481st Meeting - April 5, 2001
Official Transcript of Proceedings
NUCLEAR REGULATORY COMMISSION
Title: Advisory Committee on Reactor Safeguards
481st Meeting
Docket Number: (not applicable)
Location: Rockville, Maryland
Date: Thursday, April 5, 2001
Work Order No.: NRC-147 Pages 1-232
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)
481ST MEETING
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THURSDAY,
APRIL 5, 2001
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ROCKVILLE, MARYLAND
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The Committee met at the Nuclear
Regulatory Commission, Two White Flint North, Room
T2B3, 11545 Rockville Pike, at 8:30 a.m., Dr. George
E. Apostolakis, Chairman, presiding.
COMMITTEE MEMBERS PRESENT:
GEORGE E. APOSTOLAKIS Chairman
MARIO V. BONACA Vice Chairman
F. PETER FORD Member
THOMAS S. KRESS Member
GRAHAM M. LEITCH Member
DANA A. POWERS Member
WILLIAM J. SHACK Member
JOHN D. SIEBER Member
COMMITTEE MEMBERS PRESENT: (CONT.)
ROBERT E. UHRIG Member
GRAHAM B. WALLIS Member
INVITED EXPERT PRESENT:
STEPHEN L. ROSEN
ACRS STAFF PRESENT:
SAM DURAISWAMY
CAROL A. HARRIS
JOHN T. LARKINS
JAMES E. LYONS
ROBERT ELLIOTT
ALSO PRESENT:
ED ANDRUZKIEWIZ
HANS ASHAR
RAJ AULUCK
RAY BAKER
WILLIAM BATEMAN
CHARLES BRINKMAN
WILLIAM L. BROWN
WILLIAM BURTON
LARRY CAMPBELL
C. E. CARPENTER, JR.
ALSO PRESENT: (CONT.)
ROBERT CARUSO
OMESH CHOPRA
MANNY COMAR
MICHAEL CORLETTI
JAMES DAVIS
JENNIFER DAVIS
JERRY DOZIER
BARRY ELLIOT
ROB ELLIOT
J. FAIR
G. GALLETTI
BEN GITNICK
GEORGE GEORGIEV
JIM GRESHAM
CHRIS GRIMES
FRANCIS GRUBELICH
STEVE HOFFMAN
Y. GENE HSII
CHUCK HSU
B. P. JAIN
WALTON JENSEN
CAROLE JULIAN
PETER J. KANG
ANDREA KEIM
ALSO PRESENT: (CONT.)
STEPHEN KOENICK
WILLIAM KOO
P. T. KUO
CAROLYN LAURON
SAM LEE
ALAN LEVIN
CHANG-YANG LI
YUEH-LI C. LI
W. C. LIU
LAMBROS LOIS
MICHAEL McNEIL
S. K. MIFON
MATTHEW A. MITCHELL
RICH MORANTE
CLIFF MUNSON
RICHARD ORR
KRIS PARCZEWSKI
ERACH PATEL
PAT PATNAIK
CHARLES PEARCE
ISABELLE SCHOENFELD
PAUL SHEMANSKI
UNDINE SHOOP
DAVID SOLORIO
ALSO PRESENT (CONT.)
BRIAN THOMAS
EDWARD D. THROM
JIT VORA
HAROLD WALKER
DOUG WALTERS
KEITH WICHMAN
JERRY WILSON
. I N D E X
AGENDA ITEM PAGE
1) Opening Remarks by the ACRS Chairman . . . . . 7
2) Interim Review of the License Renewal. . . . .11
Application for Edwin I. Hatch Nuclear
Plant Units 1 and 2
3) Proposed Final License Renewal Guidance. . . 107
Documents
5) Thermal-Hydraulic Issues Associated. . . . . 158
with the AP1000 Passive Plant Design
. P-R-O-C-E-E-D-I-N-G-S
(8:30 a.m.)
CHAIRMAN APOSTOLAKIS: The meeting will
now come to order. This is the first day of the 481st
meeting of the Advisory Committee on Reactor
Safeguards.
During today's meeting, the Committee will
consider the following: Interim review of the license
renewal application for Edwin Hatch Nuclear Power
Plant Units 1 and 2; proposed final license renewal
guidance documents; safety issues associated with the
use of mixed oxide and high burnup fuels;
thermal-hydraulic issues associated with the AP1000
passive plant design; and proposed acrs reports. A
portion of this meeting will be closed to discuss
Westinghouse propriety information applicable to the
AP1000 design.
This meeting has been conducted in
accordance with the provisions of the Federal Advisory
Committee Act. Dr. John Larkins is the designated
federal official for the initial portion of this
meeting.
We have received no written comments or
requests for time to make oral statements from members
of the public regarding today's sessions.
A transcript of portions of the meeting is
being kept. And it is requested that the speakers use
one of the microphones, identify themselves, and speak
with sufficient clarity and volume so that it can be
readily heard.
I will begin with some items of current
interest or announcements. First, Mr. John Szabo of
the Office of General Counsel will meet with us on
Friday -- that is tomorrow -- at 12:15 p.m. to discuss
recent changes in ethics laws and answer any questions
that the members may have relating to conflict of
interest, contracting restrictions, prohibited stocks,
et cetera. So I suggest that we bring our lunch here
and then listen to Mr. Szabo.
There will be a meeting at noon today in
the Subcommittee Room with NRR staff to discuss
potential synergistic effects from power upgrades,
high burnup fuels, life extension, and accident
precursors, and life extension, period.
Carol Harris will pass out financial
disclosure forms today or tomorrow. And the members
are requested to fill them out and return them to
Carol at the May meeting. I will be meeting with
Commissioner Merrifield today, and Dr. Larkins will be
with me at 3:00 o'clock. You have received copies of
the ACRS summary matrix of 2,000 letters and outcomes
that are in front of you.
MEMBER KRESS: I didn't know we had
written that many
CHAIRMAN APOSTOLAKIS: Two thousand
letters, yes, 2,000 letters. At least it feels that
way. And it has the various criteria that we use to
judge effectiveness and so on. The subcommittee
chairmen are asked to find their own letters and
review what's in this handout and make sure it's
correct.
We will do this in tomorrow's session, the
P&P session. So please read them before then. We
will discuss our meeting with the Commission next
month. We will discuss it today between 4:30 and 5:30
and Friday at 3:30, between 3:30 and 4:30, and
Saturday as necessary.
You have this pink cover with some
interesting items of interest attached, several
speeches by commissioners, an inside NRC article on
the DPO report, and managerial assignments and changes
within the agency. So the members should find this
interesting.
And, finally, I am pleased to announce
that Mr. Harold Larson has been appointed as Special
Assistant and Mr. Sam Duraiswamy as Technical
Assistant to the Associate Director for Technical
Support of the ACRS/ACNW.
And, with all of that, we are ready to
start our session. The first one is on interim review
of the license renewal application for Hatch Nuclear
Power Plant Units 1 and 2. Dr. Bonaca, this is your
session.
VICE CHAIRMAN BONACA: Thank you, Mr.
Chairman.
On March 28th, we met with the applicant
and with the staff to review the application of Plant
Hatch Units 1 and 2 for license renewal. We heard
from the applicant, and also we had a significant
amount of information before to review from the SER.
On March 27, we spent about half a day
reviewing with the staff the BWRVIP topical reports
for the program in general. That includes in excess
of 20 topical reports, of which we have reviewed
specifically 4 of them.
Those topical reports are important
because they are referenced in the Hatch application.
They really are the foundation to the vessel and
internal inspections and evaluations that old BWR was
performing. They are important to us because we will
see them likely in every application for BWRs for
license renewal. Today we have the staff and the
applicant coming in and summarizing for the full
Committee what we heard on the 27th and 28th of March.
With that, I will move and ask Mr. Grimes
to introduce speakers.
MR. GRIMES: Thank you, Dr. Bonaca.
My name is Chris Grimes. I'm the Chief of
the License Renewal and Standardization Branch. I am
accompanied by Bill Bateman, the Chief of the
Materials and Chemical Engineering Branch.
And the staff is prepared today to
summarize the material that was presented at the
subcommittee meetings and to highlight those specific
areas of interest that the subcommittee pointed out.
Mr. William, also known as Butch, Burton
is the project manager. And Butch will present the
summary of the renewal reviews. We are leading off
with Gene Carpenter, who is the lead engineer on the
Boiling Water Reactor Vessel Internals Project. And
we have coordinated with the applicant, who is being
represented here today by Ray Baker from Southern
Company, in order to address the specific questions
that came up during the subcommittee meeting.
And I would also like to emphasize that
this is an interim report. You know that there are a
number of open items and issues under appeal, for
which there is an ongoing dialogue with the applicant.
And we will do our best today to represent where we
stand on those issues. And we will continue to keep
the subcommittee and the full Committee informed of
our progress on those issues.
And, with that, I will turn it over to the
staff to make the presentation.
VICE CHAIRMAN BONACA: Thank you.
(Slide.)
MR. CARPENTER: Good morning. I'm Gene
Carpenter with the Materials and Chemical Engineering
Branch. As Mr. Grimes said, I am the lead for the BWR
Vessel Internals Project, the staff review that has
been ongoing for that.
(Slide.)
MR. CARPENTER: Today I am going to give
you a very brief overview of the regulatory
perspective on this, what has been accomplished with
the BWRVIP Program to date and how the generic aging
management program has been reviewed.
Now, last week when we briefed the
subcommittee on this, Mr. Robin Doyle of Southern
Nuclear gave a fairly comprehensive, if somewhat
abbreviated, overview of it. And that took two hours.
I have 30 minutes. So my overview is going to be
exceptionally abbreviated.
To start with, BWRVIP is a voluntary
industry initiative of all the BWR owners in the U.S.
and several foreign reactors. It was begun in 1994 to
address the core shroud cracking issue, which
eventually gave rise to Draft Letter 94-03.
They now address all of the BWR internal
components, the reactor vessel and an extension of
what they had previously been chartered to do. They
are now looking at the Class I piping material
conditions also.
The guidance that the BWRs have put out
covers the current operating term and also the
extended operating period. The staff is looking at
both of those.
BWRVIP has been proactively addressing
some of the aging degradation issues that are beyond
present regulatory requirements as well as those that
are within regulatory requirements.
The BWRVIP has identified generic
cost-effective strategies that are appropriate for
plant-specific needs. They are also the regulator
interface for all BWR material issues and also the
clearinghouse for all the information that has been
gathered, both domestically and internationally. So
they are sharing quite a bit of information, not only
with themselves but also with the staff.
(Slide.)
MR. CARPENTER: One of the reasons that
Mr. Doyle gave last week for all of this is that the
BWRs were suffering through quite a bit of capacity
loss in the early 1980s. As this chart shows, in the
early '80s, the plants were down up to 20 percent of
the time. And obviously when you have a nuclear
reactor, you would like it to be running as much as
possible.
During this time, the staff had put out
quite a few information notices, bulletins, generic
letters, et cetera, regarding some of the material
degradation issues. And BWRs had started working on
this. Again, in 1994, they started doing this as an
organization, the BWRVIP organization.
(Slide.)
MR. CARPENTER: To give you a rough idea
of some of the components that have been looked at
here, not only are we talking about the entire vessel
itself, we're talking about the core shroud, core
plate, top guide, core spray piping on the internals,
the various support legs, basically everything inside
that is safety-related.
(Slide.)
MR. CARPENTER: As you may remember from
when the core shroud issue first occurred, some of the
components that were of high concern were these welds,
the circumferential welds. Later on vertical welds
were also identified as a cracking problem. And that
is being addressed in one of the BWRVIP reports,
specifically VIP-63, which the staff has reviewed.
They have also looked at, again, the support legs, the
core spray piping, the top guide, more core plate, the
jet pumps, et cetera.
To give you a rough idea again, all of the
BWRs in the United States are members of the BWRVIP.
And they all have committed to following the BWRVIP
guidance as it is reviewed by the staff and approved.
If they have any problem with following the guidance
once it is approved, they are required to tell us
within 45 days.
(Slide.)
VICE CHAIRMAN BONACA: Before you leave
the figure that shows the internals, --
MR. CARPENTER: Yes, sir.
VICE CHAIRMAN BONACA: -- you might want
to point out some of the concerns there may be. I
mean, for example, some failure of hold-down things in
top guide may lead to core movement --
MR. CARPENTER: Yes, sir.
VICE CHAIRMAN BONACA: -- and, therefore,
their ability to insert control rods. I mean, that's
the kind of issues maybe the members should hear about
briefly.
MR. CARPENTER: Right. Some of the issues
that have arisen obviously with core shroud cracking,
you lose two-thirds core coverage. If the core shroud
circumferential welds do give way and there is
movement of the core shroud, you could preclude the
ability to perform a safe shutdown by movement,
damaging of the fuel, precluding the control rods from
inserting.
Another problem was with the SLC, standby
liquid control system. If that failed, you would not
be able to shut down under an ATWS condition.
The jet pumps, one of the things that was
looked at was what would happen if you had the jet
pumps disassemble. Again, that would preclude
two-thirds core height coverage.
