectors
program, E.4. Used to be 11.E.4. Deleted from
Chapter XI to eliminate the redundancy with the
boric acid corrosion program in Chapter XI, Intent,
which is now reference for electrical improvement
also.
This is based on industry suggestions.
So we took that 11.E.4 out from programs and
reference to 11.M.10, which is --
MR. BARTON: Reference to 11 what?
MR. MITRA: 11.M.10.
MR. BARTON: M.10?
MR. MITRA: Yes. That's boric acid
corrosion program.
MR. BARTON: Yes.
MR. MITRA: Next bullet is we
incorporated examples of specific insulation tests
for medium voltage cables. Aging management program
in 11.E.3, for medium voltage cable exposed to
significant moisture and significant warpage, was
modified to include example of acceptable monitoring
tests to provide an indication of the condition of
conductor insulation.
Based on comment, ACRS has three
changes, and there will be a new paragraph in
11.E.3, which will give the specific test. It says
the specific type of test performed will be
determined prior to the initial test, and this will
be a proven test for detecting the duration of
insulation system due to weighting, such as power
factor, discharge, or polarization index, as
described in EPRI TR203834-B1-2. Or other testing
that is state of the art at the time of the test is
performed.
MEMBER UHRIG: This, then, is very
different than the -- this is not the same kind of
test -- accelerated testing that was done for the
low voltage cables.
MR. MITRA: No.
MEMBER UHRIG: This is just for normal
usage.
MR. MITRA: Used for medium voltage.
MEMBER UHRIG: Yes. Medium voltage is
for normal usage --
MR. MITRA: Yes.
MEMBER UHRIG: -- throughout the 60
years.
MR. MITRA: Right. But --
MR. LOFARO: That's correct.
MR. MITRA: The last bullet is we added
a sentence for first inspection/test of cables to be
completed prior to the period of extended operation.
And this requirement was added to the aging
management program 11.E.1, E.2, and E.3, to the
detection of aging effects, to make sure a 10-year
inspection or test frequency will provide at least
two data points during 20 years period, which can be
used to characterize that degradation rate. This
was also added to be consistent with the requirement
in the SRP.
CHAIRMAN BONACA: This is typically --
these are known EQ cables, right?
MR. MITRA: Yes.
MEMBER UHRIG: There are the medium
voltage cables?
MR. MITRA: Any cable.
MEMBER UHRIG: Any cable.
MR. MITRA: Yes.
MEMBER UHRIG: Any cable, low, medium,
or high.
MR. MITRA: Yes. And previously in GALL
we didn't have this requirement saying that it had
to be done at the completion of the period of
extended operation. So it could have been done in
50 years and only one inspection, and that would
have been all data points, more than one. So this
was added at 40. Any time before 40 is here, and
then there will be one more.
MEMBER UHRIG: You have not specified
any specific test. That's just the measure test for
--
MR. MITRA: Any specific tests?
MR. SHEMANSKI: Would you repeat that,
please?
MEMBER UHRIG: Well, it says just --
first inspection/test. You have not indicated the
type of test. Is this negotiated with the utility
at the time, or is this something that is -- they
propose and you approve? Or is this something that
is currently in use? What type of test are you
talking about here? is really my -- I guess the
question.
MR. SHEMANSKI: Basically, what we're
looking for is a state-of-the-art test. We don't
want to define the test right now, or at least the
utilities, so that -- they would prefer to wait
until the actual test is going to be performed and
see what is the best test available at that point in
time.
They were concerned about locking into a
particular test right now, committing to a
particular test, and if they chose not to do that
test then they would have to come in for a license
amendment type change. So what we agreed to was
that just prior to the conduct of the test the
utility would come in and discuss it with us, and
NRC would then have the opportunity to agree or
disagree with the type of test to be conducted.
MEMBER UHRIG: Also, assume that there
would be a discussion of the criteria for acceptance
or --
MR. SHEMANSKI: Yes. At that point,
that would give us an opportunity to discuss the
acceptance criteria that would be involved for that
particular test.
MEMBER LEITCH: Just back to the first
bullet, boric acid corrosion programs -- I'm looking
at M.10, boric acid corrosion, and it doesn't leap
off the page, to me at least, that it's referring to
electrical equipment. It says the program covers
any carbon steel, alloy steel structures and
components which have borated -- one which borated
reactor water may leak.
So where is -- I mean, it says
"components," and I guess you could infer from that
electrical.
MR. MITRA: Yes.
MEMBER LEITCH: And these seem to --
MR. MITRA: Specifically, it was
mentioned and, regretfully, it has not showed up in
your version. But I was told that it was
incorporated in a later version.
MR. LOFARO: Yes. This is Bob Lofaro
from Brookhaven. Subsequent to this March version
that you have reviewed, we did add some words to
program M.10 to specifically call out the inspection
of electrical components.
MEMBER LEITCH: Okay. That's good.
It's probably inferred here, but it's not real clear
right here. Thank you.
MR. MITRA: Are there any other
questions? Thank you.
Next presenter is David Solorio.
MR. SOLORIO: Hi. My name is Dave
Solorio, and to my right here is Omesh Chopra from
the Argonne National Lab. I'm going to talk to you
about three things today. First -- the first couple
will go real quickly. I'm going to talk about Reg.
Guide 1.188, and then I'm going to talk about NEI
95-10, and then I'm going to put up a slide here
that talks about one-time inspections that you all
asked for.
Reg. Guide 1.188 proposes to endorse NEI
95-10, Rev. 3, dated March 1st, without exception,
because 95-10 provides acceptable methods for
complying with the requirements of the license
renewal rule.
Two changes were made to the reg. guide
in response to public comments. First, guidance for
submitting electronic submittals was added, and a
note was added to clarify that if color drawings are
used no essential information should be lost from
printing them out in black and white, so -- for the
benefit of the public who may not have access to
color equipment.
MEMBER SHACK: Let me just ask a
question. I was sort of -- you know, I was reading
the BWRVIP POP Guide Reports, which I assume will be
sometime referenced in the license renewal document.
And there's a proprietary version and a non-
proprietary version, and by the time you get to the
non-proprietary version, which is what the public is
going to see, there's nothing there.
I mean, even the list of inspections
that are proposed is proprietary and disappears. Is
there some judgment here as to, you know, what's a
reasonable amount of information to be provided to
the public when this is done?
MR. SOLORIO: Well, the NRC -- not in
the reg. guide -- but the NRC does have a process
for providing -- what's the right word? Proprietary
information.
I guess it would have to be handled on a
case-by-case basis, and it would be up to the
project managers and the NRC managers to determine,
you know, what appropriate information needed to be
seen by the public, so that they had a fair shot of
looking at what we're looking at. We have a
process, and we would follow that process.
I really don't have any more --
MR. GRIMES: This is Chris Grimes. I
was involved extensively in the dialogue with the --
with EPRI and the BWR Owners Group to try and get
them to provide us with more than a cover page and a
table of contents in the non-proprietary version.
There are standards, and there is a test on the
proprietary -- proprietary nature, but it's not
always clear.
MEMBER SHACK: Well, the one that
disturbed me the most was the table which actually
outlined the inspections that would be done, which
would seem to me the thing that, you know, the
public might well want to know.
MR. GRIMES: And we listened long and
hard to the explanation about how the BWR Owners
Group and EPRI considered that to be marketable
material. And it is. And notwithstanding our
desire to be able to disclose those details in
public, the standard that we apply is whether or not
there is a -- you know, a financial gain to be made
in terms of its marketability. And --
MEMBER SHACK: That is the crucial test,
then, is is it marketable material?
MR. GRIMES: That's correct. And I can
recall when I -- when similar questions came up on
Westinghouse topical reports many, many years ago,
we were able to convince Westinghouse that "F equals
MA" was not a marketable quantity for them. And
sometimes it gets that ludicrous, but it -- but the
test is that -- it gives the owner of the report an
opportunity to protect their commercial materials.
That's its intent.
That's why we have provisions for
proprietary material and protection of confidential
business information. And it does make our job much
more difficult in terms of the transparency to the
public.
CHAIRMAN BONACA: Doesn't it also
involve, in fact, a decision on the part of the
staff on whether or not the right of the public
weights the marketable value of the application?
MR. GRIMES: That's correct. But you
will find, particularly I think in the BWRVIP,
safety evaluation that we -- we've worked very hard
to present safety evaluation findings that describe
enough of the contents of the material in terms of
what we relied on to come to a reasonable assurance
finding, without disclosing the details that the --
that the owners groups and EPRI want to market.
And I would also add that I'm -- I
believe that there is presently a rule change
underway for 2.790. That's 10 CFR 2.790, which
embodies the requirement for proprietary
withholding, that attempts to improve it, but it
still will demand that the Commission offer an
opportunity for that commercial business information
to be protected.
That's not unique to the NRC either.
All federal agencies are confronted with providing
for the protection of confidential business
information.
MEMBER SHACK: I mean, it just seems to
me there is some conflict with, you know -- I mean,
I don't see how the public could look at that
proprietary version of that document and learn
anything.
MR. GRIMES: Well, the non-proprietary
version.
MEMBER SHACK: The non-proprietary
version.
MR. GRIMES: But there is -- there are
processes by which interested members of the public
can view proprietary material by -- through legal
means, and that is to make, you know, some kind of
contractual arrangement, so that they will not
disclose that marketable material.
So if there is an interested public
organization -- and as a matter of fact, I believe
that Commissioner McGaffigan referred to it when the
issue came up during the regulatory information
conference when Ed Limon, you know, referred to his
concerns about the availability of research
information related to aging effects.
And there are ways that public interest
groups can view the details, so long as they agree
to the -- maintaining the confidence of the material
that's being marketed. Okay?
MR. SOLORIO: My next transparency talks
about NEI 95-10. As you're aware, Revision 2 was
published back in August. You probably -- most of
you probably saw it then. The staff reviewed
Revision 2 and identified a number of items that
needed to be changed to ensure consistency with the
standard review plan and GALL.
The staff met with NEI in February to
discuss these items, and NEI revised 95-10 and
submitted Rev. 3 in March of this year. On this
slide I've categorized -- or on this transparency
I've categorized the nature of the changes into
three areas.
First, there are what I would call
consistency changes. For example, the staff
requests that the table of contents in 95-10 agree
with the statement of contents in the SRP to ensure
a consistent format for future license renewal
applications. Another example was that the staff
requested NEI 95-10 include a discussion on top 10
program elements for an aging management program,
similar as provided in the standard review plan.
There was some additional guidance for
the timing with which an applicant should address
USIs and GSIs, in accordance with NUREG-0933. And,
finally, a conforming change to address changes to
the regulation involving the accident source term,
50.67.
I also want to mention that in March --
in their March 1st letter transmitting Rev. 3, NEI
indicated to support the schedule to provide this
document, along with the other documents the staff
has provided to the ACRS by March 1st. They
provided 95-10 without the benefit of industry
review. Therefore, there was a possibility there
could be changes.
In addition, there were a few items such
as the severe accident mitigation guidelines that
didn't get added to Revision 3 due to timing, but
NEI intends to add that. NEI has informed me that
they will be resubmitting Revision 3 very shortly,
and when NEI does that the staff will review it to
ensure our endorsement remains unchanged.
My next transparency here is in response
to what I understand was a request by the
subcommittee to see the one-time inspections for
Calvert, Oconee, and GALL.
CHAIRMAN BONACA: Let me just explain to
-- for the -- I made the request because we have
seen the one-time inspections, and we saw a large
number for Oconee, for example -- for Calvert
Cliffs, actually. And they've gone down in number
substantially to the point where Arkansas had very
few.
Now, that doesn't mean the issues have
been all gone away, but there is other ways in which
they have been accommodated. So, second, if I look
at the Arkansas application and Hatch, the one-time
inspection really represents the bulk of the new
programs being presented -- I mean, in large part.
And it's --
MR. SOLORIO: I'm not real familiar with
Arkansas and Hatch, but --
CHAIRMAN BONACA: Well, that's at least
what I see from them. And so they are important
because earlier they represent that. So it would be
good for us to understand, you know, where these
one-time inspections are, why they have been
decreasing with time, if you have any insight on
that that would be very useful.
MR. SOLORIO: Well, just to tackle that
right away, GALL frequently now requires a plant-
specific aging management program be required. So
that could mean a licensee might have a one-time
inspection or a licensee might have an existing
program. As long as there is something, that's what
GALL is asking -- asking for.
So that could explain a big difference
perhaps why you see a lot less for these other more
recent applicants. Again, I'm not real sure about
their particulars, but --
CHAIRMAN BONACA: Yes. One of the
reasons may be that Oconee was presented -- one of
the earlier applications, I don't remember which one
-- no, actually, Calvert Cliffs -- was much more
focused on component by component, system by system,
so there were a lot of programs there, many more
numerically, while for Oconee they were grouped
into, you know, generic programs. So there are less
in those.
But I think it would be good for us as
we go forth in our review to understand the
situation with the one-time inspections.
MR. SOLORIO: Okay. In this first
column here, what I've tried to do is represent how
these systems would be grouped in GALL. So that's
why you see the groupings. That's what they are
there. And then, to the right, I go across trying
to label the individual systems.
I also want to caution anyone near
license renewal that we're not saying that all of
these systems are only inspected one time for aging.
In fact, the majority of the cases there's an
existing aging management program also looking at
these systems. It's just a particular aspect that
they chose to do a one-time inspection for.
I also want to add that GALL has
consistently applied the lessons learned of Calvert
and Oconee regarding one-time inspections. In fact,
for these two plants, one-time inspections were
incorporated into GALL, when appropriate, as a
starting point back in '99.
In developing GALL we also had the
experience of the national laboratories in helping
us capture these one-time inspections and gained
from their experience. And staff associated with
the first license renewal reviews were involved in
reviewing these one-time inspections that were
incorporated into GALL.
GALL also had the benefit of two public
-- two rounds of public comments, and the frequent
outcome of public's participation in the GALL now
specifies a plant-specific aging management program
be proposed where Calvert or Oconee might have done
a one-time inspection, to provide flexibility in
case a licensee is already doing something as an
existing program. That's really all we need.
A plant-specific aging management
program could be a one-time inspection or an ongoing
program. At a glance, there appear to be
differences in the number of one-time inspections
here on this viewgraph between GALL, Calvert, and
Oconee. But there are a number of reasons to
explain these differences.
First, there are plant-specific reasons,
like Oconee has several features which were a little
too unique to be included in GALL, and obviously
were not applicable to Calvert, like the dam
emergency power source and the safe shutdown
facility structure, kind of some of the stuff I put
down here.
MR. GRIMES: If I could, I'd like to
clarify that dam emergency power supports as a
hydroelectric dam.
(Laughter.)
It's spelled a little differently.
(Laughter.)
MR. SOLORIO: I apologize. Maybe the
Oconee project manager would want to make that
point.
Second, in many cases Calvert proposed
one-time inspections without being asked by the
staff. I mean, it was just part of their
application when it walked in the door.
Third, different names are used for some
of the systems performing the same functions, like I
know you'll never guess this, but LPSW and HPSW at
Oconee mean fire protection.
Now I'd like to go over a few examples
on this viewgraph to explain a little more detail
what I have here. Starting at the top with the
reactor coolant system-SBP -- that's small-bore
piping -- all three require a one-time inspection.
Moving on to reactor vessel internals -- can you all
hear me okay? I'm not sure if I'm -- this mike is
doing funny things.
For reactor vessel internals, because of
component design, the staff required a one-time
inspection for certain components at Calvert but did
not for Oconee because of differences in component
design. GALL requires a plant-specific evaluation
of certain reactor vessel internals.
For steam generators, Calvert proposed a
comprehensive program that included inspections of
steam generator tube supports. Oconee, having a
different steam generator design, having an existing
steam generator program also, but proposed one-time
inspections for some of its supports due to gamma
radiation concerns. GALL requires a plant-specific
evaluation.
Moving on to the pressurizer, Calvert is
conducting a one-time inspection of susceptible
cladding locations, and so is Oconee. GALL requires
a plant-specific evaluation.
Those are all of the examples I have to
go over, but, of course, you can ask more questions.
But I want to conclude by saying GALL has
consistently applied the lessons learned at Calvert
and Oconee to adequately cover the subject of one-
time inspections. While there appear to be some
differences between Calvert, Oconee, and GALL, the
differences were due to a plant-specific nature.
MR. GRIMES: I would like to add to that
the most recent experience that we had with Arkansas
I think emphasized the plant uniquenesses and the
variability, because even on the first item where we
were consistent between Calvert, Oconee, and GALL,
on small-bore piping, for Arkansas it was inherent
in their risk-informed in-service inspection
program. And so it does not appear as a one-time
inspection or even a separate issue. It was
embodied in our conclusions relative to aging
effects for the affected piping.
So as we went back and reflected on
this, I derived considerable comfort from the
relative consistency we see across this, because it
seems to be easily explained in terms of the plant-
specific differences and also the different
approaches that the individual utilities took to
address specific aspects of applicable aging
effects.
MR. SOLORIO: And just for anyone who
might not have noticed, on the next page I have a
legend there so you can make sense of all of that,
because there's a lot.
CHAIRMAN BONACA: Yes. I wasn't able to
read it all, but that's okay. One of the reasons
why I asked that question was because we discussed,
you know, for other applications and for Arkansas.
I have some questions regarding the project, and the
projects that -- you know, I am not familiar about
the other plants. I think that will be valuable
information to convey to reviewers, because the --
you learn a lot about other applications.
And then, for example, your logic for
excluding this mobile piping from Arkansas as a one-
time inspection escaped me. For the first time now
I understood that. So that is important information
that I think is good to keep in mind as we go forth
in reviews.
MR. SOLORIO: But the explanation that
Chris gave you for Arkansas I'm sure would be
included in their SER. It's just probably hidden.
One of the things I found in going through Oconee's
was it was very hard to find an Oconee system like
the Calvert system, or an Oconee system like a GALL
system, because Oconee had -- you know, they don't
call their CVCS CVCS. They call it something else.
So that does make it difficult.
MR. GRIMES: We're challenged to try and
come up with generic ways to explain license renewal
in a plant-specific environment. There again,
that's something that's not unique to license
renewal. I think every safety evaluation is
challenged to try and describe a safety evaluation
basis for an individual plant in plain language.
We're still learning how to do that.
CHAIRMAN BONACA: I just have a question
regarding this table, the last one that you took
out. You put it away so quickly. There's nothing
wrong with it, right?
MR. SOLORIO: Oh, no, no.
CHAIRMAN BONACA: I just wanted to ask
you a question.
MR. BARTON: What's a depressing air
system? Is that one that needs psychiatric help or
what?
(Laughter.)
MR. SOLORIO: It has to do with their --
I'm not sure what the right term -- their emergency
power source, which is the dam. And I don't know
any more particulars, but it's for that system, for
the --
MR. BARTON: It's called a depressing
air system?
MR. SOLORIO: Depressing air.
MR. BARTON: Okay.
CHAIRMAN BONACA: It's depressing for
the people who read it. But anyway --
(Laughter.)
What about the -- why some of them are
in bold letters and some are --
MR. SOLORIO: So you've got differences
between A, B -- you know, when a new -- when I start
a new letter, I do bold so I can quickly look
through it and figure out where A or B was or --
CHAIRMAN BONACA: Okay. Thank you. Any
other questions for Mr. Solorio?
MR. SOLORIO: Thanks.
CHAIRMAN BONACA: Thank you.
MR. GRIMES: And I am compelled to point
out that license renewal is right on time again. We
are right on schedule.
CHAIRMAN BONACA: This is remarkable.
MR. GRIMES: That completes the staff's
presentation. But before I conclude, the next
agenda item is for NEI to describe the work that
they've done to revise NEI 95-10.
MR. WALTERS: Good morning. My name is
Doug Walters with Nuclear Energy Institute. I do
have copies of my presentation. I'm not sure I have
enough for people in the audience, but I wanted to
chat with you today about the changes we're making
to NEI 95-10, Rev. 3. Of course, it is the guidance
for implementing the license renewal rule.
A couple of key elements to the
guidance. First is I put up here including a
reference to the GALL Report. Let me just spend a
minute on that. We haven't completed all that work.
As has been mentioned in previous presentations, we
have a demonstration program that's underway. We
have the Class -- we call it the Class of 2002, the
applicants we expect to submit in 2002, working on a
project that encompasses how they think they would
use GALL in preparing their application.
Our schedule for that is to get some
information to the staff by the end of April, and
then have some dialogue with them, ultimately moving
towards some agreements I think by -- in the June
timeframe. And then at some point thereafter we
would go back and update our guidance as we think we
need to to reflect what comes out of that
demonstration program.
So there are a number of changes
actually that were identified that we need to make
to NEI 95-10 that we deferred to this demonstration
program.
The other key element of our guidance,
though, is the standard application format and
content, and that's in Chapter VI. It follows the
format and content, or certainly the format in terms
of table of contents of the standard review plan,
and that's kind of where we see all this heading is
that an application would probably reflect what you
see in those tables in the standard review plan.
And so we've got the standard application and format
in our guidance.
A third key element, I believe, is what
we call Appendix -- it's Appendix B to our document,
but it's a table of components and commodity groups
that are subject to an aging management review, and
that's a good tool certainly for doing the screening
once you've done scoping.
MR. BARTON: Can I ask you a question on
Appendix B?
MR. WALTERS: Yes.
MR. BARTON: Going down the list of
categories --
MR. WALTERS: Yes.
MR. BARTON: -- under "Structures," you
have an intake canal. How do I inspect the Delaware
River?
MR. WALTERS: How do I what?
MR. BARTON: What do I do with the
Delaware River?
MR. WALTERS: I don't know.
MR. BARTON: That's my intake canal.
What's included in the scope of this? You know,
Cooper is on the Missouri River. What's the
component that I do something with here?
MR. WALTERS: It's a structure, and it's
-- I mean, in my way of thinking, it's the intake
structure that sits at the river or whatever it is,
where you --
MR. BARTON: So you're talking about the
intake structure.
MR. WALTERS: Yes.
MR. BARTON: How about the -- what's
included in the intake structure?
MR. GRIMES: Let me attempt to explain.
Our expectation is each plant knows what it relies
on in the way of the structural elements, in order
to achieve the intended function, and so the
guidance that we've given to the staff is to focus
on intended function.
If they've got a pipe that extends out
into the middle of the river that's important to be
able to draw water from a particular place at the
point of the intake, then that would be revealed in
the definition of the structure that's relied on to
achieve the function.
I appreciate the question because --
MR. BARTON: I mean, it's so generic,
Chris, that you -- you know, intake canal, you know,
does it include a tunnel? Does it include the
discharge portion of the structure?
MR. GRIMES: It may. The answer is it
may.
