Plant License Renewal-March 28, 2001
Official Transcript of Proceedings
NUCLEAR REGULATORY COMMISSION
Title: Advisory Committee on Reactor Safeguards
Plant License Renewal Subcommittee
Docket Number: (not applicable)
Location: Rockville, Marylad
Date: Wednesday, March 28, 2001
Work Order No.: NRC-136 Pages 1-174
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
+ + + + +
ADVISORY COMMITTEE ON REACTOR SAFEGUARDS
(ACRS)
PLANT LICENSE RENEWAL SUBCOMMITTEE
+ + + + +
MEETING
+ + + + +
WEDNESDAY
MARCH 28, 2001
+ + + + +
ROCKVILLE, MARYLAND
+ + + + +
The Subcommittee met at the Nuclear
Regulatory Commission, Two White Flint North, Room
T2B3, 11545 Rockville Pike, at 8:30 a.m., Dr. Mario
Bonaca, presiding.
Plant License Renewal Subcommittee Members Present:
MARIO V. BONACA, Chairman
F. PETER FORD
THOMAS S. KRESS
GRAHAM M. LEITCH
WILLIAM J. SHACK
ROBERT E. UHRIG
ACR Consultant Present:
JOHN BARTON
ACRS Staff Present:
SAM DURAISWAMY
ROBERT ELLIOTT
Also Present:
RAJ ANAND
HANS ASHAR
RAJ AULUCK
RAY BAKER
WILLIAM (BUTCH) BURTON
JOSE CALVO
GENE CARPENTER
JAMES DAVIS
ROBIN DYLE
BARRY ELLIOT
WILLIAM P. EVANS
JOHN FAIR
GEORGE GEORGIEVE
DAVE GERBER
CHRIS GRIMES
MARK HARTZMAN
DAVID JENG
MEENA KHANNA
W. KOO
Also Present: (cont.)
MARGIE KOTZALAS
P.T. KUO
CAROLYN LAURON
CHANG-YANG LI
Y.C. (RENEE) LI
WAYNE LUNCEFORD
KAMAL MANOLY
KENNETH McCRACKEN
DONALD P. MOORE
JEFF MULVEHILL
KEITH NICHMAN
K. PARCZEWSKI
ERACH PATEL
CHARLES PIERCE
FRED POLASKI
JAI RAJAN
JANAK H. RAVAL
PAUL SHEMANSKI
JOHN STEVENSON
KATHRYN SUTTON
DAVID TERAO
BRIAN THOMAS
HAROLD WALKER
DOUG WALTERS
I-N-D-E-X
AGENDA ITEM PAGE
Opening Remarks, M. Bonaca, ACRS . . . . . . . . . 5
Staff Introduction, C. Grimes, NRR . . . . . . . . 6
Overview of SER Related to Hatch License
Renewal, W. Burton, NRR. . . . . . . . . . . . . 7
Southern Nuclear Operating Company, Inc.,
Presentation, R. Baker, SNC. . . . . . . . . . .16
Background, C. Pierce. . . . . . . . . . . . . .16
License Renewal Application Scoping and
Screening Process (IPA), R. Baker. . . . . .20
Aging Effects
Aging Management Programs. . . . . . . . . . . .98
Time Limited Aging Analyses
SER Section 2.0 - Structure and Components
Subject to an Aging Management Review, W.
Burton, NRR. . . . . . . . . . . . . . . . . . .60
SER Section 3.0 - Aging Management Review, NRR
Staff. . . . . . . . . . . . . . . . . . . . . .98
Operating Experience Summary
SER Section 4.0: Time-Limited Aging Analyses,
J. Fair, NRR . . . . . . . . . . . . . . . . . 153
Discussion, M. Bonaca, ACRS. . . . . . . . . . . 156
Adjourn, M. Bonaca, ACRS . . . . . . . . . . . . 174
. P-R-O-C-E-E-D-I-N-G-S
(8:30 a.m.)
DR. BONACA: Good morning. The meeting
will now come to order. This is the meeting of the
ACRS Subcommittee on Plant License Renewal. I am
Mario Bonaca, Chairman of the Subcommittee. 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 Southern Nuclear Operating Company's application
concerning the license renewal for Edwin I. Hatch
Nuclear Plants 1 and 2 and the associated NRC staff
Safety Evaluation Report.
The Subcommittee will gather information,
analyze relevant issues and facts and formulate
proposed positions and actions as appropriate for
deliberation by the full committee.
This meeting is being conducted in
accordance with the provisions of the Federal Advisory
Committee Act. Mr. Sam Duraiswamy is the cognizant
ACRS staff for this meeting. Mr. Robert Elliott who
is on rotational 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. It will be made available as
stated in the Federal Register notice.
It is requested that speakers first
identify themselves and speak with sufficient clarity
and volume so that they can be readily heard.
We have received notice of comments and
request for time to make oral statements from members
of the public.
We will now proceed with the meeting and
I call upon Christopher Grimes of NRR to begin.
MR. GRIMES: Thank you, Dr. Bonaca. My
name is Chris Grimes. I'm the Chief, License Renewal
and Standardization Branch and we've organized the
presentation today to discuss the staff's Safety
Evaluation Report for the Hatch License Renewal
Application with an emphasis on identifying in the
Safety Evaluation Report some of the uniquenesses of
the first BWR review.
We're going to start off with an overview
by the Project Manager, Butch Burton and then Southern
Company is going to provide a presentation on the
application. And then we'll get into the specifics of
the safety evaluation.
The staff's presentation will identify
where there are open items and we would appreciate the
ACRS views on the open items, but I want to stress
that beginning tomorrow, we're going to have the first
of what I consider to be a series of meetings in which
Southern Company is going to appeal staff positions on
these issues and we're going to work that process to
develop final staff positions and the resolution of
the open items.
And with that, I'll turn the meeting over
to Butch Burton.
MR. BURTON: Can everybody hear me okay?
I'm going to be using the mobile mike here.
As Chris said, my name is William Burton,
but as you probably -- Chris probably clued you in I
prefer to go by Butch.
I am the Project Manager for the Hatch
License Renewal Application Review. Let me get this
mike situated here.
I'll start with a little bit of background
here. I'll go through this briefly.
We've had the application in-house with
the staff for a little over a year. It was actually
submitted by application by a letter dated February
29th. As you, I'm sure, most of you know, this is a
Boiling Water Reactor, the first to come in for
license renewal. It is a BWR/4 design, and two units.
The plant is located on the Altamaha
River. I hope I pronounced that right, in Appling
County, Georgia. It's about 11 miles north of Baxley
and I believe, as the crow flies, it's probably about
70 miles from Savannah, Georgia.
Unit 1, the current license is due to
expire in 2014 and they have asked for an extension of
that additional 20 years to 2034. Likewise, Unit 2 is
currently scheduled to end its license in 2018 and
they're looking to extend it to 2038.
One thing that I did want to do, this is
not in your package, but I did want you to see the
review schedule very briefly so you can see ware we
are.
March 16th, we completed the second of the
three scheduled inspections, the V inspection where
primarily the inspection team went to the site to
confirm that some of the commitments that are
currently in the Aging Management Programs are
properly being implemented at the site. And as a
result of that inspection we have pretty good
confidence that they are identifying their commitments
as identified in the Aging Management Programs and
properly implementing them on site.
Right now, all of the changes that they
have to make to the current procedures are pretty much
in draft or proposed form, but they are u them.
It was my understanding that one of the
committee's main interests was to compare the Hatch
Plant being the first BWR with some of the previous
applicants, in particular, to see if there was
anything materially different between what we're
seeing at Hatch and what we have seen at some of the
other plants.
And having taken a step back and taken a
look at that, we really do not see any new technical
issues. As Mr. Baker from Southern Nuclear will go
into detail in a few minutes, Hatch took a commodity
approach to their evaluation and as such, what we do
is -- what they did was they identified materials of
construction, the environments that those materials
operate in, and then identify any applicable aging
effects.
And in fact, what we found is that there
are no unique materials, there are no unique
environments, and so we do not have any new or unique
aging effects. So in that respect, which is the
primary technical issue, we really don't see any
difference between Plant Hatch as the first BWR and
any of the previous applicants who are all PWRs.
Most of the differences that I'll talk
about between Plant Hatch and some of the previous
applicants is really, it's really a matter of process
and formatting and that's primarily what you see with
the remaining bullets. It is the first to use the
Boiling Water Reactor Vessel and Internals Project
Reports.
Now my plan today was not to go into a
whole lot of detail about that since you all covered
it pretty well yesterday. So what we'll do is as we
talk about it, the appropriate points, we'll point out
where BWRVIP reports were applied in the review.
Plant Hatch was the first to use the
functional approach versus the system approach in the
scoping process. I was going to go into a fair amount
of detail about this, but Mr. Baker is actually going
to be coming up after me and he's going to go into
substantial detail on the scoping and screening
process. So if you don't mind, I'll hold off on that.
Then finally, they were the first to apply
the Aging Management Program attributes to demonstrate
adequacy of aging management as opposed to the Aging
Management Programs themselves. I do have another
supplemental graph here, vu-graph here to show you
what I mean by that. Again, this is not in your
package and I know it's hard to read, so I'll try and
explain.
What Southern Nuclear did was they took
the 10 attributes that we're all familiar with and
what we're used to seeing is having those 10
attributes applied to each Aging Management Program.
And they took a unique approach which actually the
staff found good. And what they did was they took the
10 attributes and at this point in addition to
applying them to each Aging Management Program, they
actually looked at, for instance in this case, they
created what are called Aging Management Program
Assessment Tables.
This particular one I have up here is for
copper and alloys within a river water environment.
That's the commodity group and the specific aging
effect is flow blockage due to aging mechanism
fouling. And what they did was they said, for
instance, the scope, how do we ensure that we capture
everything that we need to capture for this? And they
say here are the Aging Management Programs that do
that.
And what they did was they actually went
through each of the attributes and actually showed
programmatically how they captured that. And that was
unique and the staff found that really very helpful in
our review. That was another unique aspect.
MR. LEITCH: Butch, I notice that there
seem to me, at least, to be an unusually large number
of RAIs associated with this. Would you say that some
of these four differences that you've just listed are
primarily what caused this large number of RAIs?
MR. BURTON: It was --
MR. LEITCH: First of all, was there an
unusually large number of RAIs?
MR. BURTON: It was hard to judge. We
didn't go in to the review, because it was the first
BWR. We didn't go in with any preconceived notions of
how many RAIs would be appropriate.
Obviously, we saw with the PWRs, because
we had some familiarity with them, we expected the RAI
account to drop which we pretty much saw.
If you compare the number of RAIs for
Plant Hatch, we had more.
DR. BONACA: It seems to me on the same
issue that many of them are tied to the ficklety on
the part of the staff to ascertain if certain
components were or were not part of the license. In
fact, in many cases it was more of a question of why
is the component not in and then the answer was yes or
no. I mean in many cases the component was ins the
scope. So there was an issue with the ficklety of
checking scoping?
MR. BURTON: Yes. I'd say the majority of
the RAIs fell into two groups, one was as Dr. Bonaca
mentioned because of the unique approach and the
formatting of the application, there were a number of
RAIs that were -- had to do with clarifications of
things. In the beginning, the staff had a little bit
of trouble understanding how to navigate through the
application. And we had a number of RAIs that were
related to that.
The second thing and what accounted for
approximately one third of the total RAIs and there
were some 400 and some odd RAIs, I can't remember the
exact count, 428. Approximately, one third of those
had to do with -- I put up the vu-graph before of the
assessment table and how they applied the 10
attributes.
As I said, our guidance applies to 10
attributes to each Aging Management Program. In the
initial submittal of the application, as I mentioned
before, the 10 attributes were actually applied to a
demonstration of adequate aging management. So what
happened was we had a lot of RAIs that came in very
repetitive for each Aging Management Program to say
what is the scope, what are the parameters being
monitored, what is the monitoring and trending?
Because initially, we didn't see that clearly in the
Aging Management Program descriptions. So what you'll
find if you go over the RAIs, you'll see, as I said,
fully one third of them very repetitive in asking
those kinds of questions.
Had we not asked those questions, and if
we had not had the trouble with the navigational
problems, the RAIs probably would have been in line
with the previous applications.
MR. GRIMES: This is Chris Grimes. I
would like to on a very gross basis compare the
questions on Hatch with the Calvert Cliffs and Oconee.
Calvert Cliffs and Oconee were in the range of 430 to
450. And as Butch pointed out, by virtue of the
packaging technique, we did end up with a lot of
duplicative questions on Hatch.
And if you account for those, I'd say we
were on about the same level as we were on Arkansas
and we did -- I did feel as I looked through the
feedback that we got from the applicants on the nature
of the questions that there is evidence the process
improved and that we're learning and to the extent
that we learned some lessons in terms of communication
techniques, those were fed back into the Improved
Renewal Guidance for future applicants.
So on a very gross basis, I'd say that I'm
very comfortable that the level of questions for Hatch
were not out of line for the first BWR.
MR. LEITCH: Thank you.
MR. BURTON: Now in terms of the
comparison to some of the previous applications, those
are really the major differences, primarily process.
But in terms of technical differences, we really did
not see much because as I said, they used the same
materials. They generally operate in the same
environments and so therefore we have the same aging
effects. So we really did not see much technically
different.
That's pretty much it for my overview. I
wanted to answer any questions, any comments you may
have and then after that, I'll turn it over to Mr.
Baker from Southern Nuclear.
Questions? Comments? Okay, I'll turn it
over to Ray.
MR. BAKER: Good morning. Charles Pierce,
who is the manager of the License Renewal Section at
Southern Nuclear is going to do the background and
introduction for our part of the presentation.
MR. PIERCE: I just wanted to start by
saying it is a pleasure to be here this morning before
the ACRS Subcommittee and Ray and I are going to spend
probably the next 45 minutes or so discussing our
license renewal application with you. I'm just going
to start with more or less the background and Ray's
going to get into some of the details.
For my part, I just wanted to open it up
by saying that I think Ray will mention and I just
wanted to mention for my purposes that I've been in
nuclear power for about 20 years. I started with some
that probably the ACRS is very familiar. I started my
career in environmental qualification and moved on to
a number of other areas and now I'm in license
renewal. So I began license renewal activities back
in 1991-1992 time frame with the first rule, and so
I've been working in license renewal ever since.
Southern Nuclear has also put a lot of
resources into the license renewal through the years
as well. We've put a lot of time and effort into
developing the revised rule and Southern Nuclear
actually participated in the license renewal
demonstration project with the NRC in 1996.
Next slide.
(Slide change.)
MR. BAKER: I'm not going to go into any
details on this next slide. I think Butch covered an
overview of the Hatch information and background
adequately. I'll just mention that I've always liked
this picture with the rainbow overhead. I think
that's a nice touch.
MR. BARTON: Is there a pot of gold at the
end of it?
(Laughter.)
MR. PIERCE: The renewal, right. Next
slide.
(Slide change.)
MR. PIERCE: With regard to some of the
things that I just wanted to touch on here, Hatch was
the first utility to effectively file an
electronically formatted application and drawings. I
think the NRC found that very useful. The application
and drawings were hyperlinked for ease of use. We
also -- as we heard earlier, worked to develop an
alternate application format and we filed that format
using an early version of the standard application
format.
The reason I mention that is because that
standard application format effectively was developed
between the NRC and industry in the last few months in
the development of our application. We had to do a
significant rewrite, but we felt it was important to
do so. I think it benefitted both sides, the NRC and
us, to go through that process.
We did follow in great detail the
development of the BG&E and Duke processes as they
went through their activities. We actually had either
directly attended almost every BG&E and Duke meeting
here at the NRC or had contractors attend on our
behalf and write detailed meeting minutes for us. We
followed their letters and docket interactions and we
incorporated those activities into our application as
we felt appropriate.
Finally, in the 1999, late 1999 time
frame, as the application was nearing completion, we
brought together a group of what I call key industry
experts to perform a peer review of our application.
We actually brought with our internal resources and
the industry experts, the review staff amounted to
about 30 individuals, 25 and 30 individuals.
MR. BARTON: Who are these industry
experts?
MR. PIERCE: People like Bob Nickell who
is the ASME president. I don't know if you know Bill
Denny, electrical -- he's the individual that worked
at Ogden that helped develop the spaces approach in
the early stages with -- that we applied. I think
everybody knows Jack Roe. He used to work here at the
NRC. There were some structural integrity folks as
well that supported us at that meeting. So there were
several people of that stature there, along with some
individuals from individual utilities like PECO and so
forth that actually reviewed our application.
And basically the review went along
procedural and legal lines, mechanical, structural and
electrical. We basically had those four areas that
were looked at. We divided the group up, people up
into different groups and actually had them look at
the information in that light. So we broke the
application down in four different areas for their
review. And we incorporated the comments from that
peer review as well.
So that is the background that I really
wanted to go through here and now I'm going to turn it
over to Ray and let him continue with some of the
discussion, detailed discussion on our application.
DR. BONACA: At some point I would be
interested in hearing something about this functional
approach rather than the system approach because it's
unique for use, at least. This is the first time we
see that.
MR. BAKER: I'll try to address that.
DR. BONACA: To understand why you took
that direction rather than the approach taken by the
other applicants today. It would be interesting.
MR. BAKER: All right. Good. Thank you,
Charles.
As I go through the presentation this
morning, please feel free to interrupt and ask the
questions as they occur and we'll endeavor to answer
them to the extent that we have that knowledge here
today.
My name is Ray Baker and let me say that
I appreciate the opportunity to speak to you today on
behalf of Plant Hatch. I'd also like to thank the NRC
staff for the hard work, for the professional and
thorough review that's gone on to this point. The
fact that all the milestone dates have been met to
this point indicates a significant effort on their
part and getting the application to this point in the
review process.
I first saw Plant Hatch as a brand new
junior engineer right out of college in 1972. At that
time, Unit 1 was pretty much structurally complete.
Unit 2 was coming out of the ground. So I've been
involved with Hatch for a very long time. My entire
career of almost 30 years at Georgia Power and now
Southern Nuclear has been associated with Hatch. It
pleases me that at this point I'm able to be involved
in the re-licensing activities for the plant that I
participated in the original licensing activities on
some 30 years ago.
As Chuck noted in his comments we began
discussions with the NRC License Renewal Branch
regarding a suitable application format, actually
fairly early in the review cycle of the Calvert Cliffs
and Oconee applications and we -- and I believe along
with the NRC staff were interested in finding ways to
improve on the review process and we were encouraged
to explore different approaches. Chuck mentioned that
somewhat in his presentation.
About six months, as I recall, prior to
the scheduled submittal date for Hatch, we, that is,
the industry, NEI and the NRC, began to settle on an
early version of what has become known as the standard
application format. We agonized over the decision
whether to convert at that stage in the application
preparation, but finally we did choose to adapt the
application to match the standard format to the extent
possible.
The principal impact produced by that
format conversion was the production of summary table
results and Sections 2 and 3.
In retrospect I view that as a good
decision to format, to change the format. The summary
table format is a clear and concise way to present a
lot of information so I think that on balance, the
format conversion resulted in an improved review and
so again, I think it was a good decision.
Perhaps the one place where the Hatch
application format is most noticeably different from
the current standard format is in the presentation of
programs. Butch mentioned one aspect of that and we
may talk a bit more about that later. But the
standard format assumes program descriptions will be
provided in Appendix B. The Hatch application that we
provided originally placed those program descriptions
in Appendix A which is generally called the FSAR
supplement.