If the core spray pipes had significant
cracking in it, you would not be able to perform core
spray cooling. If the top guide or the lower core
plate was cracked significantly, again, more problems
there. And these are all some of the issues that were
looked at in toto as well as what would happen if you
had cracking in the reactor vessel or in some of the
Class I piping.
VICE CHAIRMAN BONACA: Thank you.
(Slide.)
MR. CARPENTER: Okay. The previous slide
was on the domestic members. This is a listing of the
present foreign member utilities. As you can see, it
includes Germans, the Japanese, Taiwanese, et cetera.
(Slide.)
MR. CARPENTER: Some of the BWRVIP
reports, as I said several times now, have included
the BWR vessel, all safety-related internal
components, and Class I piping.
VICE CHAIRMAN BONACA: Just one more
question.
MR. CARPENTER: Yes, sir?
VICE CHAIRMAN BONACA: Of all the foreign
member utilities you showed, are they all G.E.
reactors?
MR. CARPENTER: I don't believe.
VICE CHAIRMAN BONACA: Okay. So there are
some BWR reactors of other design?
MR. CARPENTER: I believe so, yes.
VICE CHAIRMAN BONACA: Okay. So there is
a sharing of information with other types of designs?
MR. CARPENTER: Right. The BWRVIP
reports, again, they cover the core shroud, shroud
supports, the entire list that I have here, of which
the Hatch review did take a look at all of these.
Some of them are not applicable to Hatch, but we will
talk about that in a moment.
The guidelines were basically broken up
into three main sections, those of the inspection and
flaw evaluation guidelines, which create the bases for
the aging management program; repair design criteria,
which would be applicable at any time in plant life,
either during the current operating term or the
license extension term; and also mitigation guidance,
which would give you a way to preclude cracking,
hydrogen water chemistry, noble metal chemistry
addition, et cetera. And that's also good at any time
during plant life.
(Slide.)
MR. CARPENTER: To give you a brief
overview, as Dr. Bonaca said at the beginning, there
have been quite a few of these BWR reports. These are
the majority of the flaws, the inspection and flaw
evaluation guidelines.
Several, the BWR reactor vessel pressure
one, BWRVIP-74, had subsumed and the guidance that was
given in BWRVIP-05, which the ACRS reviewed several
years ago. BWRVIP-76, the core shroud, which started
all of this, subsumes the guidance that was previously
approved in BWRVIP-01, -07, and -63, -63 being the
vertical welds, as opposed to the circumferential ones
on the first two.
(Slide.)
MR. CARPENTER: And, as I said a moment
ago, they also have repair/replacement design
criteria. This is a listing of those for all of the
safety-related equipment.
(Slide.)
MR. CARPENTER: And also guidance on how
to evaluate crack growth and mitigation. And these
all either have been reviewed or are under staff
review at this time.
(Slide.)
MR. CARPENTER: Some of the other reports
that have been looked at were: the BWRVIP-03
guidance, which tells the licensees how to do a
consistent examination; and the -06 report, which was
a safety assessment of all the reactor internals. And
that gave them the bases for determining which of
these internal components would be looked at and
evaluated.
The safety assessment identified
components that were necessary for safe operation
shutdown. The criteria that was used was to:
maintain a coolable geometry, maintain rod insertion
times, maintain reactivity control, assure core
cooling, and assure instrument availability, all good
things.
(Slide.)
MR. CARPENTER: The general format of the
I&E guidelines, which, again, is the bases for the
aging management program, is an overall description of
the components, the inspection history, and the
susceptibilities of the components; failure
consequences; the inspection requirements, both scope
and frequencies; flaw evaluation methodologies; and
reporting requirements, what they are going to be
telling the staff.
The program assures that the inspections
performed correctly and on time by qualified
personnel; and that the inspection results and flaws
are properly evaluated and dispositioned; and that all
repairs meet approved BWRVIP criteria or applicable
codes, as the case may be.
(Slide.)
MR. CARPENTER: BWRVIP conclusions were
that the program is broad in scope; the BWRVIP
includes appropriate inspections, evaluation
methodologies, repair criteria and mitigation methods
to assure BWR internals integrity; and the use of the
program during license renewal period provides an
adequate aging management program. Now, that --
CHAIRMAN APOSTOLAKIS: Whose conclusions
are these?
MR. CARPENTER: Again, this is the
BWRVIP's conclusions.
CHAIRMAN APOSTOLAKIS: Not yours? Okay.
MR. CARPENTER: I'm about to give you
ours.
CHAIRMAN APOSTOLAKIS: Okay.
MR. CARPENTER: Okay?
CHAIRMAN APOSTOLAKIS: It was too good.
(Slide.)
MR. CARPENTER: Everyone has their own
little advertisement that they want to put out. This
is the staff's. And the staff has, again, completed
the review of almost all the BWRVIP reports and those
that we have reviewed and have approved. And there
have been one or two that we have not approved as
either denied or not yet approved.
The staff has concluded that
implementation of the guidelines as modified to
address staff comments will provide an acceptable
level of quality for inspections and flaw evaluations
of the subject safety-related components. We have
also performed and independent research review, which
was NUREG/CR-6677, which I provided copies to the
Committee last week. That found that comprehensive
inspection programs like the BWRVIP can significantly
reduce core damage frequencies.
CHAIRMAN APOSTOLAKIS: Can or does?
MR. CARPENTER: Can.
MEMBER WALLIS: Well, how does an
inspection program reduce a core damage frequency?
Does it lead to a reassessment of some numbers? What
is the mechanism for it?
MR. CARPENTER: One second, sir.
MEMBER WALLIS: If you found something bad
in your inspections, it would increase the core damage
frequency.
MR. CARPENTER: What the summary for the
NUREG-6677 says -- and this is on Page 194 of the
report -- "With no credit for inspections, monitoring,
or repair; i.e., no BWRVIP program, and a probability
of significant cracks developing one, coupled with the
initiating event frequencies and system failure
frequencies and the PRA studied, an undesirable
increase in the plant core damage frequency; i.e.,
greater than 5e-6 events per year, is predicted.
"With the current BWRVIP inspection,
monitoring, and repair program, there is expected to
be no significant increase in CDF; i.e., less than
5e-6 events per year, caused by failures of BWR vessel
internals. That is, IGSCC problems can be identified
and evaluated or corrected to preclude a significant
increase in core damage frequency."
So you can identify the problems before
they occur.
MEMBER WALLIS: So it's the corrective
action that changes the CDF --
MR. CARPENTER: That is my understanding,
yes.
MEMBER WALLIS: -- or is it just your
state of knowledge, which is different, because you
know more?
MR. CARPENTER: If you can find a
potential problem before it can become an actual
problem, then you can reduce --
MEMBER WALLIS: Presumably if you found
problems which you didn't know about before, you could
conceivably increase your CDF?
MR. CARPENTER: If you're correcting them
before they become a problem.
MEMBER WALLIS: But if you didn't know how
to correct them, you find something you didn't know
was there before, it wasn't in your PRA, now it is,
you could increase your CDF.
MEMBER SHACK: Well, there's the PRA.
MR. CARPENTER: That's right.
MEMBER WALLIS: But the idea is it always
increases CDF. It may be --
VICE CHAIRMAN BONACA: It seems that the
better way to put it would be that -- I mean, it
prevents increases in CDF that would result from the
cracking. I mean, that's really what it says. With
respect to what we have measured today, if we did not
have these inspections and the repair, we would see an
increase in CDF by a certain amount they seem to
quantify.
MEMBER WALLIS: What would be the
mechanism for increasing that CDF? It would have to
be some cracking in the map, which increases your CDF.
VICE CHAIRMAN BONACA: Sure. You have a
high probability of --
MEMBER WALLIS: The crack growth is in
your model, and the CDF is increasing. But by
inspecting, you somehow --
VICE CHAIRMAN BONACA: For example, he
would have an increase in the frequency of ATWS.
Okay? And now because you have these inspections and
repairs, your frequency of the ATWS --
MEMBER KRESS: It affects two things: the
frequency of certain events, one of which would be
ATWS. It also affects the probability of events in
the event tree of going one way or another and certain
event trees. It affects those probabilities. And the
outcome is it in reality has effects on the CDF.
MEMBER SHACK: Yes. I mean, your computed
CDF may go.
MEMBER KRESS: Sure. Your computed might
have gone up, but the real CDF --
MEMBER SHACK: But your actual proved CDF,
which is the one you really should worry about --
MEMBER WALLIS: There's no such things as
a true CDF.
CHAIRMAN APOSTOLAKIS: There isn't such a
thing. Come on.
MEMBER WALLIS: It's always a computed
CDF. There's no such thing as a measured CDF. It's
always computed.
CHAIRMAN APOSTOLAKIS: I think Graham is
right.
MEMBER KRESS: Well, in principle, there
is a CDF.
MEMBER SHACK: You may not know what it
is. You may not know what it is.
MEMBER KRESS: There had better be a CDF
or we are beating our head against the wall.
CHAIRMAN APOSTOLAKIS: But all you have is
the computed CDF. Why is it "significantly"? I mean,
why do you put the word "significantly" there?
MR. CARPENTER: I did not do this report.
Is --
CHAIRMAN APOSTOLAKIS: I mean, am I to
compare this with the standard 10-6 or less vessel --
MR. CARPENTER: Well, that they use to --
CHAIRMAN APOSTOLAKIS: -- carrier? So 5
x 10-6 is significant?
MR. CARPENTER: It is significant, sure.
CHAIRMAN APOSTOLAKIS: Yes. That's fine.
VICE CHAIRMAN BONACA: The question I
have: In many of these reports on a related issue,
there is a statement that some of the degradation
mechanism could lead to inability of inserting control
rods. Okay?
And then there is a statement typically
that says: However that happens, you know, the SLC
system is available. And there is no discussion there
on the fact that, you know, the core reliance on the
SLC system is based on a very low frequency of the
ATWS event. I mean, that is not something that makes
me comfortable to know that if you cannot insert the
rods, you have the SLC system anyway. Well, I hope
we'll never have to use that system.
So I guess this is in the same contrast of
the evaluation that NUREG provides, I imagine. Yes.
Low probability and low likelihood. Okay.
But, anyway, I just wanted to comment how
there is this dependency there on the systems that in
design basis, they are not supposed to be used either
for the life of the plant, --
MEMBER FORD: Gene, I have a question.
MR. CARPENTER: Yes, sir.
MEMBER FORD: -- really, following up from
the meeting we had last week. And it relates to the
risk management and how quantitative we are. It
relates to the last line there. In the VIP documents
for disposition of the cracks for the austenitic
calories, we use the upper bound of the data. What
would the procedure be if in the future you found
cracks going faster than that upper bound?
And, as you know, we have done that. That
has occurred in the past for the ASME 11 code for
corrosion fatigue. We kept on moving the line up as
we got more data. Would you do the same? Would NRR
advocate the same, just increasing the upper bound as
you get more data? That is the first question.
The second question is both for especially
the low alloy steel disposition curves. It's based on
minimal data, and it is not the upper bound. How do
you manage that risk or how would NRR judge the
management to that risk? There could well be data
above the disposition line that has been quoted for
low alloy steels.
MR. CARPENTER: Dr. Ford, correct if I'm
misstating what you just asked me. The first part of
the question was: How would we evaluate if future
data comes in that shows that the crack growth rate
that we have at present is unconservative?
MEMBER FORD: Correct.
MR. CARPENTER: Okay. If we find that we
have a nonconservative crack growth rate, the staff --
I feel very confident in stating this categorically --
will go back. And we will evaluate that, and we will
perhaps tell them -- not perhaps. We will tell the
industry to go and reevaluate based on this additional
data.
MEMBER FORD: Okay.
MR. CARPENTER: Obviously we want to be
conservative. We want to be safe.
VICE CHAIRMAN BONACA: But I would expect
that the BWRVIP program would have procedures of this
type to incorporate data in the program.
MR. CARPENTER: The BWRVIP is planned to
be a living program. And they are planning to
evaluate as it becomes available and relook at all of
this, yes.
MEMBER FORD: And the second question,
which I am really concerned about, the low alloy steel
one, well, that disposition line I know because I did
it was formulated almost out of the air. I hesitate
to say that.
MR. CARPENTER: And I would certainly not
correct you at all. You are the expert there, sir.
But I will defer this to the staff expert on this.
Bill, Bill Koo, you are the one who looked
at some of this low alloy steel stuff. Could you
address Dr. Ford's question, please?
MR. BATEMAN: Bill's telling me he did not
perform that review. So I don't think we have that
particular expertise here to support at this time. We
will have to get back.
MEMBER FORD: I guess the answer would be
the same as the previous one that it is a living
document, if you like.
MR. CARPENTER: Certainly.
MEMBER FORD: And, therefore, you would
just revise it.
MR. CARPENTER: Certainly.
VICE CHAIRMAN BONACA: Just staying on
the issue, however, it would be interesting to know
more about the BWRVIP program and the commitments it
has. I mean, the staff cannot be ultimately
responsible for all the elements of the program.
The program is really a leading program
that is supported by the industry. So I would expect
it would have a number of guidelines on how new
information is incorporated, how it is distributed
among the participants, how commitments are revised,
and how the --
CHAIRMAN APOSTOLAKIS: Well, presumably,
you know, the results of the inspection program are
evaluated by somebody.