MR. BARTON: It may.
MR. GRIMES: And what we -- and what we
struggle with is if we're too specific and too
precise in trying to define the boundaries, then
what we do is we abrogate the responsibility for the
individual plant to go through and identify where --
what the boundaries are.
At South Texas, they've got a very
elaborate canal system. I would expect them to go
out and, you know, go all the way to the end of the
structure that's associated with being able to draw
on the heat sink. But there we felt that we did not
-- we didn't want to be so specific as to relieve
the individual applicants from exercising their
responsibility to find the extent of the structure.
And that's the -- the constant struggle
that we had was give them enough guidance to know
what the right thing to do is, but don't give them
so much that you -- you know, you've gotten too
focused and missed the point.
MR. BARTON: Okay. I understand what --
MR. WALTERS: Good explanation. And I
would add to that that I think you need to look at
the guidance in total. We do have language in
Section 4 that talks about establishing the
boundaries, and the expectation is that even though
you identify it as intake structure you've got to go
back and do that evaluation boundary review and
identify what you mean by the intake structure.
MR. BARTON: Okay.
MR. WALTERS: Revision 3, I'll be brief
on this. This is Revision 3 as we submitted it in
-- I guess we submitted it in February. Again, we
included this reference to GALL. We did add the PRA
summary report and the EOPs to the table of
potential information sources, but I will tell you
we don't agree with that. We think those are beyond
design basis, shouldn't be on the table, but the
fact that the staff was going to include them in
their guidance, it just made sense I guess for us to
go ahead and include it.
We modified the table that Mr. Barton
was just referring to. We've added -- I think in
the electrical area, we've made some minor
adjustments, and we have incorporated selected
references. What that means is that you may be
aware that over the last probably two or three years
we've been working with the staff on a number of
issues; fuses comes to mind.
And what we did is we actually created
an Appendix C to the document, and we've included
the letters from the staff back to the industry, so
that the user of the document doesn't, you know, get
confused if you will about, well, what was the staff
position on that particular issue? And we've only
included a couple of those, the ones that we thought
were most significant, like fuses and consumables.
CHAIRMAN BONACA: Let me just make a
comment about bullet number two. In part, we
contributed to that, and we didn't intend to create
any change to the rule.
MR. WALTERS: I understand.
CHAIRMAN BONACA: If that was the case,
we recommended that. But I thought it was more in
terms of -- well, I'll give you an example. We
questioned for Arkansas the fact that the reactor
vessel level measurement system is not in the scope.
Now, they presented some reasons which
had to do with the fact that it is not used in any
accident analysis, and so, therefore, it wasn't part
of that. And also, this is under the Appendix B
program. We accepted that answer.
But you may have an EOP that depends
very importantly for some reason on that piece of
instrumentation. And I think that it's only prudent
for the applicant to look at it and see if it sees
that, you know, clearly that -- the reactor vessel
level measurement system cannot have any other
function than a safety function. It is not defined
as such maybe in 50.54.
But the applicant may consider it
important enough because it relies so uniquely on
that for some reason, okay, that the UP points out
as an element that they would like to keep in. It
doesn't change the rule, but I think --
MR. WALTERS: I understand.
CHAIRMAN BONACA: -- it's only prudent.
That was the only intent. And, in fact, I think the
-- even the table right now in the SRP is non-
prescriptive. It says simply document that should
be reviewed for --
MR. WALTERS: Correct.
CHAIRMAN BONACA: So --
MR. WALTERS: I agree. Mr. Solorio
alluded to the fact that we may have additional
changes, and I've identified at least the ones we --
we would intend to submit as -- as enhancements, if
you will, to Revision 3.
He talked about the drawings. This is
an issue of licensees typically send in colored --
marked up drawings in color. They need to be -- the
color scheme needs to be such that if a member of
the public wants to print it in black and white you
don't lose the meaning on the drawings. So we've
got guidance to address that issue.
We're looking at guidance to reflect
when an aging effect really requires management, but
I think, frankly, with what we're doing in the area
of GALL this may go away. This was something that
the industry felt they wanted to do, we needed to
do, to be clear on when an aging effect requires
management.
You've heard the words either it's
plausible, significant, whatever. We wanted to try
to put together some guidance to further define what
those terms mean.
We included the SAMGs as potential
information sources, and I would add that for the
SAMGs or for that table in general, the 3.1-1 table
that's got the potential information sources, we did
put some text up front in Section 3 that reflects
how we think that table ought to be used. And it
kind of gets to your point, Chairman.
And, again, we've added some additional
selected references. In this particular case, it's
only one and it was the letter that we got from the
staff on the use of FERC maintenance and inspection
programs on dams, as an aging management program for
dams.
In conclusion, on 95-10, we think
certainly there would be changes needed in the
future to reflect the lessons learned from this --
the GALL demonstration, and certainly our goal is to
continue to have the NRC endorse it without
exception.
And that's all I really had on 95-10. I
don't know if there's -- if you have any questions.
MR. BARTON: Yes. On your table 6.2-1,
other plant-specific TLAAs --
MR. WALTERS: Yes.
MR. BARTON: -- you've got Appendix B
and Appendix C as optional. Why optional? Is there
a reason for why that's not --
MR. WALTERS: Appendix B I think is the
programs appendix.
MR. BARTON: Right.
MR. WALTERS: And we're probably going
to change that to not be optional. We're probably
-- based on the -- that's one that is in the
category of deferred until GALL demonstration is
completed, because we need a repository for where we
describe programs.
MR. BARTON: Right.
MR. WALTERS: But if it's credited in
GALL, where does that show up? Should it be in the
appendix, or is it up front where you talk about the
component and the aging and you just say, "I have a
program, boric acid corrosion, for example, and it
meets the description of the program in GALL." So
that's one that's deferred.
MR. BARTON: Okay. The other one is
commodity groups.
MR. WALTERS: That's Appendix C.
MR. BARTON: Appendix C, yes.
MR. WALTERS: Right. Same issue. We
need to see how we use commodities in the -- when we
do the GALL work.
MR. BARTON: So it may or may not be
optional.
MR. WALTERS: It may or may not be
optional. It may come out all together.
MR. BARTON: Okay.
MR. GRIMES: Doug, if I could -- this is
Chris Grimes. If I could ask, I think it might be
helpful for the subcommittee if you were to describe
what you consider to be the success expectation of
the demonstration project.
MR. WALTERS: Okay. Well, what we
expect is a couple of things, and let me say that
there's one thing we don't expect. I think the work
that a licensee is required to do per the rule to
prepare and submit an application is not going to
change significantly. It's still appropriate for
the licensee to go back and look at components,
materials, environments, do the aging management
reviews.
The benefit, though, of GALL is when we
get into the programs, and we look at existing
programs that manage aging. And what we envision
GALL to provide is the one-time evaluation by the
staff of that program, and then we can say, you
know, does it need to be looked at again?
And so it's a packaging issue, I think,
in part for us. Once we do all this work on site,
how can we now package it so that we're not
describing the boric acid corrosion program every
time we use it.
And I think for us success will be that
we see an application that's kind of formatted like
the SRP tables, and that if it's a program that's
evaluated in GALL and no further evaluation is
necessary, that's all we need to say. We don't go
into any detail on the program.
Success will be understanding what level
of detail we need to go into if it's a new program.
Success will be understanding the level of detail we
need to go into if it's a program that's evaluated
in GALL. But maybe the way I implement it at my
plant doesn't quite match the evaluation in GALL,
and how do I write that up.
I think the biggest test or the success
for us will be how quickly whatever we come up with
gets through the review process by the staff and how
many RAIs do we get. And so -- and as you may be
aware, we're working with the staff in the RAI area.
We've done some cataloging of the RAIs that were
issued for ANO and Hatch, and we are going to
continue to do that with subsequent reviews to see,
you know, how are we doing, what are they
accomplishing. Well, we have different categories,
etcetera, etcetera, but I won't get into that.
But I think the -- you know, what we're
looking for is preparing an application that gets
through a review in a reasonable time with minimal
RAIs. And I want to emphasize when I say that that
that doesn't mean we're looking to reduce what we
need to do as an industry, or as an individual
licensee, to prepare the application. It's just
that we now have these lessons learned, and we ought
to be able to package the application in a way that
gets through the process in a fairly timely manner.
CHAIRMAN BONACA: On the other hand, I
agree with everything you said, but my -- I feel
almost an urge to have the finalization of this
document so we can begin to see some more standard
formats coming in. And, essentially, that minimizes
demonstration phase because if you commit to a GALL
program, I mean, then you have no further need of
explaining it.
But, for example, the issue of only
listing in an application the results of the
scoping/screening, rather than scoping as we saw for
the first applications and then the screening and
the outcome, that, to me, is one that generates RAIs
rather than eliminate RAIs, because there is no way
that the license -- the reviewer can effectively do
his job without understanding where you started
from.
So isn't it counterproductive not to
have the initial list of the scoping as the first
applicants did, and then the screening process by
which you -- you don't even have to have an outcome.
I mean, that goes into the FSAR addendum anyway.
MR. WALTERS: Well, our position on that
is -- and I think it was stated -- the rule requires
the licensee to provide the methodology. The
discussion we've had -- the ongoing discussion with
the staff is review the methodology, be comfortable
with the methodology, and then the resulting list
should not be too much of an issue.
There's no question that the applicant
will have the list, but what we -- you know, we'd
like to do is have the staff focus on the
methodology. And once they're comfortable with that
-- in fact, that's what they did on Calvert Cliffs.
I mean, they looked at the methodology. They even
wrote an SER. And so the resulting list you would I
think conclude is probably the right list.
But we'll continue to work with the
staff on that. I recognize that scoping is a bit of
an issue, and I think -- I probably should know
this. I believe what we've got in our guidance now
is a suggestion that you, in fact, provide the list.
CHAIRMAN BONACA: I think -- you know, I
think if the licensees can get over it, I mean, I
think in the long run -- because, I mean, there are
so many ways to skin the cat at the beginning when
you do the scopings. The methodology is generally
going to be acceptable.
If you look at the application we're
going to see tomorrow, it's acceptable, but it
doesn't provide the level of detail we saw for
Arkansas, for example, where before Arkansas they
had a quality program that was already founded on
the questions of 50.54.
So in there you had an easy match, and
you could progress through. For Hatch you couldn't
do that. So it leaves, still, the reviewer in a
quandary, and it forces the licensee to answer a lot
of questions. And most of all it leaves a third
party, like the ACRS, with a question that says,
since there are so many questions, so many
exceptions when the answer comes, you know, are we
really confident about adequate assurance that the
scoping is correct?
I mean, I'm sure that the work is okay,
but you are left with a --
MR. WALTERS: I understand.
CHAIRMAN BONACA: -- sample it by
yourself as a -- and I view myself as a member of
the public in that sense.
MR. WALTERS: I understand. And, like I
said, I think we'll -- you know, we'll continue to
work with the staff, but the fact is that the rule
doesn't require it, and we ought to be focusing -- I
mean, it seems to me that -- and I'm not convinced
that the number of RAIs would be reduced. If you
get the whole list, it's still the negative review
or proving the negative that is the test.
So you provide the whole list. Now, why
did you include these five systems that -- so I'm
not convinced that -- and, frankly, I don't -- I'm
not sure that we ought to be saying a good test here
is the number of RAIs. But the rule doesn't require
it. We're trying to get the staff to focus on the
methodology, and we think that the list that flows
from the methodology should provide reasonable
assurance that everything was caught.
MEMBER LEITCH: Doug, could you say
another word or two about the demonstration project
that is scheduled? Who are the participants? What
are you trying to do there?
MR. WALTERS: Yes. The schedule is --
well, let me start with the participants are --
really, it's the Class of '02. And I don't have
that list in front of me. I'm sorry.
MEMBER LEITCH: But it's those that are
in the --
MR. WALTERS: They are participating now
-- some are participating in more -- in more of the
activities than others. But our goal is to make
sure that that -- that the Class of '02 is satisfied
with where we're headed, because the -- I think the
agreement we have with the staff is that's really
the -- where GALL will be applied is on those
applications.
What we've done is we've taken a -- we
made up a list of systems, structures, and
components, and then programs, and we're going to
work the combination of those in a number of
different ways. One, we'll look at programs that
are already evaluated in GALL where -- and let me
caveat this by saying all this work is -- is real in
the sense that, you know, the participants are using
their programs. This is what they intend to put in
their application. I mean, this is application work
in progress.
So we'll look at a program that's
evaluated in GALL where the applicant thinks, yes, I
match the evaluation that's in GALL, and we'll write
an application section. There will be other
programs where the applicant feels that the program
evaluation -- their program is the same program
that's evaluated in GALL, but maybe there's kind of
a mismatch in terms of how they implemented their
program and the evaluation in GALL.
For example, GALL might say you have a
monitoring and trending provision in that program,
and this particular applicant does not have that.
We're going to show how we would write that up. We
feel like we would need to address that particular
attribute for that particular plant.
Then, the third thing would be a new
program or an inspection, not in GALL. We think we
need to do it. We'd show how we would write that
up. So, in essence, what we plan to give to the
staff by the end of April are application sections
that show these three -- these three scenarios, if
you will.
What we need to work out with the staff
is there are a lot of other things we're going to
have available. For example, how do you treat an
aging effect that's identified in Gall that you
don't think you have or doesn't apply to your plant?
How do you treat an aging effect that's not in GALL
that you think is in your plant?
And we talked about that. I mean, we
have an obligation to -- you know, to put those in
the application. So we're going to try to test all
of those different possible scenarios, give that to
the staff, and then I'm not sure that we've -- we've
come to agreement on whether they would actually sit
down and write RAIs, which would be helpful, or
whether we'll have some dialogue up front and then
repackage the demo work, send it back in and then
get RAIs.
But at the end of the day what we expect
to walk away with is an understanding of what an
application looks like using GALL and the -- and I
would say actually using the SRP, because the SRP is
the document that the staff will use. And we've had
this discussion with the staff, that GALL is not a
scoping document, etcetera, etcetera.
So we will use GALL, but it's really,
you know, the SRP and GALL that we're looking at.
And at the end of the day, what we hope to end up
with is an understanding of how an application looks
using, you know, GALL and the SRP. And then, you
know, the applicants go off and finish their work
and submit the applications that, you know, reflect
whatever we come up with in talking to the staff.
So --
MR. GRIMES: This is Chris Grimes. If I
could add to that and clarify, first of all, with
respect to -- Doug commented that the Class of '02
is the first group for which GALL is going to apply.
We intend to use GALL for the Class of '01, but the
Class of '01 -- the plants that are coming in in
June and July, their applications are essentially
complete. They're going through peer reviews.
They're prepping -- they're packaging the shipments
to send them in.
That does not mean that there is less
urgency in terms of keeping to the aggressive
schedule to complete GALL, SRP, and reg. guide for
the Class of '01. The Class of '02 is in the
process right now of figuring out how to package the
application. So they are the first customers of the
maximum benefits of this guidance.
My expectation is that at the conclusion
of whatever we agree is an appropriate demonstration
effort, that we will not only be able to identify
ways to improve the guidance on the contents of the
application, but we would also be able to provide
guidance in the standard review plan and in the
inspection guidance that explains how to treat these
commitments in an application relative to
conformance with the GALL Report.
So I would expect to be able to expand
on the guidance to the staff in terms of what is --
what does it mean when they say, "We meet the GALL
Report"? How far does that go? How is that
supposed to be tested in a safety evaluation?
And then, also, we need to provide
collateral explanations to the inspectors in terms
of how to inspect the validity of the contents of
the application in terms of how GALL is referenced.
So I would expect it to complete -- a complete
success for the demonstration project will be
revisions that we would bring to the committee and
say, "This is what we're going to do to enhance the
guidance to make sure that we will all get the
maximum benefit out of this catalogue."
MEMBER LEITCH: But isn't what you're
developing essentially a more finely divided pseudo
GALL Report? In other words, what I'm saying is
suppose that half the plants in the Class of '02
have some deviation from the GALL Report. Then, I
guess wouldn't you really like to see a GALL section
that applies to that half of the plants, and say,
"This is an acceptable approach"?
MR. WALTERS: Sure. We would. I don't
know -- I think we would, and I think that's
certainly something that may come out of the demo.
But certainly we would be looking for, I guess as
the Class of '01 and '02 go through the process --
MEMBER LEITCH: I mean, if there's just
one plant that's an outlier, that --
MR. WALTERS: That's different. Right.
MEMBER LEITCH: -- do it on a plant-
specific basis. But perhaps you identify --
MR. WALTERS: That's right.
MEMBER LEITCH: -- the plants --
MR. WALTERS: And I think we've
understood that from day one on this, that I think
the staff acknowledged that. And as we go through
the process, we might find that we missed something,
or, hey, everybody is taking credit for this
program. We don't have that in GALL. Maybe we need
to put that in GALL.
So we will be looking for those. Yes,
that's a very good point.
MR. LEE: This is Sam Lee. I guess one
of the presentations you heard earlier today was on
the buried piping program. That's a good example
where we have one program in GALL, but it turns out
the -- I guess the first couple applicants, they
actually developed something quite different. Okay?
But it's quite generic, so we say, "Okay. That
looks like a generic program. That's acceptable to
staff." We actually added that in GALL.
And so I -- I foresee this process will
continue. As we learn more, we will put more
programs together.
MEMBER LEITCH: That's good. Thank you.
CHAIRMAN BONACA: I'd like maybe a
judgment. Are we ready to finalize GALL and the
SRP? I understand there is still some negotiation
going on, but that will go on forever it seems to
me.
(Laughter.)
MR. WALTERS: Yes. I believe we are
ready. We're focusing a lot on open issues, which,
you know, we identified five and there may be some
others. But the flip side of that is there's an
awful lot that's been agreed upon. We're anxious to
get -- you know, get moving on using GALL. We're
going to have issues that come up -- the small-bore
pipe issue, for example. We need to continue to
work on that.
But, yes, we're ready to go. We think
it's the right thing to do at this point. And let
me just say that I think while we do have
differences -- and we both -- you know, the industry
feels pretty strongly about some of these open
issues, very strongly, probably more from a process
standpoint or a regulatory standpoint than a
technical standpoint.
However, I think that the process we
used -- you know, the staff developing GALL, the
opportunity for the industry to get together, the
frequent meetings we've had, has been a big success
in our view. It's worked very well. You know,
we've had good meetings with the staff. We've
gotten a lot of good insights from them, from the
labs that they used.
And so I think, you know, based on all
of that, we're ready to move. I think we're very
comfortable with where we are.
CHAIRMAN BONACA: Is it your -- you said
that you will comment on that, too.
MR. GRIMES: That's correct. If this is
the appropriate time, I would say that I agree
entirely with what Mr. Walters has characterized as
where we are in the process. We afforded -- we know
that the industry feels very strongly about the
specific issues that are identified for future
dialogue.
We feel very strongly, too, and we
afforded the industry an opportunity to say let's
stop the process right here and take these issues
through appeal. And the industry agreed that this
was something for which -- this isn't make it or
break it; we'll keep talking.
And so we -- and I also want to echo
what Doug explained as there has been a substantial
amount of agreement in terms of the resolution of
comments, clarification of treatment of aging
effects for which we expect to see substantial
benefits in the future reviews, and we all want to
start seeing those benefits as soon as we possibly
can.
The sooner that the Commission approves
the improved renewal guidance -- and at this point I
also want to mention -- but we recognize that there
are other places where we could probably improve the
guidance even further. I do not want you to leave
the impression that we're bringing to you a product
that's good enough not to be noticed as bad.
This is a product that we believe might
not be world class yet, but it certainly represents
an excellent level of effort for which we can remove
some more repetition, we can clarify where some of
the unplugged pieces might have gone.
We covered a lot of ground with this
material, and we think it's ripe for the ACRS to
endorse this product for Commission approval with
the same recognition that the industry has that
there is still some future fine-tuning that will
improve its utility and its readability and its
transparency to the public.
And we'll continue to work on those
lofty expectations, with an expectation that we'll
be able to get there in a few years, as additional
lessons are learned, and as additional feedback is
provided to add to some of the detail. But we
believe that the product that we have right now is
good to go, and we request your endorsement.
CHAIRMAN BONACA: And I would expect
that, you know, the implementation of these
documents in a final form, when they're used in the
field it will also help resolve some of the open
issues, because, I mean, we will be testing. And
without it, it's going to be open forever, because
the issues are not going to be completely closed.
MR. WALTERS: One of the lessons we
learned, you know, early on when we changed the
rule, we had a lot of good discussions with the
staff, and they were philosophical in nature,
"Here's how the rule should work." But the reality
is it's not until you get a Calvert Cliffs to
actually put pen to paper, and you submit it and
people can exercise the process that you really, you
know, identify where you need to perhaps make
changes. And that's where I think we are with these
guidance documents.
We've done a lot of talking. We've had
a lot of good interactions. We now need to get on
with the business of actually implementing it and
applying them. Let's see how it goes, and then, you
know, make changes as we think we need to.
CHAIRMAN BONACA: Good.
MR. GRIMES: Dr. Bonaca, I also want to
point out that we've received a lot of good feedback
during the meeting today as well. And there are
some questions for which we owe you answers, and
there are some commitments that I'm prepared to make
in terms of things that we're going to put on the
list for continued dialogue with the industry about
future improvements to this guidance.
But we've got a fairly substantial
package here that I'm ready to take to the
publisher, and we have had an extensive consistency
review with both of the labs participating, in order
to make sure that we've gotten as much of the
editorial improvement included without doing any
damage. That is, we didn't allow the latitude for
folks to go in and try and do any fine-tuning during
that consistency review.
But we will continue to respond to
particular questions and to gather material for the
next round when we go for the first revision in this
guidance -- in these guidance documents.
MR. BARTON: Okay. Chris, what's your
date to go to Commission with this?
MR. GRIMES: It's scheduled to be
delivered to the EDO on April 23rd for delivery to
the Commission by April 30th.
MR. BARTON: Okay.
MR. GRIMES: The Commission meeting is
scheduled for June 16th, I believe. 14th. The 16th
is a Saturday. I keep trying to get them to move it
to the 16th.
CHAIRMAN BONACA: Okay. Any more
questions for Mr. Walters?
MR. WALTERS: Thank you. Thank you very
much.
CHAIRMAN BONACA: Before we take a
recess for lunch, in the afternoon we have the
review of the BWRVIPs. But I would like to go
around the table now and get -- see if there are any
comments from members right now about the letter we
will write. I think we should write a report on
this issue.
My judgment is that we should encourage
finalization of these documents at this time. I
think that, you know, we already voiced in a
previous letter recognition of the fact that there
has been a significant effort here. This was a
remarkable compendium of information in GALL, has
been restructured and has been refocused, but hasn't
certainly been degraded as improved probably.