There was also additional significant
information on how those various program elements fit
together to demonstrate adequate aging management for
each commodity group in our Appendix C. The level of
detail that you find by combining those two areas is
really not significantly different from the level of
detail you would expect in Appendix B. They were just
in several places. So early in the review, we
concluded based on feedback from the NRC that in order
to facilitate that review, a stand-alone Appendix B
would be useful and we provided that supplemental
document as part of our responses to the early round
of RAIs that came in.
(Slide change.)
MR. BAKER: As you can see from this
vu-graph, the organization of the application does
follow familiar lines. Section 1 provides the general
information that's specified pursuant to 10 CFR
54.19(a) and (b).
Section 2 describes and justifies the
scoping and screening methodology and the results,
pursuant to 10 CFR 54.21(a)(1) and (2) and again,
that's in a tabular format.
Section 3 describes the process we use to
merge component groups into commodities. And in
addition, although not required by the regulation,
it's useful and so we placed it here, a description of
the Aging Management Review process that we employed.
Finally, Section 3 includes also in a tabular format
the summary results of the Aging Management Reviews.
Section 4 presents the time-limited aging
analyses and exemptions.
Appendix A describes the programs and
activities for managing aging. It also contains a
summary description of the Time-Limited Aging Analyses
and these items are as specified in the rule.
Where Section 3 presents a tabular summary
of the aging management results, Appendix C provides
the meat of the application from our perspective. The
appendix is divided into two sections. The first
section systematically discusses combinations of
fabrication, materials and external and internal
environments as Butch mentioned. This generic
presentation identifies aging effects requiring
management for each combination of materials and
environment. I will discuss that in more detail later
in the presentation.
The second part of Appendix C presents
more detailed summaries of the Hatch specific Aging
Management Reviews so the first part of Appendix C is
a generic evaluation of materials and environments and
the second part of Appendix C is on a commodity by
commodity basis, a more specific Aging Management
Review and again, this is grouped by materials of
fabrication and environments for component groups that
we call commodities. And I will describe the process
for grouping those components in a few moments when I
get to vu-graph 10.
These detailed summaries in Appendix C
provide the linkage of programs and activities to
aging effects associated with the commodities and in
that way demonstrating adequate aging management for
each commodity group. That is our demonstrations were
made in Appendix C.
And lastly Appendices D and E contain the
environmental report supplement and the technical
specifications changes required for their renewal term
respectively.
MR. LEITCH: Ray, just before you leave
the introductory material, I had a question on page
1.1-10. It says SNC requests a class 104 operating
license for Plant Hatch 1 and a class 103 operating
license for Unit 2. I don't understand that
terminology nor distinction there. What's the
distinction between a Class 104 and 103?
MR. BAKER: This is, I believe, ancient
history that goes back to the kind of operating
license that was granted in the original term.
MR. LEITCH: I see.
MR. BURTON: In the very early days, so
the Unit 1 license was a Class 104 as I believe you
said, and the Unit 2, Class 103.
Chuck, did you have more details on that?
MR. PIERCE: The Atomic Energy Act, when
it was promulgated specified basically two types of
licenses. One was called a research -- I forget the
complete name. It was a Class 104 license. The other
one was a production reactor which was a Class 103
license.
Actually, if you go back to some of the
earlier applications that had recently been approved,
they were typically 104 licenses, but Hatch sort of
was in that in between time where the plants were now
moving to ask-informed receiving 103 licenses, so we
have the difference in 103 and 104.
MR. LEITCH: I guess then my question is
primarily for the NRC. Is that something we want to
perpetuate?
MR. GRIMES: This is Chris Grimes and I'll
attempt to respond to that. As a matter of fact, my
recollection is that the original licenses were called
Demonstration Power Reactors, DPR licenses.
MR. BAKER: Right.
MR. GRIMES: And practically speaking for
the purpose of the safety evaluation, there is no
difference in the way that the safety evaluation is
conducted.
As a procedural matter, we've concluded
that renewed licenses should maintain the same
numbering scheme for simplicity of the way that we
manage the licenses. And so you'll find that in the
information digest as it lists the historical
milestones of each individual plant, their class is
104 and 103 and it's legally important in terms of the
basis for granting a license and it's nexus to the
Atomic Energy Act. But I think for your purpose, you
won't see any distinction in the treatment.
I do recall that during the conversion of
the Plant Hatch to the improved standard tech specs
that having two very different licensing bases, I mean
Unit 1 was reviewed prior to the Standard Review Plan
and Unit 2 was fundamentally standardized and in
trying to merge those two licensing bases during the
design basis reconstitution efforts and subsequent
tech spec conversions, that was uniquely challenging,
but I don't think the two different license types will
impede you in any way.
MR. LEITCH: Okay, thank you. One other
question on the introduction. I noticed there are
several owners in addition to Southern Nuclear but I
didn't see percentage ownerships. Are they clearly
minority owners or what is the percentage of
ownership?
MR. BAKER: Southern -- Georgia Power
Company is the majority owner of Plant Hatch by a few
fractions of a percent. A large minority stake is
held by Oglethorpe Power Corporation and somewhat
smaller percentages by the Municipal Electric
Authority of Georgia and the City of Dalton.
MR. LEITCH: Okay, thank you. Those
percentages are the same for both units?
MR. BAKER: I believe for Hatch that is
true. It is different ownership percentages between
Hatch and Ogle, but the other Georgia Power Company
plant, but Plant Hatch is the same for both units.
MR. LEITCH: Thank you.
MR. PIERCE: The other point I'll mention
with that is that the operations authority has
invested in Southern Nuclear by Georgia Power Company
and the co-owners. So Southern Nuclear has filed this
application on their behalf.
MR. LEITCH: Thank you.
(Slide change.)
MR. BAKER: So this is how the application
is organized, and now I'd like to discuss the scoping
and screening process we used.
We developed a comprehensive list of
systems and structures and we identified functions for
each system or structure on the list. Each function
was evaluated against the eight scoping criteria in 10
CFR 54.4(a)(1), (2) and (3). On this vu-graph we
showed that engineering and licensing documents were
used in the evaluation of identified functions against
the three safety-related criteria of 10 CFR 54.4(a)(1)
and also in the evaluation of functions against the
criterion of 54.4(a)(2) which is the nonsafety-related
that would prevent
safety-related functions.
And I would note that with regard to this
criterion, all functions were evaluated against this
criterion, not just the nonsafety-related functions.
We evaluated safety-related functions against the
nonsafety-related function criterion as well.
(Slide change.)
MR. BAKER: And in a similar manner,
engineering and licensing documentation was used in
the identification of functions relied on for
compliance with our Commission regulations specified
in 10 CFR 54.4(a)(3). The four regulations that are
applicable to Plant Hatch were EQ, ATLAS, station
blackout and fire protection. Since Plant Hatch is a
BWR, pressurized thermal shock is not included in that
Hatch is exempt from that regulation.
Three separate reviews were performed as
a part of our scoping process. The primary review was
a system and structure-specific review. To supplement
the system-structure specific review, NRC Safety
Evaluation Reports were reviewed to assure all
functions relied on for compliance with the four
Commission regulations were identified and scoped.
And in addition, we called on in-house experts for
further assurance that all the functions relied on for
compliance with the four regulations were identified
and scoped. These separate stand-alone reviews were
conducted for additional assurance that the scoping
relative to this criterion was complete and
comprehensive.
(Slide change.)
MR. PIERCE: As I noted on the previous
vu-graph, we have used engineering and licensing
documents to perform the function scoping. The block
on the left identifies some of the major document
sources used. Obviously, our Final Safety Analysis
Report was used. We also used our Equipment Location
Index. We call this the ELI. It's an engineering
database of components. It's not a Q-list, but it
does provide quality and seismic class information for
the components that are listed in that document.
DR. BONACA: Did you use also the
Q-list?
MR. BAKER: There is not a specific
Q-list per se at Plant Hatch. This is the equivalent
of that.
MR. PIERCE: The equivalent Q-list at
Plant Hatch is actually, you go back and I think look
at some of the earlier letters to the NRC is actually
the Safety Evaluation Documents which is listed as
well.
MR. BAKER: It's the Systems Evaluation
Document.
MR. BAKER: The reason that we don't
solely rely on the Equipment Location Index is that
it's not a complete listing of components. For
example, pipe segments are not listed in that listing.
We used other documents. Chuck mentioned
the System Evaluation Document which does, in one of
the appendices of it contain the listing of safety-
related components.
You asked why function scoping and the
Plant Hatch Maintenance Rule Manual was selected as a
key document due to similarities between Maintenance
Rule Scoping criteria and the License Renewal Scoping
criteria. At Plant Hatch Maintenance Rule Scoping was
done on a functional basis. The Maintenance Rule
Scoping identified a large number of functions and
then they scoped those functions based on the criteria
applicable under the maintenance rule.
We were able to use that as a starting
point to have a ready-made source for most of the
functions that we identified in the course of our
scoping review for license renewal. And we recognized
that there are differences in the criteria and one of
the things that we did was to assess and reconcile the
differences in results obtained by the maintenance
rule scoping and our scoping review. For example, the
safety-related criteria are almost identical and so
we're able to make substantial use of those, but other
criteria are just not applicable in license renewal
space.
So the set of functions that we identified
using all of these documents, plus other sources, we
did not restrict our reviewers to the set. This was
the beginning set of documents for each person to use
as they were doing their scoping evaluations. If
their reviews led them into other information sources,
we encouraged them to go to those sources to obtain
that information.
So as a result, each function that was
identified was evaluated against the eight scoping
criteria as stated on the previous vu-graphs and any
function that met one or more of the eight criteria
was classified as being in scope.
In the language of the rule, these are the
functions that are the intended functions.
DR. BONACA: I guess where I've been
trying to go was how did you assure that by this
process you have addressed every safety-related
component in the plant? That's the first question of
the rule. So now you choose a function and approach,
but you certainly want to verify that that is the
outcome. That's important because then all the other
applicable components are those that support?
MR. BAKER: That's correct.
DR. BONACA: Essentially those functions.
How do you assure that you have the correspondence
there and you included all those components?
MR. BAKER: As Chuck noted the system
evaluation document listing of the safety-related
components was consulted and we made sure that every
component in that listing is within at least one or
more evaluation boundaries where we did the screening.
DR. BONACA: Yes. The reason for me
asking these questions, I'll be open with this, is
that I have reviewed the application in some detail
and I had some trouble at the beginning in
understanding what was in scope. For example, I found
things like Table 2.2.1, System F-16, fuel storage
equipment not in scope. But then I go around and I
find F.16.01 storage racks and they are, I believe, in
scope.
And then there is a statement in a note
that says retained for continuated purposes. So I
didn't understand whether it -- and that was under a
different function. I could not trace it. So I was
left with some questions in my mind about what does it
mean to retain for continuated purpose? It is either
in scope or it is not in scope, I guess. I'm looking
at it simplistically, but --
MR. BAKER: You're right.
DR. BONACA: And it was a little bit
difficult and I guess so you're saying, your
circumstances for the plant, whatever, led you not to
use the approach that other system plants were using
at the same time which is because all the ones we have
seen today, they use the system approach.
MR. BAKER: They used the system approach
and I think everybody is familiar with that approach
and comfortable with that approach.
DR. BONACA: Yes.
MR. BAKER: And as Butch mentioned during
the review process early on, I believe that did lead
to some difficulty in getting the reviews started. In
retrospect, that's an area that is a little more
complicated perhaps than first appeared.
One of the things that we did do though is
to generate the evaluation boundary drawings and try
to provide those as an adjunct to the application so
that if there was a question about a particular
component, those drawings could be consulted to say is
it within an evaluation boundary or is it not. And on
that basis if it shows up outside any evaluation
boundary, then the conclusion was that it was not in
scope.
DR. BONACA: Yes. Now the staff, I
understand, we'll hear later, they audited the standby
liquid control system, the high-pressure coolant
injection system and the service water system and you
found --
MR. BURTON: Yes. I was going to talk
about that a little bit later. It's part of the
scoping inspection, went through some of that.
DR. BONACA: Okay, all right.
MR. LEITCH: I guess I had a similar
navigational problem in my review. Perhaps you could
just help me with this. Table 2.2-1, the first two
lines on there, A70 and A71, analog transmitter trip
system and nuclear steam supply shutoff and then for
in scope it says yes for both of those items.
And the third one is reactor assembly,
B11. So then I went back to 2.3-1 and I find the
reactor assembly and then it seemed like all the
others I found in this mechanical screening results,
but I don't find A70 and A71. I just had a little
trouble understanding what happened to this.
MR. PIERCE: Okay. And I'd have to --
MR. BAKER: Chuck has the application.
MR. PIERCE: I have the application in
front of me. B11 is mechanical system and as such
hit's listed under the mechanical system screening
results.
A70 and A71 are more directly related to
an electrical. You should see those --
MR. BAKER: I would expect that this kind
of navigational difficulty is really related to the
conversion format effort that we went through to try
to put this into a standard format relatively late in
the process and I believe that even for us, sometimes
we have to look to see what part, whether it was
mechanical, electrical or civil, any particular item
was placed in because sometimes they are somewhat
counterintuitive.
MR. LEITCH: In the SER, those first two
items are listed under electrical.
MR. BAKER: Yes, electrical. Those first
two items are electrical, yes.
MR. PIERCE: The electrical system because
of the implementation of the spaces approach doesn't
have the same component discussions in that same
section as mechanicals do. That's why you don't see
it there.
MR. LEITCH: Okay. So these two systems
are in scope, but then did they -- how do I find out
whether they screened out or not?
MR. BAKER: The electrical approach that
we used is the same as was used by Oconee and ANO, so
most electrical components, of course, are active in
screen out and what you're left with is the same set
of the passive long-lived electrical components that
the other plants had.
MR. LEITCH: Yes. I would expect that
they would screen out.
MR. BAKER: Yes, and it was a plant-wide
spaces approach that was used.
MR. LEITCH: Okay, thanks.
MR. BAKER: Okay. So the output from the
scoping review was a set of intended functions which
are the, as we discussed, the end scope functions.
These functions and again, this was a part of the
uniqueness that was described, cross over traditional
system boundaries and we allowed the function to go
where it naturally goes and the best example of that
function that crosses traditional system boundaries
would be a containment isolation function which would
be the active closing all lines and penetrations of
containment.
In our plant nomenclature, that's C61, but
you find that that applies to components in many, many
systems. Every line that penetrates containment with
isolation valves has a part of that story, but the
function went regardless of system designation. And
so, as a result there's some overlap of these
functions and you find some components showing up in
multiple functions.
DR. BONACA: Well, in part, it's because
those, some components have multiple functions.
MR. BAKER: That's right.
DR. BONACA: And in your approach, you
really identify a main function for it.
MR. BAKER: Yes.
DR. BONACA: And you followed through with
that approach. Okay, but I understand now the example
of the containment is a good one.
MR. BAKER: Yes, okay. So I would know
that while these functional boundaries cross the
traditional system boundaries, all components that are
required to perform or support the function once it's
identified as in scope are in scope regardless of the
system nomenclature. So a B21 function could have and
I'm just saying this hypothetically, an E11 component
supporting it.
As an aid to the screening of the
mechanical components, evaluation boundaries were
produced for each in scope function. Mechanical
components within the evaluation boundaries were
screened to identify those subject to aging management
review.
The screening criteria used were those
contained in 10 CFR 54.21(a)91)(i) and (ii), that is
we screened for the passive long-lived components.
Within each evaluation boundary we grouped the like
components with similar environments. For example,
within an evaluation boundary, all stainless steel
valves with a demineralized water environment would be
identified as a component group.
Another component group within the same
boundary might be carbon steel valves with a
demineralized water environment and another might be
stainless steel pipe and so on. Each component group
within an evaluation boundary was designated as active
or passive and as long or short lived.
For review efficiency we performed
additional evaluations during this stage of the
process. Rather than revisiting each component group
again later, during the Aging Management Review
process we assigned component functions and identified
materials of fabrication and the internal and external
environments for each component group during the
screening step. It was just for a matter of
efficiency.
The active-passive determinations for each
component group were based on the original component
list, arrived at from discussions between NEI and NRC
and the NEI 95-10 document.
During our review, we created additional
component types and assigned active-passive
determinations based on similarity to other components
or specific NRC guidance because during the process
resolution was achieved on some components that in the
original NEI 95-10 list has an asterisk. That
resolution was achieved during the process and we
applied that NRC guidance to those.
Long list components were those not
subject to periodic replacement based on qualified
life. By repeating this screening process for each
evaluation boundary, we produced nearly 2,000
component groups. These component groups were then
consolidated into commodities prior to performing the
Aging Management Reviews.
(Slide change.)
MR. BAKER: This is a figure from the
application. This figure illustrates the process used
to consolidate component groups into commodity groups.
In this example, we start with two systems that are
very similar from a materials and environment
perspective, the high-pressure coolant injection
system and the reactor core isolation cooling system,
E41 and E51 in the Plant Hatch system designation.
Several in-scope functions may be primarily associated
with system E-41 HPCI and I've just for illustration
purposes indicated that there are four functions here
and similarly, that there would be four functions for
in-scope functions for E51. In fact, that's not the
case. It's just for illustration purposes.
As I described on the previous vu-graph an
evaluation boundary then is established for each of
the in-scope functions. And the components are
screened into component groups.
Thus, on the third level, which is this
level here, you see examples of stainless steel piping
and stainless steel valves and as I said, the
environments associated with each component group were
identified for convenience during the screening step,
so we have that information developed here. For
simplicity, we only showed demineralized water as an
environment on this vu-graph.
But you can visualize component groups of
stainless steel piping, demin. water, stainless steel
valves, demin. water, from the evaluation of
boundaries developed out of this E41 path and
similarly, out of the E51 path. And obviously, other
groupings also exist due to different materials,
components and environments. This example is only
intended to show the process and it's complex enough
without adding the additional clutter of other
materials and environments.
The heavy line across the middle of the
page in this example is adjacent to the examine
environment and materials label. This pictorially
represents the output of the screening step. At this
point, each component type, for example, stainless
steel piping associated with E41 function 1 is a
component group because it has a material and
environment associated with it. So I have a component
group of stainless steel piping, demin. water at this
point.
Subsequent to screening, but prior to
performing the Aging Management Reviews, we further
consolidated the groupings by collecting like
component groups associated with all in-scope
functions into commodity groups. That is, all
component groups having the same materials and
environments were collected into a single commodity
group and the example here shows that being collected
into a commodity group of various stainless steel
components with a demin. water environment.
This commodity grouping was performed to
fully utilize a review and evaluation process that
systematically evaluated research information and
industry operating experience. Based on those
evaluations, it was possible to identify for each
combination of materials and environment, a set of
aging effects that might be detrimental.
DR. BONACA: Did you use the GALL 2
report? Because in draft 4 there is a lot of
information there.
MR. BAKER: It was under development and
actually we were observing and then watching the
process, but we did not -- we were not able to make
use of it during the development of ours. But I will
note that a number of the things that you see in this
approach are similar to processes that you saw in some
of the early development work of the GALL.
DR. BONACA: Okay.
(Slide change.)