VICE CHAIRMAN BONACA: Well, I mean --
CHAIRMAN APOSTOLAKIS: That's what makes
it a program.
VICE CHAIRMAN BONACA: That's right, but
I would like -- you know, what we have heard here is
that the NRC would make certain requirements. The
point is that the program really should be or has been
successful before the NRC participated in that.
MR. CARPENTER: Correct. BWRVIP, as I
said at the beginning, is the clearinghouse for all of
this information. They do collect it. They do
provide it to all of their member utilities. And they
do evaluate all of the material that is looked at.
And they do come in and meet with the staff on a
regular basis to discuss the materials issues that
they have been evaluating, both domestically and the
information that they receive from overseas.
To date, whenever there is a problem or
there has been a concern raised, they have been very
fast in responding to that problem. For instance, a
couple of years ago, we had an instance with cracking
in the jet pump elbow risers. The BWRVIP took that on
very fast, and they did resolve it with the issuance
of a couple of reports, including the BWRVIP-28
report, which gave us a justification as to why the
operating plants were safe to continue operation until
they could perform inspections, and then later on with
the BWRVIP-41 report, which it gave inspection
guidance.
So they are looking at issues as they do
arise. And obviously the staff is looking at the same
issues on a concurrent basis.
Yes, sir?
MEMBER SIEBER: If I would go back to
Slide 3, --
MR. CARPENTER: Yes, sir.
MEMBER SIEBER: -- which shows the core
shroud, you talk about these inspections, but the
geometries for the welds shown in that figure to me
would be pretty complex. And so my question is: What
kind of inspection do you do? And how certain are you
that you detect whatever indications are there in the
geometry that is shown on this figure?
MR. CARPENTER: The BWRVIP has guidance.
Originally the BWRVIP was seven guidance for the
inspection of the core shroud circumferential welds.
That was later added to with the -63 report, which
deals with the vertical welds. And then it was all
subsumed into the BWRVIP report, which is still under
staff review.
They also have the BWRVIP-03 report, which
is the guidelines on how to perform inspections,
visual, UT, ultrasonic examinations, various other
types of examinations that would be done of the
vessel. It gives you guidance on how to qualify the
inspections and what makes a successful inspection.
So when they perform these inspections to
the guidance of the staff-approved BWRVIP-07 and -63
reports, using the -03 guidance, which has also been
reviewed and approved by the staff and modified with
staff comments, then we have a fairly high confidence
level that you are going to find whatever there is to
be found.
Does that answer your question, sir?
MEMBER SIEBER: Yes. Just as a little bit
of a follow-up, though, if I look at a VT-type
inspection, the indication has to be pretty
substantial in order to pick that up as a VT.
MR. CARPENTER: Well, bear in mind the
VT-3 examination, which is code-required, is a very
broad examination.
MEMBER SIEBER: Right.
MR. CARPENTER: The BWRVIP has taken that.
And they have reduced that down to an enhanced VT-1,
which is a one-half mil examination. So it is a much,
much finer examination.
MEMBER SIEBER: So you have gone beyond
the code requirement?
MR. CARPENTER: The BWRVIP has gone
considerably beyond code requirements, yes.
MEMBER SIEBER: Thank you very much.
MEMBER POWERS: I don't really understand
the response. It says: Gee, BWRVIP used a bunch of
expert opinion to come up with an inspection
technique. The staff looked at that. And based on
their expert opinion, they approved it.
Does anybody at any time go back and say,
"Okay. Here is a system that we know has flaws in it.
Show that the technique, in fact, does find those
flaws"?
MR. CARPENTER: Yes, sir. The EPRI/NDE
Center qualifies the inspectors.
MEMBER POWERS: It qualifies them for the
techniques against some sort of sample. But he is
asking: In this geometry, in this complexity, does it
work?
MEMBER SIEBER: That's different.
MEMBER POWERS: That's different.
MR. BATEMAN: Bill Bateman on the staff.
I think we would need to adequately
address your question for you to select a particular
weld which you thought was a complex geometry. And
once we understood what particular weld we were
talking about, we would be better able to give you an
answer. We might even have to go back to the BWRVIP
to help get that answer.
MEMBER POWERS: I think that would be a
useful thing for me to formulate the question that
way. I don't think I can. But I think there is a
generic issue here, one that we need to think about a
little bit. What can we do to validate by actual
experience, rather than expert opinion, these
judgments on the adequacy of the inspections?
Now, in some cases; for instance, in the
flaw distributions and pressure vessels, we have been
fortunate enough to get a couple of pressure vessels?
And they tear them apart at Oak Ridge or something
like that. And they get an actual distribution, and
they can do a lot of things.
Is there anything in the offing of getting
some actual internals someday that we can keep Oak
Ridge busy tearing things apart looking for flaw
distributions?
MEMBER SHACK: They'll still be screaming
hot.
MEMBER POWERS: Well, these vessels aren't
a walk through the park either.
MEMBER SHACK: Compared to the core, they
are.
MEMBER WALLIS: It's very simple, then.
You just deny license renewal. Then you've got a
vessel you can take apart.
VICE CHAIRMAN BONACA: Actually, we could
ask a question of the licensee that they had
indications on the shroud they could not tell if,
really, there were actual cracks. But they repair
them anyway because of the concern they had.
Could you expand on how effective it was
in the inspection, what the difficulty was in
determining whether it was an incipient crack or --
MR. BAKER: I'm looking to Charles Pearce
in the audience. And I am not sure that either one of
us have the actual detailed knowledge of the repair
that was affected today. We can certainly follow up
at a later date.
VICE CHAIRMAN BONACA: For the
application, it sounds like, really, you can tell if
it was a crack or not.
MR. BAKER: It was my understanding that
we preemptively repaired it. So whether there was a
crack or not did not matter.
VICE CHAIRMAN BONACA: That's right.
MR. BAKER: The repair was to support it
in a different way.
VICE CHAIRMAN BONACA: Wouldn't that pump
be a comment on the difficulty of making that
determination?
MR. BAKER: Yes. I just don't know.
VICE CHAIRMAN BONACA: Yes. Thank you.
MEMBER SHACK: I think Dana's comments are
correct. I can't think of any situation in which one
has qualitatively determined the probability of
protection for an NDE technique except maybe steam
generator tubes. It's largely the difficulty of
getting representative samples.
You know, most people aren't going to
volunteer to take their reactor apart. Even if you
could afford to do it, the sampling sizes you get are
just small. I mean, I think it is important in this
particular case, as Gene mentioned, that the VIP has
committed to the enhanced VT-1 with the half mil
resolution.
In this particular situation, the flaw
tolerance is such that, by and large, these cracks
have to be very large before they are structurally
significant. And so probably it is an expert judgment
again, but I would probably be more confident that I
could detect a crack of structural significance here
with the enhanced VT-1 than I probably would -- you
know, that I would be more confident in that than I
would be most inspections, you know, my probability of
detection of the structurally significant flaw.
But, again, it certainly hasn't been
demonstrated in any rigorous fashion.
VICE CHAIRMAN BONACA: We just recently
had the experience where inspections were conducted,
nuclear inspections, and nothing was done. And then
--
MEMBER SHACK: Borton follow-up is a very
effective inspection.
VICE CHAIRMAN BONACA: Well, when you find
a Borton, you find that you have a crack. Then you
look back at the other nozzles, and you find that you
have indications that you hadn't seen the year before.
MEMBER POWERS: It doesn't work at all for
BWR.
VICE CHAIRMAN BONACA: No. Borton
inspections aren't very good for BWR.
VICE CHAIRMAN BONACA: No. I understand.
I am only saying that I think the issue of inspections
is a very important one. I think the answer maybe is
the one that Bill is offering, that before you have a
real effect, you would have a visible indication.
MEMBER SHACK: Well, I think it was
important to go to the enhanced VT-1 because, as Jack
mentioned, VT-3 sees when they are broken parts laying
in the reactor. And even VT-1 is like a 132nd
resolution, --
VICE CHAIRMAN BONACA: Right.
MEMBER SHACK: -- which is like for a
stress corrosion crack, rather difficult. But, again,
when you get to the enhanced VT-1 and you have a fairy
large flaw tolerance, then you begin to I think
develop more confidence.
MEMBER SIEBER: I take it a lot of surface
has to go on prior to the actual examination.
MR. CARPENTER: That is correct, yes. The
BWRVIP-03 document does describe in detail how you are
supposed to clean the lighting, et cetera.
MEMBER SIEBER: Right.
MR. CARPENTER: Bear in mind visual
examinations are not the only examinations being
performed. They all started performing ultrasonic
examinations.
MEMBER SIEBER: Yes. That bothers me,
too, a little bit. When I look at welds like H3 and
H5, the only UT shots you can make are angle shots.
And you may not be able to differentiate in the area
of the lower core plate what components are where from
a UT readout. It just seems complex to me.
MR. CARPENTER: I understand.
MEMBER WALLIS: When you look on the
bottom of one of these vessels, what do you see? Do
you see junk of any sort or is it bright and clean and
shiny or what?
MR. CARPENTER: I don't know the answer to
that, sir. I haven't looked in the bottom.
MEMBER WALLIS: I just want a feel for
what kind of things you see in there when you look.
MEMBER SIEBER: I think you see a lot of
crud.
MEMBER WALLIS: There's a lot of dirt or
buildup?
MEMBER SIEBER: Well, it's crud, which is
--
MEMBER WALLIS: Unidentified deposit?
MEMBER SIEBER: Well, it's usually sort of
a harder deposit in the core area because softer ones
would be swept away. You know, there is boiling and
all kinds of turbulent flow in there. So it would be
an adhered hard type of crud.
MEMBER WALLIS: An unidentified crud.
MEMBER SIEBER: Which has to be cleaned
off to do a VT-2 point.
MEMBER LEITCH: Sometimes you see some
pieces of debris, too. Like down at the bottom, we
have had problems with -- there is a suction line
right from the bottom to -- I think it goes to reactor
water cleanup that has been plugged or obstructed at
several plants as a result of maintenance losing
pieces of things down in that suction line.
MEMBER FORD: Gene, could you comment on
the question of inspection frequency? You talk about
it being a proactive plan, which it is. As you go
into a new era, like a relicensing era, you don't
really know what you are starting with because not
everything has been inspected, especially down in the
bottom of the reactor. And all of the stub tubes
going through there, not all of them have been
inspected.
Is that something that would normally be
required by the NRR or how would you deal with that?
MR. CARPENTER: Dr. Ford, you play a great
straight man. Specifically for the lower plenum
internals, the staff has requested that the BWRVIP
revise their document to go in and do a baseline
inspection of the internals so that you do know what
you have in there during the current operating term.
And that way when you go into the license renewal, you
will have a benchmark. So you will be able to see
that.
MEMBER FORD: The reason why I understand
that there has been a cracking incident at Nine Mile
Point, I'm told that that was not inspected. And,
yet, you had a very large crack all the way around
this particular weld. And it hadn't been inspected at
all.
So how can we guarantee or ensure that
there is a minimal possibility of cleaning that in the
future? Would this program of inspecting the reactor,
100 percent inspection of the reactor, before
relicensing solve that particular problem; i.e.,
starting your clean slate, you know what your devil
is?
MR. BATEMAN: This is Bill Bateman from
the staff. I don't think that we can tell you with
any 100 percent certainty if the BWRVIP does generate
an inspection, that they will be able to identify 100
percent of the potential defects at the bottom of the
core stub tube welds at our CRDM housings, et cetera.
I don't think we're going to tell you that.
I think what we can say is in the case of
the Nine Mile one, they did identify the leak. They
did come in for a relief request to do a roll repair.
And we accepted that under the proviso that they would
subsequently develop a permanent repair.
So that is typically how we would handle
items that were missed in an inspection. You know,
they would manifest themselves in some kind of a leak
later on.
MEMBER LEITCH: The Hatch license renewal
application depends upon certain BWRVIP reports that
have yet to receive staff approval. What is the logic
of the resolution of that? Do we expect that those
reports will be approved prior to the Hatch
application being approved or is Hatch committed to
live by those VIPs once they are approved? How did
that work out?
MR. CARPENTER: Well, let me address first
the BWRVIP reports that the staff is reviewing. And
then I'll pass on what Hatch specifically is going to
be doing.
There are two inspection and flaw
evaluation guidelines that the staff has not yet
approved which Hatch is referencing. And those are
specifically BWRVIP-74, which is the reactor pressure
vessel guidelines, and BWRVIP-76, which is the core
shroud guidelines.
Now, please note -74 is a revision to the
BWRVIP-05 document, which the staff has approved
previously and we did talk to the ACRS about. That
again is available of the licensees to perform
inspections to that guidance.
The VIP-76, the core shroud, subsumes
three other documents, which the staff has already
looked at, VIP-01, -07, and -63. -63 still has open
items on it, and the BWRVIP still owes a response to
us to that, which is the reason the -76 document is
still under staff review.
Once we look at all of those, it is going
to be a fairly -- I won't say minor effort, but it
will be a fairly quick one to complete the reviews of
those two documents.
So yes, I do expect that by the time the
final SE for Hatch is issued, we will have completed
the reviews of these two documents.