The other thing that I think is
remarkable, as we noted, was the level of
collaboration between the industry and the staff
that has made these documents quite effective. And
it shows the importance that we begin to see
application that makes reference to this baseline
documentation which has been so substantial. And
right now it's moot in the application.
So, you know, I will propose that we
will have their recommendation in a letter, and I
will appreciate from members other insights on
whatever else you need to see in the letter.
John, maybe you have some thoughts?
MR. BARTON: Well, Mario, from my
review, I think you are going to continue to have
dialogue I think until you see more applications
come in. You may have to change the -- I can see
where you will have to change --
CHAIRMAN BONACA: At some point.
MR. BARTON: -- the document. But I
think, you know, from the work that's been done to
date, I don't have any problem supporting where they
-- to go forward with where they are.
MEMBER FORD: I'm coming from a lack of
experience, Mario, but my main concern was the
document would not be so cast in concrete that it
couldn't take into account unforseen degradation.
Now I understand that that is taken into account.
CHAIRMAN BONACA: Yes, it is.
MEMBER FORD: So from my lack of
experience, yes, I would endorse it.
MEMBER KRESS: I would endorse it, too,
Mario. I think it's going to be a continuous
process of slight iterations, but I think it's at
the point where we can let those take care of
themselves.
CHAIRMAN BONACA: Yes, I think so.
Graham?
MEMBER LEITCH: I guess we are speaking
now specifically about GALL, are we, as contrasted
with the SRP and the --
CHAIRMAN BONACA: Well, the whole thing.
MEMBER LEITCH: The whole thing. Well,
let me, first of all, say I have no problem
endorsing GALL. It is, you know, one of those
documents that's 99 percent -- maybe even a higher
percentage than that -- satisfactory. And there is
a few little things that are going on that still
need further dialogue, and that will always be the
case I think.
I mean, that will be going on for some
considerable period of time. So I think it's -- the
time is to endorse this and get on with it.
I do also think there are some -- if
there are issues of disagreement, there are some
caveats at the beginning of GALL, what GALL is and
what GALL is not, that helps clarify that issue. I
mean, GALL doesn't purport to be all-encompassing.
There could --
CHAIRMAN BONACA: Or the only solution.
MEMBER LEITCH: -- be systems not
included in GALL. Conversely, there could be
systems in GALL that are not required. And it also
speaks about the plant has to ensure that programs
that they actually have complies with the -- is in
line with the program in GALL.
So with all those upfront discussions of
what GALL really is, I have no problem with
endorsing it.
Similarly, I'm not sure if we're talking
about the standard review plan. I guess it's,
similarly, in draft form, is it not? And I think --
I guess -- yes, it is still a draft, and I think we
probably need to get on with approving that draft.
And then, the last document that I
believe is still in draft form is the Reg. Guide
1.188, which endorses the NEI. But I think from
what I heard there is still some -- some changes
proposed in the NEI document. I think the reg.
guide -- I think this has to get to a point where we
say, "This is" -- that is, the NEI document has to
say, "This is Revision X," and then this document,
the reg. guide, has to say, "We endorse Revision X."
Because I think there are still some
minor discrepancies between these two things. So I
think the staff has to be clear with this reg. guide
exactly what revision is being endorsed. But I
think that should be pursued promptly. I don't see
any reason why that can't happen right away.
MR. GRIMES: And I'd like to clarify, it
is our intent to take this -- the draft regulatory
guide, in its present form with its changes, along
with NEI 95-10, Revision 3, in its final form. And
Doug explained that they're looking at some final
changes before they give us the package that we
would refer to.
And Dave Solorio pointed out, we'll look
at that final version to verify that they didn't
make any changes that would undue our ability to
endorse it without comment. But then, that whole
package, along with the draft standard review plan
and the draft SRP, is the package that we would
intend to present to the Commission the end of
April.
MEMBER LEITCH: Right. Okay.
MR. GRIMES: And we will inform you if
there are any substantive changes beyond just trying
to identify any typographical errors or missed
connections, or things. But we don't intend on
changing the substance any more than what we've
described to you today.
MR. BARTON: You said the SRP and the
standard review plan. Do you also mean the GALL?
MR. GRIMES: That's correct. The
package consists of the regulatory guide and its
connection to NEI 95-10, Revision 3, the standard
review plan. And the standard review plan
incorporates, by reference, GALL.
MR. BARTON: Right. Okay.
MR. GRIMES: And then, to complete the
package as it's presented to the Commission, there
is the NUREG report that explains the resolution of
all the public comment, so that is folded in, but it
is not guidance. It's part of the package.
CHAIRMAN BONACA: Bob?
MEMBER UHRIG: I support this.
CHAIRMAN BONACA: Bill?
MEMBER SHACK: No. I'm sure, you know,
we'll continue to approve it, even on the small-bore
piping. I like the ANO solution better than the
staff's solution, and I hope everybody will take it
as a precedent.
CHAIRMAN BONACA: But the process allows
that right now, so --
MEMBER SHACK: But as Chris said, I
mean, you really can't use this until it becomes an
official document and --
CHAIRMAN BONACA: Yes. And I think we
should stress the fact that what we review today, it
would be -- certainly make the reviewer's job much
easier if there was a more substantial referencing
to establish documents of guidance, and they are
missing right now.
The other thing that we -- in the
interim letter we wrote, we also wrote that it would
be important to update these documents frequently.
They sure don't reflect experience. So there is
already opportunity for incorporating changes.
Before we recess, I would like to ask
one more question. First of all, are there any
other issues that you would like to see reflected in
the letter?
MR. GRIMES: I have a question, Dr.
Bonaca. And is there anything in particular you
want us to prepare to present to the full committee?
CHAIRMAN BONACA: Yes, I -- yes. We
foreclose that, however, because that may be an
issue. I raised the issue of scoping because it's
one that I've been reviewing specifically, and I'm
still somewhat concerned about, you know, the lack
of transparency in some reviews when -- when -- I
mean, the early applications were transparent
because there was a scoping process. All the
components were there. Then, there was a screening
going in saying, "Well, what are the functions?"
Well, the function is not required, and it doesn't
belong in license renewal. And you see the outcome.
Right now, what is going to be agreed to
is only the outcome, which is going to be leaving
the reviewer in -- not the staff, because they have
the benefit of being able to go and audit -- it's
going to leave certainly a reviewer like ACRS unable
to make a judgment. I mean, we have to purely make
a judgment based on process and staff statements.
So do you feel that that's an issue we
should bring up or not?
MEMBER SHACK: It sounds as though they
made it a legal issue. You know, again, I kind of
surrender when they -- when they hit me with the
OGC, I give up.
(Laughter.)
CHAIRMAN BONACA: Well, I mean, still,
we've got to express an opinion, you know, because I
think ultimately we want to make sure that these
processes by which you are licensing these plants
are transparent the public. And, you know, I --
again, I view ourselves as the public in a certain
way. We are coming at the end of the process. We
are less informed than the staff and the applicant,
and we're trying to make sense out of what is being
done. So --
MEMBER SHACK: Well, it certainly sounds
as though we ought to encourage them to include it.
CHAIRMAN BONACA: Well, that would be
the only way would be purely that, you know, we like
it better one way or the other, simply not forcing
away. I mean, what is being proposed is acceptable.
I realize it meets the requirements of the rule.
MEMBER KRESS: I viewed our role as
auditing the process, to see that the process would
result in an acceptable product. So, personally, I
think it's all right to do it. You know, we've
already looked at the process, and we know that the
staff is diligent about following such a process.
So I really don't see that it needs to be that
apparent.
CHAIRMAN BONACA: Let me try -- if I put
anything in, I'll just put in a paragraph, and then
I'll let you guys make a judgment, and then we can
decide then. It certainly will be only in terms of
expressing an opinion rather than giving a
recommendation at this stage.
MR. BARTON: That's a good suggestion.
CHAIRMAN BONACA: All right. Now,
regarding the meeting next week, I think that we
don't want to go through the specifics, but it will
be interesting to have a categorization by a generic
type of changes. For example, some of them were
repackaging. Some of them -- and we don't need to
hear about the repackaging issues.
I mean, some of them were increase
focus. Okay? Some of them were minimal acceptable
programs. It will be interesting to understand, you
know, the category of changes and a judgment of
whether you see there has been any erosion of
programs or not. I guess the judgment would be that
there isn't, so -- but just the categorization of
those, it would be interesting to hear for the
committee. And then we'll decide how much time
there is for this portion here.
The other thing that -- I can maybe
provide some examples, give one example for each
category, so we understand what the process of the
change was.
The other thing that I thought
personally, and then we'll go around the table and
see what other thoughts there are here, it would be
to -- to talk about the one-time inspections. I
know that some of the other members -- for example,
Dr. Powers -- was interested in those, and I think
it's important that we get an understanding of that.
And since we are going to have a
presentation on Hatch on the same morning, it would
be interesting to see, you know, specifically the
one-time inspection for Hatch spelled out, so we can
have a correlation between what we see in the
morning --
MEMBER SHACK: Why don't we toss in ANO
and complete --
CHAIRMAN BONACA: Well, see, but that's
-- then we have an understanding how -- we
understood, for example, the issue of small-bore
piping.
MEMBER SHACK: But ANO is a very
interesting contrast. I mean --
CHAIRMAN BONACA: Sure. I mean, but it
raises questions, and there are good reasons. But I
think that it would be good for the whole committee
to hear it and to see the reasons why we're going
from so many to so little. It doesn't mean that we
are not doing it. It means that something else is
taking care of that, particularly the ISI for the
small-bore piping, which is risk-informed.
Any other issues you feel that we
should --
MEMBER SHACK: Well, I think they ought
to discuss the open issues.
CHAIRMAN BONACA: Yes.
MEMBER SHACK: Clarify those and flag
those out. Again, there has to be some emphasis on
the perspective here. You know, you have open
issues, but, you know, really, you have resolved so
much.
CHAIRMAN BONACA: And, of course, you
want to communicate your recommendation that we
recommend finalization of the documents.
Anything else? If not, then we'll take
a recess for lunch. We'll meet again at 20 after
1:00.
(Whereupon, at 12:21 p.m., the
proceedings in the foregoing matter went
off the record for a lunch break.)
A-F-T-E-R-N-O-O-N S-E-S-S-I-O-N
(1:18 p.m.)
CHAIRMAN BONACA: We are resuming now
with the BWRVIP reports and their applicability to
license renewal. With that, I pass it to Mr.
Carpenter.
MR. CARPENTER: Yes, sir. I'm Gene
Carpenter. I'm with the Materials and Chemical
Engineering Branch, and I'll be talking to you today
about the BWRVIP reviews for license renewal.
The agenda that I'll be following is an
overview of the BWRVIP program, which will be
basically given by Robin Dyle of the Southern
Nuclear/BWRVIP Assessment Chairman. Then I'll be
talking about the staff's review of the BWRVIP
reports with some overview of the current operating
period, the generic aging management plan that we
have looked at, the reports supporting the BWRVIP
generic aging management program, and I'll be giving
some specific examples of those, and then I'll be
going to the conclusions.
Staff's perspective -- BWRVIP is a
voluntary industry initiative that began in 1994 to
address the Generic Letter 94-03, core shroud
cracking issues. As you may recall, we briefed the
ACRS on this some years ago about this issue and
talked to you about it at that time.
Since then, it has grown to address all
BWR internal components, reactor vessel, and Class I
piping. It also covers the current operating term
and the extended operating period, and it is
proactively addressing aging degradation issues that
are beyond regulatory requirements.
The staff has been reviewing the BWRVIP
submittals, and that includes some 15 inspection
flaw evaluation guidelines, which I'll be going over
in some detail today; 13 repair and replacement
design criteria guidelines; four crack growth and
mitigation guidelines; 22 other supporting reports;
and 12 license renewal appendices.
Now, point of information -- although
there are 15 inspection flaw evaluation guidelines,
three of them are subsumed into two others, so that
is -- that takes care of that, and then with the 12
license renewal appendices it makes up the aging
management program.
The staff expects to finish the reviews
of these documents listed by the end of this year,
and this is, of course, dependent upon timeliness
and technical review adequacies.
Now, presentation is by Mr. Dyle. He's
going to go over some of this. He's, as I said, the
Technical Chair of the Assessment Committee.
Robin?
MR. DYLE: Thank you. I appreciate the
opportunity to be here. As Gene said, my name is
Robin Dyle. I'm from Southern Nuclear, and I'm
currently the Assessment Chairman -- Assessment
Committee Chairman.
Now I have a little bit about the
organization. I consulted with Dr. Shack last week
to try to understand --
MEMBER SHACK: He happened to be in
Oregon.
(Laughter.)
MR. DYLE: We were -- I apologize. We
were at Argonne last week, and I --
MEMBER SHACK: For rest and recreation.
MR. DYLE: Yes. And the question I
asked was, who on ACRS heard our presentation seven
years ago, and he basically said three people. So
as Gene and I talked about how to describe this and
the information we thought you might need, there is
some programmatic information. And what I'd like to
do is explain how the program was put together, the
things that went into it, so that you understand,
then, the depth and the breadth of the program and
how the licensees are using it.
What I am using here is a boiled-down
version of a six-hour class that we teach for the
licensees. So some of these slides I will simply go
through, but they're there for completeness, so that
you can have them to refer to later.
Please stop me as I go on with any
questions you have.
CHAIRMAN BONACA: Yes. At some point,
whenever it's convenient, it would be probably good
for us to have, if you have a little schematic --
and I think you do have it -- a representation --
MR. DYLE: Yes.
CHAIRMAN BONACA: -- to give us just a
brief schematic of the BWR internals, the function
that some of these perform, like the shroud, and --
MR. DYLE: Top guide.
CHAIRMAN BONACA: Yes. And then the
location of cracks that have been experienced to
date, and also -- the other thing which is important
to understand is not all kinds of cracks will cause
safety consequences.
MR. DYLE: Right.
CHAIRMAN BONACA: A few, however, have
safety implications, and you could point to us which
ones really -- you know, briefly, just so that we
get an overview --
MR. DYLE: Okay.
CHAIRMAN BONACA: -- and I would see it
as a cap to the whole package of the BWRVIP.
MR. DYLE: Okay.
CHAIRMAN BONACA: It will help us.
MR. DYLE: When I get to the point of
doing the detailed discussion, I'll -- if I forget,
stop and remind me and see if there's anything else
that I failed to address.
CHAIRMAN BONACA: Okay.
MR. DYLE: Because I'm going to try to
do a broad overview, and then I've got several
components that we talk about in more detail, so you
can see how the program is put together.
I'd also like to mention that Mr. Bob
Carter is here sitting at the table. He is the EPRI
task manager who has handled this program from an
assessment standpoint since we began this effort.
And we've got some of the I&E documents. Should you
ask a question that we don't have in the
presentation, we'll have that available.
As I mentioned, the purpose of the
presentation is to give you kind of an overview of
where the VIP came from, look at the scope of the
program and how and why we selected the components
we did, because all the internals are not in there,
and there's a reason for that.
We need to identify the attributes that
ought to be part of, you know, what a plant does to
make sure they do the things that are appropriate,
and this would apply to license renewal. And then
we'll talk about some of the guidelines.
And the detailed review that I have
planned based on input from Gene was the flaw
evaluation guidelines for the shroud, the jet pump,
the top guide, and then a discussion of what we've
done recently on IGSCC related to piping in the
recirc. loop. So that will be the presentation.
From a historical perspective, back in
the 1980s, IGSCC and piping was an issue. We were
concerned with it. And we recognized that it could
potentially affect internals and started working on
that in the owners group.
The shroud cracking that occurred in '93
and '94 provided additional evidence that we needed
to address internals cracking in IGSCC. So, in
1994, the utility executives recognized that it was
a big enough issue that they separated this issue
from the owners group and formed the VIP as a stand-
alone committee that would focus on the internals.
So that was the purpose of this organization.
And here's the executive guidance that
we had. We're to lead the industry toward a
proactive generic solution. And what we did with
that was one of the things that Bill Russell
actually said he thought was a good thing we had
done was we set aside the licensing arguments. We
made no licensing arguments in the VIP. We did the
technical thing first, described what the problem
was, what the solution would be, and then after the
fact tried to figure out how that fit into the
licensing arena. So we were trying to do the right
thing for the right reasons.
The other thing was to have options.
Because we were looking at new things, we wanted a
cost-effective approach. There might be one thing
that one utility would want to do and another that a
separate utility would like to do. But both were
equally adequate in addressing the safety issue, so
we tried to build that into the program.
We also served as the focal point to
interact with the staff, and that has worked well.
And the last item is that we share
information among the members. We've got the
program set up so that periodically all the
inspection information is funnelled back to the
members. It's also given to the staff, so that we
can keep this program a living program. If
something new happens that we didn't anticipate,
that's the vehicle to find out about it and modify
the program as we go forward.
From a dollar standpoint, here is the
issue. If you look -- and that doesn't come out
very well in the colors. I apologize. But in the
early '80s, this loss of capacity due to pipe
cracking was a big issue. We're talking 12, 14, 20
percent loss of capacity for the BWR fleet because
of pipe cracking. We didn't want that to happen,
and we've tried to manage the internals, and we
think we've done so.
Here's our biggest loss of capacity
related to internals cracking. So the other thing
that this program did was let us manage the problem
proactively, so we could continue to operate the
plant safely and minimize the cost. To date, we've
spent in excess of $30 million on this program of
utility funds to go forward.
The next slide is a list of the domestic
plants. All of the domestic plants are in the
program. I won't spend a lot of time. And the next
slide simply is to let you know the international
members.
The benefit of this is they've done
things differently. In the early days of the shroud
cracking, we wanted to understand better what the
weld residual stresses might be. The Japanese had
actually built a shroud using their old welding
procedures and then done the destructive analysis of
it. So by having them be a member, we were able to
share that information and build that into our
approach.
So that was one of the benefits of
having the international folks, and they continue to
be members and provide active support.
Here is the project scope, and the scope
for the VIP initially was we'll take care of the
vessel and the nozzle. So from the safe end weld
out, that belonged to the owners group or some other
activity. We focused on where we needed to be
early.
We did a safety assessment, and I'll
talk a little bit more about that in just a second,
that helped us identify what needed to be done and
when it needed to be done. And when it all boils
out, these are the components that are included in
the VIP program that are considered safety-related.
The other thing that we prepared -- and
Gene mentioned those, and I did, too -- what we call
I&E guidelines or inspection and flaw evaluation
guidelines. There is this one, the I&E. This
describes what and when to inspect, and this is done
by the Assessment Committee.
You know, how is this component going to
fail? Where is it going to fail? How often should
I inspect it? What method should I use?
The NDE guidelines where we have the NDE
experts working, they develop the qualification
criteria. You know, how would you qualify a UT
instrument to go down and do a shroud weld H4? So
they work on that and look at the errors involved.
We develop repair guidelines because we
anticipated having cracking and needs that -- where
we would need to fix things. So they're done. And
then mitigation hopefully offers the silver bullet
for the future, to find ways to turn off the
cracking through use of hydrogen water chemistry and
noble metal.
Real quick, that's the organization and
it's no longer current because I'm now the Technical
Chairman here. But these are how we broke -- these
represent the committees and the committee
structure. This is how we broke the work up. And
the other thing that was important was that we have
an executive responsible for each section.
And you notice that we'll have an
Executive Chair. Currently, Integration is open
because of mergers and changes like that. We
periodically have open slots. But the main thing to
see is the structure, the organization, and that
there is an executive leading each one of these
technical committees. And that has been vital to
making the program successful.
The next slide simply is a list of the
Inspection Committee products or some of them, and
we'll talk about a few of these. But this also
gives you an overview of how we work the program
together. We have the I&E guidelines, and then we
have crack growth or fracture toughness reports, and
they've been submitted to the staff. We've got one
for stainless, one for nickel-based alloys, one for
low-alloy steels. So those have been provided, and
those provide additional support to the program.
Again, I'll talk about the safety
assessment on the next few slides. Component
configuration drawings, which we provided to the
staff -- as we develop this program, we pull
drawings from all available resources at GE for the
as-designed structures. We save those, cut and
pasted them, and put them into a document so that
now each owner has a list of all the documents, has
sketches that he can look to see if cracking occurs
at one plant.
He can look and see what that
configuration is, how it applies to his plant, and
what actions he might need to take. And it's all
readily available, and it's also here for the staff
to use, so they can understand those same issues.
We've done some bounding assessments.
This goes back as a follow-on to Generic Letter 92-
01 looking at the vessel.
The effective IHSI, one of the issues
that we dealt with -- and I'll talk about it when I
get to the piping -- was the effectiveness of the
induction heating stress improvement and how well
that works in mitigating IGSCC. And it ties to the
88-01, and I'll talk about that.
Integrated surveillance -- I'll just say
here that we're working on a program similar to
that, I'd say, like the B&W plants have done in the
past where we can get a smaller group of plants that
have the right materials and integrate our overall
surveillance program, so that we better understand
what's going on with vessels and adjust the capsule
withdrawal schedules. And that's under development
right now.
The next two slides are simply a list of
the I&E guidelines for these safety-related
components, and I'll -- unless you have a question,
I'll just go on past those.
MEMBER LEITCH: Would the nozzles be
under the RPV?
MR. DYLE: Yes, sir.
MEMBER LEITCH: It seems to me there was
a particular problem with the CRD return line
nozzle. Was that return line eliminated in all
plants? I know many of them it was.
MR. DYLE: No, sir. It was eliminated
in all but two. The two BWR-2s did not cut and cap
the CRD return lines. The rest of the plants did.
And that's addressed in NUREG-0619 that addressed
the feedwater nozzle cracking and the control rod
drive return line. And then that, as it applies to
license renewal, is addressed in BWRVIP 74, which is
our vessel license renewal document. So that's
where we brought that information forward.
MEMBER LEITCH: What are the two BWR-2s?
Do you remember off hand? Is it Oyster Creek?
MR. DYLE: The BWR-2s would be Nine Mile
1 and Oyster Creek.
MEMBER LEITCH: Thanks.
MEMBER FORD: You were going at such a
rate that I didn't want to stop you.
MR. DYLE: That's fine.
MEMBER FORD: Back on page 8 --
MR. DYLE: Yes, sir.
MEMBER FORD: -- you listed the
components there, and I'm presuming they're going in
terms of priority from the core shroud down to the
RPV as the bottom priority. What was the criteria
for that risk assessment?
MR. DYLE: You're a wonderful strike
man. The next slide, page 14 --
MEMBER FORD: Okay.
MR. DYLE: Couldn't have timed it
better. Thank you, Dr. Ford.
For years we understood that there were
some components that were safety-related and not.