MR. BAKER: So based on the process
described each structure or component subject to Aging
Management Review was included in one or more in-house
reviews. The Aging Management Reviews were performed
on a commodity group basis and a total 112 Aging
Management Reviews were performed, 96 mechanical
reviews, 9 civil structural reviews, 5 electrical
reviews and 2 reviews performed by our NSSS vendor,
GE.
The box in the upper right hand of this
vu-graph depicts that aging effects requiring
management were determined systematically for each
commodity group from the set of potentially
detrimental aging effects identified in the generic
evaluation.
I mentioned this generic evaluation
earlier when I was describing the application format.
This evaluation is summarized in Appendix C1 of the
Hatch application and it's based on work that was
performed initially in support of the Oconee
application and that's subsequently been used by ANO
and Hatch and this is now an EPRI report and is being
used by other licensees as they prepare their
applications for submittal. It consists of an
extensive review of industry literature to identify
potential aging effects for various materials and
environments of interest and nuclear power plants.
The resultant information is systematically arranged
into flow charts that can be used by qualified
engineers in evaluating the license renewal commodity
groups.
NRC Generic Communications formed a part
of the industry literature examined and synthesized.
In this manner, the industry operating experience is
captured. Plant-specific operating experiences also
reviewed during performance of the Aging Management
Reviews to validate the determinations of aging
effects requiring management specifically for Plant
Hatch.
So the output of the tool is a set of
possible or potential aging effects for any
combination of environments and materials as an
engineer would work through the flow charts. And
based on the review of the summary discussion in the
report and a review of the plant specific operating
experience and the review of other technical
literature that the engineer may choose to go to, the
engineer would then make an evaluation and
determination of whether an aging effect that might
occur would be an aging effect that would require
management during the renewal term.
The box in the upper left hand of this vu-
graph depicts the assessment of aging management
activities already in place, based on a survey of
plant and support organization procedures. If
necessary, program enhancements were proposed or new
programs or activities identified. Appropriate
program coverage for the structures or components
comprising each commodity group was identified or
established. And I would -- as you noted earlier, Dr.
Bonaca, this process is similar to what you see in
some of the GALL work.
The demonstration of adequate aging
management is made for each commodity group by the
combination of programs or activities credited with
managing each aging effect for each commodity group.
The combination of aging management activity selected
in an aging management review had to address all 10
attributes we established as descriptive of an
adequate aging management program. The program
attributes we chose are the same as those identified
in the draft standard review plan for license renewal
and Butch showed you a vu-graph of one table and how
we assessed the programmatic coverage. There is a
table like that for every commodity group for every
aging effect that was identified as requiring aging
management.
As I said a moment ago, the generic
identification of potentially detrimental aging
effects was based, in part, on the review of NRC
Generic Communications. So when all the AMRs had been
completed at the end, we conducted another review of
the Generic Communications that had been issued
subsequent to the initial review and this served to
validate that all potential aging effects were
addressed by the process.
(Slide change.)
MR. BAKER: The output from the Aging
Management Review is programs, programs and
activities.
DR. BONACA: These programs you are going
to present, are they the existing one, or are they the
enhanced one, part of this?
MR. BAKER: This is the presentation that
I show here is a combination of existing enhanced and
new.
DR. BONACA: Okay, because I mean your
application shows five existing, five enhanced
programs and seven new programs. But then there was
an interaction with the staff and I believe there was
a request by the staff for an additional
one-time inspection.
I would like at some point anyway to have
a summary of the end of your presentation of where you
stand right now insofar as enhanced programs and the
one-time inspections or the new programs because I'm
using application as a basis. I think there have been
some changes there?
MR. BAKER: Yes sir.
MR. GRIMES: Dr. Bonaca, this is Chris
Grimes. I'd also like to suggest that you be very
careful about your accounting because the resolution
of open items might end up changing the results.
MR. BAKER: Right.
MR. GRIMES: And we have -- we have
promised to come back for the full committee meeting
and the discussion of the improved renewal guidance
and do the best that we can to do a consistent
accounting of one-time inspections across all of the
renewal applications.
DR. BONACA: Yes, that is exactly why I
was asking that question, so there is some flux going
on.
This is more -- accounting is purely on
the perspective we see applications coming in. We see
one-time inspections decreasing in number. We're
trying to learn as a committee where the industry is
going and why some of these programs are not necessary
any more. In some cases, we understand and in others,
we don't. Also, it gives us an idea of what
additional burden license renewal imposes on
applicants. And so that's why I asked that question.
MR. BAKER: All right. This vu-graph does
not break it down into existing, enhanced or new, but
I will address that in just a moment.
We have identified 30 programs or
activities that will be relied on in the renewal term
to adequately manage aging effects for the
in-scope structures and components.
On this vu-graph I depict two types of
programs and activities. In these examples, we credit
seven different chemistry activities and six different
regulation-driven programs.
(Slide change.)
MR. BAKER: On the next vu-graph we have
designated programs to implement the BWRVIP activities
which Robin discussed with you yesterday afternoon and
RPV monitoring. In addition, 11 plant-specific
programs or activities are credited for managing aging
in the renewal term.
(Slide change.)
MR. BAKER: And then finally on the next
vu-graph, I illustrate four new one-time confirmatory
inspections that we are crediting.
Now another way to describe these programs
would be 17 existing programs or activities that
required little or no enhancement; 5 enhanced programs
or activities; and 8 new programs or activities, half
of which are these new one-time confirmatory
inspections. The reason that there's a difference in
the number from what you said of 7 and what I said is
8 is we have agreed to provide a
non-EQ cable monitoring program that will be a 30th
program and so it shows up in that listing.
The distinction of existing and enhanced,
I think is somewhat a blurred line as well because
virtually every program will be touched and then some
small changes made to it, but that doesn't necessarily
rise to the level of being an enhanced program,
enhanced in our perspective here I think means
significantly altered.
DR. SHACK: As I'm looking through your
application, it seemed to me that although you're on
hydrogen water chemistry, as hard as I looked through
the application, I think I found it mentioned once and
I assume that means that you don't think you're taking
credit for hydrogen water chemistry, that you could
justify the extension without it, even though you have
chosen to implement it. Is that a correct
interpretation of the way you've written the
application?
MR. BAKER: That's correct, yes. And in
fact, the EPRI Water Chemistry Guidelines that we do
credit have provisions for both the normal water
chemistry regime and the hydrogen water chemistry
regime and so as a matter of our operating flexibility
you would want to maintain the ability to periodically
for maintenance purposes or whatever other reason take
the plant into a normal water chemistry regime
temporarily while you affected those activities.
Certainly, obviously, our intent and desire based on
other considerations is to operate within the regime
that is consistent with the BWRVIP guidance in this
area.
Robin, did you have anything more to add
on that?
MR. DYLE: Bill, I guess another way to
look at it is we didn't want the HWC to be a condition
of the relicensing process, but we absolutely intend
to use it and because that program is structured for
normal or HWC, if for some reason we had to stop using
the hydrogen injection, we would still have the
ability to manage the VIP program and do the
inspections because it's structured for either option.
So we simply chose not to take credit in the
application for it. But we fully intend to use it.
Once you invest that amount of money to protect the
plant, it doesn't seem reasonable to stop.
DR. SHACK: Okay, and your argument would
be that, in fact, your inspection program would then
flip back and forth to cover the -- if and some reason
you ever stopped.
MR. DYLE: Right. If for some reason we
stopped hydrogen, we'd have to go to the normal water
chemistry inspection programs. As we discussed
yesterday, there's currently only two programs that
we've got that HWC built in. The rest of them we're
waiting on approval of VIP 72 and resolution of issues
with the staff before we broaden the scope of that
credit for HWC.
DR. UHRIG: A question on the non-EQ cable
management program. This would be the medium voltage
and high voltage cables primarily since most of the
low voltage -- maybe the low voltage cables are EQ?
MR. BAKER: Let me ask Jeff Mulvehill of
our staff to discuss the scope of that program.
MR. MULVEHILL: This is Jeff Mulvehill of
Southern Nuclear. The program would actually all
types of cables. It will be mainly focused on
identifying adverse localized environments or places
where the cable could be experiencing accelerated
aging. In normal plant environments, the cable is
going to last 60 years. That's what our analysis told
us.
So it's mainly going to be focused on
identifying those areas where cable --
DR. UHRIG: This is the visual and
inspection time?
MR. MULVEHILL: That's correct.
DR. UHRIG: And some physical
measurements?
MR. MULVEHILL: We have not identified in
the answer to the REI the exact test that we'll use at
that point. Those types of things are still evolving.
MR. BAKER: Jeff, is this consistent with
the work that's being done in the industry electrical
group working in the GALL arena? Is that correct?
MR. MULVEHILL: Our cable mirrors the
program in the GALL Report.
MR. BAKER: Thank you.
MR. BARTON: Under the new NRC assessment
process, what's the NRC's assessment of your
corrective action program?
MR. BAKER: Butch, do you want to speak to
that?
MR. BURTON: I'll take a crack at that.
I have to run back and look at the color.
(Laughter.)
MR. BARTON: Basically, that's all --
MR. BURTON: I don't know that we've got
the results, but I know where the chart is posted and
at the break I'll run back and check it.
MR. BAKER: So in all, these 30 programs
that I've put up on these three vu-graphs provide the
attributes necessary to manage the aging effects that
are identified for in-scope structures and components
during the renewal term.
(Slide change.)
MR. BAKER: Finally, I'd like to describe
our process for identifying Time-Limited Aging
Analysis. The regulations provide six criteria, all
of which must be met in order for a calculation or an
analysis to be considered a Time-Limited Aging
Analysis.
As you can see on this vu-graph, we
compiled a list of calculations to broadly include any
with a time-limited nature. Because of the large
number of calculations, more than 8,300, we initially
screened them using the time-limited nature of the
calculation criterion.
Only those calculations that passed this
first test were further screened in more detail using
the remaining five TLAA criteria. More than 1,200
calculations passed this initial screening and more
than 900 met all 6 criteria.
In addition to the review of calculations,
a separate CLB review was performed to assure all
potential TLAAs were evaluated. In other words, we
did a word search of our FSAR and other documents to
try to find things that might also appear to be a TLAA
and deal with those.
(Slide change.)
MR. BAKER: And so the final view-graph
that I have in this part of the presentation is this
view-graph identifies the TLAAs for Plant Hatch that
were identified using the screening process that I
described. They are fatigue, corrosion allowance, EQ,
containment penetration pressurization analysis, RTNDT,
upper shield energy and an analysis of a technical
alternative to a code required inspection of RPV
circumferential welds.
The way it's broken out in the application
is a little different. I've combined a couple of them
in the first bullet.
DR. BONACA: In the application you have
identified them?
MR. BAKER: Right, and the last one, I
think, we're not -- is not a TLAA based on further
discussion. That was in the application. This was
the MSIV cycle items.
DR. BONACA: So, okay, the stress analysis
for thermal fatigue. Okay.
MR. BAKER: Yes.
DR. BONACA: Which one did you combine?
MR. BAKER: The first one, stress
analyses, I think is broken out as two items in the
application.
That concludes my part of the
presentation. I'd be happy to answer any other
questions if there are any.
If not, I'll turn it back to Butch.
DR. BONACA: Well, I have some questions
about some of this. Maybe I'll wait for the NRC SER
discussion because I have some questions.
MR. BAKER: Okay.
MR. BURTON: I guess we have a couple of
options at this point. Normally, according to the
agenda, we'd be taking a break.
DR. BONACA: Why don't we do that.
MR. BURTON: We're ahead of scheduled, do
you want to do that?
DR. BONACA: We're ahead of schedule a
bit, but I think the best thing to do is to break now
and then to start the NRC presentation after that.
So let's resume again at 10 o'clock.
(Off the record.)
DR. BONACA: Okay, we resume the meeting
now with the presentation by the NRC staff.
MR. BURTON: Thank you, Dr. Bonaca. What
we're going to do now is we're going to start through
the Safety Evaluation Report and talk a little bit
about some of the results that the staff has as well
as a brief discussion of some of the open items that
are on the table.
Now one of the things that -- the way I
had planned to do this was I wasn't going to go into
a whole lot of detail if you didn't want me to, so at
the appropriate times, please feel free to stop me.
We have the appropriate staff members off
to the side who will be able to handle any of the
tough questions that I can't. So let's get started.
Starting with scoping and screening,
Section 2. In Section 2.1 in both the application and
the SER is where methodology is discussed and as Mr.
Baker pointed out in the last session, Southern
Nuclear scoped at the function level. In other words,
they looked at each system, identified all of the
functions for the system and then took each function
and ran it through a series of screens. And when I
say that, what I mean is a series of eight questions
to basically see whether it meets the scoping criteria
as to whether it's safety related, nonsafety related,
whose failure could impact safety-related function and
needed for any of the four out of five regulated
events.
And anything that's -- in answer to any of
those questions, anything that was a yes was
considered an intended function and brought in scope.
Screened at the component level. Once
they identified the in-scope functions, then they
looked at components in each system that were required
to meet those functions. And as Mr. Baker said
earlier, along with the submittal of the application,
they also provided us with the evaluation boundary
drawings which was extremely helpful to the staff.
Basically, what they did was they took PNIDs and color
coded them to help show us exactly where the
boundaries were for each function.
DR. SHACK: Was that in response to an RAI
or was that part of the application?
MR. BURTON: The drawings are not
technically part of the application, but they were
provided to us with the application. It wasn't in
response to an RAI. Those turned out to be very
helpful because as was mentioned in the last session
and for some of you also, the staff, like you,
experienced some what we call navigation problems.
DR. BONACA: Those are not part of the
application. I imagine they will be retained by the
applicant?
MR. BAKER: Yes, that's correct.
DR. BONACA: So the traceability can
always be verified for any issue.
DR. SHACK: What is the documentation look
like when you go back and you try to pull the string
to find out how they went through the screening
process with the eight criterion. Is there a
checklist? What do you actually see when you go back
and you inspect?
MR. BURTON: It's actually interesting.
Let me put this up. I'm actually going to explain it
to you in reverse.
(Laughter.)
DR. SHACK: Everything's backwards for
this application.
MR. BURTON: Southern Nuclear started with
the scoping and the screening and moved towards the
Aging Management Programs. One of the things that we
did as a staff is we started at the Aging Management
Programs and worked out way back to see what were the
aspects of the Aging Management Programs, for
instance, what was in the scope of the Aging
Management Program and we would go back to the
Appendix C tables to see whether or not all of that
had been actually been captured and then from there we
took a step further back. So we actually worked in
opposite directions and the fact that the application
was electronic with point and click and it would take
you to different places, we actually found that was
one of the navigation problems that we had in that you
could point and click in one direction, but it wasn't
as easy to go in the other direction the way we were
doing the review. So yes, in answer to your question,
what we actually did was we actually looked at the
Aging Management Programs and looked at what, for
instance, what was the scope of this particular Aging
Management Program? What commodity groups were
included and then we would go from there to Appendix
to confirm that there was proper cross referencing and
things like that. So it was actually -- it's actually
like a fun jigsaw puzzle. I guess that's how you
would best put it.
DR. SHACK: But that was on the up-front
scoping. That is, when you're trying, you have a
function and you're trying to see whether it obeys the
A criterion in the rule, how is that documented? It's
not in the application, but presumably when you go
back and you do an inspection, you see some kind of
records and what kind of record is actually produced?
MR. BURTON: Actually, I guess the best
way to explain that is to talk a little bit about what
happened during the scoping inspection, because that
is where we did some of the confirmative stuff. Let
me put this up real quick.
As I mentioned before, as part of the
review process, we have three inspections that we do,
the first being the scoping inspection which was
actually scheduled for late October. We actually did
in early September. What we did -- the purpose of
that was to make sure that what we were seeing in the
application in terms of what was identified as being
in scope and what was identified as not being in scope
was actually confirmed through looking at some of
their source documents as Mr. Baker had identified
before, the Maintenance Rule Scoping Manual, the
Equipment Locator Index, things like that. So the
inspection team actually went down and we took a
sampling of several systems and actually walked
through the process and what we found was that as a
practical matter, the scoping was actually done in
accordance with the way it was described in their
application and in accordance with the rule. One of
the things that we also found though was that the
actual guidance documents at Southern Nuclear that was
to explain step by step how to do it, it was results
oriented as opposed to step by step, here's what you
need to look at, things like that. And we had
identified that in the scoping reports, inspection
report, that that was one of the areas that needed
improvement which they subsequently did. And in fact,
the next time we visited them we took a second look at
the procedures that provided the guidance for doing
the scoping. We found that it was much more in line
with what we had expected.
So again, to answer your question, what we
actually did was and again, a lot of it was driven
because of some of the initial questions that we had
as a result of navigational problems as we said well,
let's sit down and actually take a look at this.
Let's look at the evaluation boundary drawings. Let's
see what functions are captured. Let's look at the
things that are in the boundary. Let's look at the
things that are out of the boundary. Let's see how
they documented that and see whether it is in line and
appropriate. And we found that as a practical matter,
it was.
Did that answer --
DR. SHACK: That helps. The other
question I had was this Maintenance Rules Scoping
Manual which would sort of strike me as a secondary
source kind of thing. Somehow that meant that
somebody went through an analysis, presumably from the
FSAR, some more fundamental document and did that once
and have other people used that as a kind of a primary
source for this approach?
I assume that everybody has something like
that. They've done it as part of their maintenance
rule implementation.
MR. BURTON: Yeah, I really can't speak to
how other applicants have done it. All I can say is
and again, correct me if I'm wrong, the Maintenance
Rule Scoping Manual, when you looked at what was
scoped in and you compared that to what we were
looking at for license renewal, there was a
significant amount of overlap, so I think from --
again, correct me if I'm wrong, from Southern
Nuclear's point of view, work smart, not hard. Let's
start with what we have and expand from there.
MR. BAKER: Butch, just to amplify on that
and actually maybe clarify a question that was asked
during my session, Chuck mentioned that we
participated in a demonstration project with the NRC
back in the early days of license renewal and one of
the things that we did in that demonstration was to
present a full plant scoping which was done from a
system orientation. And the review at that time asked
a number of very difficult questions related to
comparing our results to maintenance rule scoping
results and so we took out of that a task for
ourselves to go back and redo the scoping oriented on
functions, similar to the way that the maintenance
rule scoping had been done. And so that was the
genesis of that. In fact, the maintenance rule
scoping that was done was an expert review panel kind
of an approach at Plant Hatch. You had a number of
people that were assembled together that crossed the
spectrum of experience, plant operations people,
engineering personnel and so forth to cover everything
from operating procedures to the FSAR in identifying
the functions and then doing the scoping work in
accordance with the maintenance rule. And so that was
really the genesis of that document's use for us in
license renewal. It was related to our experience in
the demonstration that we did as well as having that
ready made source of information available.
And I think, also in answer to your
question, what you will find in-house is, on a
computer data base a record for each function that was
identified that answers for each of the eight criteria
yes or no, in scope or not in scope as a result of any
of those being a yes. So the direct answer is, there
is a data base that contains the results.
MR. BURTON: And -- go on, I'm sorry.
MR. LEITCH: I was going to bring up
another issue. I thought there was -- it seemed to me
there were some unique problems associated with
scoping and screening of skid-mounted equipment.
MR. BURTON: Yes.
MR. LEITCH: Could you say a couple of
words about that?
MR. BURTON: That is, I believe, two
vu-graphs from now.
MR. LEITCH: Okay, fine.
MR. BURTON: I'll hold on to that one.