VICE CHAIRMAN BONACA: From what you have
said, what you are telling me is that you don't see
the issues being reviewed are major issues of
contention or problems?
MR. CARPENTER: There are some open items
still in the Hatch review.
VICE CHAIRMAN BONACA: Yes.
MR. CARPENTER: But those I'm not ready to
address at this time.
VICE CHAIRMAN BONACA: I'm not talking
about the elements of those vessel and shroud VIPs
that have not been approved yet.
MR. CARPENTER: Hatch has --
VICE CHAIRMAN BONACA: Not Hatch. I'm
talking about the VIPs.
MR. CARPENTER: Oh, okay. If you're
talking about just those two reports, --
VICE CHAIRMAN BONACA: Yes.
MR. CARPENTER: -- no, I don't see that we
are going to have a terrible amount of contention
between the staff and the VIP to resolve the open
items.
VICE CHAIRMAN BONACA: That's the sense we
got during the subcommittee meeting.
MR. CARPENTER: Yes, yes.
VICE CHAIRMAN BONACA: Thank you.
MR. CARPENTER: And if there are no other
questions on this, I will go to my final slide.
(Slide.)
MR. CARPENTER: The staff is completing
the review of the license renewal appendices. And we
have found that by referencing the aging management
programs and completing the action items in the
staff's SE, that there will be a reasonable assurance
that applicants will adequately manage aging effects
during the extended operating period and that the
generic AMPs usage will significantly reduce staff
review of license renewal applications in the future.
MEMBER WALLIS: This reasonable assurance
is somebody's judgment?
MR. CARPENTER: Yes, sir.
MEMBER WALLIS: This is a nice sort of
expression here, but what do you really mean by
"reasonable assurance"?
MR. GRIMES: This is Chris Grimes. I'll
address that question because this transcends license
renewal.
Reasonable assurance is the finding that
we have associated with our libation under the Atomic
Energy Act because we cannot provide the public with
certainty of safety. We developed a finding that was
derived from the requirements in Part 50 that say that
our obligation is to have reasonable certainty,
reasonable assurance, that the plant is safe. And the
whole construct of the regulations is built around
that.
Each individual piece, whether it's the
vessel internals program or the adequacy of aging
management associated with water chemistry or the
completeness of the scoping, all of those are
predicated on individual staff judgments that are
founded in criteria that we usually promulgate in reg
guides and the standard review plan.
MEMBER WALLIS: So these are the same
words you use when you have a new reactor. So one
could conclude that the licensed reactor is as safe as
a new one.
MR. GRIMES: I wouldn't go that far. I
would say that there are standards that were
established on a different basis. We use --
MEMBER WALLIS: It's less safe than a new
one. So how much less safe is it?
MR. GRIMES: We don't make any assertion
that it's more or less safe. We assert there is
reasonable assurance that aging will be adequately
managed for the purpose of issuing a renewed license.
But the original license we established reasonable
assurance that this plant will operate within its
design envelope.
MEMBER WALLIS: I'm just saying if I try
to explain that to an undergraduate, it doesn't mean
anything. It just means that the staff is satisfied.
I like that. That's fine. You're doing your job.
But it's not English. It's not something
that is the understandable to the public. If you
could say these are as safe as they were when they
were new or something, some sort of measure of this
assurance, it might be more helpful.
MR. GRIMES: It's a very good point. And
so I don't want to make light of it. The difficulty
that we have is trying to establish in plain language
what constitutes -- we're satisfied it's safe enough,
recognizing that the degree, whether it's more safe or
less safe, is something that evolves. And that is why
license renewal focuses not on some established line
in a sand of safety but more the processes that are
used to continually challenge the judgment over time.
And we will continue to try and work on
articulating some simple explanation for the purpose
of trying to explain to the public how we reach these
decisions.
MEMBER WALLIS: One problem is, of course,
it's not risk-informed. As you continue to measure
the risk, you might be able to provide assurance that
it's no riskier than it was.
MR. GRIMES: I would like to be able to
say that. I hesitate primarily because of the process
aspect and the state of the knowledge. Several
comments before got to the complexity of the
inspection activity relative to a finding of whether
or not we have identified everything that possibly
could happen. And we don't emphasize enough the
living program aspect that learns as it goes. And
reliance on the quality assurance process is to change
behavior when knowledge teaches you something
different.
I think that we might say that we believe
that it will be as safe or more safe, but then when
we're challenged by a quantitative measure that we
struggled to be able to explain what we thought was
safety when it was originally licensed versus what we
know of safety today versus what we speculate about
safety in the future.
MR. CARPENTER: If there are no further
questions on the BWRVIP, I will turn this over to Mr.
Baker.
VICE CHAIRMAN BONACA: Thank you. I
appreciate it. Any other questions for Mr. Carpenter?
(No response.)
VICE CHAIRMAN BONACA: If none, then we
can move on. I believe we have now a presentation by
Southern Company. Mr. Baker?
(Slide.)
MR. BAKER: Good morning. My name is Ray
Baker, and I am the Hatch project manager for the
Hatch license renewal application. I would also like
to say that with me today is Charles Pearce, who is my
direct supervisor, who is the manager for the license
renewal group at Southern Nuclear. I appreciate the
opportunity to speak to you today on behalf of Plant
Hatch.
In the subcommittee meeting last week, we
were asked to specifically focus on two items for your
attention today. So today I am pleased to speak in
some detail about the recent Hatch operating
experience and to discuss our programs in terms of
existing, enhanced, and new programs.
(Slide.)
MR. BAKER: I would like to first provide
a summary discussion of the Plant Hatch vessel
internals operating experience. And following that I
will discuss the significant aging issues that Plant
Hatch is currently addressing; that is, those items
that were observed during the five years preceding the
Hatch application's submittal.
This discussion addresses aging issues
only for those systems, components, and structures
that are subject to aging management review under the
license renewal rule.
First I would like to discuss our reactor
vessel internal experiences. And we have actually
talked some about that already, but let me go back a
bit further than the shroud to the core spray
spargers.
On Unit 1, IGSCC was identified in one of
the core spray spargers early in life. That was
repaired by a mechanical clamp. No additional IGSCC
or other degradation has been detected since then. A
full flow injection test was formed a few refueling
outages ago with pre and post-injection inspections.
And no problems were noted.
Another experience relates to feedwater
nozzles. Unit 1 experience feedwater nozzle cracking
in the late 1970s we replaced and the old slip-fit
sparger that was the original design with the
triple-sleeve, double-piston sparger. And we modified
operation of the feedwater flow controller at that
time. These changes appear to have eliminated the
causes of cracking in that component.
The Unit 2 sparger was replaced during
construction with a welded sparger. And these fixes
that Plant Hatch and other BWRs have implemented
appear to have resulted in elimination of feedwater
nozzle cracking. This was identified in a Hatch
submittal that led to a generic submittal for the
current inspection program. That is a revision to the
original NUREG-0619 program that the BWRs use for
feedwater nozzles. This, in turn, is referenced in
BWRVIP-74 as a corrective approach for extended
operation. And this is also referenced in the GALL.
As we noted earlier, both core shrouds
have been preemptively repaired. The repair hardware
and the vertical welds are inspected per the BWRVIP
criteria.
And the final internals item I would note
is that the access hole covers have been replaced with
covers attached by mechanical means, as opposed to
welded. And the materials used in the replacement
covers are not considered to be IGSCC-susceptible.
MEMBER LEITCH: You have removed the CRD
return line from both Hatch units, the CRD return line
with a nozzle on the vessel that was experiencing some
cracking?
MR. BAKER: I'm not familiar with that.
I'm sorry. I don't know.
MEMBER LEITCH: I think most of the BWRs
had removed that, but my question was basically
specifically related to Hatch. So I would like to
know the answer to that question when we get a chance.
MR. BAKER: We'll follow up with that.
MEMBER LEITCH: Thank you.
MR. BAKER: Next I'll turn to the current
aging issues for the in-scope system structures and
components; that is, those components that are of
particular interest for license renewal. First I'll
mention the control rod drive cap screws. Across the
BWR fleet, a number of control rod drive cap screws
have exhibited indications of localized corrosion and
stress corrosion cracking.
G.E. issued a SIL, SIL Number 483, to
address this issue. G.E. determined that inadequate
design in conjunction with environmental conditions
contributed to the failures. G.E. developed redesign
cap screws to mitigate that degradation. The new cap
screw design has a larger radius at the shank-to-head
transition region to reduce stress concentrations and
to fabricate from a higher-strength material. It
includes a new washer design that features slots to
facilitate drainage of any collected fluid.
These indications that were observed were
detected during VT-1 examinations. And no bulking
failures occurred. Plant Hatch is currently in the
process of upgrading all the control rod drive cap
screws to the new G.E. design.
Next I'll discuss plant service water
piping corrosion and fouling. Instance of fouling and
corrosion in plant service water pipelines have
occurred and continue to occur at Plant Hatch.
Areas of significant degradation or
leakage have been limited to smaller diameter piping
sections less than or equal to four nps. Specific
areas of focus are low flow areas where fouling and
localized corrosion may occur in creviced areas and in
heat exchangers. In many cases, the plant service
water and RHR service water piping inspection program
identified the degradation prior to leakage. In all
cases, no loss of system-intended function occurred.
The plant service water and RHR service
water piping inspection program does aggressively seek
out those areas where degradation may be occurring
based on past experience. So it is experience-rated.
The future inspections are based on the past
experience.
We continue to selectively replace
sections of carbon steel piping in this river water
environment with 304, 304L, or AL-6XN stainless steels
to greatly reduce the potential for recurrence.
The next area of operating experience I
would like to speak to is flow-assisted or
flow-accelerated corrosion; in particular, in the
high-pressure coolant injection system and the reactor
core cooling system.
We had initially excluded locations in
HPCI and RCIC from the fact program based on their low
usage. These systems are expected to operate less
than two percent of the time. However, degradation
and minor leakage of piping downstream of the HPCI and
RCIC steam supply drain pipes has occurred in the past
five years. This is piping that is downstream of the
condensers for these turbines.
The identified leaks were minor in nature.
And no loss of intended function occurred. These
indications resulted in the addition of fact program
sample points in these two systems for the Plant Hatch
application.
The next area I would like to speak to is
related to the torus shell, the corrosion of the torus
shell. Plant Hatch protective coating activities in
the torus have identified limited areas on the
interior torus shell surfaces where some breakdown of
the inorganic zinc coatings and subsequent localized
corrosion have occurred.
The protective coatings program provides
for regular monitoring of the corrosion rates in the
torus and for repair of degraded coatings and
surfaces. And no loss of intended function has ever
occurred with regard to this.
Another area of interest is general
corrosion of carbon steel in components such as piping
and supports in areas routinely exposed to weather,
such as intake structure pit area, service water value
pits, and the emergency diesel generator-building
roof. Plant Hatch has implemented actions to address
those areas and is in the process of implementing
additional actions to identify and prevent future
degradation occurrences due to weather exposure.
Finally, I would like to mention the fire
water storage tank. Damage to the original installed
vinyl coatings and subsequent corrosion of fire water
tanks has occurred due to various causes. The Plant
Hatch fire protection program identifies this
degradation during routine inspection of the tanks and
provides for continued monitoring of those areas of
degradation. No loss of intended function or leakage
of any kind has occurred due to this degradation.
MEMBER SIEBER: What kind of water
treatment do you use for fire water?
MR. BAKER: This is deep well water. So
there is no water treatment applied to that.
MEMBER SIEBER: Treatment.
MR. BAKER: That's right. It's raw water.
MEMBER SIEBER: So it's pretty high in
dissolved solids and minerals and --
MR. BAKER: It's raw water.
MEMBER SIEBER: Thank you. Filter?
MR. BAKER: That's deep well. So it's a
clean source, yes.
MEMBER WALLIS: But deep wells have lots
of dissolved materials in them. Water from deep wells
has all kinds of stuff in it.
MR. BAKER: Yes, sir. There are chemistry
samples taken. And there are limits applied to that
that --
MEMBER SIEBER: But there is basically no
treatment?
MR. BAKER: There's no treatment. That's
right.
VICE CHAIRMAN BONACA: You mentioned in
the beginning that you replaced the vessel access hole
cover plates?
MR. BAKER: Yes, that's correct.
VICE CHAIRMAN BONACA: Okay.
MR. BAKER: They were replaced with a
mechanical design, as opposed to a welded-in design.
VICE CHAIRMAN BONACA: So they have been
experiencing degradation?
MR. BAKER: We replaced them. And I do
not recall if that was a preemptive repair or whether
there was an indication it was observed.
MEMBER LEITCH: There were at least
industry indications.
MR. BAKER: Yes, there were industry
indications. I don't recall whether there was one at
Hatch or not.
MEMBER POWERS: Can I come back to this
fire water tank that you have?
MR. BAKER: Yes.
MEMBER POWERS: You say that you have a
degradation because the liner has been damaged in the
past. And it is corroding. But no loss of function
has occurred. How long do we have to wait before it
does have a loss of function?
MR. BAKER: The entire purpose of the
monitoring program is to prevent that from occurring.
So that is is --
MEMBER POWERS: I guess I am a little
perplexed. Corrosion is only taking place when the
guy is inspecting it?