But when we started the VIP, we said, "Let's make
sure. Let's revisit that issue. Let's go back to
GE and talk about how this thing was designed and go
from there."
So we said, "We're going to identify the
safety-related components and separate them from the
non-safety," and here's the criteria that we used
when we looked at the components -- maintain a
coolable geometry, rod insertion times, reactivity
control, core cooling, and instrumentation
availability. So all of those were considered in
determining whether something was safety-related or
not.
Some components, as it turned out, were
not. The feedwater sparger sometimes is surprising,
but it has no safety function. It disperses the
water equally about the annulus, and it improves jet
pump performance, but it is not relied on in any way
for safe performance of the vessel or any ECCS
function. So that's just an example of how we did
that and how we separated those.
MEMBER KRESS: What exactly is a safety
assessment, contrasted to a PRA, for example?
MR. DYLE: Oh. It was a deterministic
assessment where we looked at the failures of the
components, and I have that discussed later in VIP
06. But we did a deterministic assessment, said,
"What is this thing supposed to do?"
MEMBER KRESS: If it failed --
MR. DYLE: If it fails, what happens?
What other systems are available? And given that
those systems available, what happens if it fails?
And so one of the things we found -- and we
determined this when we did the core shroud
initially and did the detailed safety assessment
that Dr. Hackett and I presented years ago.
But when you looked at the core spray,
every scenario -- or the core shroud, every scenario
said, "We need the core spray." And if the core
spray failed, what else did we need?
So that's part of what, then, Peter, led
us to, how do we prioritize these things? And the
core shroud kept coming up on top. Every time we
assumed a component failed, that was it. And that's
the way we approached these things.
We just said, "What happens if it fails?
Where can it fail?" and did the assessment from that
perspective.
Any other questions?
MEMBER FORD: But a frequency of events
in the past didn't enter into this particular --
MR. DYLE: Not per se. We did look at
inspection history to try to figure out what the
nature of the cracking was. Core spray was one of
those things that we had had lots of inspections and
repeated instances of cracking. So we knew that it
was also something that we needed to look at quick.
We relied on it in a lot of scenarios,
and it was one that was degraded to the point early
on that we found cracking. In fact, the staff wrote
a bulletin on it in 1980 requiring visual
inspections every outage. So we have been
inspecting the core spray lines and spargers since
1980 every outage. So that's an example.
CHAIRMAN BONACA: I think the issue of
frequency is important when it comes down to
mitigation. In some cases, for example -- I don't
know. I was looking at top guide. There is some
fragile mode where you may end up with core
movement, inability of inserting rods. You know,
for that particular case, there is a statement that
says, "If that happens, you know, there is the SLC."
Granted. But SLC is not supposed to be needed more
than with a certain frequency in the original design
of the plant.
And so it leaves you a little bit with
the question of how likely is this failure mode to
occur now because of the cracking beginning to take
place, which is the answer that there is mitigation.
I don't think, in and of itself, it is enough.
MR. DYLE: Well, and I understand your
question, and I think the answer is is when we did
the safety assessment it let us know what was
safety-related and what the consequences of a
failure were, which we then rolled into
consideration of which components do we look at
first as far as developing a program, and then it
also led us to decide what needed to be inspected
and how often and what method.
CHAIRMAN BONACA: So that really was
focusing -- okay, so there was a consideration. The
main focus was the prioritization of the efforts
because of the significance.
MR. DYLE: Right. One of the questions
the staff asked initially when the core shroud
failures and cracking started to occur was, why are
the plants safe to continue to operate? And we felt
this was the degree necessary to evaluate that, so
we looked at all of the components.
So that's been done, and we've built
that into these inspection and evaluation documents,
which I guess leads into this.
As far as what's in an I&E guideline,
this is it. Each one of them has a description of
the component. We look at the susceptibility of the
IGSCC, discussion of failure consequences of each
location, and we tried to identify every location on
an individual component where it might fail and
said, "What happens if it does that?"
We looked at the inspection history, and
then from that we develop inspection requirements
and flaw evaluation methods, and it also talks about
how to report the information.
MEMBER KRESS: Could you give me an
example of a consequence, the third bullet?
MR. DYLE: Yes. For the shroud, one of
the things we considered was if you have a 360-
degree flaw at the H3 weld, and then you have a main
steam line break, what's the possibility that you
might actually lift the whole shroud now that it's
separated?
And if that occurred, what would happen?
Would you lose two-thirds core height? If a jet
pump disassembles, if a jet pump beam fails, and
then I eject the jet pump ram's head, then I could
disassemble the jet pump, and I no longer have the
ability to maintain two-thirds core height.
So we have to go put together an
inspection program that would preclude those kind of
things, or have a monitoring program that says we do
daily surveillance to do some tests to get that kind
of information.
CHAIRMAN BONACA: But many of these
failure modes -- that's why I had the original
question in the beginning -- end up with core
movement, right?
MR. DYLE: Right. They are -- and one
of the questions that was asked early on, and I'll
go ahead and address it now and then I'll let the
staff talk about their studies, was, what are the
synergistic effects? And we struggled with that,
finding a way to do that evaluation and spend enough
money.
So we did our deterministic view. Then
we did a probabilistic assessment that I'll -- that
was very simplified. We set the conditional failure
probability of each component to one and let that
help tweak, if you will, the approach in VIP 06.
And then the staff, on their own, did an
independent assessment of that. I believe one of
the labs did the work, and I'd leave that to the
staff to discuss the results of that.
As far as the description of the
components -- again, we have sketches, we have
locations labeled, general plant variations. So if
you've looked at the -- if any of you have had a
chance to look at these documents, you may see four
or five configurations, so that we can adequately
describe what a different plant would have to do.
And it's based on the best-available design
information.
The onus we put on the owners is that
this is the way it was designed. If you have made
modifications since then, you have to look at this
document, look at the requirements, and then go
forward from there. So we built that in.
Just an example of configuration
sketches, not to have a detailed discussion. But
the double-leaf riser brace for the jet pump, there
are two different types of double leaves, so that's
just an example of the detail that we put in the
document so you can figure out how it applies.
Susceptibility discussion -- which
locations are likely to fail. They're either
through IGSCC or other mechanisms like fatigue. We
considered that. What are the non-susceptible
locations? In those where we determined that they
weren't likely to fail because of material
considerations and the way that the component is
built, we didn't necessarily require inspections.
But one of the things is you don't
expect cast material to suffer IGSCC. At least it
would occur after you've got the wrought material
that's been welded. So we use those as kind of a
criteria, and then all of that goes into the
inspection requirements.
And I recognize I'm going quick, but
this is to get you a description of the program.
And then your question about the
consequences of failure. We looked at those, what
happens, what's the other system responses.
Locations that could fail and have no adverse safety
consequences, we said, "Well, maybe we don't need to
inspect those." But we did look at those anyway to
see if there's other benefits for doing the
inspections.
There may be economic reasons to do
that. You may want to do something. We do a lot of
inspection on feedwater spargers because we want the
plant to continue operating. If it fails, there's
no safety consequences. But we still do
inspections.
At one time, I know at Plant Hatch we
had three pages in a procedure that were safety-
related inspections and 51 pages that were not.
That's the degree that we were doing internals
inspections on non-safety components, so we do a lot
of things in addition to the VIP.
The other thing we looked at was
inspection history. What inspections have been
performed? What was the adequacy of them? If
somebody had done a VT-3, and then said there was no
IGSCC, we discounted that, because a VT-3 is not
going to find IGSCC. It's not going to see tight
flaws.
So we tried to understand what the
inspection history told us. Is it appropriate data
to consider? And then we used that to help guide
us.
The inspection requirements list where
to inspect, what's required for a baseline, what's
required for reinspection, what's the reinspection
frequency. Sometimes the reinspection frequency
depends on the method you use to do your baseline
inspection.
For example, core spray. You do an
inspection of it visually. You have to do something
every outage. If you use ultrasonic, we'll let you
go every other outage, because you've got a better
idea of what's going on with that piping. So that's
an example of how we would use that.
We also specified what kind of scope
expansion needed to be done if you found cracks,
where would you look, what would the response be.
And then, alternatives to inspection -- is there
something you could do instead of inspecting? Could
you modify the component that eliminates the
consequence of failure?
The easiest one to think of is what we
call the core plate, which is kind of a misnomer,
because it's a plate in the core but the fuel
doesn't sit on it, but the inspection criteria for
the bolts around the periphery, so that it can carry
a seismic load.
However, we allow that if an owner goes
in and installs wedges around the periphery so that
even if the bolts fail the core plate can't move in
a seismic event, then we say you don't need to
inspect the bolts because you've put something else
in there that will preclude its movement and it'll
still perform its intended safety function.
MR. BARTON: Has anybody done that? Or
is this a hypothetical?
MR. DYLE: Yes. Yes, they have done
that. In fact, in the GE design for the shroud
repair, that is integral to what they do. To my
knowledge, all of the plants that have installed the
shroud repair in the GE design have the wedges
installed. So that's been done that way.
As far as inspection methods, here's the
definition of them. The EVT-1 -- well, let me start
at the bottom, and maybe this -- the CSVT-1 is the
old core spray visual that was required in the
Bulletin 80-13. We started using that and found in
some cases it wasn't adequate, and we had renamed it
MVT. We finally eliminated that because it was an
interim between these two and wasn't warranted.
So what we have is an enhanced VT-1,
which is a visual with a 1/2-mil wire resolution of
the camera before you ever start the inspection, so
you've got to be able to clearly see a 1/2-mil wire.
In addition to that, there is also some criteria
about what you can see about the weld. There's
requirements of necessity, whether you need to clean
or not. But you can do appropriate examinations.
The VT-1, you have to be able to resolve
a 1/32-inch wire, and this is a standard code exam
with VT-3 as a general visual for mechanical
condition. And, again, that comes from ASME Section
11.
And then, ultrasonic and eddy current,
and we qualify those methods based on what the
component needs are. And all of the details of the
methods are in VIP 03, and it's in a three-inch
binder that the staff has available if you need
that.
Flaw evaluation considerations -- we
tried to describe the procedures that are necessary,
the analysis techniques, and in some cases we
provided equations. And I'll address some of that
later. But where we had equations that we could use
and standardize, we've developed those. In one
case, we've even developed a computer code to deal
with that.
What kind of assumptions do you make
when you can't inspect something? One of the issues
on the shroud was you go inspect the circumference,
but you can't get all of it inspected. What do you
assume about that region you can't inspect? So we
looked at statistical studies and the behavior of
the materials and said, "What is the appropriate
safe thing to assume, since we couldn't inspect it
and factor that into the flaw evaluation?"
NDE uncertainty -- early days of the
shroud the cracking was such that we were trying to
do ultrasonic examinations. We hadn't qualified the
techniques, and we were even using transducers on a
long pole to try to get additional information. If
you've got a pole that's, you know, 60-feet long,
you can get a lot of flexibility. So we accounted
for that in the calculations when you do a flaw
evaluation.
Also, limitations on use. You know,
once you exceed a certain fluence level you just
can't use some of the approaches that we've got. In
the crack growth rates that we describe, here's a
reference to the documents for later use if you'd
like to look at those. But that's where the crack
growth studies are documented. And the staff has
issued initial and final SEs on that.
An example of how you would use all of
this -- if you don't do an inspection, and you've
qualified the technique using VIP 03 and you found a
flaw -- well, you know what the uncertainty of the
technique is. VIP 14 has the crack growth criteria,
what you'd use for stainless in certain situations,
whether you want to use the K dependency or a
baseline, a base disposition curve.
VIP 20 and VIP 80 -- VIP 20 is the
distributed length ligament computer program that
allows you to calculate the remaining ligament and
what's acceptable. Vertical cracking criteria,
because the cracks are oriented different, behave
different. And here is the shroud inspection
guidelines. All of it goes together to do the flaw
evaluation.
And then, VIP 07 is the reinspection
criteria. And I think I mentioned earlier, but
we've rolled 01, 63, and 07 all into VIP 76. We now
have one document that addresses all of it for the
shroud. But that's how you'd deal with a component
like that.
We want inspection guidelines. We want
the information provided to the staff. And this is
what we've put in the guidelines. EPRI compiles a
summary and provides it to the NRC every six months.
So once we finish what we call basically an outage
cycle, we accumulate all the inspection information,
we provide it to all our members, and then we
provide it to the staff.
We've got spreadsheets that reports
that. And the biggest thing for us, it lets us look
at what's going on. Is the program headed in the
right direction? Do we need to make changes? Are
we seeing things that are different? And go from
that perspective.
And I guess the thing is is it's a
current term and a renewal term issue. Some related
issues in the program that I'll discuss now is the
impact of hydrogen water chemistry, noble metal
chemical additions, and VIP 03 repair issues, and
some interaction with the code, and then license
renewal.
VIP 62 -- I guess the way we'd look at
it is if we're going to implement hydrogen water
chemistry and noble metal, to turn off cracking, to
slow down cracking, to help mitigate it, can we
then, in return, get some credit for it in our
inspection program? Can we inspect less often? And
what this document does is go through and look at
how you would justify a reduction in inspections
based on the mitigation aspects of this program.
It is currently under staff review.
They've issued RAIs and an initial ASE, and there
are still some open items that we're looking at.
How do you fully identify what an acceptable
hydrogen water chemistry program is? We need to
define the parameters, so that the staff has
assurance that what licensees are doing is fully
mitigated.
So we're trying to come up with an
approach that addresses factors of improvement on
crack growth, what the ECP or conductivity levels
ought to be in that regard, before we can take
credit for those. And we've got that built into the
program.
MEMBER LEITCH: You talked about how
effective is the hydrogen water chemistry deep in
the vessel. In other words, there is varying
degrees of hydrogen water chemistry. Some just
suppress cracking high in the vessel, and when you
put a full-blown program in you are able to suppress
all the way down. Does that enter into --
MR. DYLE: That does enter into it. And
what is identified is is the function of the
electro-chemical potential and the availability at a
location. So let's say you're monitoring in the
recirc. loop but you want to claim credit that I'm
protecting halfway up the shroud. You've got to be
able to show that in the injection rates you're
using, that the water chemistry parameter is such
that you know that you've got the ECP at the
appropriate level at that point on the shroud, or
you can't take credit for it.
MEMBER LEITCH: Okay.
MR. DYLE: So that's the way it's
structured. And there is the water chemistry
guidelines. You can monitor ECP. We've got
secondary parameters that you can use to look at how
effective the program is. And as you're probably
well aware, if you're using noble metal you need
much less hydrogen, so you can lower the hydrogen
rate. It helps with dose issues, but you still get
more mitigation because it's more effective up in
the core region.
VIP 03, here's just an overview of
what's in it, and I've mentioned it several times,
so I don't know if we need to spend a lot of time on
it. But it's a description of the inspection
technique.
UT, using what kind of transducers, how
many megahertz, what size, what angles, whether it's
a 45 RL, 60 RL, 45 sheer, all of that, a description
of the vendor demonstrations that are performed on
mockups. And we've got a lot of mockups at the NDE
Center, and I'll go ahead and make the invitation
for Bob. You're welcome any time you want to go see
what the VIP has got at the NDE Center in the way of
mockups and how this stuff is done. We would more
than welcome you to come look at them.
We established NDE uncertainty, and we
-- in some cases we include the flaw evaluations as
uncertainty. It depends on the nature of it and the
component. We don't worry about the uncertainty for
determining reinspection intervals currently.
This thing is updated annually. We've
agreed to the protocol, how we'll qualify things, so
once a year all of the new techniques have been
qualified, are published, and everyone who has a
copy of that book gets an update on the new
techniques that are available to revisions that are
made.
And I believe, Gene, you have a copy of
that also.
And then we tried to deal with repair.
What if I have to do a repair? What if I find
something that says it's a problem? The flaw
evaluation says I can't operate. We have general
design criteria that we developed for each
component, and those are documented, and we talked
about those this morning. We're in the process.
We're got SEs on most of those, and
we're trying to finalize that. And it looks at the
structural requirements, the material
considerations, how it was fabricated, and what
you're going to do in the way of inspections.
If component degradation is anticipated,
you can buy contingency repair. And in the case of
Plant Hatch, the way we looked at it with the shroud
-- and this is just an example of how one would do
this -- our management said, "We're going to have
the repair on the shelf. Before we do the
inspection next outage, you're going to do the
repair. You're going to have the repair there in
case we need it." That was 85 percent of the cost.
So we said, "Why do all this detailed
inspection? We're better off eliminating the circ.
weld cracking issue with the shroud, install the
repair preemptively, and have less to worry about."
So that's an example where one could do that.
And there's also ways to get partial
cycles. You know, if you really can't go a full
cycle, you can justify one cycle, so you can have
time to install the repair.
This should go without saying, but we
wanted to make sure of this. For the safety-related
internals, anything you do has got to be done to an
Appendix B program. We didn't want licensees to
misinterpret the VIP program, that because we had
these design criteria that's all you had to
consider. No. That's just the criteria. You still
have to use your Appendix B program.
If this happens to be a code component,
like the shroud or attachments to the vessel, there
are also code criteria that must be satisfied, and
you'd document those on the appropriate code forms.
And that's the way we described that.
MR. BARTON: Was there any question of
our licensees if this needed to be an Appendix B
program?
MR. DYLE: No.
MR. BARTON: Okay.
MR. DYLE: What our approach has been,
and as I've learned through the years doing some of
these owners programs, we wrote things
simplistically, and sometimes an owner would say,
"Well, since you didn't discuss this, does it mean I
don't have to do this, or is there something
different?" So we just -- we'll get rid of any
ambiguity if it's safety-related to Appendix B.
And then the other thing -- early on we
were asked to develop inspection criteria for
repairs. We don't know how. Let's say a jet pump
riser brace cracks. We don't know what that repair
would look like if it's a mechanical repair, so we
can't specify inspection criteria now.
So what we did is put the onus on the
owner that when he has a repair developed that the
-- the developer of that repair must specify those
inspections necessary to assure that the repair, in
conjunction with that component, will perform their
intended safety function. So we've put that on
there.
Interface with the code -- as I
mentioned, in some cases, Section 11 has got
requirements already. Now we have the VIP
guidelines, and we get a safety evaluation on it.
We understand that until a licensee has approval to
use that document that he also has the code
requirements imposed by 10 CFR 50. So there is an
overlap, and before an owner can simply use the VIP
criteria in lieu of the code they must come to the
staff, document such, and get it approved. And
that's so we don't violate what's in the law.
So we're working with that, and we're
trying to develop a template that we could use for
owners to send that information in.
Now, the punchline I guess is what we're
here for. The I&E guidelines were developed without
real consideration to time. At the point in time
the shroud cracking got as bad as it did, and we did
the safety assessment, one set of documents that
were available for us to use were what they called
the industry reports for plant-life extension or
license renewal.
And it was the documentation where the
industry and the staff had worked through a myriad
of issues related to license renewal, what were the
open items, what were the agreed-upon items, how
would you address aging management programs.
So the degree to -- that it was
applicable to the VIP, we looked at that. And we
said if the owners are going to go for license
renewal, if this is a reality, then we ought to
construct this program so that we don't have to do
this twice. We didn't want to submit I&E documents,
have them reviewed and approved and get SE, and then
turn around and have to resubmit those when a plant
approached license renewal.
So what we tried to do was when we
looked at the failure mechanisms, and the cracking
issues, we jus said, "What's going to happen? When
is it going to happen?" and deal with it. Let's not
put any time limits on it. We're not trying to
operate a shroud for another 20 years. It's what
keeps the shroud functional for the life of the
plant, however long that is.
So that's the approach we wrote, and
that's what -- that's what's built into these
documents.
We then approached the staff and talked
to Gene and Chris Grimes and others and said, "We've
got another rule out there that we've got to
satisfy, how we do this." And the staff worked up
their internal mechanism, and I'm not going to go
into it because I'll probably mess it up, but where
the technical staff could review the documents and
find the technical adequacy of them, and at the same
time the license renewal staff could also review
them and see how they applied to the license renewal
arena.
One thing that facilitated that is we
had some folks go through and look at each one of
these I&E documents and say -- and show in an
appendix how different aspects of the document
satisfied the provisions in Part 54. So we
submitted to the staff a technical document, and
then an appendix that says, "Here's how we satisfy
the rules and the requirements of Part 54. Please
review it."
In return, the staff gives us a
technical SE, and then we also get an SE for license
renewal. And that's how we built the program to go
forward into license renewal space.
The next thing is just to look at some
of the program issues.
MEMBER FORD: Excuse me. Robin, can I
ask a question? We heard this morning from a
representative of NEI about an NEI document 95-10.
MR. DYLE: Right.
MEMBER FORD: Is the VIP actively
collaborating on that, so in the future we'll see
the same sort of application from a technical point
of view? Or you're talking very specifically about
technical arguments?
MR. DYLE: Right.
MEMBER FORD: Quantitative technical
arguments. Will that be part of the NEI approach?
MR. DYLE: I guess the more correct
answer, Peter, would be 95-10 was in front of the
VIP, but where we brought this all together was in
the GALL. As the GALL was being developed and we
started looking at these different components, and
they listed the shroud, degradation is irradiation
and IGSCC, we said, "We've got a program. Here's
the VIP program."
We described why it was adequate. The
staff reviewed that, and I do believe that the GALL
will come out and say, for instance, for the shroud,
BWRVIP 76 is acceptable, and the standard review
plan draft that I've seen also makes reference to
those kind of things. So that's where we tie that.
95-10 doesn't yet reflect implementation
of the VIP, as far as how the licensees ought to do
that, and we're working on that within the VIP to
try to get that specified. We're doing these
training classes. We're talking to executives to
try to develop additional training so that licensees
do this the same way. We've done self-assessments.
Matter of fact, the third one starts
today or tomorrow at one of the plants where we go
in and look and say, "All right. You've had the VIP
program. How are you doing with it? What problems
have you encountered?" And one of the things that
comes out of that, we found a couple of places where
they implemented the requirements right but with
great effort because we did a not-so-good job of
writing it.
So we're going to revise those documents
to make the requirements more clear. But as far as
95-10 goes, it's not integrated yet, and we're
trying to work that direction.
Our belief is is if we get the people
implementing the VIP documents right now, they just
continue. The license renewal is immaterial. They
never know that they crossed the 40-year mark,
because this is the right kind of program for the
current term and the renewal term. That's our hope
and expectation.
Any other questions?
One of the things -- and this is where
we need to interact with the staff some more. When
we talk about a VIP program, we consider that any
control process that implements this thing properly,
and make sure that all the requirements are met and
the plant is safe and we've maintained the integrity
of the components.
I personally put together three
different programs, and they were done three
different ways. And when you go to a plant, some
people may accomplish all of these tasks in
procedures. Some may do it, as some plants do, they
have an ISI program, and then they augment their ISI
program with these VIP criteria.