But I do want to say that given some of the initial
challenges that we had with the scoping portion of the
application, the scoping inspection was real critical.
We made sure that all of the reviewers who were
involved with the scoping had basically given us a
list of tasks for the inspection team, in addition to
the things that we had as part of our inspection plan
and primarily, we did take a sampling of the systems
and actually walked from the beginning of the
development of the functions for that system and
actually walked all the way through to see how they
scoped it, how they established the evaluation
boundaries and then ultimately how they did the
screening.
For the electrical portion, it was
actually somewhat done in reverse as Mr. Baker had
explained before. For that, they had identified all
of the electrical types, regardless, just all of them.
And then identified those that were passive and long-
lived and then from that population identified those
that met the scoping criteria.
DR. BONACA: Now you said that you went in
reverse, but I also saw in the SER that you reviewed
resistance as I mentioned before. So you went more in
reverse, you went --
MR. BURTON: Yes. Well, those were the
three. The reverse process that I spoke about is what
the reviewers pretty much did here at headquarters.
DR. BONACA: And their review of two of
those three systems showed everything that you would
consider in scope was in scope?
MR. BURTON: Yes, yes, yes. Okay, one
area that I know has come up with some of the previous
applications is the issue of design-basis events and
what population of events was actually considered in
the development.
At the time that the application was
submitted, Southern Nuclear was in the final stages of
putting together what they call the Nuclear Safety
Operational Analysis and that has subsequently been
finalized and actually been incorporated into their
FSAR, but at the time of the application, it was still
in draft form. One of the things that we did during
the scoping inspection was to take a look at this
analysis and what the analysis was was a comprehensive
consideration of all the design basis events and as
part of that, if you recall from the rule, one of the
things that's done is on an annual basis there is an
update to the application based on changes to any
changes that may have taken place to the CLB. What
Southern Nuclear did was because it was in draft form
at the time that the application was submitted, they
did commit as part of that annual update to take a
look at the results of that NSOA, Nuclear Safety
Operational Analysis and to update the LRA based on
any additional changes to the CLB that may have come
up. And they did that and I think as a result of that
there was maybe one additional, the rod block monitor
that actually came in scope as a result of that. But
as part of our inspection, we did take a look at that
NSOA as to understand exactly what DBEs were
considered in their evaluation.
As a result of our review of the scoping
methodology, we did come up with one open item having
to do with seismic II/I piping. Seismic II/I piping
current is not in scope. The staff had a disagreement
with Southern Nuclear about that. We viewed seismic
II/I piping as being part of the more general category
of non-safety related SSCs whose failure could
adversely, you know, the one scoping criteria.
From what Southern Nuclear has done is
they've identified the seismic II/I piping and have
taken the step of seismically supporting that and
their point of view is that given that it is
seismically supported, the fact that it could fail or
fall on safety-related equipment is basically
hypothetical at this point. So it is one of the items
that we have on the table and we are in continuing
dialogues trying to resolve that. So that is one of
our open items.
MR. GRIMES: Butch, and this is one of the
appeal issues. So for each of the open items that's
on the agenda for the appeals session that we're going
to have tomorrow, we'll identify those.
MR. BURTON: Okay, that's right. That is
one of four appeal items and I'll point those out to
you as we go.
DR. SHACK: And what exactly does that
mean?
MR. BURTON: Appeal?
DR. SHACK: Yes.
MR. BURTON: Good question. Appeal items
are open items where at least on the face of it the
staff and the applicant are fairly far apart and what
the license renewal process allows for is an appeal
process. The appeal process involves an airing of
each side to -- I guess for lack of a better word, a
panel. The appeal meeting that we're going to be
having tomorrow is basically at the Branch Chief level
so what we'll have is a staff and Southern Nuclear
each giving their view of the open item and why they
feel the way they do and we'll have several Branch
Chiefs and Chuck Pierce from Southern Nuclear who will
sit and listen to both sides and question and dialogue
and hopefully reach a resolution. If not, the appeal
process moves on where we will next schedule another
meeting at the next higher management level and we
will continue on through like that until we can reach
a reasonable resolution. That's what I mean when I
say appeal process.
DR. SHACK: Now was this used with the
other application? Somehow I don't recall hearing
about it before.
MR. BURTON: It's always --
MR. GRIMES: The answer is yes. We
established this as part of the procedures for the
conduct of the renewal review and it's consistent with
the approach of the staff asks one round of questions
and then drafts a safety evaluation with open items
and then the resolution of the open items is either
obvious by virtue of the staff's articulation of what
needs to be resolved or the resolution is then
appealed to successive levels of management and we use
this technique for Calvert and Oconee and it was quite
effective.
Now for Arkansas, they had six open items,
but there was only one appeal issue and that was on
the scope of fire protection equipment. And that
issue ended up being resolved at the first appeal. In
the articulation of the issue, the staff and the
applicant saw various lights and decided on a
solution.
And for Hatch, we've got four of the I
believe it's 17 open items, Butch?
MR. BURTON: Eighteen.
MR. GRIMES: Eighteen open times. Four of
the 18, there's a dispute and we need to air the
dispute in order to understand how the open item is
going to be resolved. If it's identified as an open
item and we don't designate it as an appeal issue,
then presumably you will gain some confidence that the
staff and the applicant understand what the issue is
and what it takes to get it resolved.
(Slide change.)
MR. BURTON: Okay, moving on to plant
level scoping results, Section 2.2 of the SER. We did
not have any open items, but I did want to take the
opportunity to point out here and actually Dr. Bonaca
had mentioned it in the last session. One of the
things that we found as the staff in reviewing, in
particular, Table 2.2-1 which several of you have
mentioned in the last session is that there were
several instances where when you look at a system and
all the functions that that system performs,
obviously, we know that there are certain things that
we know a certain system performs and in the
particular case I was going to bring up was
containment isolation. We know, for instance, that
main steam has a containment isolation function and
yet when our reviewer looked at the Table 2.2-1, did
not see that identified as one of the functions. This
is getting to what you were talking about before. And
so that naturally led to the question where is that
function? Why do you not have it there? And in our
dialogue with Southern Nuclear is when we came to
understand that certain functions that cut across a
number of systems, they chose to pull out and actually
have it in its own place. In this particular example,
it turned out to be under C61. But that's another
navigational issue that the staff had had to deal
with. So that's what I mean when I say grouping of
common system functions.
(Slide change.)
MR. BURTON: Section 2.3.1 of the SER was
just an introduction. And then we got into reactor
and reactor coolant systems. I've identified the four
systems that make up this group. Again, we found no
open items. We found that the scoping and screening
were appropriate. This is where we started to get
into dialogue with them about some of the BWRVIPs and
primarily many of the questions when we asked about
why something not in scope and why it is or is not, we
were referred back to some of the BWRVIP documents
that would identify that this is not an event that we
really think would happen and things like that and
that's why you would not see it as a system or a
component within a system that would have any aging
effects that would requirement management. And we
found some of the references to VIP in this section.
MR. LEITCH: There are a number of VIPs
referenced that are not yet approved by the NRC. How
did you resolve that issue in your own mind?
MR. BURTON: Yes, go ahead.
MR. ELLIOT: Barry Elliot. I was going to
address that later, but even though some of the VIPs
were not approved, we reviewed them and the reviews
were far enough along that we could look into them and
see how they applied to Hatch. And some of our open
items result from those reviews. And I'm going to
discuss that later on.
MR. LEITCH: Okay, thank you.
MR. BURTON: Let's see, where am I? We're
going to get to, Dr. Leitch, one of the things that I
had asked you to hang on with me for a second.
(Slide change.)
MR. BURTON: The next section involved the
engineered safety feature systems. There were eight
of them and I have them listed here. We did have a
couple of open items that came out of that. The
first, scoping and screening of skid-mounted
components for the hydrogen recombiners. This is a
complex assembly issue if any of you are familiar with
that.
We wrestled with this issue of complex
assemblies with Oconee and the emergency diesel
generators. At this point in the review, Southern
Nuclear has committed to actually doing the scoping
and screening in accordance with what was agreed to
and is now in the SRP that came about as a result of
the review of Oconee.
DR. BONACA: And it's also in the NEI
document, right? There is addressing complex
assemblies there.
MR. BURTON: It does address complex
assemblies. From what I understand the latest
revision of NEI 95-10 has made some modifications, but
I believe it is still basically there with a few
modifications, yeah. So we are actually on our way to
resolution on this one.
The second issue, this is one of the
issues that's going through the appeal meeting
tomorrow. Scoping and screening of housings for fans,
dampers and heating and cooling coils for the standby
gas treatment system. This is actually going to come
back again for a couple of systems in the next section
for auxiliary systems.
What this involves is housings for active
components. Under license renewal, fans, dampers,
these components are active. The staff's question is
that's fine, but what about the housings for these
components? We are looking at that similar to what is
currently in NEI 95-10 where they make the distinction
between valves and valve bodies or pumps and pump
casings. NEI 95-10 specifically identifies valve
bodies and pump casings as being passive and rightly
so. The staff is saying in the same vein the housings
for these active components are similarly, have
similar functions in terms of pressure retention,
structural integrity, things like that. So this is
another item that's on our appeal meeting for
tomorrow, on the agenda for our appeal meeting.
MR. GRIMES: Butch, if I may, in order for
you to understand our terminology distinctions, the
first is called the complex assembly issue and that
has to do with how groups of equipment are treated
with respect to potential passive functions and the
second one is we refer to as a piece parts issue and
it's not, again, it's not a new issue. In fairness,
from the applicant's perspective, it's how low do you
go in terms of breaking active components looking for
passive elements and we're going to hopefully learn
some, another lesson in this exercise that will help
us to clarify how you identify passive elements of
active components.
DR. BONACA: Yes. This already, these
issues were discussed already for the previous
applications.
MR. GRIMES: Actually, not this particular
twist.
DR. BONACA: I understand, but I believe
that housing for these kind of components for other
applications were included.
MR. GRIMES: They didn't come up in the --
this issue did not emerge in the previous reviews.
DR. BONACA: Are they in scope for Oconee,
for example?
MR. GRIMES: I'm prejudiced to staff's
findings. We thought the previous applicants had
treated the housings for ventilation system components
as part of the ductwork. And that's why it's at
issue. The applicant contends they didn't. Before we
go attack the other applicants, we're going to try to
settle the matter on this application first.
DR. BONACA: When I review this I thought
that this issue, not in specific, but in general, but
the components had been included. That was my --
MR. BARTON: That's the way I felt too.
DR. BONACA: Now when you -- in the
position of the staff, when you talk about, for
example, the housing of a certain component, it
identifies specifically a function for it and so
you're recognizing other pressure attending function
or obstruction contained in the function which is in
this license renewal.
MR. GRIMES: Correct. In order for the
staff to prevail in its position, there has to be a
passive function that -- passive safety-related
function that we're attempting to manage aging for.
DR. BONACA: Okay, thank you.
MR. BURTON: One thing I should have
pointed out before I got into all of this is how we as
the staff approach the scoping and screening reviews
which we've done from Day 1 is that things that the
applicant identifies as being within scope or being
subject to an AMR, we don't really question that.
What we really focus on in our review are things that
are not identified as being within scope or subject to
an AMR to see if those were actually identified
properly. And in fact, back in Section 2.2 with the
plant level scoping results, the primary effort for
that portion of the review was to go through that
Table 2.2-1 and actually look at the functions that
were identified as not being in scope and see whether
or not we agreed with that and we understood that. So
it's almost -- I don't know what you would call it, a
negative consent kind of thing. I don't know what
you'd call that. But that's how we worked through
these.
(Slide change.)
MR. BURTON: Section 2.3.4, auxiliary
systems. As you can see, we had 20 systems that were
divvied up amongst our reviewers.
MR. BARTON: Before you go past 2.3.4 are
you going to talk about 2.3.4?
MR. BURTON: No, it's in two slides. I'm
going to talk about it now.
MR. BARTON: Okay.
(Slide change.)
MR. BURTON: We did have some open items
here too. The first two are actually analogous to
what we had in 2.3.3, the issue of complex assemblies,
that diesel was another one where we had the same
issue.
DR. BONACA: Is that being contested?
MR. BURTON: No. This is as I said
before, they've agreed to do it like Oconee.
DR. BONACA: All right.
MR. BURTON: The second one here is the
same housing issue, in addition to standby gas
treatment in Section 2.3.3 it also applies to the HVAC
systems for the Control Building, Outside Structures
and Reactor Building. So it comes up. It's all
captured in one open item.
DR. BONACA: Sure.
MR. BURTON: But it's actually identified
in several different places.
A third open item in this section was
scoping and screening of fire protection system in the
radwaste building. Initially, this was not captured
as being in scope. The staff went through the fire
hazards analysis and disagreed with that being
appropriate. And I think at this point we have
actually gone through and Southern Nuclear actually is
going to bring this suppression system within scope.
MR. BARTON: That resolves one of my
questions.
MR. BURTON: Okay.
DR. BONACA: I thought in addition to that
was a proposal to have a one time inspection that the
staff wants to see as a program, is it?
MR. BURTON: That is going to come up in
the discussion in Section 3 when we do the Aging
Management Programs. And understand that as with
anything, if the final resolution is that something is
going to be brought in scope, we're also going to be
bringing in the Aging Management Review and any
applicable Aging Management Programs and assessment of
the effects, all the things that go along with
bringing that in scope.
MR. LEITCH: While you're on the auxiliary
systems, I guess I was a little confused about the
river water intake structure. How is that done at
Hatch? Not the circulating water, but the
-- I don't know what they would call it, the RHR.
MR. BURTON: I know, plant service water.
MR. LEITCH: Plant service water. Okay.
MR. BURTON: Okay, let me talk a little
bit about that. Commodity-wise, what -- the way the
application breaks down is they have an environment
that they call raw water. Raw water is made up
actually of -- consists of two different entities.
One is river water from which -- which is the source
for the plant service water. Another one is well
water which is used primarily for fire protection.
But they are both captured under the environment of
raw water.
So yeah, if you're asking about structural
stuff, that comes up in Section 2.4. But in terms of
the actual service water and that environment and
things like that, we actually have plant service water
that actually captures that.
MR. LEITCH: I guess my question is really
the pathway that leads to the ultimate heat sink. In
other words, you've got the RHR heat exchanger that's
cooled by plant service water.
MR. BURTON: Oh no, I'm sorry. Yeah, and
I don't have it listed separately out here, but
there's actually a plant service water and an RHR
service water.
MR. BAKER: Butch, if I could interject.
MR. BURTON: Please.
MR. BAKER: RHR service water doesn't have
a separate designation in Plant Hatch's numbering
scheme. It's a part of RHR, so it shows up on the
previous vu-graphs about the engineered safeguards
features.
MR. LEITCH: Okay, and what source does
that RHR service water -- where does it take suction
from?
MR. BAKER: It's at the intake structure.
The intake structure is a common structure for both
units. It has both plant service water and RHR
service water for each unit, specifically the Altamaha
River.
MR. BURTON: And it actually is called out
separately as one of the titles for one of the Aging
Management Programs. We actually have PSW and RHR
service water both what, chemistry and inspections.
MR. BARTON: Leave that on there, Butch.
MR. BURTON: Sure.
MR. BARTON: Maybe some of my problems
here are navigational also. I haven't consulted a GPS
on my boat that didn't help me.
(Laughter.)
Access door systems is talking about
containment doors. Within the reactor building there
are also, I would imagine, fire barrier doors and I
didn't see those covered under access doors although
I find fire doors and their management under fire
protection or is it not included at all in the
application?
MR. BURTON: Probably the best thing for
me to do is let them explain how they did it and then
I can turn it over to our reviewers.
MR. BAKER: Fire doors are covered under
the fire protection activities. Some of the access
doors may also be fire doors, so they may do double
duty.
MR. BURTON: And the actual commodity
group is actually structural steel when you go to the
Section 3 tables.
MR. BARTON: All right, and also in this
section control rod drive system? It's in this
section some place. Page 256.
Control rod drive system. I couldn't find
where the Aging Management Program is for the SCRAM
discharge volume.
MR. BURTON: Oh, oh, okay, okay. That was
actually -- I'm glad you said that because that helped
clarify things for me.
The SCRAM --
MR. BARTON: I'm glad it helped you.
MR. BURTON: We actually, if you go into
the SER, our scoping guy actually had a question about
the SCRAM discharge volume and how that actually was
captured, where is it, because it's not specifically
identified. You're right. This is a navigational
problem. It's very typical of many of the issues that
the staff had.
Now again, correct me if I'm wrong, but I
recall that the SCRAM discharge volume was actually
captured as piping, does that sound right?
MR. BARTON: Yeah.
MR. BURTON: It was actually captured as
piping and we had a phone call about that which is
documented in the SER. I can point that out to you.
MR. BARTON: See, my problem is I only had
certain sections of the SER to review, so it may be
some place else.
MR. BURTON: That's an issue. But I can
show you where that is. But that's very typical of
some of the navigational issues that we had.
DR. BONACA: In fact, on access doors, by
the way, you had request for additional information on
seals because you thought that they were not in scope
and then the answer was they were in scope, but the
reality they were not subject to AMR because they were
replaced or repaired based on the performance and
conditions under the preventive maintenance
procedures. And you accepted that answer that says
they are in scope.
That applies to any doors and seals, those
that function as fire protection barriers?
MR. BAKER: That's correct. It is both
the access doors, the fire barriers as well.
Those are -- all of the heavily traveled
doors, especially see continuous use and require
maintenance replacement of those seals.
MR. BARTON: So they're covered under your
preventive maintenance program?
MR. BAKER: Yes.
MR. BARTON: Cranes, hoists and elevators.
MR. BARTON: You're going to be here a
while.
(Laughter.)
MR. BARTON: I can't find where reactor
building, polar crane, well, that's not a polar crane.
The refueling crane, the 125 ton hook and the
auxiliary hook, where in their program are they
captured for tests? Don't you check the hooks for
-- inspect them and do mag particle and crack checks
or whatever? Aren't they covered in your program some
place? You talk about the component, the structural
steel and the crane, but how about the hooks?
MR. BURTON: I have to turn over to him
for those specifics. I'm not sure.
MR. BAKER: The lifting function part of
the crane was an active activity. The scope of our
review focused on preventing the crane from falling on
the safety-related components.
MR. BARTON: You don't care about dropping
a load, just that the crane doesn't fall?
MR. BAKER: Interestingly, the hatch
refueling floor, the main crane, the 125 ton crane is
a single failure proof crane with redundant rigging
and breaking in the CLB. It's probably unique in the
industry.
MR. GRIMES: Actually, I'm not sure --
this is Chris Grimes. I'm not sure whether it's
unique, but I recall there are certain elements, the
design of cranes that include linnets and stops and
administrative procedures to reduce the likelihood of
dropped loads, but it's an interesting question in
terms of the distinction between active and passive
features and so we can explore that further for you.
But I don't know that it came up during the course of
our review.
MR. BURTON: I certainly know that NUREG
0612 and 0554 for single failure proof, I know they
have a lot of provisions for just that kind of thing
and I'm sure as Mr. Baker would verify, I'm sure that
in the evaluation of a lot of these, where does active
end and passive begin is sometimes a question. That's
all I can say about that, but --
MR. BARTON: Drywell pneumatic system?
MR. BURTON: Okay.
MR. BARTON: I can't where air receiver
and drywell pneumatic nuclear boiler system
accumulator are subject to AMR. Are they someplace
else or not in the program?