MR. BAKER: No, that's not --
MEMBER POWERS: Well, what is it about the
inspection program that prevents the tank from failing
at 1:00 o'clock in the morning?
MR. BAKER: First, the corrosion is not
significant corrosion. It is a surface corrosion that
is well-behaved. It's not something that is a rapidly
occurring situation.
The monitoring is frequent enough to
observe any progress of it. It is in localized areas
where the damage to the liner had occurred. And there
are acceptance criteria relative to how much corrosion
would be allowed before further action would be
required.
Routine maintenance activities are
performed in the plant. So this is not something that
would just be left to corrode through to failure.
MEMBER SIEBER: But I think there is
another issue, which you may be referring to, Dr.
Powers. If the liner comes off, it's inorganic, and
it usually comes off. It's flakes. Flakes go through
the fire water system. And if you have all of the
sprinklers in the plant, the sprinkler heads have
pretty small nozzles in them. And so they're
susceptible to plugging from this debris caused by the
coating.
If I remember your application, you
actually have two ranks.
MR. BAKER: Two tanks. Yes, that's right.
MEMBER SIEBER: And they are 300,000 a
piece?
MR. BAKER: Yes. Large tanks, yes.
MEMBER SIEBER: So one of the tanks by
itself is adequate to satisfy the code requirement for
a fire water system. Does that mean that you on
occasion drain the other tank through the inspection
system?
MR. BAKER: That's correct.
MEMBER SIEBER: So the tank is fully
drained. And, therefore, you can work on the coding
and restore it as necessary?
MR. BAKER: That's one of the mechanisms
where some of the damage has occurred, in fact, is
from scaffolding up inside a tank to nick the
coatings.
I would also observe that outside the
scope of license renewal, just as part of routine
plant activities, there is a plan to drain and recoat
those tanks with a newer state-of-the-art.
This coating was the state-of-the-art 25
years ago or so. When it was applied today, it's no
longer state-of-the-art. I believe that there will be
a recoating of that in the future.
But it is from our perspective here in
managing the aging, the focus would be to make sure
that we have it captured by identifying it and then
managing it.
MEMBER SIEBER: A secondary issue is the
fact that you have debris now in fire water.
MR. BAKER: Yes.
MEMBER SIEBER: And if it goes to
sprinklers, you may have sprinklers that don't
operate.
MR. BAKER: That's right. Thank you.
MEMBER LEITCH: What's the material of the
recirc piping at Hatch? Is it still 304 stainless?
Most of the plants of the Hatch vintage had 304 and
were --
MR. BAKER: Unit 1. Unit 1 has the
original recirculation piping. So it's the original
304 or 304L. I do not recall which. Unit 2, the
recirculation system piping was replaced. If my
memory serves me correctly, it's 316 nuclear grade of
the place design so that it doesn't have the dead ends
on it.
MEMBER LEITCH: Yes. Thank you.
MR. PEARCE: Ray, my name is Charles
Pearce. I'm with Southern Nuclear. I stepped out for
a second. I can give you your answer on your CRD
return lines. They were cut and capped. We do an
inspection of that weld periodically. The lines now
feed into the reactor water cleanup. So, actually,
the CRD line was rerouted to reactor water cleanup,
which now feeds back into the feedwater, ultimately
back into the vessel.
MEMBER LEITCH: That's both units?
MR. PEARCE: Both units.
MEMBER LEITCH: Yes, thank you.
MR. BAKER: Thanks. I just could not
recall whether we had done that specifically.
MEMBER LEITCH: Thank you.
(Slide.)
MR. BAKER: Now I would like to turn to
the Plant Hatch license renewal programs. This first
viewgraph lists the existing programs that we had
credited. We characterize a program as existing, as
opposed to enhanced or new, if only administrative or
minor technical changes were made.
Typical administrative changes include
revisions to identify the license renewal commitments
in the program. For example, you see several water
chemistry programs in the left-hand column. And so
for each one of those, the applicable water chemistry
programs would note commitments to the minimum
standards that are contained in the appropriate EPRI
BWRVIP water chemistry guidelines. In addition,
technical changes of a minor nature were made to the
two programs that I have highlighted there in the
blue.
MEMBER SIEBER: Do you use hydrogen
injection?
MR. BAKER: Yes, we do. It is a part of
the regime that is provided for in the EPRI water
chemistry guidelines.
MEMBER SIEBER: Right.
MR. BAKER: There are two modes you can do
it with or without. Certainly there is no desire to
do it any period of time without. Our normal mode is
with hydrogen injection.
MEMBER SIEBER: Have you used hydrogen
injection? For how many years? The plant is too old.
MR. BAKER: We were one of the first.
MEMBER SIEBER: The plant is too old to
have always used it.
MR. BAKER: No. We were one of the first.
MEMBER SIEBER: All right.
MR. BAKER: So that I don't recall the
exact year. For a number of years now.
MEMBER SIEBER: Okay.
MR. BAKER: And we also have aggressively
pursued and implemented a noble metal addition.
MEMBER SIEBER: All right. Okay.
(Slide.)
MR. BAKER: On this next viewgraph, I list
our enhanced programs. As you can see on this
viewgraph, most of the programs were enhanced by
broadening the scope of the program. I would note
that the categorization here is not absolute. All of
these programs, perhaps with the exception of
structural monitoring program, also include monitor
technical additions.
However, for the programs, protective
coatings program and equipment piping and insulation
and monitoring program, the technical changes that we
made for license renewal were more extensive.
MEMBER SIEBER: In the structural area, do
you monitor building settlement?
MR. BAKER: Building settlement has been
observed user technical specification requirements
from the beginning of operation. And a consolidation
settlement occurred prior to the completion of
construction. And we have observed no significant
differential structure to soil or building
differential settlements.
So it's not really a part of the
structural monitoring program.
MEMBER SIEBER: Do you have a requirement
to survey the buildings with appropriate benchmarks
that see over the years how much one changes relative
to the other?
MR. BAKER: We continue to monitor
building settlement by the tech specs.
MEMBER SIEBER: All right. Thank you.
MR. BAKER: Yes, sir.
(Slide.)
MR. BAKER: Finally, this viewgraph
depicts the new programs that are being accredited for
license renewal. The four programs on the left are
the four new one-time inspections. These inspections
are to be performed during the last five years of the
current term and serve as confirmatory inspections.
Therefore, areas where we believe no significant age
degradation is occurring beyond that which is being
managed by other programs, these inspections will be
used to confirm those expectations.
The three highlight programs contain many
elements that were contained in existing plant
procedures and activities. However, a number of those
activities were not appropriate for crediting and
license renewal. So we have repackaged, revised, and
rearranged those activities into the three programs
shown here for primarily documentation purposes.
So these are the 30 programs and
activities that will function during the renewal term
to adequately manage aging effects for the end scope
system structures and components at Plant Hatch.
That concludes my presentation. Are there
any questions?
MEMBER FORD: What spurred the galvanic
susceptibility inspection? Was it a problem that you
foresaw or was there a real problem that you reacted
to?
MR. BAKER: It's potential. We have a
number of dissimilar connections; for example,
in-plant service water. And we want to observe it.
That will be the leading indicator for us. We believe
it's raw water and dissimilar metal connections. So
we would want to make sure.
MEMBER FORD: Okay. So it is not in the
raptor itself?
MR. BAKER: No. No, sir.
MEMBER SIEBER: Another aspect of galvanic
corrosion is the grounding mat. What steps do you
take to determine that it is still intact and capable
of performing its function?
MR. BAKER: The grounding was not an end
scope component for license renewal in our plant, but
I would need to find out what the routine maintenance
of those is.
MEMBER SIEBER: When those mats fail, when
a plant gets 40 or 50 years old and those mats
deteriorate, then you can take a Simpson volt meter --
MR. BAKER: Yes.
MEMBER SIEBER: -- and go from one pillar
to another and get 10 or 15 volts. Sometimes that
changes trip settings on equipment, causes higher
currents during restarts. It can make a lot of
problems.
MR. BAKER: I know that we have paid
attention to the grounding mat for the 2 units over
the first 20 years, but I would have to specifically
address that later as to what we currently are doing.
MEMBER SIEBER: Thank you.
VICE CHAIRMAN BONACA: Just for
clarification, a passive component inspection, that's
why you have an inaccessible component inspections;
right?
MR. BAKER: Yes, that is correct. Yes,
primarily the focus of that is when something is
excavated or exposed that is normally not accessible,
we will take advantage of that opportunity to examine
it.
VICE CHAIRMAN BONACA: Yes.
MEMBER LEITCH: I'm concerned about the
suction to the river water pumps. I'm not sure what
you call them, but I assume you have river water
cooling a heat exchanger which, in turn, cools the RHR
system.
MR. BAKER: Yes. It's a part of RHR
system. It's RHR service water.
MEMBER LEITCH: RHR service water. And
they take suction. Those pumps take suction from the
river?
MR. BAKER: Yes, that's correct.
MEMBER LEITCH: Now, I'm not familiar with
the configuration of Hatch. I was kind of concerned
about this over years silting building up and then
some unusual tide condition occurring, high winds or
something, that might cause those pumps to lose
suction.
MR. BAKER: We have a couple of activities
that address that. The Altamaha River is basically a
floodplain. It's a meandering river historically.
The area immediately adjacent to the plant has been
straight for a number of years. It is a nice straight
section of the river.
We have permits for dredging. And we do
dredge in front of the intake structure approximately
every 18 months. There is also a periodic inspection
by divers that we send down to make sure that the
actual intake structure pit itself as clean. So those
activities occur routinely.
MEMBER LEITCH: Okay. Thank you.
MR. BAKER: Thank you.
VICE CHAIRMAN BONACA: Any other questions
for Mr. Baker?
(No response.)
VICE CHAIRMAN BONACA: If not, thank you
for your presentation. And now we want to hear from
the staff, somebody with the NRR. Mr. Burton?
(Slide.)
MR. BURTON: Good morning. My name is
William Burton. I generally go by Butch. I am the
lead project manager for the staff review of the Hatch
license renewal application.
I want to make my apologies up front. I
like to make my mistakes early, obviously full
Committee, as opposed to the subcommittee meeting.
(Slide.)
MR. BURTON: The first thing I want to do
is give a little overview of the Hatch application
submittal. The application was submitted by letter
dated February 29th of last year. As you all know, it
is a two-unit boiling water reactor. It is located
about 11 miles north of Baxley, Georgia and
approximately 70 miles from Savannah, Georgia, west of
Savannah.
Right now Unit 1, its current license is
due to expire in August of 2014 and asking for a
20-year extension to 2034. Similar, Unit 2, current
license is due to expire in June of 2018, again a
20-year extension to 2038.
I did want to put up briefly -- this is
not in your package -- just where we are in terms of
the review.
(Slide.)
MR. BURTON: We just completed on March
16th the AMR inspection. We took a team of folks from
both Region 2 and from headquarters to go down and see
how some of the commitments that are currently
outlined in the aging management programs are actually
being implemented on site.
And compared to some of the previous
applications, Southern Nuclear is a lot further along
at this point in terms of actually implementing those
commitments from the aging management programs into
their on-site procedures.
MEMBER WALLIS: I would think this is very
important. I mean, I read the SCR draft. It seems to
be this assurance that they have these programs. I
don't have the same assurance that they are really
good programs, that they are good enough programs.
Just the fact that they have a program doesn't mean to
say that it is good enough.
MR. GRIMES: This is Chris Grimes. I
would like to emphasize that the scope of these
inspections is intended to verify that the procedures
are in place or that the attributes of the program
relative to scope, methods, criteria, and so forth are
there.
Another aspect of the inspection includes
the inspectors looking at the effectiveness of the
programs relative to operating experience. Now,
clearly if they are new programs, you are correct.
There's not much we can ask the inspector to do about
trying to assess the effectiveness of the program.
For some of the longstanding original
inspection and maintenance activities, we do gather
insights in terms of the effectiveness of the programs
in order to try and bolster the conclusions in the
safety evaluation about the effectiveness of the
programs. So it is an aspect of the reasonable
assurance finding we try to develop.
VICE CHAIRMAN BONACA: And I understand
also that, although it is not referenced yet because
it is not finally approved, the GALL information has
been extensively used as a reference for evaluation.
MR. GRIMES: Yes, sir, that's correct.
The staff had the benefit not only of contributing to
GALL in parallel with this review but also having it
available for the users to use as a reference
material, even though we don't explicitly cite it in
the safety evaluation.
VICE CHAIRMAN BONACA: Thank you.
MEMBER POWERS: Before we move on, could
I ask a question about this inspection team that you
send down there? Did that include people who looked
at the fire protection system?
MR. BURTON: Yes. In fact, I was the team
member who actually did look into fire protection.
One of the questions that came up earlier had to do
with the fire water tanks. I do want to say that as
part of that inspection, I did go down and look at
some of the videotapes that they took at the inside of
the tanks. What they did was they did an inspection
of the tanks back in '91 and observed that some of the
coating was beginning to break down into grade and
looked at some of the condition reports that followed
from that.
And then they did it again in '99 and
actually observed those tapes. There was some -- you
could see the decomposition and some of the debris in
the bottom. But, as Mr. Baker had said, they are
actually in the process of -- they are going to be
recoating the tanks in the near future. And those
were the original coatings.