Others have specifications that they
use, so we've gotten to leave the technical
requirements as they are, not be overly prescriptive
on what the program should look like, but identify
the things that had to be part of it. And that's
another thing that's currently being assessed with
these self-assessments.
Now here's what the program gets at.
Make sure the inspections are done when they should
be, that they use the right techniques, that they
are evaluated properly, use the right people. We
want to make sure the folks can do the exams. Use
the correct methodology, and, where appropriate, the
repairs meet the code or the VIP criteria. So
that's what has to be done to implement one of these
programs.
MEMBER LEITCH: Do the licensees that
are part of the VIP program that you had mentioned
earlier, are they -- are they automatically
compliant? Can we assume that they're complying
with the program? Or is that a future decision?
MR. DYLE: The way we have that set up,
because as Gene mentioned I think on his first slide
this is a voluntary initiative --
MEMBER LEITCH: Are they volunteering? I
guess is the question.
MR. DYLE: Yes, they are. And what the
executives have said repeatedly, and we've even put
it in writing, is that we will implement the VIP
documents as written. And I -- I'll pick one.
Let's say jet pump. We provide the jet pump
document, it's out, the owners review it. They've
bought into it. We submit it to the staff.
We expect in a reasonable amount of time
they start implementing that document. And it may
be that the document comes out in February and the
outage is in April, so you can't build that in. But
as soon as you can, you start doing those
inspections.
The staff may review those, and say,
"Well, I don't particularly like that inspection.
I'd rather see this." We, the VIP, will negotiate
with them on that issue and try to determine the
right thing. But in the meantime, we, the owners,
keep implementing it the way we said we would.
At such time that we have what we call a
clean safety evaluation, where the VIP members and
the staff are in agreement, then we will reproduce
that document with the clean SE. And at that point,
the licensees are committed to implementing the
document as specified in the NRC safety evaluation.
And if they're not going to, if for some
reason they can't or they've got an alternate
technique that they want to use, they have 45 days
to notify the staff. So that's the arrangement we
have worked out at this point in time.
Gene, would you --
MR. CARPENTER: At this time, every BWR
licensee in the U.S. has committed to following the
BWRVIP. And we have only seen a few instances where
they have taken minor exceptions to the VIP
documents, and that has usually been a matter of
timing as opposed to actually doing the inspections.
MEMBER LEITCH: Okay. Thank you.
MR. DYLE: Any other questions? Because
this is kind of a break from the programmatic. Now
I'm going to look at some of the documents in a
little more detail. I don't know what you all have
in the way of schedule for a break or what
questions, so --
CHAIRMAN BONACA: No, there is still
time. I think when you get to your slide number 39
or 40 --
MR. DYLE: Yes, sir.
CHAIRMAN BONACA: -- I would appreciate
it if you could do what I asked you before, which is
provide us with a brief summary. The next one
actually is very clear -- a summary of the function
that they provide, those components, for example,
the shroud, the top guide, the lower core plate, top
guide, etcetera.
The location where the cracks have been
-- mostly been experienced, because I think it would
be interesting for us to see the location of the
welds on the shroud. And the other thing that I
would like to understand is I read, for example, in
the BWRVIP for the top guide that all the top guide
elements have already exceeded the amount of fluence
for which you have become susceptible to cracking.
And so my question -- and, again, I am
not a material expert, so -- is you have a certain
series of intervals for inspection that you have
set? Would that change with age, given that
susceptibility is high and you would expect with age
the number of locations where you may have cracks to
increase or the frequency to increase? I just would
like to have that kind of information as part of
this presentation, if you could. So --
MR. CARPENTER: If I could go ahead and
address that right off the bat.
CHAIRMAN BONACA: Yes.
MR. CARPENTER: Basically, what the
staff has agreed to is that once you achieve a
fluence level of 5E+20 neutrons per square centimeter
-- it's a threshold limit -- you fall into a crack
growth rate of 5E-5 inches per hour, which is about
three-quarters of an inch per year crack growth
rate.
When you're below that threshold
fluence, for certain geometries, for certain
chemistries, you would have a lessened crack growth
rate, perhaps as low as 1E-5 inches per hour. So,
basically, as the plants age, they will be
inspecting more, not less.
CHAIRMAN BONACA: Okay. So the
inspection intervals are changing with age.
MR. CARPENTER: They will be increasing.
CHAIRMAN BONACA: Or they may be
increasing. So there are provisions within the
guidelines to increase the inspection, depending on
certain measurements like fluence, and so on.
MR. DYLE: And that's generally
associated with an issue if you have a flawed
component. For example, the top guide, there's
nothing that says once we reach a certain interval
or a certain fluence level we'll start inspecting
the top guide more frequently. But we're doing the
inspections at what we believe is a frequent enough
interval to catch any problems before they create a
serious issue. And by looking at 36 BWRs and
integrating that information, as soon as we find a
problem with one we can go with the other.
For example, we have one BWR that has
the top web cracking. And we've been monitoring
that location and looking at that, and it's got the
highest fluence level. So we use that sort of to
set our inspection frequency. Given what's happened
at this plant, how often should we inspect to make
sure we catch that? So that's how we tried to build
that into the program.
And I'll try to answer the questions you
asked. I'm not a systems guy. So I'm not going to
be able to go into great detail about all the things
that these different components do and recall all
the history off the top of my head, but --
CHAIRMAN BONACA: No, no, no. I just --
you know, I think for the benefit of the whole
committee, to understand where the cracks have
occurred, what the experience is. The other one
that I would like to point out, that's -- at least I
give you my train of thought there. I spoke of the
top guide, and there -- the possible failures of
components which link the top guide to the shroud,
and so on, have been postulated.
Only a few of those failure modes have
been identified as safety-significant. One of them
I think some of the pins up there --
MR. DYLE: Right.
CHAIRMAN BONACA: -- the failure of
those pins may cause the core to move, so that you
have normal insertion. For that particular failure
mode, I would expect that you would have a
commensurate provision for inspection maybe more
frequent than others. That's the kind of insights I
would like to have on the program.
MR. DYLE: Right. And I've got --
CHAIRMAN BONACA: To understand what the
logic is behind that.
MR. DYLE: I've got some details on the
top guide, but a simple answer to that -- not only
does the pin have to fail, but you also have to have
a main steam line break, so that you have sufficient
delta P to lift the top guide above the fuel so that
it can tip over and then you can't insert the rods.
CHAIRMAN BONACA: Okay.
MR. DYLE: So one of the provisions is
is that if you can look at the delta P that's
developed during a main steam line break, and show
that the top guide will never lift because of the
weight and the attachment arrangement, then there's
much less safety concern. So those are the kind of
considerations we built into that.
The LPCI injection -- this is limited to
BWR 5s and 6s. They have special couplings. It's
arranged somewhat like core spray. To the best of
my remembrance -- and, Bob, correct me if I'm wrong
-- we haven't seen any problems with LPCI yet,
because it's installed on the newer plants, and we
wouldn't expect to have any problems. But that is a
means of implementing the low pressure coolant
injection that we would need during certain accident
scenarios.
The core spray line, which we've talked
about in the accident scenario, it provides the core
spray on top of the fuel. Some plants are more
needful of having the spray dispersal, so that the
nozzles are more significant about being maintained
on the sparger itself that's inside the core, that
it sprays down appropriately.
We had some discussions early on four
years ago about trying to identify which plant was
what, so that the plants that needed the spray
distribution would inspect the nozzles and the
others didn't. We finally gave up on that and said
that doesn't make any sense. Everybody is going to
inspect the nozzles. So there is some conservatism
we built in. Instead of worrying about that
evaluation, we put it in.
The core spray piping that comes from
the nozzle delivers that to the sparger so it cools
things. The top guide, as we talked about, keeps
the fuel from shifting. It also lets the rods
insert. The core plate -- here it's the same thing.
We've not seen any problems at the core plate.
There's been limited inspections, but the
inspections to date haven't been an issue.
And, again, this doesn't really show it
well, but there are bolts around the periphery, and
depending on the unit and the diameter the number of
bolts change. But as long as they're there, the
core plate is not going to shift. We don't worry
about it lifting because -- and I don't believe I
have a slide to this effect. I may have a backup.
But when you look at the control rod
drive housing there is a lip on it that's a half-
inch above the top guide. So that even if all the
bolts were to fail and then you had a main steam
line break, so that you developed the delta P to try
to lift, it can't lift more than a half-inch because
it engages --
MR. BARTON: Are you talking about the
core plate?
MR. DYLE: Right. The core plate. It
would engage the bottom of -- it would engage that
lip on the drive housings. So that's a --
CHAIRMAN BONACA: The topical says that
you could.
MR. DYLE: It will --
CHAIRMAN BONACA: That's why I asked
that question.
MR. DYLE: Now, the core plate or the
top guide?
MR. BARTON: No. I think the thing
you're talking about talks about the top guide.
MR. DYLE: Okay. The top guide.
CHAIRMAN BONACA: Okay.
MR. DYLE: The top guide can lift in
some scenarios. The core plate is limited
vertically to a half-inch. So it won't disengage.
CHAIRMAN BONACA: Correct.
MR. DYLE: And when we were developing
what was the right inspection criteria, we would
have loved to have justified not trying to get down
here, because it's a difficult access to do. We
looked at some old General Electric studies that
they had done. How far can this thing move? What
happens with rod insertions?
And we could postulate that the nature
of the way the system behaved, that even though you
had a seismic event and the core plate was going
back and forth, the rods would insert maybe
sporadically but eventually would go all the way in.
Again, we said, let's not argue that.
Let's just go do the inspections. And, again, you
either look at the bolts or you install the wedges.
The shroud you're probably well aware
of. It ensures a coolable geometry. It supports
the fuel. It holds the top guide and core plate in
place. We have had significant cracking in multiple
cases. It's been inspected extensively.
Several plants are on their third
inspection using the improved criteria. We're not
seeing much growth, which is good. And it's
encouraging that this thing is not a rampant problem
that we can't deal with. So we seem to have found
--
MR. BARTON: Do we understand why we're
not seeing much growth?
MR. DYLE: I probably ought to say no
and defer to some other folks sitting around the
table. But the --
MR. BARTON: That would be all right,
too.
MR. DYLE: The simplistic answer from
our looks is is that as you go through thickness in
the shroud, the K distribution changes, K dies off,
the growth mechanism slows down from a stress
standpoint. And that's a very simplistic answer.
Bob?
MR. CARTER: And mitigation.
MR. DYLE: And mitigation is working
also.
MR. BARTON: And what?
MR. CARTER: And mitigation. Hydrogen
and noble --
MR. BARTON: Hydrogen. Okay.
MR. DYLE: And that's -- anything else
is far beyond my expertise, and I'll defer there.
CHAIRMAN BONACA: He said hydrogen and
noble metal, right? Okay.
MR. CARTER: Yes. Either separately or
in combination.
MEMBER SHACK: What fraction, again, of
plants - of BWRs are on hydrogen now?
MR. CARTER: A very high percentage.
MR. CARPENTER: Last week when we were
at Argonne discussing this, basically the GE folks
told us that it was somewhere in the neighborhood of
about 33, 34 plants, which is almost all of them.
MR. DYLE: Worldwide.
MR. CARPENTER: BWRs. Now, worldwide,
that's a different story, and I can't begin to
answer.
MEMBER SHACK: No. We just meant the
U.S.
MR. CARPENTER: Yes. Almost every one.
MR. DYLE: And a lot of them are
seriously looking at noble metal as the augmentation
of the hydrogen to be more effective.
The jet pump assembly, I'll go through
that in some detail. But, again, that preserves the
two-thirds core height. It also lets the recirc.
flow come in and distributes it below, so that's the
function. But its main safety function is either to
maintain two-thirds core height, or some of the
threes and fours, that's the route that LPCI has
injected, should you need that in an accident
scenario.
That's all I see on here that's listed
as safety-related. Any other specific questions
before I go on? I don't want to skip over things
that you're interested in.
MEMBER LEITCH: In the jet pumps, for
example, have you considered fracturing -- that is,
debris -- as a safety issue? Or --
MR. DYLE: We did.
MEMBER LEITCH: -- do you just look at
cracking, or do you think a jet pump is -- the
fracture is --
MR. DYLE: We looked at fatigue, and we
looked at every weld location for the jet pump. We
looked at fatigue issues. We looked at IGSCC. We
looked at what happens. And when I get to that
slide, we'll talk about how we classified the jet
pump components high, medium, or low. That looked
at the consequences of the fracture.
We did look at loose parts, in general,
in VIP 06. And we addressed that, and we looked at
large, medium, and small parts, and had GE do the
systems analysis. This is what happens if we have a
part this big, what happens if we have a part
smaller that clears the recirc. pump and comes back
in, can it block the flow to the fuel channels, and
things of that nature. So that was considered in
VIP 06.
I'm not sure that I answered your
question, though.
MEMBER LEITCH: Well, I mean, you talk
about the safety implications of the jet pump, for
example, as being two-thirds core coverage and to
provide a LPCI injection pathway. But is there also
a safety function that's got to remain intact?
Because if you -- if it fractures --
MR. DYLE: Right.
MEMBER LEITCH: -- it could obstruct the
core coolability, could it not?
MR. DYLE: It would be hard for -- from
my limited systems understanding, that if the jet
pump assembly failed that it would block the core
cooling. It could fail in such a way, and this is
one of the issues we dealt with with the jet pump
riser pipe cracking that occurred in '96 or '97 --
and I can show you that when I get to the jet pump.
But if it failed down low where the
inlet flow comes in, and then in combination with a
fatigue failure we lost a riser brace, you could
disassemble the jet pump so then with a recirc LOCA
you have a freeflow path. And you can't maintain
the two-thirds core height, so we addressed it from
that perspective. We tried to look at the impact of
all of those possibilities.
MEMBER LEITCH: Okay.
MR. DYLE: This is probably the most
familiar to you because we've talked here before
about this. And this shows the shroud, and this is
the general numbering scheme. Different plants --
H1, H2, and H3 are generally the same. Some plants
have an H5 weld in here. Some would call this H5
and H6A. So there's different numbering sequences
or schemes that you might see. But, generally, this
is how the shroud is put together.
The bulk of the cracking we've seen is
up in this area, in the high fluence region and up
top. When we did the original shroud safety
assessment, another conservatism -- you can argue
that should you fail here there are no safety
consequences. But we still are requiring
inspections and treating it as if it is.
Similarly, for most of the plants, if
you failed at H2, depending on how the top guide
arrangement is, that could lift -- and unless it
damaged the core spray piping, it is still not a
safety-significant issue, in that you could shut the
plant down and maintain coolable geometry. But
we're requiring inspections all the way through.
The H7 weld was the one of significant
interest early on because it's a dissimilar metal
weld with a backing ring. This is generally the
filled fit-up weld where things were put together.
We've seen some cracking here. The
cracking at H3 is actually in this ring. There's a
lot of structural margin there, and so far we
haven't had too many issues concerning that. The
biggest thing is here when you start evaluating
flaws in this arena, and as the fluence level goes
up, and we restrict ourselves in the allowable
margin, we have to start inspecting more frequently.
So until we have a good handle on what
the crack growth rate is of irradiated stainless,
we're going to have conservative inspection
schedules based on that when we do flaw evaluations.
H8 and H9, we consider these as part of
the shroud support. They're handled in VIP 38, and
that's simply because the shroud support ring was
such a unique beast.
These are code welds, so there's ASME
criteria there. What we've imposed is more
restrictive than what the code has as far as the
quality of the examination. But one thing we did
look at -- and I don't have details on it, but there
is a lot of flaw tolerance in that structure.
We postulated that if you had these
legs, each one of them cracked 50 percent
throughwall, or 50 percent of the legs gone, how
much margin do I need in this weld for structural
liability? And it's 10 percent of the ligament. So
there's a lot of structural margin in there, and the
details of that are in VIP 38.
And then here it shows the jet pump and
the core spray piping arrangement.
MEMBER LEITCH: Isn't there an access
patch in that --
MR. DYLE: Right.
MEMBER LEITCH: -- that has been
troublesome?
MR. DYLE: You're correct. There are
what we call access hole covers.
MEMBER LEITCH: Yes. Yes, that's what
I'm talking about.
MR. DYLE: And in some plants there's
two.
MEMBER LEITCH: Yes.
MR. DYLE: And there are varying
designs. As we went through the generations of the
GE BWRs, they came up with a top -- what they called
a top hat design that eliminated having to weld and
leave a crevice in that Inconel 600 which eliminated
some of the cracking.
But those have been inspected for years.
There has been cracking detected. They've been
removed and replaced with mechanical connections to
replace that. And that's one thing I didn't address
in the flaw evaluation criteria.
Let's say you're going to do a shroud
repair and that requires you to drill a hole in the
shroud to attach some hardware. What we require
people do is to go back and look and say, okay, what
about the leakage if you replaced your access hole
cover? We know you now don't have a leak-tight
joint.
So you have to account for that leakage,
any leakage that might be created with the holes
you'd make in the shroud to attach the hardware, or
down here, and then all of that gets rolled up to
look at what that does to your fuel clad temperature
limits and make sure you've got sufficient cooling
flow. So we've required that as part of the
program, too.
MEMBER LEITCH: Okay.
MR. DYLE: Here is the inspection
history on the shroud, and I think this is some of
the information that you were wanting. We've got
significant cracking at horizontal welds, some in
the vertical welds, and this is generally in the
older plants. Less structural significance because
of the nature of it.
There has been a couple of instances
where the shroud repair hardware has been installed
and reinspection has found some degradation in that,
and we've addressed that. We've required
reinspections and built that into what we're doing.
And then there was one plant that had
what we called a ring segment crack, and I guess --
I'll put this back up. In this forging here, as you
go around the circumference there are some places
where these plates were welded together. And when I
say a "ring segment weld," that's the weld that
joins these different ring segments together.
MEMBER FORD: Robin, could you go back
to your previous slide, 40. I'm trying to help
Mario.
CHAIRMAN BONACA: The other one.
MR. DYLE: Okay.
MEMBER FORD: What about the penetration
welds at the bottom of the -- through the --
MR. DYLE: Oh, the CRD welds?
MEMBER FORD: Yes. What would happen
from a safety point of view if there was an
excessive amount of cracking at those penetration
welds? We saw some with a lot of hydrogen water
chemistry -- be a devil's advocate here -- a lot of
hydrogen water chemistry conditions, ECP,
susceptible 182 weld. What would happen from a
safety point of view if you had a lot of cracking
down on those --
MR. DYLE: From the global point of
view, even if you had significant cracking you can
insert the rods, and with a combination of the SLC
and other systems you can shut the reactor down,
maintain it at a coolable situation, and it's not a
safety issue from that perspective. Do we want
that? Absolutely not.
But the bottom head is flaw tolerant,
the low alloy steel is not very susceptible to the
cracking. The studies that we've done looking at
the vessel shows that if I have stress corrosion
cracking -- and I'm going to stress that these are
studies that more knowledgeable people than I have
done -- that the cracking, once it reaches a low
allow steel it just dies out. There is not the
driving mechanism for it.
We have had some instances in the
industry where down in the bottom head we've had
some leaking CRDs that we've been able to repair by
using the rolled repair, where you go in and roll
and expand the joint. And generally what happens is
you have a leak up in the vessel, and it runs
outside of the CRD, and you see the leak. And by
rolling the CRD housing back into the vessel wall
you turn that off.
We also developed, as part of the repair
program, a welded repair for that activity where you
go in and do the same rolling situation to stop the
leak, but then do machining and a reweld, so that
you would structurally replace that weld that's on
the ID. And we've been able to get that approved
through ASME as a code case, so that's available for
use, too.
You can eject the rods. We've looked at
the possibility of failing and ejecting, the
likelihood of growing 360 degrees and losing that.
It's not going to happen. It's going to be
restrained above the core plate, as long as you
don't disconnect the connection. Because if it
tried to drop out, it would catch on the top guide.
It can only drop a half an inch as long as this
whole assembly stays together.
So there's a lot of reasons that we
don't believe that's a significant issue, but we
still do inspections to address that.
And with hydrogen water chemistry, we've
shown that we can get adequate protection down in
the bottom head.
MEMBER FORD: Has there been a lot of
inspections?
MR. DYLE: There's been very limited
inspections. That's one of the areas where we're
struggling and we're trying to get people, you know,
as they have access, go do inspections, find out
what's going on. Those few plants that have done it
have not found problems, other than the limited
leakage at Nine Mile 1.
MR. CARPENTER: But the staff is
encouraging expanded inspections in those areas.
MEMBER LEITCH: There's a lot of other
stuff down there besides CRDs. Have you taken a
look at, like, instrument connections, core plate
Delta P, lower head connections?
MR. DYLE: We did look at that from --
and the SLC -- as you're probably aware, the SLC and
the core plate delta P are an integral unit.
MEMBER LEITCH: Right.
MR. DYLE: The studies we've looked at
shows that if the SLC line was to crack and fail any
place, we could still get the borated solution in
the bottom head and shut the reactor down. It'll
perform its function even if it cracks throughwall.
The only way we could envision ever
having a problem with the line was if you had a
seismic event that might collapse the line, and
we've looked at that. In fact, that was a question
that came out of this group in '95 that we answered,
you know, to go look at that and show that we could
get the adequate mixing in the bottom head.
The core plate delta P, if that line
fails you have an instant recognition of it by the
operator because they've lost the core plate delta
P, which says what happened, and they can take, you
know, action to try to figure out what has occurred
there.
We've got the LPRMs, and those
insertions there included in the -- what we call the
bottom head, or the lower plenum I&E document is the
correct name. So we've addressed all of those
penetrations and locations in that document and
prescribed --
MEMBER LEITCH: SRMs and IRMs as well?
MR. DYLE: Correct. They're in there,
the dry tube, and look at all the pressure boundary
issues.
Do you remember the number? I don't
remember the number on that one.
MR. CARPENTER: 48.
MR. DYLE: 48. Okay.
MR. CARPENTER: I'm sorry. 47.
MR. DYLE: 47?
MR. CARPENTER: 47.
MR. DYLE: 47. There's the shroud
history.
This is a busy slide, and I -- I guess I
wasn't going to put a whole lot of time on this, but
it gives you an idea. When a shroud cracking
occurred, what we did was go through and look at all
of the shrouds and break them up based on what their
materials were, how long they had been operating,
and what their initial five-year -- their first five
years of operation what the conductivity was.
And we classified the plants as A, B,
and C, and the staff agreed to that. And this went
from least likely to crack to most likely to crack.
Eventually, every plant will go from A to B. We
hope using mitigated technologies that no more Bs
move to Cs, and that means it doesn't see cracking.