MR. BURTON: That rings a bell as another
navigational item and let me just double check that.
(Pause.)
The reason why I'm saying that rings a
bell is I think that that was a question that our
reviewer asked about those kinds of things. I know in
several cases, I'm not sure whether drywell is one of
them, but the issue of accumulators and tanks and how
were they identified, because when you go to the table
--
MR. BARTON: Air receiver is another
example. I can't find air receiver.
MR. BURTON: It's a tank.
MR. BARTON: It's under tanks?
MR. BURTON: Tanks. And we had a number
of things like that.
MR. BARTON: All right.
MR. BURTON: The questions you're asking
are not unusual. I mean it's the exact same kind of
questions the staff had. Navigational questions. Go
ahead.
MR. BARTON: The question on insulation.
It didn't -- I couldn't see where insulation within
the drywell was subject to AMR. Is there a specific
reason for that or did I miss it? You talk about
insulation and what was in scope. I didn't see
anything within the drywell covered in that section.
MR. BURTON: All right, I promised I
wouldn't do this, the person who actually -- go ahead,
if you want to --
MR. GRIMES: Ray's volunteering to answer,
so let's let him answer.
MR. BURTON: Okay, go ahead, please.
MR. BAKER: The insulation inside the
drywell was initially scoped in during our review, but
during the process before we submitted the
application, Plant Hatch completed it's evaluation of
ECCS suction strainer issues, clogging issues and
we've determined based on the results of that that
there was no intended function for the insulation
inside the drywell and so we removed it from scope.
MR. BURTON: Okay.
MR. BARTON: The other system primary
containment chill water, but the piping inside the
drywell is covered in the program, but piping outside
is not? Is there a reason for that?
MR. BAKER: The purpose of the piping to
the extent that it's in scope is to form a part of the
containment pressure boundaries, to closed-loop inside
containment in that respect. So the piping outside
the isolation valves outside containment serves no
function.
MR. BARTON: This one is a little bit
different than navigation. The traveling water screen
and trash racks system, the SER describes screen and
racks must remain structurally intact during an
accident, but not required to move.
My question is based on this statement,
the applicant did not include screen wash lines and
motors and scope. What happens to the service water
flow as screens get plugged with debris during an
accident?
MR. BAKER: There are two aspects. You
have the trash racks and you have the traveling water
screens.
MR. BARTON: Right.
MR. BAKER: As I understand our CLB, the
structure, the intact structure part of that was to
protect against something like a barge impact or other
impacts from things on the river. There is no
indication of a problem with clogging due to the
design of the structure and the bays, the way that
that is arranged. It just is not an issue.
MR. BARTON: Then why do you have a screen
wash system?
MR. BAKER: That's an operational, as I
understand it.
MR. BARTON: It's not to take care of
grass or stuff that flows down a river after a storm
which gets through the racks. The smaller it gets
through the racks and it can't plug your screens and
it can't impact your service water flow?
That's an impossible scenario at Hatch?
MR. BAKER: I would not say anything is
impossible. I don't know the detailed --
MR. BARTON: I guess my question, why
aren't the screens in the program? It seems if you've
got them and they're there to remove debris so you
don't impact service water flow, I don't understand
how you exclude that from the program. That's my
comment.
MR. PIERCE: Well, one other aspect of
that and I'm not that familiar with the technical
discussion that you're bringing up, but I do know that
the CLB specifically states that the only credit being
taken for the traveling screens is the structural
aspects of it staying in place. If you go back into
our FSAR and look at that, that's specifically stated
and I'd have to go back to my people and discuss the
technical reasons of why that is.
MR. BARTON: You may want to talk to
people at Salem also.
MR. PIERCE: We owe you one on that one.
More?
MR. BARTON: Yes. The condensate transfer
system, pumps and piping are discussed as not being
essential water sources for accident mitigation, but
my question is aren't they a backup source and if
they're a backup source why aren't they included in
the program?
MR. BURTON: Could you repeat?
MR. BARTON: Condensate transfer system,
pumps and piping, it's in the SER, says may not being
essential water sources for accident mitigation, but
my question is aren't they a backup source and if
they're a backup source why aren't they included in
the program?
MR. BAKER: I don't believe they're a
backup source.
MR. BARTON: They're not a backup?
MR. BURTON: The condensate transfer
provides the transfer of demineralized water from the
chemical plant to the condensate storage tank.
MR. GRIMES: This is Chris Grimes and Mr.
Barton makes a good point in terms of the scoping
technique that's used for license renewal includes
those things that are credited in the accident
analysis as part of the current licensing basis.
Particularly in a BWR where there are so many
overlapping ECCS capabilities, we only capture for the
purpose of the Aging Management Review, those things
that are explicitly credited as performing intended
safety functions. There are going to be a series of
backup capabilities. They might not be captured in
the review because they are not explicitly treated or
relied on in preventing or mitigating accidents in the
current licensing basis.
MR. BARTON: That's all I've got.
MR. BURTON: So I guess to piggyback on
what Chris said, the thing that has really come
through with all of the applications is how -- what's
really come through is how important it is to really
know your CLB. The better you know it, the better it
is for all concerned.
And we found that in particular where
we've had problems like in fire protection, just the
whole history of fire protection is that people have
done a lot of different things with it and there have
been all kinds of exemptions to things and the issue
of the -- that I pointed out before about the fire
suppression system and whether or not it was in scope.
Being able to track through exemptions and changes to
the FHA and things like that speaks to the importance
of really knowing and understanding your CLB. And it
has come up from time to time.
DR. BONACA: Let me just propose that
these are good questions.
MR. BARTON: I'm done.
MR. BURTON: These are very good
questions.
DR. BONACA: Because it provides some
comfort to the committee that we can trace back some
of these issues although the navigation issues may be
there.
Could we get maybe an answer next week?
MR. GRIMES: Yes. I've noted the -- Mr.
Barton's questions. And we are going to go back and
explore each of those in terms of traceability for
Hatch specifically and then all these questions about
to what extent the current licensing bases capture
these capabilities. And I've got crane hooks, the air
receivers, the intake design and the condensate
storage tank water source.
Whether or not debris accumulation during
an accident is considered as part of the design basis.
MR. BURTON: Good, very good questions.
Okay. Moving right along to steam and power
conversation systems.
(Slide change.)
MR. BURTON: Again, no open items. When
all was said and done we saw that the scoping and
screening was proper. We did have a question on main
condenser and why it was actually captured in scope,
but at Unit 2, main condenser is credited as a hold up
volume during accidents, sort of played out things
like that. But no open items there.
Next we went into structures and
structural components.
(Slide change.)
MR. BURTON: We have 13 items in this
category. No open items. Again, we had several
requests for additional information. Some of them
were navigational in nature, but bottom line is once
we understood where the applicant was going, we saw
that they had actually scoped and screened
appropriately, so we had no open items in this
section.
The next section was electrical.
(Slide change.)
MR. BURTON: Fourteen systems were
identified in the application. These first couple Dr.
Leitch had already made mention of in terms of where
you could find them and actually as you were looking
in Section 2.3 you couldn't find them they were
actually in Section 2.5 under electrical. Again, no
open items, given that electrical -- the electrical
scoping and screening was actually sort of reversed of
how it was done with the mechanical and civil. They
identified component types. Identified those that
were passive and long-lived, in that population,
looked at the ones that actually met the scoping
criteria.
That's pretty much what I have for Section
2, the scoping and screening. I've got to do list.
Any other comments, questions on any of this?
DR. BONACA: I don't think so. Any
questions?
MR. BURTON: Okay, moving into Section 3,
I'm actually going to have some of the lead reviewers
actually discuss their sections, so I'll have them
come up and try and clear some of this out of the way.
MR. GRIMES: While Butch is doing a set
up, I think this might be an appropriate time to
respond to Mr. Barton's question about the Quality
Assurance Program and Rob, did you find --
MR. ELLIOTT: I couldn't find it on my
--
MR. GRIMES: Okay, couldn't find it on the
web, but the latest posted chart outside Sam Collins'
office of the Reactor Oversight Program is dated
January 25th and it shows to all of the performance
indicators for Hatch Units 1 and 2 are green, except
for one category and the EP03 category is designated
as unique, so it's not color coded for Hatch. So
they're green across the board on the performance
indicators.
For the inspection findings, there are
seven categories of inspection findings and some have
findings for one unit, but not the other. There are
five greens on the chart for the inspection findings
and nine no finding areas. So all of the oversight
indicators for Plant Hatch are in the green.
MR. BARTON: Thank you.
(Slide change.)
MS. KHANNA: Good morning. My name is
Meena Khanna and I'll be talking to you about Section
3.1 which is the Aging Management Programs of the
Hatch SER.
SNC originally identified 29 Aging
Management Programs. After a staff review, the staff
identified the need for an additional Aging Management
Program which is on non-EQ cables. Later, the
applicant did agree to add this Aging Management
Program on cables.
I'll be discussing the significant open
items that the staff has identified for the Aging
Management Programs listed on this vu-graph. Then
after my discussion, Jay Rajan will discuss open items
on the Fire Protection Aging Management Program.
Okay, the first one is Reactor Water
Chemistry Control Program. The applicant based its
Reactor Water Chemistry Control Program on EPRI
TR103515 which is the BWR Water Chemistry Guidelines,
Rev. 2. The staff is familiar with Revision 1, so
what we're asking, we've asked the applicant to
address the differences between Rev. 1 and Rev. 2 so
that we can understand what the aging effects for the
Reactor Water Chemistry Control Program, the
differences in the aging management effects that are
addressed in the reports. We're just asking for the
differences, so that we know, you know, what we need
to understand to review the program.
Okay, for the Diesel Fuel Oil Testing
Program, the applicant indicated that corrosion is an
aging effect for these diesel fuel oil tanks. So
therefore, the staff has requested that the applicant
address corrosion and lack of inspection for the
diesel fuel oil tanks.
DR. BONACA: And here, if I understand the
issue, the concern is --
MS. KHANNA: The one time inspection.
DR. BONACA: -- stagnant water?
MS. KHANNA: Right.
DR. BONACA: In the bottom that may cause
--
MS. KHANNA: Corrosion.
DR. BONACA: Corrosion.
MS. KHANNA: In these tanks, right. And
actually, in the report, if you look at the SER,
that's where we actually talk about the one time
inspection.
DR. BONACA: Yes.
MS. KHANNA: Okay.
DR. BONACA: If I remember, this was
already an issue with previous application.
MS. KHANNA: Right. We've done that with
all the other applications, we've asked for that.
DR. BONACA: This is an open item being
appealed?
MR. BURTON: No, this is not an appeal
item. In fact, what has gone on since issuance of the
SER is that Southern Nuclear has actually, I don't
know if you want me to speak on that or if you wanted
to -- they've actually done an inspection of one of
their large diesel generator fuel oil storage tanks.
Found no significant corrosion in the tank bottoms and
so now the argument is how applicable is that result
to the other three diesel fuel oil storage tanks as
well as the two smaller fuel oil storage tanks for the
diesel fire pumps. So we are in dialogue on that.
MS. KHANNA: Okay, going on to the Torque
Activities Program, the applicant did not identify
stress corrosion cracking as an aging effect for high-
strength bolting, however,
high-strength bolting is susceptible to SCC if it has
been heat treated to a high hardness. Therefore, the
staff requested that the applicant address the
susceptibility of stress corrosion cracking to high
strength pressure boundary bolting.
All right, for the Reactor Pressure Vessel
Monitoring Program --
DR. BONACA: Again, I would like to --
every time you go through one of these I would like
you to comment if it is, in fact, one which is being
appealed or not.
MS. KHANNA: Okay, I can do that.
DR. BONACA: To give us an understanding.
MR. BURTON: No, this is not an appeal
item, and in fact, this was spoken on a little bit
yesterday by Jim Davis with the high strength bolting.
MR. GRIMES: This is Chris Grimes. This
isn't a plant-specific appeal. This is an
industry-level appeal. As Jim explained yesterday,
the industry has challenged us in terms of the
evaluation guidelines, making the high strength bolts
or differentiating high strength bolts on a generic
basis.
But the applicant understands what our
expectations are for our ability to get to a plant
specific resolution of this.
MR. BURTON: Let me just say that none of
the items on this page are part of tomorrow's appeal
meeting.
MS. KHANNA: Okay, thanks. For the
Reactor Pressure Vessel Monitoring Program, the
applicant indicated that it plans to implement the ISP
which is the Integrated Surveillance Program, but is
currently under staff review. However, if the ISP is
not improved by the staff or if it is modified such
that Hatch is not going to be covered by the ISP, the
applicant has indicated that it would develop an RPV
Surveillance Program for the renewal period.
Therefore, this will remain an open item until the ISP
is approve.d
Finally, the RHR Heat Exchanger Augmented
Inspection and Testing Program, the applicant did not
identify vibration-induced cracking as an aging effect
for the RHR heat exchanges. The staff requested that
the applicant provide details regarding how the RHR
heat exchanger augmented-inspection testing program
manages vibration-induced cracking.
Okay, and if you don't have any further
questions on these Aging Management Programs, Jai
Rajan will continue on with Fire Protection Aging
Management Program.
MR. BARTON: Are you still on 3.1?
MS. KHANNA: Yes.
(Slide change.)
MR. RAJAN: I am Jai Rajan and I will be
discussing the two open items which were identified in
the Fire Protection Program.
The first item is related to the testing
of sprinkler heads in the fire suppression system.
And the second one relates to the sprinkler head
inspections intervals.
MR. BARTON: What was the second one
again?
MR. RAJAN: Sprinkler head inspection
intervals.
MR. BARTON: Intervals, okay.
MR. RAJAN: The applicant routinely
performs sprinkler piping float tests to check for
clogging from corrosion products. And this is done as
part of its normal fire protection activities.
MR. BARTON: They actually run water
through sprinkling systems?
MR. RAJAN: Through the sprinkler header.
The way they run this test is they open the sprinkler
head valve and the farthermost sprinkler in the system
and look for the flow through the valve to check for
clogging. If there is unobstructed flow, the flow
normally proceeds and that indicates there is no
clogging in the system.
The staff was initially concerned that
these may not be adequate for demonstrating
operability of all the sprinkler heads during the
extended period of operation. However, as the staff
position has evolved, the staff is no longer requiring
additional testing for checking flow blockage and
clogging in the piping headers, so this issue most
likely is going to be resolved.
MR. BURTON: Let me break in just for a
second. We spoke in some of the earlier sessions
about the impact of GALL, in particular, on the Hatch
license renewal application and I think we had
explained that due to the timing, they weren't always
able to incorporate some of the lessons learned from
GALL, but what we're finding is, as we're going
through this stage, as GALL, as some of the issues
related to GALL are being resolved, we're at a point
in our review where we can actually incorporate them
and this is one of them, the whole issue of the flow
testing of the fire headers.
DR. BONACA: And what's the solution that
GALL suggests? The question that was raised here was
that the testing of the just farthest most head in the
system is not a demonstration that the other heads are
working.
MR. GRIMES: This is Chris Grimes. The
way that the issue was described yesterday in relation
to GALL, it was described to us -- I've forgotten the
word. But it's the flow plugging issue where we made
the distinction between the active features of system
flow and the crud deposits' impact on corrosion and
the attack on the pressure boundary and so we do not
look at flow, loss of flow as a passive element, but
we do look at the impact of the crud build up as its
impact on an aging effect. And that's -- we've
applied that conclusion in this case.
And I don't know if you want us -- whether
or not you want to pursue the question about how these
tests -- how the active tests are performed relative
to how they test, flow through the sprinkler without
sprinkling safety-related stuff which is an issue that
has come up before.
DR. BONACA: Sure.
MR. GRIMES: And Mr. Barton says no, we
don't have to explain it again.
MR. RAJAN: Okay, now with regard to the
second open item, the sprinkler head inspection
intervals, the applicant is proposing a one-time
inspection at or before 50 years of service life. The
staff is concerned that this may not be sufficient for
an Aging Management Program throughout the extended
period of operation. The staff position which is
based on the National Fire Protection Association
Codes and Standards requires that where sprinklers
have been in place for 50 years, they shall be
replaced or representative samples tested for field
service operation in a recognized laboratory. And
after this initial testing, thereafter every 10 years.
So there is a clear distinction between the staff
position and what the applicant is proposing and so
this remains an open item.
DR. BONACA: Is this being contested?
MR. BURTON: Yes. I was going to say
neither one of these items are on the agenda for the
appeal meeting right now.
DR. BONACA: So that would substitute a
one-time inspection with a program?
MR. BURTON: Yes.
MR. RAJAN: That concludes my
presentation.
MR. BARTON: I have a question on 3.1,
Butch. Torus Submerged Components Inspection Program
talks about lots of components within the torus --
where is the torus itself covered?
MR. BURTON: Yes, containment.
MR. BARTON: It's under containment?
Okay.
DR. BONACA: I have a question on the
embedded components. This is listed under passive
component inspection activity. There is a program, I
believe, the Passive Component Program. Okay, so it's
an existing program right now. Right? Or is it a new
program? New program.
And if I understand it. It's similar to
what we have seen in other applications which is
essentially in case you have maintenance activities or
design changes that will expose embedded piping, then
you will perform inspections. Okay, so that's the
same program that we have seen before?
MR. BURTON: Yes. Let me speak to that
very briefly, because that was one of the items that
we looked at in our second inspection which we just
completed a couple of weeks ago.
The issue of buried and embedded
components, both mechanical and structural, you know,
our concern was -- and the purpose of the second
inspection was to see how these things were actually
implemented with the on-site procedures. And what is
actually done is yes, the Aging Management Program
that you mentioned also the Protective Coatings
Program and the Structural Monitoring Program also
have provisions to make sure that when structures or
buried components are dug up for some reason that we
take that opportunity to inspect them and take a look
at them and we actually have looked at their
excavation procedure on site and they have actually
proposed changes to that procedure to make sure that
when they do excavation, there's a heads up in the
procedure to actually do that.
DR. BONACA: Now this is an activity that
takes place irrespective of whether or not you have
indications from exposed piping that there may be some
problem with that, right?
MR. BURTON: That's correct.
DR. BONACA: In case you do have
indications, then you would have a more aggressive
program, go after -- and there is provision under the
program or is this separate provision, the one that
says that should you have indication in structures
that from exposed equipment that embedded equipment
may be affected, I thought you had a specific program
for that?
MR. BAKER: I don't recall the detail of
the Passive Component Inspection Program as to whether
it has a scope expansion item in it. We'll go look
and get an answer for that.
DR. BONACA: I appreciate it. Thanks.
MR. GRIMES: This is Chris Grimes. To try
and avoid some further confusion in the Generic Aging
Lessons Learned, we referred to this as inaccessible
components and there was a distinction between those
things that are covered by the code, the structural
elements under IWE were treated separately from
inaccessible -- other inaccessible features that are
covered by the code, and then of course, anything
that's not covered by the code we treat it as
inaccessible in a broader way.
DR. BONACA: Okay. Thank you.
(Slide change.)
MR. ELLIOT: I'm Barry Elliot, Materials
and Chemical Engineering Branch of NRR. I'm going to
discuss the reactor and reactor coolant system. The
reactor and reactor coolant system is the reactor
pressure vessel, the reactor vessel internals, the
reactor recirculation loops, the reactor coolant
system piping and valves which includes the main steam
line, the safety relief valves, the main steam
isolation feed water lines, feed water line check
valves and instrumentation and control.