MEMBER POWERS: Did they have to re-flush?
Did the fire water dispersal lines
MR. BURTON: I believe that was probably
part. I know when they emptied the tanks, I believe
that was part of the entire thing. Procedurally, they
do that.
One of the things that the Committee is
interested in is comparing applications. Obviously
because this is the first BWR, there is particular
interest in whether there are in particular any new or
unique aging effects that BWRs are subject to versus
the Ps. The staff did pay particular attention to
that.
Now Southern Nuclear took a commodity
approach in that rather than just looking system by
system, they actually identified what materials are we
looking at, and in what environments are those
materials operating, commodity groups.
As such, what we found was that there are
no unique materials. The materials are not being
operated in any kind of unique environment. As a
result, we did not see any new or unique aging
effects. In fact, in the application there is an
Appendix C-1 that really speaks to aging effects and
some of the consequences of that. But we did not find
anything new. So in that respect, we really don't
expect the BWRs -- we don't expect to see anything
unusual compared to any of the PWRs.
MR. GRIMES: This is Chris Grimes. I want
to emphasize that we did see uniqueness relative from
application to application. But when Butch says we
didn't find any new aging effects, remember that
that's drawn on the nuclear plant aging research
program that began over a decade ago. I would have
hoped that we would not have found any new aging
effects in this application. So that was reassuring.
But we did learn some process lessons in
terms of the way that the information was packaged.
Specifically, with respect to commodity groups.
MR. BURTON: And actually to follow on on
that, to talk about some of the other differences that
you may see compared to some of the previous
applications. As Chris said, it really was the
uniquenesses were really a matter of process and
packaging I guess you would say.
As you now know, it's the first to use the
BWRVIP reports, which we have already discussed. It
was the first to use a functional approach versus a
system approach in the scoping process.
Now what do I mean by that? What Southern
Nuclear did was they looked at every single system in
the plant, identified all of its functions, and then
bounced the functions off of the scoping criteria. So
what you see is not a direct correlation between the
system and whether it's in scope or not. What you see
is the identification of the in-scope function, which
was I think a little bit different approach.
Then finally, Southern Nuclear as you all
know, there are 10 program attributes that are
assigned as criteria to evaluate the aging management
programs. Southern Nuclear took a unique approach in
that they took the 10 program attributes and applied
them to a demonstration of adequate management.
Probably the best way to do it is to show
you what I mean by that.
CHAIRMAN APOSTOLAKIS: This "functional
versus system approach" what does that mean? Even if
you look at the system, you look at its function,
right?
MR. BURTON: Yes.
CHAIRMAN APOSTOLAKIS: So what's the
difference?
MR. BURTON: The difference is that
normally you would look at a system and you would say
does the system directly meet what turns out to be the
eight or nine questions that constitute the scoping
criteria. Probably the best way to do it is to give
you an example.
Main steam. Main steam, most of us think
that would obviously be in scope. But what actually
happened was they looked at main steam and looked at
each of its functions, and which of those functions
would actually meet the scoping criteria. As it
turned out, for main steam the in-scope function was
contained in isolation.
So that is actually what brought the
system into scope, but it was actually that particular
function. In fact, maybe this wasn't the best
example, because what we also found was that as they
looked across systems, you found certain functions
that were common across a number of systems. What
they chose to do was to actually pull those functions
out and group them separately. Containment isolation
was one of them. Because it cut across so many
different systems, they have a specific category for
the containment isolation group C61.
Another one was reactor coolant pressure
boundary. That function cut across a number of
systems. It was actually pulled out and categorized
separately. So it was really a function-based
assessment.
CHAIRMAN APOSTOLAKIS: That's not very
clear, but at least we are making progress.
VICE CHAIRMAN BONACA: We commented quite
a bit during the subcommittee meeting that that
created a lot of difficulty for reviewers,
particularly when the people on the subcommittee had
to review it because you have a system that you
presume just because there will be scope, then you are
looking at it, you don't find a description of the
system up front. Then coming through this, you just
don't find it. You have to search through these
functions, for example, that it perform a containment
isolation, then you find an element of that system.
So you say well wait a minute now, are the other
pieces of that system out of scope? A lot of the
questions in the NRC had to do with that. The answer
is no, they are in scope. They are somewhere else.
So it made it very confusing, I must say.
But I think that ultimately, you learn to do it.
CHAIRMAN APOSTOLAKIS: This is a good step
forward. If you keep it up, eventually you will
rediscover PRA.
MR. BURTON: Okay. Let's go on.
MEMBER POWERS: We're busy trying to
decide whether that's a good rediscovery or a bad
rediscovery.
MEMBER SHACK: If you didn't put in core
damage frequency, George, it wouldn't exist.
MR. BURTON: Oh boy. What Dr. Bonaca just
spoke about, we spoke about that extensively at the
subcommittee meeting. We reached a consensus that
these issues are what we call navigational issues,
being able to see your way through the application.
There were several challenges in that respect.
This is an example, this is in the
application, in one of the appendices, called the
Aging Management Program Assessment. What Southern
Nuclear did was they looked at each commodity group
and each aging effect for that commodity group. What
they did was they took the ten attributes, as you see
over here on the left, and actually showed where the
program coverage was for that, which was actually very
good.
It wasn't what we normally see in terms of
how the 10 program attributes are applied. I should
say that the navigational -- the RAIs that came out
having to do with navigational questions, and we had
a number of RAIs because we didn't see how the ten
attributes were being applied directly to the
programs. We had a number of RAIs that came out as a
result of that. By my estimate, probably a third of
the RAIs fell into those groups.
We issued the safety evaluation report.
We had 18 open items. Obviously we have had ongoing
dialogue. At this point, we have four that are under
appeal. I need to explain what that is.
With the license renewal process, we allow
for situations where if we don't seem to be making
progress at the working level, we have a series of
appeal meetings that start at the branch chief level
and move ahead, to try and resolve those issues.
Right now, of the 18 open items, we have
four that are under appeal. In fact, one of my
takeaways from the subcommittee meeting was to give
you the status because when we had the subcommittee
meeting, the following day we were going to have the
first of the appeal meetings. So the next slide, I'll
be speaking on that.
So we have four under appeal now. That's
not to say that that's the be all and end all. As we
continue our dialogue at the working level, if we find
additional items that need to go into appeal, we'll
start to do that.
Of the 18, five are now in a confirmatory
status. What that means is that the staff and
Southern Nuclear, we have reached agreement but we
haven't dotted all the Is, crossed all the Ts. It's
not official yet. So until then, it is actually
confirmatory.
CHAIRMAN APOSTOLAKIS: Who is the ultimate
authority regarding appeals, the one that says this is
it?
MR. BURTON: This is it? Well, I'll let
Chris speak to that.
CHAIRMAN APOSTOLAKIS: Chris?
MR. GRIMES: I don't think that highly of
myself. The ultimate authority would be the
Commission. If an individual applicant isn't
satisfied with the staff position after it's addressed
at the branch level, we go to the division level.
Then we go to the office level. Ultimately, the issue
could go up through the EDO to the Commission if it
were significant enough.
Most of the issues of industry concern
that got to that kind of strategic level, I think were
revealed in the credit for existing programs issue
that went to the Commission and instruction the
Commission gave us in terms of how to offer the
industry an opportunity to take credit for existing
programs, which is the way that it was phrased.
So we'll discuss that a little bit further
in the next meeting, where we talk about the improved
renewal guidance.
MR. BURTON: I did want to -- I didn't
write down all the items that are now confirmatory,
but I did want to give you an idea.
One of the open items that we had was we
asked for a one-time inspection for the fuel oil tank
bottoms. That was on the table. We since learned
that they had actually already done such an
inspection, and have actually given us the result.
They had actually dug up and inspected one
of the four big EDG fuel oil tanks, and found that
there was very little reduction in thickness. That
argument also carried over into their two smaller fuel
oil tanks for their diesel fire pumps.
So we got that response fairly quickly
because they had already done it. So that's basically
closed, but again, we haven't done all the official
paperwork.
Another one is the complex assembly issue.
If you remember, that issue came up with Oconee. That
was actually resolved. We developed an approach to
resolving that. Initially it was not clear that
Southern Nuclear was taking the same approach. But
since then, we have clarified that they are going to
be doing the assessment similar to Oconee.
MEMBER SIEBER: You are talking about
skid-mounted equipment?
MR. BURTON: Yes.
MEMBER SIEBER: That means you treat
individually each component or sub-component on the
skid?
MR. BURTON: Yes. The complex assembly
issue, as it arose at Oconee, had to do with the
diesel generators, which are active components. But
in addition to the diesel, you had skid-mounted
auxiliaries. Should they be considered part of the
active assembly and therefore not subject to an AMR or
not?
MEMBER SIEBER: Right. That was resolved,
that they are now treated separately. For example,
transformers and like components, piping?
MR. BURTON: That's right. We found from
Oconee that it was really not appropriate to lump the
skid-mounted auxiliaries and treat them as if they
were all active, to actually do an assessment
separately.
Again, initially it was not clear to the
staff whether Southern Nuclear at Hatch was taking the
same approach, but we have since clarified that they
will be taking that approach.
MEMBER SIEBER: One thing that I found in
a number of plants is that often licensees do not
identify with mark numbers valves, heat exchangers,
and other components in the skid package. For
example, the generator hydrogen seal oil system might
have 50 valves in it. It's mounted on a skid, on a
bed plate. It has one mark number.
Is that the condition at Hatch? Does
anybody know? Or do you have individual mark numbers
for all the components or sub-components on the skid?
MR. BAKER: Certainly for the two items
that are the subject of the open item, which are the
diesel generator and the hydrogen recombiner, we
specifically know all the sub-parts of those skid-
mounted assemblies.
MEMBER SIEBER: But other ones, you don't
know?
MR. BAKER: I'm not aware of anything that
would be in the license renewal envelope that would
meet that. What you say is probably true for parts of
the plant that are not in the scope of license --
MEMBER SIEBER: Seal oil, some chillers,
for example?
MR. BAKER: Yes.
MEMBER SIEBER: The chillers often are
skid-mounted thing. A lot of times, they are safety
related.
MR. BURTON: A couple of things that I did
want to point out. One had to do, we touched on it
earlier, had to do with inaccessible components,
buried and the like. One of the things that we
emphasized when we went down on the AMR inspection was
to understand exactly how these things are identified
and taken care of procedurally. In fact, as a result
of the inspection, what we have is -- well, they have
an excavation procedure. They have in the proposed
draft form, a mark-up of that procedure which actually
says when you are either burying up components or if
you are digging around a structure, they actually have
the hooks in the procedure to actually take you to the
appropriate aging management programs to do the
inspection.
Another thing that I wanted to talk about
scoping issue, in the past the Committee has had
questions about design basis events, and what is the
population of events that you are looking at to
determine what's in scope.
Because of the functional approach to the
scoping, as I mentioned before, the staff is not real
clear on exactly how they identified the design-basis
events. As it turned out, at the time that they
submitted the application, they had a draft version of
what they called the nuclear safety operational
analysis, which has since been incorporated into the
FSAR.
This analysis was a comprehensive look at
the design-basis events. Even though it was in draft
form and they didn't take specific credit for it in
the application, it was a part of their general review
in their scoping process.
Since then, the rule requires an annual
update to the application based on any changes to the
CLB. So we actually caught the NSOA as part of the
annual update. As a result of that, they actually
brought in -- the only thing that was brought into
scope that wasn't there previously was the rod block
monitor. So that was taken care of also.
VICE CHAIRMAN BONACA: But you didn't go
through every indication that all the components for
the scoping match the one in the design-basis, or did
you?
MR. BURTON: Well, okay. If I speak to
your question, maybe this will address it. One of the
things that is important to understand is exactly how
the staff approaches its review.
The application identifies things that the
applicant has identified as being in scope and subject
to an AMR. Obviously we look at that. But a large
part of our review is to look at the things that the
applicant decided was not in scope and was not subject
to an AMR to see if there's anything that was in that
population that actually met the scoping or the
screening criteria and to bring it in.
Was that getting at your question?
VICE CHAIRMAN BONACA: I think so, because
I know also that you took three systems.
MR. BURTON: Yes.
VICE CHAIRMAN BONACA: And for those, you
went through what I would call a painstaking
verification that everything which had to be in it
would be. So that audit I guess provides the level of
comfort.
MR. BURTON: That is correct.
We have had two inspections at Southern
Nuclear so far. The review process allows for three.
We have done two. I have spoken already about the AMR
inspection, which was the second inspection. The
first inspection, which we did back in September, was
the scoping inspection. Again, because of some of the
navigational issues that the reviewers were having and
again, the functional approach to the scoping, when we
went down to the scoping inspection, we actually took
several systems and actually walked through step by
step from beginning to end how you identified their
functions, how you bounced those against the scoping
criteria, how you evaluated the evaluation boundaries,
and how you did the screening. So we walked through
several systems step by step.
What we found was that talking with their
engineers, we were comfortable that they were doing
things properly, but we found procedurally it wasn't
real clear. It didn't take them through step by step
exactly what to do. They were doing it, but the
procedure didn't really match.