The next slide says, "Here's how you
decide for a category B shroud to do inspections,"
and you're probably better off looking at your
handout. But you go do the inspections as specified
for H3 and H4, you've got to do one of those, H5,
and H7. Is the cracking less than 10 percent of the
inspected length?
And if the answer is yes, then we have
to do -- you have to do more inspections. If the --
you know, you've got to make sure you've got enough
coverage, and then you can decide what to do. If
the question -- if the answer is no, you've got to
make it a category C and expand scope and look at
more welds. So we have some conservative criteria
for those plants.
And then, this next chart is similar.
It says, "Here is how you deal with the category C
shroud." And one of the first things is, and it
goes back to the discussion we had earlier about
uninspected length. Is the inspected length of the
weld greater than 50 percent of the length of the
weld? In other words, did I get more than 50
percent coverage?
And if the answer is no, I've got to go
do some other things to make sure that what I'm
doing is acceptable. If the answer is yes, then we
had a treatment of that. So we're trying to require
minimum coverage, and if you didn't get that you had
to do a lot more.
Similarly, there is criteria for doing
the vertical weld inspections. You know, how much
cracking do you find? And make decisions based on
that. And, you know, I've just showed you three
slides that summarize what's in 40 pages of a
document. So it's -- I'm not sure that I gave it
fair treatment, but that's how we set this program
up.
And like I said, we've done a lot of
shroud inspections and are staying on top of that.
There's more inspection requirements for the
vertical welds, which we've changed and added more
to. And, again, is the vertical weld free of crack
indentations? Yes. Then we have an inspection
period. No. And then you work yourself through how
much of it is, how much do you inspect, and what's
the appropriate evaluations to perform.
All of this -- I should say, when we
talked about the flaw evaluations, we applied code
margins, so this is not -- we've got code margins in
there on upset loads and things of that. So when we
say yes or no, it's safe, that includes the margins
that ASME would put on its normal components.
And then we set the reinspection
intervals based on the amount of cracking found also
using the stress that would be applied at that weld.
And then we also accounted for fluence to the degree
that low fluence plants can use limit load only. As
fluence increases, we require people to use LEFM to
evaluate their flaw carrying capability. And that's
indicated in the notes at the bottom of that page.
Bob, speak up if I leave something out
on this. Again, this is a summary of the flaw
evaluation for the shroud. It depends on the
fluence. At the end of the evaluation period -- and
what we mean by that is is if I find a flaw today, I
don't look at the fluence that that component is
going to experience today.
I look at the fluence for the period of
time I expect to operate. So if I want to operate
six years, I have to estimate out what the fluence
will be then and then put that number in and do the
calculation on the flaw tolerance.
Use limit load for ductile behavior,
LEFM and elastic-plastic for the less ductile
behavior. And this is the code that I talked about,
the distributed ligament length code. It's been
updated a couple of times. You can also use this
for LPCI, for core spray in the nature of the code.
And the last item on the shroud, here is
the status of the review. And I -- I think this is
accurate. And, again, VIP 01 was the initial, 07
was the reinspection, 63 was the vertical welds, and
we've rolled all of those into VIP 76, submitted
that, and it has a license renewal appendix. So
that's one, once it's reviewed and approved, that'll
include the license renewal aspects.
Any questions on the shroud?
CHAIRMAN BONACA: I have a question
regarding timing. How much time do you think you
still need? Is this part of the rest of the
presentation? The agenda shows a full presentation
later on provided by you of half an hour each.
MR. CARPENTER: Yes, sir. And I will
not need a half hour each. So --
CHAIRMAN BONACA: Okay. So, because
this is part of that.
MR. CARPENTER: Right.
CHAIRMAN BONACA: So maybe we should
take a break now, and then continue the presentation
later?
MR. DYLE: If you'd like. I have three
more components to discuss like I did the shroud,
so --
CHAIRMAN BONACA: So you need at least
half an hour to go through it.
MR. DYLE: At least a half an hour. But
then I believe that's -- what I tried to do was give
a description of the program, so that when the staff
talked about what they've done with it it makes
sense.
CHAIRMAN BONACA: So why don't we take a
break now and meet again at 10 of 3:00.
MR. DYLE: Okay.
CHAIRMAN BONACA: Okay? Good.
(Whereupon, the proceedings in the
foregoing matter went off the record at
2:35 p.m. and went back on the record at
2:51 p.m.)
CHAIRMAN BONACA: We are resuming the
meeting now, and continuing with the presentation.
MR. DYLE: Okay. The next component --
we're on page 50 of the handout -- is the jet pump
assembly, and this is -- we've had some questions on
this. What we've got -- and this is a sketch that
comes out of VIP 41, which is the document. The
numbers that you see next to each one of these
locations are individual numbers and paragraphs that
we have a discussion in the VIP document, and the
appropriate need to inspect or not inspect,
depending on the materials.
We have these different -- there's
different configurations on how these rings are
attached to the shroud support. It sometimes seems
that our designer was trying to find a unique
version for everything they built, because we have
quite a few configurations here.
The jet pump sensing lines which measure
the jet pump pressures and performance, we take
those lines out. That's one of the ways we do
surveillance, by seeing if we have the jet pump
operating properly.
You have the jet pump inlet that comes
in here, goes up, goes through what we call the
ram's head. You have the jet pump hold-down beam.
We've had failures there. We've had cracking,
different types. If you look at VIP 41, there's a
discussion of those.
And then, we accelerate the fluid
through, and then we have the nozzle here that
allows the fluid from the annulus to be sucked in
and then taken to the bottom head. So that's how
the jet pump works, and we've got a detailed
discussion of that in the document.
As you ask about what's the inspection
history, we've had indications on the hold-down
beams. We had at least one plant where the hold-
down beam failed, and that ram's head that I was
talking about came off, and then they were able to
detect that because when they look at the jet pump
sensing lines it shows no flow through there. They
understand that there's a problem. They bring the
unit down and then do the appropriate repairs.
Riser brace welds -- we've had some
cracking there. Riser pipe welds -- we had
discussed that earlier, and that is actually where
this riser pipe comes into the nozzle and is welded.
We had cracking down in that region that we've
inspected and found and dealt with.
Riser brace-to-yolk welds, wear at the
set screws, and one of the things we do, you can
look at the set screws and wedges where these
brackets attach. And if you see evidence of wear on
the wedges, like the jet pump has been moving, then
we understand that there may be a fatigue issue that
you can expand scope and do inspections from that
perspective.
For the jet pump, all welds were ranked
based on safety significance. And hindsight being
what it is, we might have done away with medium and
low, because if you look at our document -- and I've
got some discussion of that -- but in the VIP 41,
the medium and low get the same inspection criteria,
and that was to be conservative.
Although we could have argued less
inspections for the low priorities, we did something
different. But the way we classified these were
high was any location that if it cracked it could
create an immediate failure, and the jet pump would
come apart. That had to be inspected quickly. We
wanted those, and we set the baseline appropriately.
Medium, it could crack and eventually
lead to a jet pump disassembly, but it was a long
period of time. And then, low, there was really no
significance to the cracking, but there was some
reasons to go look.
MEMBER LEITCH: In the document, it says
that low may be -- excuse me -- low right now is
treated as medium.
MR. DYLE: Right.
MEMBER LEITCH: But in the future, it
may be reevaluated.
MR. DYLE: Right.
MEMBER LEITCH: Could you say what would
be the criteria for that reevaluation?
MR. DYLE: Well, one of the criteria
would be is if we go through and do -- the fleet has
done a series of inspections, and over the next 10
or 12 years we find no evidence of indications in it
or the mediums, and we better understand how the
materials behave, we may change those inspections to
a sampling. We may eliminate some of them,
depending on the materials.
By the same token, if we start to see
more indications than we expected, we may change and
make it more frequent.
MEMBER LEITCH: That's one of the
questions I had. The inspection frequency seems to
be based upon safety significance.
MR. DYLE: Right.
MEMBER LEITCH: Rather than operating
history. Is operating history factored in? In
other words, if you have something that's low safety
significance, but there's been a significant number
of problems with it, does it ever get to be high?
MR. DYLE: It may not be high from a
safety perspective, but we would inspect it more
often.
MEMBER LEITCH: I mean, from an
inspection frequency.
MR. DYLE: From an inspection
standpoint, we would upgrade that and do the
inspections more frequently if that was warranted,
because we want the plants to operate. We want the
plants safe. And if we did that, then we bring the
document back to the staff for their review and
approval. So --
MEMBER LEITCH: So the categories high,
medium, and low are really safety significance.
MR. DYLE: Safety significance.
MEMBER LEITCH: But the operating -- but
the inspection frequency may be biased depending
upon operating history.
MR. DYLE: Right. Operating history and
safety significance combined. And what we think
we've done -- and the staff has agreed with us -- is
that by accelerating these high locations, they are
precursors, if you will, they're more serious if
they should crack, and then the same materials, and
they're in the same general environment in the
annulus, so they should give us some indication how
the rest of the assembly would perform.
MEMBER LEITCH: Yes. Right.
MR. DYLE: So we're kind of building on
the totality of the program. And part of what we
argued to ourselves was is I've got -- you know,
I've got 10 of these jet pumps, 20 pipes, 35 plants.
Over six years I'm going to have a lot of inspection
data to let me evaluate what's going on.
MEMBER LEITCH: Right.
MR. DYLE: And we believe that's
conservative.
MEMBER LEITCH: Okay.
MR. DYLE: And this is -- to your
question, this is the inspection flow chart on how
you would do this. If the component is high safety
significance, inspect 100 percent of the population
in the next inspection cycle, which is defined as
six years. So for a plant that's on two-year
cycles, over three outages I'll inspect all of
those, with at least half of them to be inspected
the first outage that you implement this document.
So right up front we're wanting to get
information on those quickly and try to understand
what's going on. If you have flaws, you expand
scope and do everything in that outage. If you have
no flaws, then you use the reinspection frequency
that we specified.
For the medium and low, you come down
this path, and here's the inspection scope that's
set up. Because they are less significant, we allow
more time. But, then again, depending on what
happens here, it may affect what we do with these
other components. So we would move back and forth.
And then here's the reinspection
frequency that's contained for the jet pump. We
require more inspections on high inspections, so you
inspect 50 percent of the population the next
inspection cycle. So the first inspection cycle you
do the whole population. The next six years you do
at least half of them from a sample perspective.
And you do 25 percent of the medium and
lows, and that's consistent with the sampling
process that the code uses.
MEMBER LEITCH: These thermal sleeve
welds that are inaccessible on the -- associated
with the jet pumps. It seems as though there's an
open issue there. Can you comment on what work is
being done to resolve that? Is there no inspection
technique available for those --
MR. DYLE: There is not yet one proven,
but that's being worked on. And you're talking
about where this riser attaches down in the nozzle?
MEMBER LEITCH: Right. Yes.
MR. DYLE: We're doing the inspections
of all of those that we can see and get access to.
And that gives us some indication of how well that's
performing. For several years, some of the plants
did what we call the -- the acronym we used was
RENSA weld examinations, where we actually looked at
where the thermal sleeve was attached to the nozzle
from the OD of the nozzle.
And what you did was ultrasonically look
through. But what that really characterizes is
whether you have a bond there, or whether you have a
crack that might be propagating out of that weld
into the safe end of the nozzle. But it wouldn't
look at anything below there because you couldn't
get the sound in and back out from an inspection
standpoint.
And those examinations have resulted in
no problems to date. That's one of those that was
never required by the code or anything else, but the
owners did that. And I know we've got a lot of
inspection data for Hatch that we looked at for
years doing that. But, again, that doesn't get at
the thermal sleeve itself. It looks at the weld and
then the nozzle, and that's the best effort that you
can do right now.
MEMBER LEITCH: Yes. Okay. Thanks.
MEMBER FORD: Robin, could I follow up
on that particular point that Graham brought up?
How should -- we had a similar question this morning
about containment, corrosion -- inaccessible parts
of the containment. What you're saying is if you
don't see a crack in the areas that you can inspect,
then there's a likelihood that you won't see -- that
there are not cracks in an area that you cannot see.
How sound a reasoning is that?
MR. DYLE: Well, to some degree, it's
the best we can do with the technology we have. So
we're requiring inspections of everything we can get
at and try to reach conclusions, because the
materials are similar and the environment is
similar.
MEMBER FORD: But the stress may not be.
MR. DYLE: But the stress may not be.
The other thing is -- and this is where the
monitoring comes into play again -- we're requiring
this jet pump monitoring of performance. And if
that weld were to crack to the degree that it would
leak and degrade the flow, or affect the performance
or completely go throughwall, then this jet pump no
longer operates. You do your daily surveillance and
it says, "I don't have flow in that jet pump. I've
got a problem."
MEMBER FORD: So your risk assessment,
though, for any part, you would go through that kind
of risk -- the impact of that was assumptions you
are making.
MR. DYLE: Yes. The document where we
looked at that is VIP 28. When we looked at -- when
we looked at the impact of cracking at the weld just
outside of that one that's -- and what we found
there is that you have IGSCC might start. And then
later fatigue takes over and the flaw would grow.
And the window in which you have the
opportunity that you'd have insufficient ligament to
carry the load should I have an accident, which it
really creates the problem, versus the thing
separating and then I'm able to detect that the jet
pump is not operating, was a matter of a few days.
And when you looked at the risk assessment from that
perspective, it was a very low number.
I don't remember what the number was,
but that was -- we did that in '97, '98, somewhere
in that timeframe. And the staff has reviewed that
and approved that as a JCO for everybody to continue
to operate until we started doing more of these
inspections. So that's been considered from a risk
perspective.
Flaw evaluation is just simply we use
the limit load techniques, and the DLL code that I
discussed earlier could be used for this component
as well. And the current status is we've gotten a
safety evaluation from the staff in February of this
year, and there are some guidelines that need to be
revised based on the comments they've made. And
we've discussed those. We understand what they
want, and we're in the process of doing an update to
incorporate that information.
And I guess this is an example of --
someone asked earlier, and I don't remember who --
about how we implement a document. We would expect
the owners to continue to implement VIP 41 as we
wrote it until such time as we update the document
to reflect the safety evaluation, and then that's
how they would implement it. So that's the
agreement we have.
The next item is the top guide. There
is -- just looking down on it, and here's the side
view of it, so you can see that configuration.
That's typical for the 2s through the 5s. The BWR 6
has got a slightly different configuration.
I believe, Dr. Bonaca, you were talking
about these pins here. These are aligner pins that
you set the top guide down on. It aligns it and
holds it in place, and we've evaluated what's the
consequences of failures of these, can the thing
move or not, and what's the appropriate inspections.
And there are different configurations of those.
Another one is the hold-down assembly.
You have to study -- every time I look at this, I
have to stop and look at it again to try to figure
out what all we've got captured here. But this is
the BWR 2 through 4 hold-down device. This is the
5. This is the 6. So there are some differences.
And, again, you can look at the failure of this
component and say, "If all of these failed, will the
top guide lift? Can it move? Can it not?" And
that lets you set whether you need to inspect this
top guide hold-down device or not.
Rim welds on the top guide -- and,
again, this is just to give you an idea of the
technical detail that's in these documents. I don't
know to what degree you've had the opportunity to
review them. But we've got -- here's the
fabrication weld on the top plate here, and then
you've got the rim weld that would be in this
structure.
And different ways to hold the core
plate down -- the plate down on this rim and how it
sits on the bottom plate, and then this is set down
at the H5 weld region. Excuse me, this is up at the
H2 and H3.
I mentioned that the BWR 6 has a
slightly different configuration, and this you can
see -- we've got it shown here, so you can see how
the H1 and H2 shroud welds are in relation to that.
And it's a slightly different configuration, and
it's shorter.
The inspection history and what we've
seen to date, there has been a lot of VT-1s and VT-
3s. And using VIP 26, there were previous GE SILs
that were used, and we did inspections in relation
to that.
And I guess this is a good place to make
the comment, one of the things the VIP program did
is we went back and revisited all of the individual
SILs for a given component. If they were safety-
related, we made sure we incorporated either those
requirements or new requirements into the VIP
document and replaced the safety-related SILs.
For those SILs that were not safety-
related, but were suggestions that owners might
consider, we didn't try to address that, and we left
it to the owners to choose what of those they wanted
to use. So that's what we've done.
As I mentioned earlier, Oyster Creek has
got indications in the top guide. We have removed
those samples. We've looked at them. We've looked
to see if they were weld repairs.
We've also taken those samples and put
them in what we call the CIR, which is a program
looking at cracking and irradiated stainless, and
we're assessing the degree -- it appears that these
flaws would be IASCC. We haven't determined that
yet, but that's one of the things we're going to
look at.
And then, based on the results of that
metallurgical review, see if there's anything else
we need to do. But to date, that's the only plant
that's had that problem.
There's rim weld cracking and it
oversees non-GE BWR, and I think that was in non-
stabilized 347, if I remember right. That was --
MEMBER SHACK: There's no such
statement.
MR. DYLE: That was the problem.
(Laughter.)
It was supposed to be 347, and the
metallurgical results indicated it may not have
been. But we have limited access to some of that
information, so I -- you know, I wouldn't take that
to the bank. That's --
MEMBER SHACK: Now, the Swedes replaced
the top guide, right? But they did that without any
indications?
MR. DYLE: There were some that replaced
all that -- they have the removable internals.
They're not welded in place. They were bolted, so
they could remove them. So it's a different design.
MEMBER LEITCH: Talking about SILs there
just a minute, there is a statement in VIP 41
concerning the jet pumps on Roman numeral XI, the
executive summary. It says that the -- basically,
that if you use this, you can -- that the VIP --
these guidelines can be followed in place of prior
GE SILs related to safety to assure the essential
safety functions of the jet pump.
MR. DYLE: Correct.
MEMBER LEITCH: It seems to me that's
too sweeping a statement. There's some SILs that
tell you how to read and interpret jet pump
instrumentation, and recommend actions to do this.
This would seem to say "forget all that."
MR. DYLE: No. If that's what it says
to you, then we need to take a note to look at that,
because what we mean by that is any inspection of
the assembly itself we've replaced those
inspections. We've either incorporated them into
VIP 41 or replaced them with what we think is newer
and more conservative or more appropriate
inspections.
The monitoring of the jet pump
performance is still required.
MEMBER LEITCH: Okay.
MR. DYLE: And we would --
MEMBER LEITCH: You have another note
back on page 3-2 that says it more clearly, but I
just think this statement here taken at face value
is a little too broad.
MR. DYLE: And that's in the executive
summary?
MEMBER LEITCH: Executive summary, Roman
numeral XI, about the middle of the page.
MR. DYLE: Okay. Thank you.
Bob, we need to -- we'll just take a
note to make that more clean.
MEMBER LEITCH: Yes. Thank you.
MR. DYLE: I appreciate that. Thank
you.
And, you know, we think we did a real
good job with these things, but obviously we're
going to have things like that where we could have
been more clear, and somebody reviewing it anew and
looking at it from a different perspective. We've
had some of that with the staff interactions.
What did you mean? We thought we knew
what we meant, and they said, "What did you mean?"
This is just an example of the table,
and I -- we've gone a long time, and I don't want to
bore you to tears, but here are some of the examples
where from a table you have the location identified,
a description of it, what's applicability, which
plant. For example, the grid beam, location 1 is
applicable to 2 through 5s. Whereas, the aligner
pins at locations 2 and 3, if you go back to the
figure in the document, would only apply to the BWR
2.
And then there's a discussion of the
results of the structure, what happens if it fails,
and then based on that what inspection should be
done. And there are several pages of this that
would allow you to go through and make the decisions
for your plant, for your configuration, for your
operating condition, what inspections are
appropriate.
MEMBER SHACK: When I was looking
through this, and I look at the staff RAIs on this
-- you know, there's one, for example, that comments
that VT-1 really can't see stress corrosion cracks
very well, and you would have to look at an enhanced
VT-1. And I didn't see a response to that.
Now, is, in fact, in -- do you use
enhanced VT-1 here? Or --
MR. DYLE: What we said we would do --
this was several years ago, and it's a general
policy -- we've had this discussion with the staff
that we need to -- there's been discussions like
this that went on over time and were pointed out.
The approach that we were going to use
is any place that we were looking for tight IGSCC
type flaws we would use EVT-1, because we understood
that was the right mechanism to use. It was that
logic that said we'll do away with the MVT or the
CSVT-1. So if we're not looking for tight flaws, if
we're looking for like a fatigue failure that might
be more readily visible with the VT-1, we could use
that. But for tight IGSCC type flaws we were going
to require that to be updated for everything.
MEMBER SHACK: I saw that statement, but
then it wasn't clear whether we considered this an
EVT-1 or a VT-1.
MR. DYLE: Well, we will --
MEMBER SHACK: Everywhere it says VT-1
--
MR. DYLE: Every place -- our commitment
was every place that we're looking for IGSCC flaws
we're going to bring it up to EVT-1.
MEMBER SHACK: Even if the document
doesn't say that.
MR. DYLE: Because we've got to go back
and revise these documents. The process for this
will be once the staff has issued a safety
evaluation that we agree with, then we will revise
the document to incorporate all of those comments
and other enhancements that we've seen that have
been necessary, like the comment that was just made.
We will then provide that to the staff
and let them see that we've incorporated those
changes, and make sure we've done what we said we
would do and let them buy into that. And then we
would issue this document again with an A on it, and
it would mean it's an approved topical, and it would
include the safety evaluations and all of the
reviews.
So that's the process, and that's the
next step in the process with the staff, that over
the next year or so -- Bob?
MR. CARTER: Yes. That one is hard to
trace. And we addressed that particular issue in
response to --
CHAIRMAN BONACA: Would you use the
microphone, please?
MR. CARTER: Oh, certainly. We
addressed that particular response or that
particular issue in the response to the core spray
I&E document, where we had originally some -- maybe
not as stringent visual techniques. And we -- in
the response back to the staff on that, we committed
to perform EVT-1 for detection of IGSCC.
MEMBER SHACK: Yes. I guess we got --
it was -- you had the general statement in the
letter that Robin just made, that when you were
looking for tight, you know, SCC cracks you were
going to use EVT-1. Some of the inspection
guidelines actually call out EVT-1, and some of them
still call VT-1 in situations where it's clear to me
you're looking to address SCC. And all you're
really saying is that those just haven't been --
MR. DYLE: Yes, that's a timing issue.
We made that commitment in response to core spray
after this document was already published. So we
wouldn't have revised the document just to fix that.
That's just one of the changes we understand we have
to make and bring forward in the final approved
version.
There's three more pages of the top
guide inspections, and unless you have specific
questions I'll go ahead, for time's sake, and skip
over that.
MEMBER SHACK: Now that you've put this
in the public domain, can we remove the non-
proprietary from the non-proprietary version of it?