There are 15 Aging Management Programs
associated with these components. Two of them, the
Boiling Water Reactor Vessel and Internals Program and
the Reactor Pressure Vessel Monitoring Program
reference the BWRVIP Programs. There are 12 BWRVIP
Program Reports that establish guidelines for
inspection during the license renewal period. The
Reactor Vessel Report -- we have not completed review
of the Reactor Vessel Report, however, we have
reviewed it relative to Hatch and it's referenced in
our safety evaluation how it affects Hatch and we're
satisfied with what Hatch has provided to resolve the
reactor vessels issues.
The other BWRVIP Report that is not
complete for review is Core Shroud Report and the Core
Shroud Report for inspection, the inspections during
the current license term are being carried over into
the license renewal period and that's found acceptable
by the staff for Hatch.
And the last one that we haven't
completed, but we really have completed, we just
haven't put the SER on is the jet pump assembly and
that takes care of all the ones that are as far as
inspection is concerned.
As far as open items, I would like to say
that BWRVIP did a wonderful job of looking at all of
the current issues that projecting them out into the
future. However, we have two issues that we think
they need to address. First, is a loss of fracture
toughness resulting from neutron irradiation for the
CASS jet pump assemblies and the fuel supports. The
CASS stainless steel is composed of two phases, a
ferritic phase and an austenitic phase and the
ferritic is subject to thermal embrittlement and
neutron irradiation embrittlement. And I mention
neutral irradiation embrittlement here because I think
that thermal embrittlement is not going to be a
problem here, in particular, because the BWRs operate
at much lower temperatures and that should make the
thermal embrittlement less of a problem.
The flip side of that is the lower the
temperature, the more neutron embrittlement you get.
So this is why we're concerned about this. And we
think that this is an area where inspection -- if we
don't see flaws, if we don't see cracks in the CASS
stainless steel components, then we wouldn't be
concerned about the loss of fracture toughness. And
this is a case where an inspection of the limiting
component, CASS stainless steel components would be
appropriate.
DR. BONACA: It's a one-time inspection
you're asking for?
MR. ELLIOT: Yes.
DR. SHACK: Just on that very -- is the
CASS part of that, has that ever been observed to have
-- there's jet pump fatigue problems, but has it ever
affected this CASS component?
MR. ELLIOT: At the time we don't have a
problem with CASS stainless steel components, but
current inspections are of the welds and the adjacent
material. So we're going to ask that it be expanded
a little bit.
DR. BONACA: And you can see that the jet
pump assembly components as the limiting component for
CASS assembly?
MR. ELLIOT: Yes.
DR. BONACA: Okay.
MR. ELLIOT: The second issue is cracking
of the small-bore piping. Our concern here is that we
are giving a license for 60 years and in the first 40
years we're not going to do any volumetric inspection
of small-bore piping and so we think that it's
necessary to do a one-time inspection to convince
ourselves that cracking isn't occurring on these type
of lines and a sampling of lines would be appropriate
of the small bore piping. We prefer -- the
susceptibility here is to -- what we're worried about
is stress corrosion cracking in and turbulent
penetration and stratification, fatigue issues. And
if we can get the most susceptible components
inspected, we'd be satisfied and again, a one-time
inspection.
DR. BONACA: And it would be just for a
specific limiting components?
MR. ELLIOT: Right. If that can be
judged. If it can't be judged, then we would just
take -- we would look at the consequences and maybe
take the components with the most consequence and
inspect those.
DR. BONACA: Are these open items being
appealed?
MR. BURTON: No appeal on these.
DR. BONACA: I have a question --
MR. PIERCE: Let me -- there are some open
items that we're still in the process of working out
with the NRC and if we -- and at some later date we
may take an open item into an appeals stage later,
even though we're not appealing them tomorrow, they
could come at a later time.
DR. BONACA: I understand of the ones that
you already are dealing with, I understand you have
these options, sure.
MR. GRIMES: Dr. Bonaca, this is Chris
Grimes and I want to take this opportunity to point
out this is another one of the GALL appeal issues that
we discussed yesterday.
DR. BONACA: Yes.
MR. GRIMES: The industry has challenged
the need for one time inspections on small-bore
piping.
DR. BONACA: Yes.
MR. GRIMES: On a generic basis.
DR. FORD: I have a comment. I agree with
you that on the VIP reports relating to disposition of
stress corrosion cracking of austenitic alloys,
stainless steels, the nickle base alloys. It seems as
though the disposition curves are reasonably
conservative. I would have a bit concern, however,
about the conservatism for the alloy steel stress
corrosion cracking enunciated in I think VIP-60.
It relates to -- if, in fact, those are
not conservative curves for alloy steels, then we
could have a safety issue for cracking at the H9 weld,
for instance, or at the core penetrations and then the
bottom head.
What assurance do we have that as more
-- if there is more data coming out, to show that
those can't -- 60 disposition curves are not
conservative, can we address those?
MR. ELLIOT: Gene is coming to the
microphone.
MR. CARPENTER: Yes, Dr. Ford, just
because of you, Dr. Ford, yes. Gene Carpenter of
EMCB. As we discussed yesterday in the BWRVIP
Program, the program is looking at the Aging
Management Program consists of all the INE documents
and those are supported by the crack growth and the
various mitigation documents, including the BWRVIP 60
documents just referenced.
If the staff finds or the industry brings
to our attention that there are nonconservatisms that
come along due to aging, we will revisit the programs.
At this time, to the best of our knowledge, this 60
report appears to be accurate.
But if it does not continue to be so, we
will come back and relook at it.
DR. FORD: And following on from that,
what programs shall we have in place for monitoring
the cracking of those very thick section components,
H9 and the bottom head. How will we know if they're
not cracking?
MR. CARPENTER: And again, the inspection
programs that are called out are the ones that will be
doing those monitoring and as was pointed out
yesterday, the industry provides to us on a semi-
annual basis a listing of all the inspections that are
done for every plant, so we would be able to see if
there is any trending of cracking occurring.
MR. DYLE: If I could, this is Robin Dyle
for Southern Nuclear. Peter, the other thing that
maybe I didn't make clear yesterday, one of the
documents that we credit in our application is VIP-38
which is the document that requires the inspection of
the H8 and H9 welds, so there are inspections being
done.
Because of some overseas incidents of
cracking, we're evaluating the impact of that.
Whether the document should be revised or not and will
incorporate the appropriate results and we have on-
going work with the staff. They're aware of the
situation, we are and we're working on it, but the
inspections are being done at H9.
In accordance both with VIP-38 and it's
currently required by Section 11 to be inspected also.
DR. FORD: If there was cracking it would
be a huge safety concern. And that's why I bring it
up.
MR. DYLE: And there's quite a few
evaluations that have been done to assess that. It
was done as part of the VIP-05 report which this
committee has reviewed several times to look at the
possibility of what happens if you have stress
corrosion cracking that might propagate from clad into
the reactor vessel. But it's been thoroughly
investigated.
MR. ELLIOT: Your question had to do with
the internals or was it to the vessel?
DR. FORD: Vessel.
MR. ELLIOT: I'm going to answer the
vessel question. That's my area. And we don't think
that stress corrosion cracking of the alloy steel is
an aging effect we have to be concerned about. Let me
tell you why. We've had a few cases where we have
seen cracks go through the clad and they just don't
propagate. They go through the clad and they just --
we inspect them year after year, not year after year,
but every 10 years. And they just don't go anywhere.
They just stop right there, they blunt. The other
case is a summer case, is whether the cracks went
right through the Iconel 183, got to the carbon steel
and stopped. So that was primarily more due to stress
corrosion cracking and so we've seen in our experience
that stress corrosion cracking of low-alloy steel is
not an issue that we're concerned about.
DR. FORD: I would agree entirely with you
for 99 percent of the cases and you're absolutely
correct. However, there have been at least one case
as I know of, if not two where a crack has penetrated
considerably into low-alloy steel underneath the
cladding.
MR. ELLIOT: And I would say this, when I
say it's not -- we don't consider it an issue. We
looked at it as far as the BWR VIP-05 which was the --
we talked about yesterday which was the
circumferential welds and that -- in that analysis was
done two ways. We did it one way and the industry did
it another. The industry's way was a probability
argument, a probability analysis. In their analysis
they looked at the probability of a stress corrosion
crack based upon their experience penetrating and then
they grew the initial crack based on those
probabilities and was able to through the Monte Carlo
simulation technique, determine the impact of stress
corrosion cracking on fracture of the weld and it
turned out from their method of evaluation that it was
not significant and the failure probability on the
circumferential welds were very, very low.
DR. FORD: I agree with you in principle,
yes, but given the severity of a problem I would
question whether the data upon which such statistical
analysis such as experimental data is up to the
quality for this severe a problem, potential.
MR. ELLIOT: And I agree, it's a potential
problem. What we're doing is we inspect the axial
weld. They're at higher stresses than the
circumferential weld, so they are sort of like the
limiting material and if we see stress corrosion
cracking of the axial weld, then we could go to the
circumferential weld. I'm not saying we don't think
it's significant. It doesn't mean we're not
interested in it. We're interested in it and we have
an inspection for it. But we just don't think, based
upon our experience that it's a significant issue.
DR. FORD: I won't belabor the point any
more.
DR. BONACA: It's a well-taken point and
I think -- I have a question just regarding the void
swelling.
MR. ELLIOT: The what?
DR. BONACA: Void swelling. The fact is
of the problem. Now I agree that it shouldn't be a
problem because the plants are not running at the
temperature that would justify that, just in the SER
it's confusing because it says since BWR reactor
vessel has relatively low nuclear neutron fluence and
the applicant would perform inspections in accordance
with the -- I mean is it an issue or is it not?
MR. ELLIOT: We don't think it's an issue
because it's at lower temperatures. But even if it
was an issue, even if it ever became an issue, they're
doing inspections already of the critical areas of the
core shroud. It would show up as cracking or
something.
DR. BONACA: Yes. Okay.
DR. SHACK: They have much more likely
problems to occur if they do have a strike force.
DR. BONACA: I understand. I'm only
saying that they're not specifically doing this
inspection to look at swelling because swelling is a
credible issue there. I think that's -- all right.
I was trying to understand if it is will an issue and
they're looking for it.
MR. ELLIOT: No, they're not looking for
it. It's lower temperature and it's not an issue.
DR. BONACA: You are saying if it was
active then something would be a problem. That's a
different story. Thank you.
MR. BURTON: Okay, next we'll talk about
the ESF systems, the auxiliary systems, steam and
power conversion systems and Carolyn Lauron will do
that.
(Slide change.)
MS. LAURON: Okay, my name is Carolyn
Lauron and today I'll be presenting the next three
sections, the summary of the Aging Management Reviews
for the Engineered Safety Feature Systems, the
Auxiliary Systems and the Steam and Power Conversion
Systems.
Let me preface my presentation with a
statement that the concerns identified by the staff
during their review has been addressed in a previous
section, the Aging Management Program Section which
was discussed earlier by Meena Khanna.
The ESF system consists of eight different
systems and includes a wide range of materials and
environments as noted on the slide. The staff did not
identify any open items.
The auxiliary system consists of 20
systems and encompasses, once again, a wide range of
materials and environments and the staff did not
invite any open items.
The steam and power conversion system
consists of the electro-hydraulic control system and
the main condenser system and once again, the staff
did not invite any open items.
If there are any questions -- if there
aren't any --
MR. GRIMES: Wait, wait, wait.
(Laughter.)
MR. GRIMES: This is Chris Grimes.
Carolyn scores extra credit for really moving right
along on the schedule.
MS. LAURON: Thank you.
(Laughter.)
MR. GRIMES: I just wanted to make sure
that the committee had ample opportunity. There were
a number of questions that you brought up in scoping
the screening and Mr. Barton's questions about the
crane hooks, the intake design, we've noted those and
we'll work to get answers on those, but are there any
other questions related to the Aging Management
Programs associated with --
MR. BARTON: I didn't have any in that
area, Chris.
MR. GRIMES: Okay.
MR. BARTON: I don't know if the rest of
the committee did.
(Slide change.)
MR. ASHAR: I am Hans Ashar, Mechanical
and Civil Engineering Branch and I'm going to talk
about SER Section 3.6, Structures and Structural
Components. Thirteen structures/structural components
are included in this area. Originally, I believe we
had 46 open items in August of last year. The problem
more was navigation and where is what kind of a thing
more than anything else. I think we are left with
three open items now and out of three, I think two of
them we have closed them after you received your SER
copies and I am going to talk about those two and the
third open item is still open and it is one of the
appeal items.
Let me first talk about the items which
have been closed since you saw the SER. First item is
torus corrosion in which we requested applicant to
tell us as to where the torus penetrations are being
addressed and how the torus penetrations are being
managed as far as the aging is concerned. Again,
partly integrational and partly informational
provided. There is enough Aging Management Programs
to cover the torus corrosion as well as the
penetrations within the torus corrosion and they
provided us with -- it's been a very nice drawing
which saved 10,000 words more or less saying that
which area is called by what Aging Management Program
below water, above water, so it was very descriptive
and that item was closed.
MR. LEITCH: Is the torus at Hatch, is it
coated? Does it have a zinc --
MR. ASHAR: The torus is coated, yes.
MR. LEITCH: And the inspection of that
coating is --
MR. ASHAR: It's part of the Coating
Management Program, yes.
MR. LEITCH: Okay.
MR. ASHAR: The second open item which we
closed was related to the gears, latches and linkages
which were mainly related to the access openings. Our
concern -- now this was also in parallel with a GALL
item and let me go into that. In GALL, we have the
same items being recommended as part of the GALL
evaluation. However, the basic reason why the
industry complained that hey, it is an active item and
they're going to be monitoring during the opening and
closing of the doors and latches. The concern that we
had was because the outages, you know, during
operation of the plant, when anything can happen and
if they don't properly close and they go to aging,
what would happen to them? And I'm right now
referring to GALL and then we'll come back to Hatch
specifically.
In GALL, we resolved this item when the
safety reviewed a number of programs, particularly IS,
due to IWE, IS program and then Appendix J testing
during the time when they opened any equipment access
opening and they inspect them and they close it. They
go to 5B testing. So -- this particular answer is
that there are enough things there, so what we did
identify these three items such as IWE, IS, Appendix
J and but in the evaluation we said no, so far as the
programs is in effect. So on the same basis, we
closed the open item in Hatch.
Now the third item, this is still an open
item --
MR. LEITCH: Excuse me, there's a term
used in that discussion Nelson frames.
MR. ASHAR: Yes.
MR. LEITCH: I'm not -- it's a term I
don't understand. What is Nelson frames?
MR. ASHAR: Nelson frames are -- you want
to expand on that?
MR. BAKER: The reactor building
penetrations for electrical conductors essentially
consist of a large structural frame with then inserts
that are used for the cables to penetrate through.
That entire assembly is commonly called a Nelson
frame.
MR. LEITCH: Okay, thank you.
MR. ASHAR: The third open item still is
open and it is related to the reactor building
controlled leakage characteristics. The applicant
argues that we got a very in-depth instruments
inspection requirements, structural monitoring and
looking at all the access doors and we are going to
make sure that on a periodic basis that the aging
management is being conducted.
However, the staff -- the secondary
containment building including the SGT, the standby
gas treatment system requires certain amount of vacuum
in the building in order to make sure that the SGT
will work or during an accident. And for that the
staff is insisting that there has to be some kind of
an Aging Management Program to make sure that the
characteristics of the reactor building for secondary
containment is maintained, the way it is in the
current license.
MR. GRIMES: This is an appeal issue.
MR. ASHAR: I would like have some
thoughts from you too because it's going to be an
appealed and I would like some help or words from you
guys.
MR. BARTON: What, do you want a vote?
MR. ASHAR: No vote, but just your
opinions.
DR. BONACA: Well, clearly, we will be
looking at these things, but just because there is an
appeal, it seems to me that it's important we reflect
on that before we decide on one perspective or the
other. I think we need to see how the members feel.
MR. GRIMES: This is Chris Grimes. I'm
sure that you'll give us a reaction when we tell you
how we've disposed of the appeal issue.
(Laughter.)
DR. BONACA: That's right.
MR. LEITCH: I had a couple of questions
in that section. Yard structures, on page 3-180. I
wonder if that goes as far as the switchyard. I'm
thinking particularly about a transformer, tanks,
circuit breaker tanks. Did the review go out into the
switchyard and were those types of tanks considered as
passive structures?
MR. ASHAR: I would defer to David Jeng.
Maybe he can -- he was the main coordinator in that
entire area.
MR. JENG: I am David Jeng. To answer
your question, I think the yard structures in our
section particularly covers the pad that anchors and
the structure support elements. As to the components,
the transformers, I think they should be covered
within the system. So we did not review the component
as I say, but we review the supporting anchors in the
frames and so on and make sure they are properly
married to aging effects.
MR. LEITCH: Okay, so the transformer
pads, so to speak --
MR. JENG: Anchor bolts.
MR. LEITCH: Anchor bolts.
MR. JENG: And supporting frames. These
are the things we talk about.
MR. LEITCH: Well, then is there someone
that can address the issue of transformer tanks and
circuit breaker tanks?
MR. GRIMES: I would suggest the applicant
respond.
MR. BAKER: The scope of the electrical
part of the plant is at the 4160 volt level as it
comes into the plant from the supply from off-site.
As a result, the electrical switchyard that you're
referring to, none of the items in that electrical
switchyard are in scope at Plant Hatch.
Now the entire diesel generator building
and this includes the ability to supply the alternate
sources of AC, from there in is all in scope.
MR. LEITCH: Now is the switchyard not in
scope by definition or it's not in scope because it
doesn't meet the criteria?
MR. BAKER: We evaluated against the
criteria and it did not meet the criteria.
MR. LEITCH: Okay. I understand. And I
guess I have a similar question on the end of the
plant regarding the intake structures. Did any of
that thought go out into the river, I'm thinking of
silting that may occur over long periods of time or
changes in the characteristics of river flow, river
soundings and so forth.
MR. BAKER: As I recall, we addressed
siltation at the intake structure as a part of the
application.
MR. LEITCH: And there is a program then
to sound that area periodically or how did that --
MR. BAKER: We send divers down.
MR. LEITCH: Okay.
MR. BARTON: Although the switchyard isn't
a scope, who owns the switchyard? Does the plant own
it or does something else in Southern Company own it?
The maintenance programs in the switchyard are
performed by who under what process, under what
program, under what procedures?
MR. PIERCE: I can check on that during
lunch, but I am reasonably certain that currently
today, the switchyard is being maintained by Georgia
Power Company.
MR. BARTON: Not the plant.
MR. PIERCE: Right.
MR. BARTON: And it's under Georgia Power
Company's procedures, processes, programs and not the
plant's?
MR. PIERCE: There are some elements of it
that I think the plant gets involved with, but I'll
have to check on that.
MR. BARTON: I'd like to know what the
plant's involvement is.
MR. BAKER: Just to follow up on that,
this is an area that was discussed somewhat in the
environmental review part of the discussions as to who
performed the routine procedures for the switchyard
and for the transmission lines. So we have that.
DR. BONACA: I have a question regarding
the unit. Does the plant have a program to monitor
building settlement, if any? And at what point do you
feel that during the life of this plant settlement may
affect somehow structures or impingement on piping and
--
MR. BAKER: In the original licensing of
the plant, building settlement and differential
settlement between structure and soil was considered.