So one of Southern Nuclear's takeaway from
our scoping inspection was to update the procedure to
make it less goal-oriented, which is how it was
originally, and make it more prescriptive. In fact,
we went down later to confirm that they had made those
changes. In fact, they had.
MR. GRIMES: This is Chris Grimes. I
would like to clarify. There are two aspects to the
staff's evaluation basis for scoping. There's the
inspection that looks at how the scope verifies that
the scope of equipment matches our understanding, our
safety evaluation basis. But we separately conduct a
methodology audit. I think it was during the audit
that we identified the procedural weaknesses.
But the audit looks at the process and
verifies that there is a completeness aspect to the
process that the applicant uses so that we don't have
to rely simply on our sample of results in order to
develop a conclusion about the completeness of the
scope.
MEMBER WALLIS: I asked you about scope by
way of an example, take say spent fuel pumps, look at
spent fuel pull section of the Hatch application. You
find a lot of stuff about boring things like anchors
and bolts and structural steel and so on. What about
the function of the pool? The pool shouldn't leak.
What is there that assures it shouldn't leak? It has
a liner, I believe. It's not in scope. It's not in
scope presumably because something else takes care of
it. Is that what I conclude from this?
Only the boring things are in scope. The
things that really matter don't seem to be there.
Why?
MR. GRIMES: This is Chris Grimes. I
would first like to start off by observing that Dr.
Wallis is obviously not a civil engineer.
(Laughter.)
It wasn't boring to --
MEMBER WALLIS: I'm one of the most civil
members of the --
(Laughter.)
I think that is something that when you
first look at it, strikes one. That doesn't mean it's
not really a question of civil versus mechanical or
something. The things that are picked out to be in
scope are the things which one would sort of least
expect to fail, so something must be happening to take
care of all the other things.
What is that something?
MR. GRIMES: Mr. Baker should address the
Hatch specific. Then I'd like to address the generic
aspect.
MR. BAKER: I think what you are seeing
here is what Butch was referring to as one of those
navigational things. In reality, the spent fuel pool
liners are in scope.
MEMBER WALLIS: They are?
MR. BAKER: Yes, sir.
MEMBER WALLIS: They don't appear in the
spent fuel section as being in scope. You have to
find them somewhere else?
MR. BAKER: I'll open up the book and show
it to you during a break. But it is in scope, yes.
We consider that important as well.
MR. GRIMES: And from a generic point of
view, we learned a lesson on Calvert Cliffs and Oconee
on articulating what is in scope for spent fuel pools.
You may recall that Chris Gratton spent some time
trying to explain why the cooling function is not
considered a design-basis function for the purpose of
license renewal because the staff relies on the
capability for the pool to be able to maintain its
geometry, even with the loss of cooling. So the
cooling function was explored most extensively during
the first two applications. Then we have refined the
guidance to look for those things that are really
important to the boundary integrity of the pool and
the ability to maintain the coolable geometry.
So I think that when we learn some more
packaging techniques and some more plain language
lessons, I think that you will find that all of the
really interesting stuff is buried within those civil
structural kinds of details.
VICE CHAIRMAN BONACA: And also I would
like to add in addition to that's true that your
cooling system was not in scope, but your make-up --
you had a make-up capability which was a safety grade
and was in scope that would allow you to make up
inventory in case you were losing the cooling
capability.
So the basic functions are assured. That
was the whole --
MEMBER WALLIS: Maybe it's a problem with
the way the thing is organized. The function of
cooling is somewhere in the report. I look up fuel
pools in the part that was assigned to me to look at,
it's all about acapults. But somewhere else, someone
else is reviewing the cooling, which makes it
difficult to get the perspective on how you handle the
fuel pool.
MR. BURTON: Now you see some of the
challenges the staff had. This all falls under the
category that I spoke about before regarding
navigational problems. So yes, if there is anything
specific, we can probably get you to the right place.
As I mentioned, there were four items that
are currently on the table as subject to appeal. We
had the subcommittee meeting on March 28th. We had
the appeal meeting the next day on the 29th. So one
of the takeaways from the subcommittee meeting was to
report back and see exactly where we stood as a result
of that meeting.
So what I have done is I have taken the
four issues and tried to put them in a simple question
format. The first one was should the draw-down test
that's required by the technical specifications be
credited as an aging management program to confirm
maintenance of reactor building in leakage limits.
One of the things that the staff was
concerned about during the period of extended
operation, how will Southern Nuclear continue to
maintain their controlled in-leakage for the reactor
building. What was on the table was that all of the
inputs to controlled in-leakage are going to be
managed through inspections and corrective actions,
the penetrations, all of the structural elements.
Our question was well, that is somewhat of
an indirect measure of whether it's actually going to
do that. I guess one example of that, and I am going
to go back to my ABWR days, is that one of the items
that they looked at concerning turbine building
flooding was they monitored pressures for service
water, surf water, things like that, and that a drop
in pressure would be indicative of a large leak and
subsequently flooding in the turbine building.
One of the questions that came up is
suppose you had leakage that wasn't quite enough to
reduce the pressure to the point where you got the low
pressure actuation. You get all this flooding in
there, but there's nothing instrumentally to tell you
that.
So we said okay, well what's the direct
measure of flooding, level. Okay. That was one of
the things that we came up with.
Similarly here, you can look at all of the
inputs to in-leakage for the reactor building, but it
is somewhat indirect. The way you can tell most
directly is to measure the draw-down, for which we do
have a tech spec.
Southern Nuclear was saying that is a very
gross test. In order for you to see anything as part
of that drawdown test, you would have to have
substantial degradation in the penetrations and things
like that, which we would catch by our existing aging
management programs far before they would degrade to
that degree.
So as a result of our discussions, we felt
like probably the best thing is to have a combination
of the two. To have the inspections and the ongoing
corrective actions when you saw a problem, along with
the drawdown is a confirmatory sort of test.
So that is where we are with this right
now. Still dialogue going on, but --
VICE CHAIRMAN BONACA: Confirmatory still
would put it into the aging management program as part
of it?
MR. BURTON: Yes.
VICE CHAIRMAN BONACA: Okay.
MR. BURTON: Number two --
MR. GRIMES: Actually, Butch, in the
interest of time, make sure that we get through the
whole presentation and try and stay on schedule. I
think it would be fair to categorize all four of these
things as ongoing dialogue, haven't made any
decisions. We need to make sure that we clearly
understand what the true value of the drawdown test
is. We need to clearly understand the current
licensing basis treatment and categorization and
bookkeeping associated with category II piping with
respect to the seismic II/I issue.
VICE CHAIRMAN BONACA: We would like to
hear something about that issue however, because you
know, a face value seems as if those components should
be in scope. But I understand that there are issues
to do that maybe too much of the piping was placed,
was evaluated as a II/I and shouldn't be. So there
are other things we don't understand.
MR. GRIMES: And that is the point that I
want to make. At this point, on all four of these
issues, I know I do not have enough information to
make a decision. I think the applicant and the staff
both went away with an understanding that we need to
talk some more because we do not know the whole story.
On the seismic II/I, it was clear from the nature of
over an hour's dialogue that we still do not have a
very clear understanding of how the applicant treated
the design capability for postulated breaks in
category II piping. We need to understand that before
we can move forward on that issue.
VICE CHAIRMAN BONACA: Wouldn't that be a
significant expectation of the guidelines you have
established if you had to say that now there are
seismic II/I components that do not fall into -- I
mean there is a --
MR. GRIMES: Yes. I would say there's
fundamentally a violation of the current licensing
basis if we don't capture the capabilities. We have
a semantic problem because the piping is not in scope.
The criterion in the license renewal rule says the
failure of components whose -- the postulated failures
of components whose failure could affect safety-
related piping or safety related functions.
If you have included the pipe whipper
strength in scope, do you now have to postulate that
the piping fails in a different way? Do you have to
inspect the piping to make sure that the pipe whipper
strength prevents the failure that it's going to
impact the safety function?
The pipe wasn't in scope. The restraint
was in scope. So this gets back to the problem that
we have communicating with this commodities approach
because you looked for a system. Your paradigm was
built on the way that we normally do system reviews.
But their communication package is different. It
looks at functions. This gets back to Dr.
Apostolakis' point earlier. That is, we have backed
into a new way of categorizing that is more in line
with the way that PRA analysts look at things.
But in terms of our ability to clearly
articulate how aging will be managed so that the
current licensing basis will be maintained for the
period of extended operation, what I observed on the
29th was two groups of people talking past each other,
because they were talking from a different paradigm of
how they packaged their scope.
VICE CHAIRMAN BONACA: What about the
housing? The housing, will it be covered by your
complex assembly definition, which has been in this
position previously.
I mean all I'm trying to say is that I
think that maybe there are ways to, for example, for
the seismic over one, one could conclude that elements
have to be in scope, and then accept a modified or a
known existing accident management -- I mean aging
management commitment because of special
circumstances. Are you exploring the possibility? I
mean that would be one way to maintain the commitment
to II/I, but the recognizing as you always do that in
some cases, you don't need the specific problem.
MR. GRIMES: That's why I jumped in and
tried to cut short the debate over the issues because
I know that on all four of these things we only have
half a story, and that we clearly need to have more
dialogue with the applicant in order to achieve a
shared understanding about whether or not we disagree
about anything.
On the housings, I believe that we made
our point more clearly to the applicant in terms of
what our expectation is. We discovered that housings
to some are not housings to all, and that they now
better understand that we are not violating the
Commission's tenets of going into piece parts. We
need to develop some guidance beyond what we are going
to tell you at the next presentation about improved
renewal guidance.
We need to develop some improved guidance
on making this distinction between complex assemblies
that are on skids and separating out active and
passive functions of components, which is a piece
parts issue. They sometimes get described using the
same terminology.
VICE CHAIRMAN BONACA: I asked for this
presentation if you remember last week, because I
thought that you expressed an interest in having our
position on these four items. Are you still
interested in having our position on the fourth or
not?
MR. GRIMES: After the meeting that we had
on Thursday, I think that I would say not, because I
think that we owe you an explanation about what it was
that we decided that we wanted to argue about. We may
be in a position soon when we come back to the
subcommittee with the explanation of the resolutions,
we may want you to express a view about whether or not
the pipe-break criteria are time-limited or not,
because of the explanation that the applicant gave us
about how they were used as a screening tool for
design, and that they do not actually -- they are not
limited in some way.
But even on that issue, I think that we
need some more dialogue in order to understand what
the regulation envisioned as a time-limited aging
analysis. So at this point, I don't think that you
have enough information to give us an informed opinion
on these issues, because I know I don't.
VICE CHAIRMAN BONACA: Okay. Thank you.
MR. BURTON: That's all I have.
MEMBER WALLIS: I have a question for you
now. I thought you were going to talk about the SER.
So I want to ask you a big picture question. This
slide with the four appeal items sort of supports what
I want to say.
I read the SER. A lot of it is simply
repeating what's in the application. Then there's the
staff evaluation. The staff evaluation seems to
consist of saying something is within scope. The
applicant has identified this component subject to an
AMR. There's some AMP here and this other thing is a
TLAA, which is what your appeal issues are all about.
Okay. There's a procedural thing, it
seems to me. You are now saying we are going to
consider this, this, this, and this.
The big question is is the AMR good
enough? Are the components that are subject to review
really going to last another 20 years? All these
questions don't seem to be addressed because there's
all this stuff about procedure. Is this in scope or
out of scope? Is it a TLAA? Is this AMR? You know,
that's okay, that's fine. But that seems to me is the
preliminary to now evaluating the quality of all these
things for the purpose of license renewal.
MR. BURTON: Do you want to --
MR. GRIMES: I'll take it. It's in my job
description. The staff did exactly what we asked of
them in terms of prepare a safety evaluation that
addresses the requirements of the rule, because the
Commissions said that the rule is the predicate upon
which they develop a basis for granting a renewed
license.
I would say that we looked very carefully
during the concurrence review to make sure that for
scoping, it specifically says there is reasonable
assurance that everything that needs to be in scope is
in scope and it's based on an explanation about what
was looked at.
There are statements in the safety
evaluation that precede the we have reasonable
assurance that aging will be adequately managed for
the scope that talk about we conclude that the program
is effective or that there's experience that
demonstrates that it works or things like that.
Actually as I was reflecting on the
challenge that you offered before concerning could we
put the reasonable assurance finding in more plain
English. I was thinking to myself now where in the
NRC, where in the agency would I go to get a really
good explanation about what the reasonable assurance
finding means in plain language that I could use to
convince the public. It occurred to me that the best
qualified group would probably be some advisory
committee to the Commission.
(Laughter.)
As we proceed to try and develop a plain
language version of our traditional safety evaluation
findings that more clearly explains why the Commission
felt that managing aging for the stuff that's in the
CLB that is relied on to prevent or mitigate accidents
or protect against station blackout or all the rest of
the stuff that the Commission determined was
important, will continue to look for ways to express
that in language that the general public, the folks
that attended the workshop yesterday with Mr. Cameron
and the public participation interests, as we find
ways to try and articulate these things so that they
can better understand what we are really trying to
tell them, then we'll evolve those into improvements
in the style guide for our safety evaluations.
But at this point, the language construct
was based primarily to have everything in the
regulation covered. We'll try to look for ways to
improve on the clarity of that finding.