MR. DYLE: Now that I've put what? That
portion of the table?
MEMBER SHACK: This table is
proprietary.
MR. DYLE: Well, it's available for
public today, that portion of it. We have non-
proprietary versions of all these documents
available, because we had to do that --
MEMBER SHACK: Right. This isn't
included in the non-proprietary version.
MR. DYLE: Yes. And that's something
that we constantly have to discuss and consider.
It's in here. It's in the public. We're not going
to make the whole document non-proprietary, no,
because -- well, I'll leave it at that. I'll let
the lawyers discuss it.
Flaw evaluation criteria for the top
guide -- we've got considerations for the grid beams
where you use LEFM to look at that, and there's
equations given in the appendix. This is one of
those where it was a unique component. We developed
the equations and gave them to the licensees. The
staff has reviewed them.
For other locations along the rim, or
other things, you would use different methods. And
we would use the stress analysis to determine the
acceptability of it.
And here is the status of the review. I
guess, Bill, to your comment, if you look at the SE
data, it was in September of '99. So that was an
earlier document that had been submitted.
We're going to have an accelerated
program this year to try to get these things brought
up to date.
That's all I was going to discuss on the
internals. The last item that I have been asked to
discuss was what we're doing with the IGSCC and
piping, just because the VIP had done this, and
that's what the next several slides are about.
We labeled it BWRVIP 75. That's where
the documentation is contained.
Yes, Bill?
MEMBER SHACK: Just one -- your
evaluation really looks at the cracking of the
single beam. I mean, this looks to me like a highly
redundant structure. If I broke one beam --
MR. DYLE: Absolutely.
MEMBER SHACK: -- nothing is going to --
have you ever gone through a -- you know, how much
would you really have to bust this thing up so that
things could really begin to move?
MR. DYLE: We had some finite element
studies that looked at some of that initially, and
the numbers were rather large. And depending on
what the seismic loads were, what the different --
the specific plant configuration was, and everything
else, it was hard to get your arms around and figure
out what you put generically.
So we require the inspections, and then
on a plant-specific basis you would look at your
flaws for your plant.
Bob?
MR. CARTER: I couldn't say it any
better, really. Just the myriad of different loads,
different design configurations, made it difficult
to say, "What's the absolute minimum?" you know, so
we didn't -- we didn't try to take that approach.
MR. DYLE: Some of this stuff you all
could present better than I could. You know the
history better than I do.
But for the BWR piping, in the '60s we
had some scattered incidents of IGSCC. In the '70s,
we had the small diameter crack, pipe cracking,
particularly in the bypass lines around the valves,
that the industry started dealing with.
And I remember reading statements of
large bore piping will never crack. Well, in the
1970s, large diameter piping cracked, and we've been
dealing with it ever since.
In response to that, there was a
concerted effort among the industry, the old BWR
Owners Group pipe cracking initiative, and the staff
worked for years -- Warren Hazelton and others --
developed Generic Letter 88-01 and NUREG-0313 to
address the cracking issues. And that has been in
place for years. What VIP 75 does is revisit that.
As I said, there was the owners group
activities, BWROG-1 that lasted here, and then 2
through 88. A lot of plants did different things.
Some replaced all of their piping. Some replaced
parts of them, different sections. Some did local
repairs and then did inspections more frequently,
because what was going on in this arena was still
under development.
Mitigation people used HWC early and did
augmented inspections. In the end, 0313 was the
technical basis document that was issued by Generic
Letter 88-01. And that's been in place since then.
These categories remain today, and I
will say that we didn't -- we didn't do anything
with these in VIP 75. We just accepted the
categories for what they were and addressed
inspection criteria. But this is how the NUREG
categorized things from resistant material that was
pristine, pure, to stuff that hadn't been served
very long and that was stress-improved, to longer
service stress-improved, no stress improvement, non-
resistant, and so forth. So those are the
categories that have been in place actually since
before '88.
And here's the control strategies that
we use. We try to detect the IGSCC before the
damage compromises system integrity. Obviously,
that's what you want as a regulatory body. That's
what we want so we can operate the plant.
Remove the defects if you can. We try
to do that, because we don't want that to be a
problem. We prevent initiation by introducing
resistant material. Again, do the replacement, use
L grade piping. Some of it is 316NG.
The structural integrity -- we've got to
make sure that that's there. That's just it.
That's all we're going to do. In some cases, we've
used weld overlays to reinforce the material. The
weld overlays also help mitigate the cracking by
putting compressive stresses on the ID.
This other -- modifying the residual
stress distribution, it can also be done by using
stress improvement processes, whether it's IHSI,
which is induction heating stress improvement, or
MSIP, which is mechanical stress improvement.
And then the last item is to use the
mitigation technologies of water chemistry to slow
things down.
If you think back to that slide I had
earlier about the capacity factor losses, that was a
problem in '84. But things have been effective to
slow that down, and that's no longer really an
issue. We've been really effective as an industry
to be able to eliminate the problem.
However, continuing to do inspections
creates a dose problem, particularly in those plants
that use hydrogen water chemistry. Something about
the nature of that process causes the dose to go up,
and that's about all I can say about it from a
technology standpoint. We understand that's an
issue.
So that was one of the concerns that we
had. We're really saturating people with dose to do
inspections.
What the VIP tried to do was we went
back and looked at all of the categories and tried
to figure out what would be appropriate. We looked
at the service experience. We looked at the
deterministic evaluations to evaluate performance.
We looked at inspection results, how effective
hydrogen water chemistry has been, how effect IHSI
and MSIP have been.
BWRVIP 61 is a document that discusses
in detail IHSI and the industry survey that we did.
And then we looked at the crack growth studies.
We've developed VIP 14 and other documents and said,
"What do we know now about crack growth?"
And we did use some generic risk-
informed studies. We didn't do a risk assessment,
but the different plants that have done risk-
informed ISI, and some of the pilot studies that
were done to develop these code cases, we looked at
those and tried to learn from them, and said, "Based
on those insights, what makes sense? What is the
right thing to do as we go forward?"
So we tried to incorporate all of that.
And here's I guess the crux of what we've done, is
these are the proposed inspection frequencies in 75
for normal water chemistry and for hydrogen water
chemistry. And I guess I should also say for normal
water chemistry what that is today is far superior
to what it was, you know, 15 years ago.
The conductivity has been maintained
very low. I think the staff evaluation was that the
average conductivity for the fleet is .15
microsiemens. ECPs are being managed. We're
keeping things under good control.
So even normal water chemistry is far
better than what it was. And then, the use of
hydrogen water chemistry would include use of noble
metal. For the purposes of this document, we
considered effective HWC, either hydrogen alone or
hydrogen and the catalyst noble metal.
Obviously, without noble metal, we have
to inject greater rates, greater amounts of hydrogen
to be effective. But we've come up with tools to
evaluate that.
So those are the revisions to the
inspection frequencies that we think are appropriate
based on inspection history and the way things are
performing.
The status of VIP 75 -- you know, we
think that the countermeasures that the NRC
required, and the things that have been implemented,
have been effective. And we think the inspection
experience over the last 12 or 13 years shows that.
Some of these welds have been examined
four or five times since 1988, because of the
original criteria and the rate that they were
required to be inspected.
We think there is -- that a revision to
NUREG-0313 or the generic letter was warranted. We
put that in VIP 75. And we've got some open items
the staff has in the safety evaluation that we're
working on resolution of. One of them is tied back
to VIP 62, which I discussed earlier.
What is the appropriate level that you
must reach with your hydrogen injection and your
water chemistry parameters to have an effective
water chemistry program? So we're working on that.
And I guess this is what you all would
like to see -- me conclude.
(Laughter.)
Not my conclusions, but just for me to
conclude.
We think that at the direction of our
executives, in response to a problem we had, that we
took ownership of our problem, we developed a
technically sound program that's broad in scope, and
sufficiently in-depth technically to address the
concerns of the BWR internals and the associated
programs.
We think we have the appropriate
elements in regard to what we inspect, how often we
inspect, how often we reinspect, the methods that we
use, how we evaluate the flaws, the repair
methodologies that we would use, the mitigated
technologies that we can use to minimize the effect
of IGSCC.
And all of that, because we did this for
current term and renewal term to try to address all
known degradation mechanisms, we think it's
appropriate for use for license renewal and have
provided it to the staff as such and have gotten
safety evaluations for it.
So that's -- that concludes the overview
of the program and a description. And unless you
have other questions, I would turn it back over to
Mr. Carpenter.
MEMBER SHACK: You're proposing to go to
10 percent every 10 years, which is like what the
risk-informed people do, except you want to do it
without actually doing the risk-informed analysis?
MR. DYLE: We don't do the detailed
risk-informed analysis, but what we learned from the
risk study is that the real locations of concern
were on ECCS, where you had the potential for
geometric discontinuities or dissimilar metal welds.
So we put in VIP 75 that you select
those locations, and that you also select the
locations in the piping that would be problematic,
such as the piping between the dry weld and the
outboard isolation valve. Because from a risk
perspective, if you have a failure there, it's
harder to mitigate that. So we said you are going
to go look at those.
So we looked at those generic risk
studies and put some deterministic criteria in for
how to select the welds and addressed it from that
perspective.
Any other questions? Thank you.
MEMBER SHACK: Thank you.
MR. CARPENTER: Okay. Now that Robin
has given a fairly comprehensive overview, I'll
continue on with what the staff has found out or has
come to.
We have completed a review of almost all
of the BWRVIP reports to date. There are only a few
more that are left, and we are looking at those.
And, basically, what we've concluded is that
implementation of the BWRVIP guidelines, as modified
to address the staff's comments in our various SEs,
will provide an acceptable level of quality for
inspection of flaw evaluation of the subject safety-
related components.
And it should be stressed once more that
the vast majority of the BWRVIP program deals with
components that are outside the scope of the
regulatory required inspections. So this is a
voluntary program that is looking at more than what
the staff has presently required.
We've also done -- and this goes back to
an earlier question by the ACRS -- an independent
review by the Office of Research -- that's NUREG-CR-
6677 -- and has found that the BWRVIP program and
other such comprehensive inspection programs will
significantly reduce core damage frequency. And
that's one that I'll provide you a copy with a
little bit later.
CHAIRMAN BONACA: Reduce with respect to
what?
MR. CARPENTER: I'm sorry?
CHAIRMAN BONACA: Reduces it with
respect to what? I mean --
MR. CARPENTER: In respect to not having
such a program. If you merely did the required
inspections that are required by the rules and
regulations that the NRC has --
CHAIRMAN BONACA: But it doesn't reduce
with respect to the current results of the IPEs. I
mean, they don't assume this kind of failure rates.
MR. CARPENTER: That is correct.
CHAIRMAN BONACA: Okay.
MR. CARPENTER: If you go in and you do
this, you can find things much before you would
otherwise.
MEMBER SHACK: This is the PNNL,
essentially, risk-informed inspection kind of
document. Is that what we're talking about here?
MR. CARPENTER: INEL. Right. And I
will provide some copies to you a little bit later.
What we've done with the generic aging
management plans of the BWRVIP, we are completing
the reviews of the various license renewal
appendices for the 12 reports that we're looking at.
And what we are finding is that by
referencing the BWRVIP aging management programs and
completing the action items that are in the staff's
SEs for each one of those, that there will be
reasonable assurance that the applicant will
adequately manage aging effects during the extended
operating period.
And generic AMPs usage will
significantly reduce staff review of license renewal
applications, and that's one of the things that --
one of the benefits to the staff.
Robin mentioned that they've spent over
$30 million on this program. The BWRVIP has told us
in public meetings that by some of the inspections
that they are doing they are looking to save
somewhere in the neighborhood of about $100 million
in inspections. This is saving staff resources, so
it's a win-win for both sides.
Just to go back over real quickly again
the various I&E documents -- the core spray
internals, the core blade top guide, standby liquid
control (SLC), shroud supports. You've also got the
VIP 41, which we'll be talking about here in a
moment, 42, LPCI, the lower plenum guidelines,
vessel ID attachments, the penetration guidelines.
And the reason why I'm telling you this,
again, is just to reinforce that this is a fairly
comprehensive program that we've been looking at.
BWRVIP 74 report, which is the BWR
reactor pressure vessel one, is one that the ACRS
has basically looked at before because we came to
you a few years ago and talked to you about the
BWRVIP 05 report, which was the shell weld
inspections. And that has been subsumed by the 74.
76, which is the core shroud I&E
guidelines, which I'll be talking about in a moment
-- as Robin mentioned, it includes the VIP 07 and
the VIP 63 documents.
And we'll also be talking about some of
the additional reports, which is VIP 75, here in a
moment -- which is supported by the BWRVIP 61 on
induction heating stress improvement effectiveness,
and the BWRVIP 78, which is the integrated
surveillance program, which is supported by the '86
report.
There is also a variety of the repair
and replacement design criteria, which we've already
discussed, so I'll just go through this rather
quickly, and also some of the mitigation reports,
which deals with crack growth and how you also
mitigated the VIP 62, which is the hydrogen water
chemistry guidelines.
And then, you've got various other ones
-- the VIP 03, which is the internals examinations,
the 06, which was the safety assessment that dealt
with what was the cracking.
Now, we're reviewing some of the
proposed guidance in VIP 76, and, as I said, it
incorporates in the BWRVIP 07 guidelines, the VIP 63
guidelines. And what it's basically proposing is
that the weld inspection strategy and unrepaired
shrouds, weld inspection strategy and the repaired
shrouds, the inspection and evaluation reporting
requirements, a demonstration of compliance for the
license renewal rule.
And, again, it incorporates 07 and 63,
and right now we are working with the BWRVIP to
resolve some interpretation issues that we found in
the -- between what we said in the 07 document, SE,
and what they understood us to say.
BWRVIP 41, jet pump assemblies. We have
completed the plant-specific reviews. Now we're
completing the license renewal review. And,
basically, what we've seen is that the VIP 41
document has -- provides component descriptions,
functions, describes susceptibility factors --
again, all of the things that Robin went through
earlier.
MEMBER LEITCH: A question about
BWRVIP 41.
MR. CARPENTER: Yes, sir.
MEMBER LEITCH: There's a sentence in
there that puzzles me a little bit. It says, "The
VIP 41 report also contains an Appendix A and
demonstration of compliance with the technical
information requirements of the license renewal
rule."
MR. CARPENTER: Yes, sir.
MEMBER LEITCH: And then it goes on to
say, "Appendix A to the VIP 41 report is not
evaluated in this SE report, but will be evaluated
under a separate license renewal review."
MR. CARPENTER: Yes. What we've done,
basically, with all of the I&E guidelines, which is
what constitutes the aging management program, the
generic aging management program for the BWRVIP, is
the staff has taken in these reports. We've
reviewed them. As necessary, we've issued a request
for additional information, RAIs.
The BWRVIP has responded back to that.
If there are any additional questions, we have
issued an initial SE with open items, which
basically allows licensees to utilize the document
with these -- with plant-specific addressing of
those open items, while we're still completing the
review.
Once the BWRVIP has responded back to
the open items, and we have reached agreement as to
the review, we have issued a final SE, and that
takes care of the present operating term for the
BWRVIP reports. Once that is completed, then we go
in and we take a look at the various license renewal
appendices, which demonstrate how they meet the
license renewal rule, Part 54.
MEMBER LEITCH: Okay.
MR. CARPENTER: And as long as they meet
Part 54 rules, then we issue a third SE, which is
license renewal SE, a generic SE.
MEMBER LEITCH: A generic SE.
MR. CARPENTER: As long as the licensee
is showing that they are in compliance with that,
then we don't need to look at their applications
further.
MEMBER LEITCH: Okay. Okay. Thank you.
MR. CARPENTER: Certainly, sir.
One of the things that we found in the
VIP 41 is that there were instances of cast-off
stainless steel components in the jet pump
assemblies that may be adversely affected by high
fluence levels, and that is going to be looked at in
future reviews. So that's going to be resolved
before the license renewal term begins.
So preventive actions that are also
discussed in these documents -- obviously, you
maintain high water purity. That reduces stress
corrosion cracking, susceptibility. And also,
again, hydrogen water chemistry and noble metal
chemistry additions will reduce it further.
Some of the parameters monitored and
inspected -- the inspection and flaw evaluations
performed in accordance with staff approved
guidelines, and then you go in and, as necessary,
you have examination expansion, reinspection as
necessary, to take a look if you have flaws.
And if you detect aging effects, again,
you look at it in accordance with the staff approved
guidelines to ensure that the aging-related
degradation will be detected before any loss of
intended function occurs.
For monitoring and trending, the
inspection schedules in accordance with the VIP
guidelines ensures timely detections of cracks, and
the scope of examination expansion, reexaminations,
will take care of beyond baseline inspections if you
do have flaws.
For acceptance criteria, degradation is
evaluated in accordance with the approved VIP
guidelines, staff approved guidelines I should say.
For corrective actions, you have the
repair design criteria if you need to do repairs,
and the staff is in the process of approving those
also -- again, with some open items in those.
And, again, as far as operating
experience, as Robin mentioned, you've had several
instances in the past 20 years where the jet pumps
have had some problems.
Staff has completed its review of the
VIP 26 guidelines. The scope of the program is
pretty much as Robin described earlier. So go
through that.
The VIP 26 document, the aging
management programs, the 10 elements are similar to
what was in the VIP 41 review. So I really don't
need to go through that again.
And the operating experience -- again,
we've had cracking found at various locations over
the years. And they have also been observed in the
Swedish BWR, which I believe Dr. Shack mentioned
earlier.
Going into VIP 75, the technical basis
-- now, this is where we change stride here.
Basically, the I&E guidelines are what constitutes
the aging management program, the generic aging
management program for the fleet. But the VIP 75
and some of the other documents are intended to be
applicable at any time in operating life, be that
year 39 or year 59.
So there is no license renewal SE that
will be issued on this one. Once the final SE is
issued, and we've gotten the BWRVIP 75-A document,
licensees will be able to utilize it at any time.
Robin discussed some of the revisions to
the extent of the frequency, and why it's based on
considerations of inspections.
And, again, we went through how they are
specifically applicable to inspections, but our SE
is not applicable to any other welds. We need to
stress that. It's only applicable to the Generic
Letter 88-01/NUREG-0313 welds. So this is not going
beyond the scope of that.
CHAIRMAN BONACA: Here you -- your
previous slide you talked about extent and frequency
for piping inspections contained in GL 88-01. That
is the first time I see this issue of frequency of
piping instruction. Does it imply that -- that the
frequency changes with time?
MR. CARPENTER: I'm sorry, sir. Could
you repeat that?
CHAIRMAN BONACA: If you go to the
previous slide, the BWRVIP 75 report proposes
revisions to extent and frequencies for -- plant
frequencies. I mean --
MR. CARPENTER: Yes.
CHAIRMAN BONACA: -- could you comment
on that? Frequencies -- what --
MR. CARPENTER: Yes. Basically, gain,
the BWRVIP 75 report proposed to reduce the amount
of inspections that were necessary.
CHAIRMAN BONACA: Okay.
MR. CARPENTER: And this is for the low
fluence regimes. Okay? Again, once you get into
the high fluence regimes where you go into less
hydrogen water chemistry, you drop out of that and
go into normal water chemistry, the inspection
frequencies will increase. So the frequencies are
being reduced because the inspection results through
the years and the mitigations that have been
occurring have been improving it.
Once you find that your cracking is
increasing or is occurring, you expand that. So
it's not that you're forever reducing. There will
be a time when you will be inspecting more.
CHAIRMAN BONACA: Okay. So there is
some consideration -- yes. Okay.
MR. CARPENTER: Anything else, sir?
Okay.
Basically, the scope of the program was
that it provided a summary of the generic letter, it
discussed the use of hydrogen water chemistry to
inhibit initiation and growth of IGSCC, it proposed
revised inspection criteria and associated risk
considerations, much as we've just discussed.
The staff issued the SE with several
open items, and those included proposed inspection
frequency and scope of the category A, B, C, and E
welds. We didn't precisely agree with the BWRVIP on
those.
We also requested more in the way of
sample expansion, and we talked about reactor water
coolant conductivity and what was necessary for
that, what exactly constituted an effective hydrogen
water chemistry and noble metal chemistry addition
programs, and also just how do you identify safety-
significant locations. And that's all in the SEs
that we provided to you.
And we have met with the BWRVIP. Just
last week we discussed this, and they're going to be
coming in with a response to that SE here in the
near term.
Again, the staff has the VIP 75 guidance
to be acceptable except for the open items, and the
revised 75 report can be used by licensees to
replace inspection guidance and Generic Letter 88-
01. And several licensees have already started
making use of that revised guidance addressing the
open items as necessary.
And we believe that this will provide
reasonable assurance for integrity of the subject
BWR piping welds.
In conclusion -- the reason I'm going so
fast is because Robin took care of the majority of
the information that we wanted to provide to you --
we have found that referencing the VIP aging
management program, including the staff required
action items, will provide reasonable assurance that
applicants will adequately manage the aging effects
during the extended operating period, and that the
generic AMPs will significantly reduce staff reviews
of license renewal applications.
I believe that will be borne out when
you talk with the people tomorrow on Hatch regarding
how much was reduced on that.
And that concludes my presentation. Any
questions?
CHAIRMAN BONACA: Well, I just had
question maybe for both presenters. And I just
mentioned it before; I still am belaboring on this
issue. You know, the oldest program says that, you
know, you identify these materials which have
different susceptibility to cracking.
And then for the less susceptible it
will be every 10 years you perform an inspection.
For the more susceptible locations, all materials
you do it every six years.
You maintain a step up to 60 years, or
can maintain it to 100 years I guess. It's
counterintuitive to me that, as you continue to age
this material, you would expect to need the same
frequency of inspections. I mean, I just -- maybe
my material expert colleagues here could help me
with that, particularly where you have this
susceptible material in a susceptible region, high
fluence.
MEMBER SHACK: Well, no, this is piping
inspection.
CHAIRMAN BONACA: Yes. Well --
MEMBER SHACK: So you're not
accumulating any fluence in this piping.
CHAIRMAN BONACA: No. I thought that,
however, there are also intervals of inspections for
intervals, for example, that would also have the
step-wide frequency.
MEMBER FORD: Essentially, your concern,
Mario, is that -- your concern is that the
assumption is that the damage is occurring literally
over time.
CHAIRMAN BONACA: Yes.
MEMBER FORD: And if it's occurring
exponentially with time, then having it every four
years or 10 years is inappropriate.