There were technical specification requirements to
monitor that. That monitoring showed that the
consolidation settlement was essentially complete by
the time construction was finished. There were some
concerns at one time regarding a possibility of
differential settlement between structure and soil at
the intake structure. There was some remedial actions
that were taken there. Subsequent to that there's
been no indication of any additional settlement
issues.
MR. JENG: This is David Jeng. I'd like
to supplement this answer. Settlement is a general
issue. If the structures are in the scope in the
design CP, OL review has been reviewed and accepted to
determine to be adequate, there's no concern. In the
license renewal, we did not come across any special
concern from the standpoint of RAI.
DR. BONACA: Okay. I was more curious
than anything else. The other thing I would like to
do, by the way, we're close to the end of the Section
3 presentation. I would appreciate at some point if
the applicant could give us a very brief summary of
operating experience. If you look at the application
and then the SER, there is substantial information
provided in different sections regarding particularly
the operating experience for crackings and so on and
so forth, but it would be good for us to have a
feeling about what are the major issues that the
applicant is tracking right now that they consider,
they focus on mostly. So just for our benefit.
(Slide change.)
MR. BURTON: Just briefly, the next
section was 3.7, again electrical components. We
looked at 14 systems and again, we found that the
Aging Management Review and the Aging Management
Programs seemed to be appropriate to manage the aging
effects associated with this. The only issue which we
had already talked about before was the additional
Aging Management Program that came into play for the
non-EQ cables. That's it.
MR. BARTON: Butch, I know yesterday in
the discussion in the electrical area, that electrical
cabinets were in scope, but switch gear was excluded
from aging management. Is there a logic for that?
What in switch gear is not -- is excluded from the
program?
MR. BURTON: Okay, this was part of
yesterday's discussion?
MR. BARTON: Yes, I believe so.
MR. BURTON: I probably need to call in
our electrical person. Paul? Paul Shemanski.
MR. SHEMANSKI: Paul Shemanski, Electrical
Branch. Basically, switch gear are excluded by the
rule.
MR. BARTON: Okay.
MR. SHEMANSKI: And the basis is that they
contain for the most part active components which are
--
MR. BARTON: How about the cabinets
themselves?
MR. SHEMANSKI: Well, the cabinets would
be in scope because they're the -- they would be in
from a structural standpoint.
MR. BARTON: That's why I'm confused. You
talk about electrical cabinets in scope and switch
gear not in scope. When you talk about electrical
cabinet, how about a 4160 switch gear room that's
contained within a cabinet and you've got breakers and
dials and indicators and meters. Is the cabinet
itself an electrical cabinet that's in scope or not?
MR. SHEMANSKI: My understanding is that
the structural --
MR. BARTON: The cabinet that's bolted to
the concrete.
MR. SHEMANSKI: That would be in scope and
that would evaluated for aging effects such as
corrosion, whatever else, but the internal components
--
MR. BARTON: I understand internal
components. They all move in something. I thought
the definition that was given, the description that
was given talked about breakers and switches,
etcetera, as not being in scope and I can understand
they're active components, but then it said switch
gear. I'll have to find it. It was in yesterday's --
it said switch gears excluded. I was trying to
determine what they meant by switch gear. Was that
the cabinet itself and there's also electrical
cabinets are in scope. What's electrical cabinets?
Is that all motor control centers and switch gear, the
outer envelope, the housing so to speak or is it more
than that?
MR. SHEMANSKI: Basically the housing, the
structural cabinet would be in scope, the metal, okay,
the enclosure itself would be in scope, again, the
internals are out of scope because --
MR. BARTON: I can understand the
internal. I understand that.
MR. SHEMANSKI: But electrical cabinet,
panel, enclosure, that would be in scope and would be
evaluated for aging effects of corrosion, rust, that
type of thing.
MR. BARTON: Okay, thank you.
MR. BURTON: Okay, that's pretty much it
for section -- I'm sorry. That's pretty much it for
Section 3. Comments, questions?
DR. FORD: I have a much more general
question. A lot of your argument for the aging
managing, especially for environmental degradation
problems, based on the VIP documents which are
primarily deterministic based on data and you come up
with a deterministic upper bound, admittedly
disposition curves. I haven't seen anywhere and I'm
talking from lack of knowledge because this is the
first time I've been on this committee, I've seen
very, very little reference to use of extreme value
statistics, bearing in mind that we're really
concerned about the first event. That's what's going
to kill us. So has this a place in all of these
evaluations?
When will a first event occur which is
going to kill us all?
MR. GRIMES: Somehow I have a feeling that
question is in my job description.
And I would emphasize that if you look
very carefully at the statements of consideration of
the license renewal rule, I think the industry
originally argued that -- we don't need to do anything
for license renewal by virtue of we've got regulatory
processes and look at operating experience and when
stuff breaks, we fix it and we've been doing that fine
for 25 years and let us have another 20 years.
The Commission concluded that while we've
got maintenance rule and we do have confidence in
active components because they break a lot and we've
got a large data base from which we can draw
reliability information. And it's that data base that
led us into the maintenance rule and its requirements
in order to monitor very carefully the information
that's used to derive reliability and failure rates
and core damage frequencies and other information
that's used to try and be informed about risk. But
for passive things like the fracture toughness of the
vessel or sprawling -- did I say that correctly?
Spalling. Sprawling was probably Freudian in terms of
my vision of structural inspections.
(Laughter.)
But the Commission concluded that because
these are rare events, we do not have large -- we
don't have a large data base to draw on for the
failure rates of tanks and pump casings and structural
elements and they do not get challenged in the way
that they will be challenged if an accident occurs.
And for that reason we will look to ensure that there
are Aging Management Programs that are going to
monitor the condition that are going to identify when
applicable aging effects appear to the extent that
they jeopardize the intended safety functions.
So the entire focus of this review is
almost the inverse of your question and that is
because there is a lack of data and reliability values
associated with these functions, we concentrate on the
inspection and maintenance practices that are relied
on in the current term and to what extent do they need
to be modified, adjusted or augmented for an extended
period of operation so that as new failures occur in
the future that there's a process in place that's
going to account for new information and adjust
according to aging effects in such a way as to
continue to maintain the condition of the system
structures and components so that we have reasonable
assurance that they'll perform their intended
functions for the period of extended operation.
Did that answer your question?
DR. FORD: Yes. You've been proactive, to
a certain extent proactive.
MR. GRIMES: Right.
DR. FORD: You're going to hope to see it
before it becomes --
MR. GRIMES: We're going to hope to see it
and if we haven't seen it we've got a process in place
that by through the corrective action process it will
reveal an aging effect that was not considered in this
revised licensing basis and then we would expect a
corrective action process to say we don't have a
procedure to manage this aging effect. Now we need
one.
And I think that the issue is more clearly
illustrated in some of the industry comments on
Generic Aging Lessons Learned where you see these one
time inspections. They're aging effects that the
industry believes don't warrant an aging management
program, but at the same time they're not so out of
the question that we could simply dismiss them as not
applicable and in those cases, we've insisted on a
one-time inspection in order to provide a benchmark in
time that says is there any evidence that it's
occurring. if there is any evidence, then the process
will account for that.
DR. BONACA: Okay. Before we take a
recess for lunch, it will be interesting to us to hear
just a brief summary of the operating experience and
all you had, for example, cracked sparger. It wasn't
clear to me that you had both at Unit 1 and Unit 2.
You also had indication of -- so just a summary of
operating history and what is -- which is focusing
mostly on inspections right now?
MR. PIERCE: Yes, I think Robin could
probably answer some of the discussions on some of the
internals in operating experience. At a broader
level, we do have an individual that is calling down
at the plant to make sure that we give you the right
information. So it might be better to do that right
after lunch and just go through the whole thing,
including what Robin has, if that's okay with you.
DR. BONACA: Okay, sure. No problem. And
again, remember I'm asking you for just a summary in
the application, interspersed in so many locations
operating experiences. At times you lose a little bit
sight of what are the major issues that right now we
are facing or you are concerned with. Some of them
seem to be disposition, once and for all, so that kind
of information.
MR. PIERCE: Right, and that's why we
wanted to go down to the plant and make sure that we
had a good understanding of they viewed the major
issues were for operating experience.
DR. BONACA: Okay, with that I think we'll
take a recess for lunch and I would like to start the
meeting at 1 o'clock. We don't need an hour. I have
to catch a plane pretty early, so why don't we just
start the meting again at 10 of 1. Okay?
(Whereupon, at 11:57 a.m., the meeting was
recessed, to reconvene at 12:50 p.m., Wednesday, March
28, 2001.)
. A-F-T-E-R-N-O-O-N S-E-S-S-I-O-N
(12:50 p.m.)
DR. BONACA: Okay, we're going to resume
the meeting now and first of all, we will ask the
licensee if they have received the information to give
us a brief update. We don't need a lengthy one, just
a summary.
MR. PIERCE: Okay, I think during lunch we
worked on basically two questions. One was on Mr.
Barton's issue on the switch yards and secondly the
operating experiences.
Regarding the operating experience, I'm
going to let Robin start and then turn it over here to
Wayne Lunceford to continue with some of the switch
yard discussion, I'm sorry, the operating experiences
discussion. On the switch yards, I'm going to let Jim
Mulvehill speak briefly to that.
MR. DYLE: This is Robin Dyle. You did
mention the sparger and I guess the first thing that
popped into mind which sparger.
So instead of going that path, I'll just
discuss both of them. The core spray spargers, there
has been an occurrence in Unit 1 years ago where there
was IGSCC detected, a mechanical clamp has been put in
place and that is inspected as part of initially the
IEB 8013 inspections that were required and then when
we implemented VIP-18, VIP-18 replaced those
inspections. So we continue to do that.
Also, and I do not remember exactly when,
three to five years ago, there was actually a full-
flow functional test performed on core spray where
they injected through the sparger and looked at that
clamp before and after and looked at the general
conditions. So that's been evaluated.
In regard to -- Unit 1. Excuse me. In
regard to feedwater spargers and the feedwater nozzle
issue, we've been performing inspections in accordance
with NUREG-0619 for years. It had to do with the
thermal fatigue initiation of a flaw in the inner
radius and the propagation of that. Unit 1 was
originally a slip fit sparger. That was replaced with
the triple sleeve double piston sparger. Unit 2, as
the problem had been detected was still in
construction and it was replaced in the field with a
welded in-place sparger with a single thermal sleeve.
So those are the issue on the two
spargers. Since we've done the replacements and
implemented the NUREG-0619 program, we've had no
problems, nor has any other BWR in the industry, so we
believe that's been handled generically and that's
addressed in some of the VIP documentation.
MR. BARTON: You said no other plant has
had a problem since when?
MR. DYLE: Since -- there was a series of
changes that were made as part of the NUREG-0619
process. Not only were spargers changed out, but in
some cases, spargers weren't changed, but operating
procedures were changed to minimize the effect of the
on-off flow of the cold feedwater, so you eliminated
the thermal cycling and the initiation mechanism at
the inner radius.
So there was a generic report that was
published. The staff has reviewed that and that's the
new position that all the BWRs use for inspection that
has shown that there has been no cracking throughout
the feedwater nozzles in 15 plus years.
In regard to other internals, we've
inspected the jet pumps. We've replaced the jet pump
beams and put in the newer heat treat versions so
we've got the newer generation jet pumps. We do the
inspections per the VIP. We have done inspections at
the top guide. We've seen no evidence of cracking.
As I mentioned yesterday, the only plant that has has
been Oyster Creek.
We did do a preemptive repair to the
shroud as I've briefly mentioned. And that was an
economic decision where we knew the repair replaced
all the cirumferential welds so instead of spending
the money to do that, we preferentially, from a
financial standpoint just installed the repair and now
inspect that on a routine basis consistent with the SE
that the staff provided.
We replaced access hole covers. There was
indications detected several years. We were not sure
they were IGSCC and the reason is you couldn't
actually track the indication to the water surface,
but plant management conservatively decided to remove
those and they've been replaced with mechanical
devices and we inspect those at a regular period also.
And I believe that's everything as far as the
internals and the vessel goes.
The mention was made of the open item, the
Integrated Surveillance Program. We're lucky there
because if the VIP Integrated Surveillance Program is
not implemented, Hatch 1 and 2 or 2 of the 7 plants
that were in the program, so we have capsules
available that we can withdraw. So we have a backup
available for that.
MR. LUNCEFORD: Wayne Lunceford, Southern
Nuclear. All I'm going to do is describe to you some
of the general issues that the Plant Hatch is dealing
with right now regarding components that are in the
scope of license renewal.
The first one would be CRD cap screws or
control rod drive housings. Those are -- Hatch has
detected corrosion and stress corrosion cracking on
some of those cap screws. GE issued a SIL subsequent
to that. I don't recall the date or the number
suggesting an improved design, upgraded material, a
different washer design that doesn't college fluid
leakage so it tends to mitigate that type of
corrosion. Plant Hatch currently is replacing any CRD
cap screws with any sort of noted damage as they pull
out CRD drive housing at the replacement process, it's
in progress right now.
Second item, and probably the most
significant that the plant's dealing with is corrosion
and reduction of flow in plant service water piping.
Currently, this phenomena is restricted to small bore
piping. The failures we've seen are in 4-inch and
under lines. We have replaced some lines with 304 or
304L stainless steel an upgrade from the carbon steel
that was originally installed.
There have also been failures in plant
service water minimum flow lines, discharge lines due
to corrosion and we've replaced some of those lines
with 304.
The failures in plant service water had
been in both safety-related areas of the plant and
nonsafety-related. I believe that's all I'll say
about that.
MR. BARTON: They were flow erosion
problems?
MR. LUNCEFORD: We have had both erosion
problems on the minimum flow lines off the plant
service water pump and discharge lines and we have had
corrosion problems in areas of low flow where under
deposit corrosion occurred and we have also had flow
blockage in drain lines.
DR. SHACK: This is erosion is essentially
a room temperature line?
MR. LUNCEFORD: Right. There is no -- it
is not FAC-related. It is simply an elbow, high
energy line flow rate going through a relatively small
line and it just tends to wear away the carbon steel.
We replaced those with stainless steel to mitigate
that problem.
It's happened in more than one of the
minimum flow lines.
DR. SHACK: How fast is this going?
MR. LUNCEFORD: I don't know right off
hand. All I know is they had problems and replaced
them.
MR. BARTON: What was your question, Bill?
DR. SHACK: Just how fast was the flow
rate? I was zipping through?
MR. LUNCEFORD: It was obviously
significant enough to erode the carbon steel.
The next item for license renewal, a FAC
item would be a failure we've had in a HPCI, an RCIC
drain line downstream of the drain pipe. Steam supply
to the turbine, you've got a drain pipe. You've got
that line that's just going to the condenser. It's --
they have noted some FAC in that area and the response
was to include portions of RCIC and HPCI in the FAC
program.
It was originally excluded from the FAC
program based on low usage. Less than 2 percent usage
under normal operating circumstances. But we've
included that in. They don't model it, but they will
periodically go out and look at those areas that will
be most susceptible to FAC.
Torus corrosion. The inner shell of the
torus, there have been instances of minor corrosion
pitting on that surface where the originally installed
inorganic zinc primer and coating has broken down. We
have an aggressive coatings program that currently not
only trends and tracks certain areas we've mapped out
on the torus shell to see the rates of pit depth
growth, the rates of corrosion, but we've also got an
aggressive program to desludge the torus, to recoat.
They're using an underwater epoxy coating right now
for repairs and are considering in the future what
they may have to do to ensure the long-term viability
of that coating.
MR. BARTON: Do you inspect that coating
every outage to your knowledge?
MR. LUNCEFORD: They inspect, I forget
which unit is which but currently, one unit is
inspected every outage with divers. The other unit,
due to reduced corrosion rates, that we observed, is
inspected only every other outage.
MR. BARTON: Why is the corrosion rate
different there? Is it different coating?
MR. LUNCEFORD: I believe that the Unit 2
is holding it better and it may be due to improved
water chemistry controls implemented. I don't know
that they've established exactly why that coating is
performing somewhat better.
Also noted, this was an issue that came up
in a recent inspection for Aging Management Programs
at Plant Hatch was general corrosion in exposed areas
of the plant such as the intake structure, valve pits
for service water, the EDG building roof area where
the inspectors noted excessive rust on components,
supports, etcetera and the plant has made that an
issue to improve their identification and corrective
actions in those areas.
One other item I'll mention is
particulates in our diesel fuel tanks. There have
been instances of high particulates above the 10
milligram per liter limit required by tech specs and
those were all properly corrected by filtration or
draining, cleaning the tanks and the plant is pursuing
what methods they need to ensure that reduced
occurrences of high particulate in those tanks.
I believe that is all the current items
identified.
MR. BARTON: Back to service water or
erosion problem you had.
MR. LUNCEFORD: Yes sir.
MR. BARTON: Did your erosion/corrosion
program pick it up or was it a failure that led you to
discover it?
MR. LUNCEFORD: Service water, the service
water line, if you're talking of the FAC program.
MR. BARTON: Whatever you use for
erosion/corrosion program. Is that pick it up or did
you have a piping failure, an actual leak and then you
found out you had a problem?
MR. LUNCEFORD: It is not an
erosion/corrosion problem per se. It's simply an
erosion problem. If you look at it from FAC --
MR. BARTON: But don't you have a program
in place that looks for that kind of stuff and picks
out susceptible areas or potential areas that you
could have this problem? Don't you have a program
like that?
MR. LUNCEFORD: Correct, that's our plant
service water piping inspection program. I do not
believe they identified all of those failures prior to
leakage.
MR. BARTON: Prior to, okay.
MR. LUNCEFORD: Once they --
MR. BARTON: What makes you have
confidence that the program is effective? What
confidence do you have in your erosion program that
it's effective? If you're finding failures --
MR. LUNCEFORD: The service water
inspection program, one line was identified, they
implement inspections of the other lines, trended
those corrosion rates and the engineer at the site who
is responsible for that, actively goes out and tries
to identify. If they do identify a failure, he will
review other areas of the plant where similar
materials, environments could exist and we include
those in routine inspections.
DR. SHACK: But that's not included in
what you call your FAC program?
MR. LUNCEFORD: That is correct. It's
covered by the plant service water inspection program.
DR. SHACK: In other words, they really
didn't expect it.
MR. BARTON: I gotcha.
MR. LUNCEFORD: It's not FAC is the point.
DR. SHACK: A rose by any other name --
(Laughter.)
MR. BAKER: I think the point we're
making, the distinction is, there's an industry
program that might get confused with that in terms of
the scope.
MR. LUNCEFORD: That's all I have unless
there's any other questions.
DR. UHRIG: Question.
MR. LUNCEFORD: Yes sir.
DR. UHRIG: Are the two plants identical,
even though they're several years difference?
MR. LUNCEFORD: No.
DR. UHRIG: What are the substantial
differences?
MR. LUNCEFORD: I'll let Ray address that.
MR. BAKER: Unit 2 has a hydrogen
recombiner associated with containment. Unit 1 does
not rely on hydrogen recombiner. That's one
difference.
DR. UHRIG: Well, of course, those kinds
of things, but in general, the types of systems are
very similar.
The same power level.
MR. BAKER: Yes.
DR. UHRIG: Are you involved in this large
PWR upgrade program?