CHAIRMAN BONACA: Well, at some point,
it seems to me that because --
MEMBER SHACK: It's not only linear in
timing, because it suddenly bounces up to 5 times
10 --
MEMBER FORD: But it's just because
you've seen it. It's kind of up to NTE resolution
on --
CHAIRMAN BONACA: The only thing is --
the rest I think is -- I'm very comfortable with the
fact that there has been a very careful look at
every component, every location, every environment,
and it can -- you know, I think it's a very thorough
effort.
It just still -- and I guess if there is
an acceleration of damage being experienced, there
will be some response coming at some point for that.
And so --
MR. CARPENTER: Well, if I could echo
what Robin said earlier, if you're looking at some
of these components, and you see degradation
occurring at an increased frequency, obviously, what
we have been trying to do in some of these reviews
is that you were going to do scope expansion and
frequency expansion.
So as things -- if things, I should say,
begin to crack and degrade in greater frequency over
the years, the VIP program is pretty much a living
program. It's not once you've done it you put it on
a shelf and you're complete with it.
The staff has been working with them on
this. If need be, we will be going back to the
BWRVIP and saying, "We need to revisit some of these
inspection frequencies and scopes."
MEMBER KRESS: That concept of
increasing the frequency based on what you see puts
a great deal of emphasis on the first frequency, the
first inspection frequency. How was that arrived
at? Did you have -- the six years, for example.
You know, if you're looking for linear
extrapolation and want to be sure it doesn't go up
exponentially, and you're looking at frequency of
inspections to keep you away from that, you know, a
whole lot rides on that first frequency that you
choose. And I was just wondering how that was
chosen.
MR. DYLE: If I could maybe try to help
with that. Maybe the way the presentation went made
it look like it was a decision on a discrete
component basis, and that's really not the case.
You know, when we looked at how often
should we inspect something that has, for example,
182 weld metal, we looked at all of the components.
We said, "Have we seen cracking anywhere? What's
the industry-wide experience? What's the behavior
of this stuff?" If it should crack, how fast would
it grow? If I don't find it today --
MEMBER KRESS: That's the key right
there.
MR. DYLE: Right.
MEMBER KRESS: You have a model for how
fast it will grow.
MR. DYLE: Right. And those were things
that we took into consideration. If I look today
and it cracks tomorrow and starts growing, what's a
reasonable inspection frequency to look again to
ensure integrity?
MEMBER KRESS: So the -- that first one
-- decision on how long to wait for the next
inspection depends on the crack growth model or
crack initiation model. And the question I have is,
is there any reason to expect those to be linear?
MR. DYLE: No, not necessarily. We
tried to be conservative. If you look at some of
the components -- and we did this -- and you said,
"Well, if I have a crack today," and using, let's
say, in VIP 14 for the crack growth rate for
stainless steel that's not irradiated, you could
justify an inspection frequency of 20 years.
We'd say, "Well, that's -- that doesn't
make sense." So --
MEMBER KRESS: So we're -- over a short
time, linear is a good enough approximation is what
you're saying.
MR. DYLE: It would seem to be. And
then, again, as Gene said, we called it a living
program. If we find a problem in stainless that's
welded -- I don't know, pick a component -- to core
spray, if we find something new, we say, "All right.
What's the impact on that of every other location
that's got stainless material that's welded?" We
need to revisit everything.
CHAIRMAN BONACA: The other key thing
that comes to mind now is you have about 30 or 40
plants in the program.
MR. DYLE: That's right.
CHAIRMAN BONACA: So, really, you are
having probably --
MEMBER KRESS: So you're having
inspections, really, pretty often, naturally. When
you look at the population --
MEMBER SHACK: Even there, when the guy
inspects his pipes, it's not as though he doesn't
inspect the pipe, you know, in 10 years, and then he
suddenly goes in the next outage and looks at it.
You know, he's got to look at all of the welds over
the 10 years. He's looking at a sample --
MEMBER KRESS: So spreading them out.
MEMBER SHACK: Right. And when you do
that on a plant-wide basis, you've actually got a
pretty good sample of things going on. I mean, you
know, the alternative to an expansion rule is to
somehow pretend you really understand this well
enough.
(Laughter.)
CHAIRMAN BONACA: I hope you're --
MEMBER SHACK: I prefer the expansion
rule myself.
(Laughter.)
CHAIRMAN BONACA: I hope you would. No,
but I think the sheer number of plants involved in
the program, and the sharing and communication of
information, is sufficient, give a lot more comfort
because you essentially have, on average, three or
four inspections a year.
MR. DYLE: Right. And we hope that --
and maybe I wasn't clear in the beginning of the
presentation. But by giving this semi-annual update
of what's happened, it allows the staff to
independently assess the adequacy of the program
also.
So we're willing to accept that
feedback, and this -- this has been a good effort
where we could do what we thought was the right
technical thing, and the staff comes back. We're
not worrying about licensing arguments, so we hope
to keep that relationship.
MR. CARPENTER: And I didn't bring a
copy of what Robin was just talking about, but the
semi-annual inspection and summary that the BWRVIP
provides to us is approximately, you know, a
quarter-inch thick. So we do have a very large
database that we are accumulating, and that has been
coming to us for the last four or five years now.
Any other questions?
CHAIRMAN BONACA: Any more questions for
Mr. Carpenter?
MEMBER KRESS: Are we writing a letter
on this?
CHAIRMAN BONACA: Well, we plan to
address the review of this, you know, as part of the
Hatch application. The Hatch application references
these reports. So we did pretty much what we did
originally for, for example, the use of the B&W
topical in support of the Oconee application.
MEMBER KRESS: But we haven't reviewed
these models -- plant growth and initiation, on
which a lot of this relies on. Can we make
judgments without reviewing those models and the
database that underlies them? Or we just rely on
Bill and Peter to tell us it's okay? Or --
MEMBER SHACK: The staff has written
SEs.
MEMBER KRESS: Okay. Well, the staff
has got an SER. Why don't we -- I mean, that
doesn't --
CHAIRMAN BONACA: We have reviewed only
a sample of SERs.
MEMBER SHACK: Yes. I mean, it's like
our whole review of the license renewal process. I
mean, we don't review every SER of every supporting
document.
MEMBER KRESS: We rely on the staff's --
MEMBER SHACK: Well, I mean, you sort of
try to sample I guess is what we've done.
CHAIRMAN BONACA: Yes.
MR. DURAISWAMY: That's what you did,
Tom. This time we really picked four reports. I
think, Bill, you got two, and Graham got one, and
John got one. So you guys, you know, found it
satisfactory? Any problems?
MEMBER SHACK: Yes.
MEMBER KRESS: I did, too.
MEMBER LEITCH: Yes.
CHAIRMAN BONACA: Okay. So that's all
we can do -- sample it.
MEMBER KRESS: Yes. But the whole
committee has to sample it.
MR. DURAISWAMY: Well, and the next --
next BWR plan comes in, I think we will take
probably about 10 reports and give one to each
member.
MEMBER KRESS: Give all 10 of them to
each member.
MR. DURAISWAMY: Well, we can do that,
too. So -- we can do the other thing, Tom. It's
going to be tough.
MEMBER KRESS: I know particularly in
this area, it's -- this is a tough area.
MEMBER SHACK: Yes. I mean, you can
count the number of man-years they spend on this,
and then you -- you know, you go around and you try
to figure out how we're going to do it.
(Laughter.)
MEMBER FORD: Could I ask a question of
clarification? It relates to your crack growth
disposition algorithms. Are we using 5 times 10-5
inches per hour?
MR. CARPENTER: We are using that for
the majority of the cases, and any time you get
above the threshold fluence level inside the reactor
vessel for 5E-5 inches per hour is what we're using.
In some cases, we have reduced the crack growth rate
because the BWRVIP has been able to show that there
is a case to do so.
MEMBER FORD: So this five times 10-5
for both higher rated and not -- it's five times --
MR. DYLE: If I could, BWRVIP 14, which
is the statistical correlation, sets a new
disposition line at -- I think it's 2.2E-5 for
disposition purposes. And that's based on the
statistical review of the data, plus with some input
from GE with their verification in another way that
that was an acceptable disposition curve to be used.
MEMBER KRESS: Is that the main line, or
is that a 95 percentile line through the data?
MR. DYLE: 95.95.
MEMBER KRESS: 95.95. Okay.
MR. DYLE: Of the data.
MEMBER SHACK: You've got to remember,
first you look at the crack growth curve, and then
you have to look at the stresses. And so, you know,
what they've done is sort of taken --
MEMBER KRESS: All the data.
MEMBER SHACK: -- an approximate -- you
know, a conservative crack growth curve, and then
what is for most cases an approximate stress-
intensity value, and picked it there. You know, I
think you would have to argue that it's an
engineering judgment rather than a statistical
model, because it's very hard to characterize the
stress distributions.
You know, you can do something with the
crack growth curve, but then you still have to make
a judgment.
MEMBER KRESS: I thought the crack
growth curve had inherent in it the stress.
MEMBER SHACK: No. It says that for a
given stress intensity I get a crack growth rate.
But then I have to decide what the stress intensity
is at this weld at this point.
MEMBER KRESS: Oh. The data is not --
is data taken in the laboratory for a given -- where
you impose an intensity and a chemical --
MEMBER SHACK: Right. Because it's the
only way you can do it. I mean, because it does
depend on the stress intensity. You have to have
the crack growth rate depend on the stress
intensity.
MEMBER KRESS: And you have a
laboratory-based model.
MEMBER SHACK: Which means, then --
well, even if it wasn't a laboratory-based, it means
if you did a field measurement you would have to
know what the stress is in that weld.
MEMBER KRESS: Well, I --
MEMBER SHACK: So I get out stress
meter --
MEMBER KRESS: Not if you put all the
data on a curve and took the 95.95. That would take
care of it. But if it were all field data -- that
was where I was confused. It's not field data,
though, you're talking about.
MEMBER SHACK: Even the field data --
you know, then, you have to decide when the crack
started growing.
MEMBER KRESS: Yes. Of course, you'd
have to have the data. Yes.
MEMBER FORD: I think that this present
discussion arises out of the comments that you all
made. Does the ACRS write an approving letter, or
whatever it is that we write, for this methodology?
MEMBER KRESS: Well, I think what we do
in the case of this license renewal is to say the
ACRS has looked at the staff's SER and the staff's
procedure, and we approve the procedures. But we
don't -- I think we keep hands off on saying we
approve the license --
MR. DURAISWAMY: No, it doesn't say --
just the word "approve," yes.
MEMBER KRESS: Yes, we don't approve
license renewal. We agree with the staff's --
MR. DURAISWAMY: Exactly.
MEMBER KRESS: -- has done a good job of
SER, and that the procedure is okay. I think that's
the way we have to deal with it, but we can't
approve all of this.
MEMBER FORD: Well, I was about to
follow it up with another comment on -- that there
has been a fair amount of discussion within industry
about the methodology used for coming up with these
statistically-based algorithms, which then, in turn,
depends on the quality of the data upon which they
are statistically derived -- however those are
derived. And there will always be arguments along
those lines.
The question I'm really asking the staff
is, are they happy that that disposition curve is a
safe disposition curve? In other words, there have
been very few data points which exceed that value
of, what, 2.2 or -- steady state value of 2.2 times
10-5. That is the -- as far as the safety point of
view. Forget the specifics of, you know, whether
you agree with the methodology.
So the question is: are the staff -- is
the staff happy that this statistically-derived
disposition algorithm is a safe upper-bound value?
MEMBER KRESS: I think if you read his
last conclusion on the slide, you would have to say
that, yes, they're happy with it.
MEMBER FORD: Yes.
MR. CARPENTER: The staff hasn't seen
that. The staff has approved the BWRVIP 14 document
with several caveats, which are being addressed by
the BWRVIP.
MEMBER FORD: Okay.
MEMBER SHACK: So, basically, for
application to low irradiation levels, they have
accepted that.
MEMBER FORD: As a conservative.
MEMBER SHACK: As conservative, right.
CHAIRMAN BONACA: The heart of the
license renewal rule is that you have adequate
programs to inspect passive components to assure
that you can manage aging degradation.
You know, so there is -- I think that
you are -- the way I see it, it addresses the issue
of looking at specific locations, looking at the
environment in those locations, conditions for the
aging effects there may be on those components, and
establishing inspections and repair techniques and
approaches.
And so I think in that sense, really, it
seems to be totally in agreement with the license
renewal steps that you have not questioned, that
really we have not explored in detail for each one
of the locations, etcetera, as the correlations.
And, therefore, the timing of the inspections, for
example, and we haven't -- we can't comment on that,
except for the specific four examples that we
reviewed.
But we can conclude that the process is
really in line with the license renewal process.
MEMBER KRESS: Yes. And I think that's
what we ought to -- Bill, you mentioned that the
correlations were conservative for non-irradiated
material. Does the database include radiated
material? That seems like a pretty tough laboratory
assignment to get --
MEMBER SHACK: Well, that's why it gets
a lot higher when you have irradiated materials.
MEMBER KRESS: But do we have data on
that?
MEMBER SHACK: You have very limited
data, which is why you have to make conservative
assessments.
MEMBER KRESS: I can see how it would
have to be, yes.
MR. DURAISWAMY: We're trying to get --
MR. DYLE: We're trying to gather data
from different -- we've leveraged our money. We've
bought into different research programs, so we can
obtain data, say, for Halden and other activities.
GE has worked to develop that. And as
soon as we have something that is usable that we
think justifies a change in rate or a better
definition of the rate, we'll give that to the staff
for their review. But we understand that that's
something that we've got to deal with.
We're looking at fracture toughness
also. There are some irradiated issues that we need
to deal with and understand.
CHAIRMAN BONACA: Any other comments?
Let's talk just briefly about two
things. One is, again, the way we view -- the way
we view this review of the BWRVIPs. In the letter
for Hatch, is there any other insight to provide
here? Or shall we just treat them the way we
treated the B&W topicals for the Oconee application?
I would say that would be the approach that I would
propose. Any other --
MEMBER LEITCH: Have you picked your two
-- that is, one letter dealing with the BWRVIP
program, and another letter dealing with the Hatch
license renewal application that references this.
MR. DURAISWAMY: No. I think I
better --
MEMBER LEITCH: Because this is going to
be used much more widely than Hatch in the future,
right?
MR. DURAISWAMY: Yes. But, Graham, I
think in the Hatch application, you know, they're
referencing, what, close to 20 reports? How many?
MR. CARPENTER: Can you tell me --
you've got something like -- well, almost every one
of the I&E documents --
MR. DYLE: Yes, for the -- and you would
have referenced 01, 07, 63, and then 76, which is
really just one document, but there's four
references. So we've referenced all the I&E
documents where applicable.
An example would be core plate we
didn't, because we've installed wedges. So by --
although we considered the scope of that, we looked
at the core plate and said, "What does the VIP
require that we do?" the answer was nothing, because
we've installed the wedges. The core plate can't
move should the bolts fail. So that's not
specifically referenced but it was concerned.
The Hatch commitment is to implement the
VIP documents as the NRC SE specifies or we'll
notify the staff of changes that we need to make to
do that. That's in the application, and that's the
direction we're headed.
MEMBER LEITCH: But my question is, when
the next BWR comes in, what do we do about that?
CHAIRMAN BONACA: See, their burden is
to demonstrate that the topical -- these topical
reports are applicable to their plant, the
application they propose. That's what the staff is
supposed to review.
And, again, on our part, it's to assure
that we feel comfortable that the staff has
performed the verification. Granted, we are
approving -- we're not approving -- we're using or
referencing these BWRVIPs in our review of the
individual applications, with no complete review on
our part of all the topicals.
We really have reviewed only four, and
we have reviewed the staff presentations and the SER
provided by the staff. But this is not unlike other
things that we do -- we do reference in our review
of the applications and the SERs.
I don't know -- I know that there are a
number of others that will receive separate
evaluations that aren't completed -- totally
completed yet. Do we have any plan to review those
when they come through? I don't think so.
MR. DURAISWAMY: No. I think the next
-- you know, next time, I think we've got to pick
and choose, you know, some additional reports, you
know, important reports. I think we can do -- when
the staff has completed the safety evaluation, so
you've got to do the same thing what we did this
time. You know?
So Tom is willing to, you know, look at,
you know, some more reports. And I think --
MEMBER SHACK: Well, for example, the
important one will be the hydrogen water chemistry,
because that will be fundamental to a major change
in inspection frequency. And so, you know, I think
when the SE for that one comes out, for example,
that would be one that would -- we would want to
look at.
CHAIRMAN BONACA: Yes. I think what we
should plan to do probably is to reflect on that,
think about it, and then make a little plan on our
part on what we're going to review and under what
kind of conditions. It may be that we do it for the
next BWR license renewal committee that we have.
MR. ELLIOTT: Peach Bottom is only six
months away, or less. They're coming in this
summer, I believe.
CHAIRMAN BONACA: Okay. Now, the second
issue I would like to talk about briefly is, what
are we asking the staff to come and tell us about
this at the next meeting next week for the full
meeting? I would expect that we will have some
condensed presentation as part of the Hatch
application. So that's really the way we're going
to address the BWRVIPs anyway.
MEMBER KRESS: What do we have, two
hours?
MR. DURAISWAMY: How much time? I
forgot. Yes. We get two hours for Hatch and --
MEMBER KRESS: Yes. But how much time
do we have --
MR. DURAISWAMY: No, but -- yes, for the
-- and the guidance documents and -- we have an hour
and 10 minutes.
MEMBER KRESS: Okay.
CHAIRMAN BONACA: My suggestion is that
we try to stay within the schedule. We may need
less time for the guidance documents.
MR. DURAISWAMY: Yes. But they are --
all of things are included under Hatch. You know,
so we can -- you know, they can address, you know,
some of these things at that time.
CHAIRMAN BONACA: Okay. So we will have
-- we will need a summary of the -- from the staff
of this effort, the BWRVIP report that has been
produced, and they are referenced in the application
for Hatch, and then some summary of -- I guess I'm
wrestling right now with the time available to us
for that presentation, which is limited.
So what do you think will be interesting
to the other three members which are not here right
now?
MEMBER FORD: Could I ask, what's the
expectation of the meeting next week for the Hatch?
Are we expected to come up with an approval?
CHAIRMAN BONACA: No. We are going to
have a report on this SER, which still has open
items. So, therefore, we will have an opportunity
to review it again. But this is a time when we can
provide some feedback if there is feedback we want
to provide.
MEMBER FORD: Okay.
CHAIRMAN BONACA: So -- yes, my
suggestion is that we will probably commit to maybe
half an hour of the whole presentation dedicated to
the BWRVIPs with -- probably the best way would be
to start with those two figures of the core and the
components, so that there is an overview for the
other members of what components we're talking about
here. Very briefly, the kind of failure experience,
the program that was implemented to address these
failures.
I certainly think that the members
should see, one, the population of the BWRs involved
in this. The other way -- the other thing you
should present is the -- the unavailability of the
-- how much it has gone down since 1984, which
definitely speaks of a success story for the program
which has been implemented to test those.
And then, I think that I would focus
purely on the four BWRVIPs that we chose, which I
believe are pretty central. They were regarding
internals -- you know, the --
MR. BARTON: Jet pumps and --
CHAIRMAN BONACA: -- the jet pumps, the
shroud, the --
MR. BARTON: -- top guide.
CHAIRMAN BONACA: -- top guide.
MR. BARTON: And Class I piping.
CHAIRMAN BONACA: That's fine.
MEMBER SHACK: But, still, in a half an
hour, you can barely do more than mention the
titles.
CHAIRMAN BONACA: Well, I mean, I will
be expecting only to see some conclusions as far as
inspection frequency. I don't think we want to have
more than that. For Oconee, when we have the -- I
don't think we had almost any presentation of the
B&W topical reports.
MEMBER SHACK: No, we didn't.
CHAIRMAN BONACA: We didn't. Are you
suggesting we don't have it?
MEMBER SHACK: No. I guess I would
focus on primarily how successful the program has
been in, as you say, reducing the outages, and, you
know, the sort of incidence of cracking.
CHAIRMAN BONACA: Yes.
MEMBER SHACK: And, you know, which is
in a way the proof of the effectiveness of the
program. Whatever you may argue about, you know,
what we understand and what we don't understand, you
know, we're just not getting nearly as much cracking
anymore.
CHAIRMAN BONACA: And, again, focusing
on the fact that the outcome of all this work really
is a number of guidelines which seem to pattern
exactly the -- for example, what you find in GALL
for other components. Okay? So, essentially, the
rate of inspection required, etcetera, etcetera, the
programmatic requirements of license renewal.
MR. CARPENTER: Well, bear in mind GALL
relies heavily on the BWRVIP program for the
internals, so --
CHAIRMAN BONACA: And that fits right
into that.
MR. CARPENTER: Right.
CHAIRMAN BONACA: So it will be almost a
presentation, you know, within that context.
MR. CARPENTER: Yes.
CHAIRMAN BONACA: You said a half an
hour cannot provide much, but the -- I don't think
we should spend more than half an hour on that,
because there are many other issues we need to
discuss.
MEMBER SHACK: No. You can't give more
than half an hour.
CHAIRMAN BONACA: Maybe 20 minutes,
whatever.
MEMBER KRESS: Take a look at Mr. Dyle's
conclusions slide. He's got three major
conclusions. The scope is all-inclusive and broad,
and that it includes the appropriate elements,
including inspection evaluation, repair, and
mitigation. And that the program has been
successful, and so forth.
If you could choose slides to illustrate
those three conclusions --
MR. BARTON: We just have one slide that
talks about how you looked at risk, so that will
save George a 30-minute tirade on the --
MEMBER KRESS: Yes. We had less than --
we had one bullet on this.
MR. BARTON: At least one bullet on it.
MEMBER KRESS: But, anyway, you know, if
you could -- if you could come up with some much
shorter supporting slides for those three
conclusions, it would be a good approach I think. I
think, actually, you can go in here and choose some
that would fit in a time period. Might be able to
do it.
CHAIRMAN BONACA: Okay.
MEMBER KRESS: I think those are
conclusions they'd like to know.
CHAIRMAN BONACA: Sure.
MEMBER KRESS: Things they'd like to
know about.
CHAIRMAN BONACA: Okay. You'll be
providing that, or somebody?
Okay. Any other comments? If there are
no further comments, I think we are ready to adjourn
the meeting today.
MR. DURAISWAMY: Yes. This meeting
tomorrow is a different --
MEMBER KRESS: You're adjourning this
meeting and you want to start a new one tomorrow.
CHAIRMAN BONACA: Okay. We'll start a
new one tomorrow -- the Hatch application.
Okay. If nothing -- no comments from
the public? Okay. The meeting is adjourned.
(Whereupon, at 4:15 p.m., the
proceedings in the foregoing matter were
adjourned.)
Page Last Reviewed/Updated Tuesday, August 16, 2016
Page Last Reviewed/Updated Tuesday, August 16, 2016