MR. BAKER: We have done the extended
power upgrade on both units.
DR. UHRIG: You've already done that?
MR. BAKER: Yes. Thank you.
MR. MULVEHILL: Jeff Mulvehill, Southern
Nuclear. Changing the subject to switchyard and
maintenance. The plant is involved with monitoring
and minor maintenance of switchyard components inside
the protected area fence. Any large item of
maintenance such as replacement of a transformer would
be a joint effort between Georgia Power Company and
the plant people.
Inside the protected area fence, changes
to the switchyard are controlled by the design change
process there so and once you get beyond that fence
into the transmission line area coming in and so
forth, that's pretty much all Georgia Power.
MR. BARTON: What control do you have over
the work they do in the switchyard?
MR. MULVEHILL: If they're working under
a PCR, a design change request, they would have to
follow the procedures that the --
MR. BARTON: Station procedures?
MR. MULVEHILL: Right.
DR. BONACA: Thank you. All right, then
let's move on now to the Time-Limited Aging Analysis.
MR. BURTON: This is Butch Burton again.
I'm going to turn it over to John Fair from the staff
to discuss the TLAAs.
(Slide change.)
MR. FAIR: Good afternoon. I'm going to
go over the areas that were identified as
Time-Limited Aging Analyses at Plant Hatch and I'm
going to discuss the open items that we have in the
draft SER.
The first section is in the identification
of TLAAs and we have two open items. The first open
item involves the fatigue analysis of components. In
the application, the applicant identified TLAAs for
the reactor vessel and for the reactor coolant lube
piping, but did not identify other major reactor
coolant system components as TLAAs and did not
identify the reactor vessel internals as a TLAA.
The staff reviewed the Hatch FSAR,
identified that the reactor vessel internals had been
discussed and a fatigue evaluation of the internals
was identified in the FSAR so that we ask a question
as to why this was not identified as Time-Limited
Aging Analysis.
The response to our question was that the
criteria of the vessel internals program, VIP-74 were
used to identify items that are TLAAs. We really
didn't understand what that meant in terms of
response, so we held this as an open item and maybe
some misunderstanding in the terminology, but since
there isn't an identified fatigue evaluation of at
least the internals, we want to know how that was
dispositioned.
And the second item there was really just
a catch all, in case there's some other component that
there was a fatigue evaluation. We don't know from
review of the FSAR whether there are. But we'd like
the applicant to identify if there's any other
components they did fatigue evaluations on and how
they dispositioned those.
The second open item in the identification
TLAAs is one of the items of contention and that's the
high-energy line break postulation based on fatigue
cumulative usage factor. Again, the staff believes
this meets the definition of a TLAA per the 54.3
criterion and the licensee's response was that they
just used this criterion to select break locations and
they really didn't consider it a Time-Limited Aging
Analysis.
This particular item was identified as a
potential Time-Limited Aging Analysis, this high
energy line break postulation based on cumulative
usage factor. In the statement of considerations of
the rule, it's in the draft SRP as an item where
there's a potential TLAA and I believe there was even
an industry comment in the fatigue section of the SRP
that this item should be identified as a potential
TLAA. So we're still holding this open as TLAA and
want to have a discussion on how we're going to
resolve the issue with the licensee.
DR. BONACA: Are these under appeal?
MR. FAIR: This is an item that's under
appeal.
DR. BONACA: Not the second one?
(Slide change.)
MR. FAIR: Yes, the second one. The
second item is under the fatigue analysis issue and
really the heading in the license renewal application
is pipe stresses, the way the applicant has labeled
this. And the open item really is the resolution of
environmental fatigue issue or the GSI-190 issue.
In response to the staff concern on this
item, the licensee has referred to generic EPRI
studies that were performed previously to try to
address this generically for BWRs. The open item that
we have is really the applicability of these
particular generic studies to specific locations at
Hatch and we have on-going discussions, I believe, we
anticipate with them to try to resolve this issue.
MR. DYLE: If I could, John, just one
thing to add to that. This is Robin Dyle. Not only
are we working that between Hatch and the staff, this
is also a generic issue that we're trying to work this
particular resolution of environmental assisted
fatigue with the MRP, so we're trying to develop not
only the Hatch specific, but also a generic position,
that others could use and this is on-going dialogue.
(Slide change.)
MR. FAIR: The next ones are just -- I'll
go over the items that were in the license renewal
application, briefly, but there were no open items
identified. The first one was a corrosion allowance.
There were some specific piping systems that they had
evaluated for corrosion and they went back and
dispositioned those.
Environmental qualification, again, they
dispositioned those. We had no open items. And they
did have a calculation on containment pressurization
cycles, a fatigue evaluation which they went back and
dispositioned.
(Slide change.)
MR. FAIR: The next area was the reactor
vessel and really there were a number of subitems
under this, but the issue is the effect of neutron and
irradiation embrittlement and one of the various items
listed under this. And there were no open items again
identified under this.
(Slide change.)
MR. FAIR: The last item was an
interesting item. This is main steam isolation valve
operating cycles. This was originally identified as
a TLAA by the applicant because they had specified in
the FSAR a number of cycles. They went back and
reconsidered.
They had put this number in a design
specification, but did not have the actual basis of
why it needed to meet this number of cycles, so they
decided this really doesn't constitute a TLAA and that
they do have on-going programs to refurbish these
valves and restore them. So we accepted that
resolution and there's no open item on this.
MR. BARTON: Is this handled through the
LLRT program and overhaul is needed?
MR. PIERCE: That's one of the programs,
that's correct.
MR. BARTON: What's the other one?
MR. PIERCE: There is a number of
individual activities that are done on the MSIVs that
I'd have to go back and refresh my memory on, but
everything to tech spec., routine tech spec.
surveillance, in terms of operating, testing, testing
the valves for closure time and so forth are part of
it as well.
MR. BARTON: Okay. I understand.
MR. FAIR: And that was the extent of the
time-limited aging analyses done by the applicant.
DR. BONACA: Are there specific questions
from the members?
What I'd like to do is to ask Mr. Grimes
to give us a summary of the five issues that will be
appealed tomorrow?
MR. GRIMES: I think it's four.
DR. BONACA: I thought it was five.
MR. GRIMES: I'll go back and enumerate
the issues that are on the agenda for the meeting that
we're going to hold tomorrow.
DR. BONACA: Okay.
MR. GRIMES: But rather than summarize
them which I think is the purpose of the meeting that
we're going to have tomorrow, I would suggest that
we'll be able to better articulate what the nature of
the dispute is after we've had an opportunity to sit
down with the applicant and compare notes. And just
going through the agenda for -- the reactor building
leakage, the use of the drawdown tests.
DR. SHACK: Chris, on that one, they have
a tech spec., right, so they have to test for that?
MR. GRIMES: Yes.
DR. SHACK: And you want an Aging
Management Program as well as the inspection program
and the test?
MR. GRIMES: No. The issue, as best as I
can characterize it, without prejudice to my position
as judge and jury tomorrow, the applicant conducts
inspections of the secondary containment and they go
around and they check the condition of the
penetrations. They have access controls to make sure
that doors are closed when they're supposed to be
closed. They check all of the individual parts of the
building in order to make sure that the building is
standing up properly.
But they also perform a tech spec required
draw-down test to demonstrate the leakage integrity of
the secondary containment as a secondary containment.
The staff wants the leakage test to be included as an
element of the aging management program and the
applicant argues that's an unnecessary regulatory
burden because the inspection of the individual
component should be sufficient for the purpose of the
aging management purposes. I think I've fairly
characterized the nature of the issue. Details to be
explored tomorrow.
The second issue is seismic II/I and that
gets to the design basis for nonsafety stuff that
could fall and prevent safety-related functions. The
applicant has designed seismic supports for the
nonseismic piping and the staff has said that the
piping could fail so the piping needs to be included
in the scope as well as the supports. And so we'll
need to explore the extent of that scoping issue.
Pipe break criteria is a time-limited
aging analysis. There are -- the piping has a fatigue
design and there's a fatigue analysis that's
identified as the Time-Limited Aging Analysis, but
there are also analyses that are performed to look at
crack growths rates as it relates to where you
postulate pipe breaks and so the pipe break criteria
as a separate Time-Limited Aging Analysis is going to
be discussed.
And then, of course, the general question
about housings as separate passive functions of active
components. And that generally applies to all HVAC
systems.
So those are the four issues that are in
dispute that are going to be discussed in an appeal,
but as John Fair pointed out, the rest of the open
items we think that there's a course of resolution and
we understand what information needs to be exchanged,
but that still needs to be verified. Our ability to
be able to close all the open items and prepare a
final safety evaluation in accordance with the
schedule that Butch showed you earlier will still be
monitored very carefully.
MR. BARTON: The housing issues on HVAC
systems plus standby gas treatment, right?
MR. GRIMES: Yes sir.
DR. BONACA: Thank you.
MR. GRIMES: I would point out and I'm not
sure that we can promise that the results of
tomorrow's meeting will be a sufficient basis for us
to be able to tell you what the answer is by the time
that we get to the full committee. And so we'll need
some guidance from the subcommittee in terms of what
material you want presented for the full committee
meeting on April 5th.
DR. BONACA: Well, what I would like to
ask you to do is to by some means to gather --
depending on how the meeting goes tomorrow, and what
the closure on the items are, probably no closure, but
progress and clarification and making available to the
members say by Friday, if you could.
And then I would like to have the members
review these issues, what happens tomorrow and give me
by e-mail to pass out to me during the weekend your
thoughts. I would appreciate that because I think
I'll try to put together these comments and then bring
them back next week for our use so we can discuss
them, look at our perspectives and then be ready then
for the presentations we receive from the staff and
the licensee next week.
Okay, we may decide not to express an
opinion or we may have an opinion at that point that
we can express, but certainly that becomes an issue of
agenda next week and you bring a position on the
staff. We will consider commenting on those. So that
would be helpful for me as a member to send me their
perspectives on these issues, once we get the
information from the staff.
With that, I believe we have completed the
presentations. I'm just asking now if there are any
other comments or questions. I see none.
So what I would like to do now is to go
around the table and see if any one of the members has
any comment at this stage regarding what we have seen.
We have reviewed the application. We
heard the support provided by the BWRVIP program to
this application and so I would like to gather your
thoughts, if you have any this stage.
Bill, we'll go in this direction.
DR. SHACK: No. You know I don't see any
major stumbling blocks here. There are a number of
open issues to be resolved. I would say that I found
their approach to putting together the report to be
more confusing, for example, than the last example we
saw at ANO 1. The information may be there, but it
just was more difficult to access. I really did sort
of miss the Appendix B compilation which I thought was
a very nice feature of the ANO 1 license renewal. If
I see license renewals again I sort of hope they look
like that.
DR. BONACA: Okay. Graham?
MR. LEITCH: No, I don't really have
anything to add except to echo Bill's comment that I
did find I guess the word we're using is the
navigation a little difficult, but I think now that I
understand a little more clearly the layout of the
report, I think it's quite understandable. It was
just somewhat confusing to me without some of the sort
of tutorial we've had today.
DR. BONACA: John.
MR. BARTON: Well, I don't see any show
stoppers, but I've got some concerns. I think I'm not
going to be at the full committee meeting, but I think
the committee ought to hear the results of the staff's
looking into some of the questions that we raised and
the committee ought to be satisfied that those
components are, in fact, covered by the Aging
Management Program or not and also I think we ought to
weigh in on where we stand on the issues that are up
for appeal, whether we've got a strong position one
way or another on that.
But as far as overall the application, I
think, the committee gets satisfied with those and the
answers that the staff will provide the full committee
meeting. I don't see a problem overall.
I think it was a harder process to review.
Took a lot more time to review it because you try to
figure out where were things that you had seen before
or located in this application and from a technical
standpoint, it's not detrimental. It's just from an
administrative standpoint it was harder.
DR. SHACK: We'll charge them for it.
(Laughter.)
MR. GRIMES: I wish you'd be careful with
that. There is a fees issues on this plant as well.
(Laughter.)
MR. BARTON: Oh yeah?
DR. FORD: My main concern as I said
earlier on was the whole question of the conservatism
or otherwise, the disposition curve, and the process
was compliant enough to take into account new data, if
and when it becomes available.
I'm satisfied that that compliance is
there.
DR. BONACA: Tom?
DR. KRESS: I agree with the comments on
navigating through the documents and I agree with John
Barton that we need to express our opinion, whatever
it turns out to be on these appeal issues. I'm
particularly interested in two of those, the reactor
building leakage issue and the question of what
constitutes passive versus active in terms of
housings. I think there may be a need for some
clarification of that and this may be a chance for the
staff to clarify what the passive component really is.
I didn't see any major show stoppers and
I also found that BWRVIP documents provide a pretty
good basis for referencing and I thought those were
pretty good documents, at least the ones we've
reviewed.
So that's about all I had.
DR. BONACA: I could pretty much echo the
same comments. On the issue of navigation,
navigating, that's why yesterday also, when we were
talking about a generic approach, I felt that the
earlier applications where you had scoping system and
then the screening doggedly going to the outcome. It
was really helpful in the review process and helping
people to understand on their own without searching.
So what I would consider the scrutability
of the documentation that allows for the public as I
said yesterday, we are the public in many ways, to
feel the confidence that we know this stuff has
reached a position if the audits hadn't taken place
and you found that in fact the methodology was
implemented as stated.
So I do believe that not specifically on
the Hatch application, but maybe on the others, we may
express some preference in that sense or direction in
that the next applications have the opportunity to be
clear or less clear.
I also have some -- I feel we need to
express an opinion on these open issues because those
are issues we have reviewed for other plants. I mean
clearly, we looked at II/I. I thought we had looked
at those at casing components. You're right. We
would not have looked at them. I assume that they
were being treated just like equipment on skids. But
there's a need for clarification on that particular
issue. In the context, I still feel, that's personal
opinion that the rule specifically talks about passive
components and active components and not inactive
systems. But --
DR. SHACK: It looks a lot like an
electrical cabinet to me.
DR. BONACA: Yes. So I think we should be
open about resolution that there will be reached on
this. I think we should look at them positively also
because they're going to bring resolution to some
issues on a generic basis and they're going to help
finalizing the guidance documents that we have and
making it easier for the industry.
And certainly we will look for answers to
the questions that John raised and for which we have
no answer. They were good questions. Good questions
particularly because they give us some feeling about
the scoping issue for which we have various questions.
I would like to just briefly now ask the
members about what we should ask the staff to present
next week. There is a limited amount of time there.
MR. BARTON: Bob wasn't here when you
asked the question.
DR. BONACA: Yes.
MR. BARTON: How much time is on the
agenda?
DR. BONACA: Oh, I didn't see a question.
We skipped you.
DR. UHRIG: I was out.
DR. BONACA: Okay.
DR. UHRIG: I don't have anything of major
concern. I spent most of my time concentrating on the
electrical components and I see those resolved,
essentially the same as the previous plants have been
and it's satisfactory.
DR. BONACA: Right. Yes.
MR. DURAISWAMY: Did somebody ask a
question of how much time we've got? We've got two
hours, scheduled for the agenda.
But that's for both the staff and --
MR. BARTON: And the applicant.
DR. BONACA: And the BWRVIPs. We have to
be parsimonious about how we spend the time.
DR. KRESS: That includes the BWRVIPs,
that two hours?
DR. BONACA: Well, we're not going to have
a specific view of those. We're simply going to
discuss the part of how they support particularly the
internals and the vessels, some of the TLAAs and the
other inspections.
MR. DURAISWAMY: I don't think we're going
to spend too much time on that thing, Tom. I think
primarily we're going to spend most of the time, I
think I split them between the applicant and the
staff. So now we've got to get on about the agenda.
DR. SHACK: You'd better let Gene
Carpenter know that.
MR. DURAISWAMY: Gene knows that. We told
him yesterday, unless he was sleeping.
(Laughter.)
MR. GRIMES: Actually, this is Chris
Grimes. In Gene's defense, we were hoping to convince
you to let Robin do 25 of the 30 minutes allotted for
VIP and Gene could have the last 5.
You mentioned yesterday about half an
hour's worth of VIP. I would also suggest that you
look at the way that you treated the BWR topical
reports for the Oconee review as a model of what the
desired outcome looks like.
DR. UHRIG: Ar you going to spend time on
the results of the appeals?
DR. BONACA: Yes. It seems to me that the
first thing we need to talk about, the scoping and
screening because this has been probably one of the
places where we had some difficulty in reviewing, not
because there is anything wrong with that
fundamentally, but because we had some trouble with
that issue. Then, I think we need to understand the
open issues as a summary with specific focus on those
which have been appealed right now, understanding that
others may be appealed in the future. That doesn't
preclude that.
But right now those are the ones on the
table. So and then I think we need to, as we talk
about TLAA or even management programs to see how the
BWRVIPs fit. That will be the half hour dedicated to
that. It will be interesting to have again the
perspective on how one-time inspections and the new
problems have gone from application to application.
MR. BARTON: You need the mike.
DR. BONACA: Sorry, how they have gone
from application to application, so we have an
understanding of how that is evolving as we come
closer to final documentation of GALL.
MR. GRIMES: Dr. Bonaca, if I could
suggest, we've committed to provide you with the cross
cut of one-time inspections for the following session
on improved renewal guidance.
DR. BONACA: Okay.
MR. GRIMES: So I would suggest for the
purpose of the full committee meeting on the Hatch
application, that if we could have the applicant
simply decide on how they want to account for what's
existing, what's modified, what's new in a very broad
way.
DR. BONACA: Exactly, and only as it
fairly relates to Hatch.
MR. GRIMES: Correct.
MR. GRIMES: Okay, good. I think that if
you include all those items you pretty much will run
out of time, so my suggestion is to stay with that and
with whatever else you feel you want to communicate to
us at that point and that goes for both the staff and
the applicant.
MR. LEITCH: Maybe you mentioned this,
Mario, but I think Butch's slide that's labeled
overview, the four important distinctions, first BWR,
first use of the BWRVIP program, functional approach
versus systems approach, that slide, I think --
DR. BONACA: It's a good introduction.
MR. LEITCH: That's a good introduction,
exactly.
DR. BONACA: One thing that I suggest is
if the applicant finds a way to fit it in, the brief
communication he gave us on the experience of the
plants I think was very important because I mean it
told us a pretty good story about the plants and the
recent history of travel and the plants and a good
history and so -- I think also that slide we saw
yesterday where the capacity factor has improved so
significantly through the years, I think is a
demonstration that the initiatives of the BWRVIPs have
been effective.
The other point we have noted yesterday in
the presentation was that this is not only one plant
operating and gathering information, but is three
plants, before including maybe including foreign
plants.
So therefore, there is substantial
experience being gathered of every year that is really
applicable to every plant out there, so that gives a
lot of additional confidence in the BWRVIP. I would
probably present that point as part of the BWRVIP
element to the presentation.
Any other thoughts? So if I remember now
next week is going to be practically the whole morning
first of all on Hatch and then --
MR. DURAISWAMY: First two hours, 8:35 to
10:30 on Hatch and then go the license --
DR. BONACA: Okay. Any other comments or
questions for the members? Comments or questions from
the public?
None, the meeting is adjourned.
(Whereupon, at 1:37 p.m., the meeting was
concluded.)
Page Last Reviewed/Updated Tuesday, August 16, 2016
Home
About Us
Popular Documents
Stay Connected