MR. BURTON: And I guess I just wanted to
add to that, because I'm not exactly sure what parts
of the application we're looking at. But certainly in
section 2, the scoping and screening, the primary
thing was to ensure that all the right things are
being captured.
Section 3 is more the assessment of the
adequacy of the aging management and things like that.
I don't know if you as part of your review included
section 3. If it did and if there's some question
again --
MEMBER WALLIS: Yes, I did, and section 4
too.
MR. BURTON: In section 4, the TLAAs.
MEMBER WALLIS: So maybe what I'm asking
questions, might have some influence on how you finish
up writing the SERs so that it is clearer. That you
haven't just gone through sort of putting things in
boxes. You have actually done some really digging in,
convince yourself that things are in good shape.
MR. BURTON: Sure.
MEMBER LEITCH: I have two quick
questions. I guess they are really for Mr. Baker. A
number of BWRs are in the pipeline going to be asking
for power uprates. Is that in the Hatch plans?
MR. BAKER: Hatch has done the extended
power uprate on both units.
MEMBER LEITCH: Is that five percent order
of magnitude or was it one of those larger ones?
MR. BAKER: Go ahead, Chuck, if you have
the numbers.
MR. PEARCE: Charles Pearce, Southern
Nuclear. The first uprate we did was five percent,
105%. The second uprate was greater than five
percent. I'm not sure about this number, but I think
it was eight percent. So we did 105% uprate and then
we did another, about eight percent uprate.
MEMBER LEITCH: So you see, Hatch is being
at its ultimate capacity now?
MR. PEARCE: Well, I can't speak to
whether there's going to be a further uprate plan or
not. I think we don't have any plans in the immediate
future, let's put it that way.
MR. BAKER: The original license was 2436
megawatts. We're currently talking 2736 megawatts.
So that is the extent of the uprate.
MEMBER LEITCH: And the other question was
do we know what the core damage frequency is for the
Hatch units?
MR. BAKER: We have that. Chuck, if you
can find it before I can. I have it in my notes.
MR. PEARCE: The core damage frequency,
the total is 1.22 e to the minus fifth.
CHAIRMAN APOSTOLAKIS: When you say total,
what do you mean?
MR. PEARCE: That includes the frequency
from all the events.
CHAIRMAN APOSTOLAKIS: External as well?
External events?
MR. PEARCE: The external events, you are
talking about the earthquake, fire? That, I do not
know. I'm not a PRA expert. I just have the total.
I don't believe it includes external events, but I can
check into that in the break.
MEMBER LEITCH: And that's the same for
both units?
MR. PEARCE: Yes. It's in that ballpark
for both units.
MEMBER LEITCH: Thank you.
VICE CHAIRMAN BONACA: Okay. Any other
questions?
MEMBER WALLIS: Those where there's no,
what will it be in 20 years? Do you make any
predictions like that? There must be some effect of
aging.
CHAIRMAN APOSTOLAKIS: This is not in the
PRA.
MR. GRIMES: This is Chris Grimes. But we
have been periodically checking with the Office of
Research. I understand that they do have some model,
aging models for PRAs that they are continuing to try
and develop, but they are not ready to try and roll
them out yet. But we have continued -- we will
continue to monitor the research programs because we
are looking forward to an opportunity at some point in
the future where we might be able to see a risk model
for age, for a plant age.
VICE CHAIRMAN BONACA: All right. Are
there any more questions for Mr. Burton or for any of
the presenters? There are none, so Mr. Chairman, I
pass it onto you.
CHAIRMAN APOSTOLAKIS: Thank you. We will
recess until 10:55, with a narrow factor of three.
(Whereupon, the foregoing matter went off
the record at 10:40 a.m. and went back on
the record at 10:58 a.m.)
CHAIRMAN APOSTOLAKIS: The next issue is
proposed final licensing guidance documents. Dr.
Bonaca is still the leader.
VICE CHAIRMAN BONACA: Thank you, Mr.
Chairman.
In November of last year, we wrote a
report with comments on the license renewal guidance
documents. At that time, we had reviewed in draft
form. Since that time, also the industry and the
public has had an opportunity to provide a lot of
comments to the NRC. The staff has now updated those
documents, essentially the SRP, the reg guide, and the
GALL report, to address those comments.
They have written them now in a final new
reg form. I mean they have assigned new reg members
and reg guide number to it. They have presented it to
the subcommittee last March 27th. We are here to
review them and to provide recommendation if possible
on whether they should be finalized and other issues.
With that, I will begin to introduce Mr.
Grimes.
MR. GRIMES: Thank you, Dr. Bonaca.
Yes, by way of introduction, we drew from
the subcommittee meeting a desire to make clear to the
full committee that we believe that the substantial
amount of effort has gone into improving the guidance
for the conduct of license renewal reviews and
understanding of the attributes of effective aging
management programs.
The staff is going to describe highlights
of those features for you. But I want to emphasize
that we continue to rely on the foundation of the
renewal rule, which relies on the regulatory process
to provide for the unforeseen. We are certainly going
to have new experiences in the future, and may reveal
new aging effects or may, like the core shroud
cracking that you just discussed, a decade from now,
something else is going to occur. We have a process
to impose new generic requirements when we learn new
lessons in the future.
The whole theme of this activity to
develop generic aging lessons learned has been a focus
on process, on providing the tools to the plant owners
so that they will continue to find and learn and
correct as they go, because these programs aren't
going to start until more than a decade from now.
Then they go 20 years beyond that point. So we are
looking way out into the future in terms of the
expected behavior changes that result from these
regulatory requirements.
You also asked us to present a judgement
on the potential erosion of the safety margin. This
gets back to the conversation that I struggled with
Dr. Wallis' challenge to try and articulate a safety
conclusion.
Recognizing that there's constant growth
of knowledge, this process approach fundamentally
relies on an ability to continue to maintain an
adequate margin of safety. That doesn't necessarily
mean that the margin is larger or smaller or better
known or less well-defined. It really gets to the
individual inspection and maintenance activities that
learn and grow and adjust according to what is
understood about the impacts on margins.
In some cases, we learned things that
cause us to take margin away because we think we're
smart enough to know how to reduce the margins. In
other cases, we recognized that the uncertainties are
growing, and so we provide additional conservatism in
the way that we manage the plant design. So we
increase the margins of safety where we learn that we
do not know enough.
Trying to find a simple way to articulate
that in plain language will continue to be a
challenge. So there are still issues that we will
pursue for future improvements in this guidance. But
we believe that, and I mentioned before, more than a
decade of nuclear plant aging research that's actually
going on the 20th anniversary of the NPAR program,
about a decade's worth of experience in trying to do
license renewal reviews, we think that the guidance is
now sufficiently mature that the Commission should
approve it for implementation on all future renewal
reviews with the recognition that we will continue to
add to it as we learn new lessons in the future.
Our hope and expectation is that after we
have made this presentation, that the ACRS will agree
that it is more than adequate for this purpose, and
should endorse it with the Commission.
VICE CHAIRMAN BONACA: One last note I
would like to make. Before the meeting, this
presentation is over, I would like also to hear about
the commitment that was made in the response to our
previous letter that the GALL report to be updated
with some frequency I understand? At the time, there
was a commitment made but no procedures or specific
processes established yet. Maybe you could comment on
that at the end of the meeting?
MR. GRIMES: I'll do that.
VICE CHAIRMAN BONACA: Thank you.
MR. GRIMES: I'm sorry, and I was supposed
to say and now I'd like Dr. Sam Lee to introduce the
staff's presentation.
MR. LEE: Good morning. My name is Sam
Lee. I'm from the License Renewal and Standardization
Branch, NRR. This is this morning's agenda. After my
introduction, Jerry Dozier is going to talk about some
examples of the public comments received. Ed Kleeh is
going to talk about certain NEI continued items. Dave
Solorio is going to discuss the one-time inspections.
The improved license renewal documents
consist of the generic aging lessons learned, GALL
report. With that document is an evaluation of aging
management programs -- references to GALL report to
focus to staff review in areas where the programs are
evaluated, and a regulatory guide that endorses NEI
document 95-10 that provides guidance to licensing
applicant in preparing their application.
This has been a significant agency effort
involving staff from the Office of NRR, including the
staff that are doing the license renewal application
review. Also, the Office of Research. On my left,
Jit Vora is a team leader from Research. Contractors
from Argonne National Lab. On my right, Young Liu is
the project manager from Argonne. Also from National
Lab, on my left Rich Morante. He is the project
manager from Brookhaven.
We are preparing a SECY paper to the
Commission submitting this document for the approval
by the end of the month. During our interaction with
NEI to discuss the public comments on the documents,
they identified five items for further discussion with
the staff after the issuance of these documents.
After we discuss these items with you later today,
we'll continue a dialogue with NEI on these items.
The result of any additional guidance of clarification
will be incorporated in a future update of the
documents.
In addition, when new technical
information and new operating experience becomes
available, and also when the staff reviews additional
applications, and what we learn, we will incorporate
into future updates of these documents.
NEI indicated to us that the applicants
that will be submitting the applications next year
will be using these documents.
So to address how these documents ought to
be applied, NEI is conducting a demonstration project
in which they are preparing sample portions of an
application and submitting them for staff review and
comment. They are scheduled to submit this by the end
of the month. We'll be working with industry through
this demonstration project over the details for the
implementation for procedures.
That concludes the opening remarks. If
there's any questions? Okay. Jerry Dozier will go
into the public comments.
MR. DOZIER: Good morning. My name is
Jerry Dozier. I'm from the License Renewal and
Standardization Branch. With me, I have Mike McNeil
from the Division of Research, Barry Elliot from the
Division of Engineering, and Omesh Chopra from Argonne
National Laboratories.
There were over 1,000 comments that were
on the improved regulatory guidance. This slide just
represents some of the ways in which we evaluated the
comments and tried to incorporate them into the GALL
report, primarily chapter 4.
For example, in the first bullet, there
was a lot of discussion and a lot of debate and a lot
of comments on where is the threshold for radiation-
assisted stress corrosion cracking, void swelling,
where is this threshold? Is it 10 to the 17th, 10 to
the 21st, somewhere in between?
What we did though is really what the
staff wanted, is to have an effective aging management
program. What we wanted to do was to find the
components that had the most susceptible locations.
We wanted to monitor and inspect with an effective
inspection technique those locations. That was really
the aging management program we wanted.
So by getting rid of the threshold, we got
rid of a lot of the comments and a lot of the debate,
and uncertainties. We came out with an effective
aging management program, which is what we really
wanted in the first place.
On the second bullet, any unmade comments
that in the GALL report, in earlier versions, if we
could credit a program, we would credit. For example,
in boric acid corrosion, you could use the regular
boric acid corrosion program and you could also credit
ISI. Any IS that we provide only a minimal
acceptable, the boric acid corrosion program has been
effective in the current term, and we expect it to be
very effective in the extended term, so we
accommodated that comment by only referencing the
minimum program.
VICE CHAIRMAN BONACA: But I thought the
GALL was also a means of providing alternatives to
minimum programs.
MR. DOZIER: What the GALL report
primarily gives you is one acceptable program. It may
not in all cases be the minimal program, but it is an
acceptable program that primarily we have in the past
through Oconee and Calvert Cliffs, if we could say it
on a generic basis that this was an acceptable
program, that is what you really see in the GALL
report.
We don't want to limit the creativity of
the licensee. If they have a more effective
methodology, of course in the application they can
propose that on a plant-specific basis for us to
review. The limitation being that they couldn't
reference back to the GALL report in that case.
MEMBER WALLIS: What does "fully credited"
mean? I don't understand that.
MR. DOZIER: As I was talking about
earlier, for example, we would have the component,
some carbon steel component here. Then we'd have the
aging effect would be boric acid corrosion. Then we
would credit two programs. We would say ISI was
effective in finding it, and also would say boric acid
corrosion. We would put two. In this case, we only
have one.
MEMBER WALLIS: Credited means that the
programs take care of your concerns with the issue?
Is that what you mean?
MR. DOZIER: Yes.
MEMBER WALLIS: It resolves the issue
then?
MR. DOZIER: It resolves the issue, yes.
It would be fully acceptable. By fully credited, I
guess I should have made to this have said fully
acceptable to the staff.
MR. GRIMES: Actually, you can drop the
fully and it still means the same thing.
MR. DOZIER: In the next bullet, the
earlier versions, for example, the pressurized bottom
head, we had those as plant-specific evaluations. In
that case, the applicant could propose a program.
Well, during our revisions and incorporation of the
comments, we started really focusing on trying to give
as much information to the applicant as we could. In
other words, now for the bottom head we credit the
chemistry program and ISI and tell the applicant that
we're only concerned with the Iconel 182 welds. So it
gives the applicant more direction on really what the
staff's interest is.
In the GALL report, of course you'll have
a component. You'll have many aging effects.
Sometimes in our public comments from the earlier
version, there may be one of the aging effects that
there was some controversy on whether or not that was
really a significant aging effect or not, or really
applicable.
In some cases we would remove based on the
comment and further evaluation, we would remove some
of the aging effects. Does that mean the component
went away? No. That meant just the aging effect.
In the last bullet, of course GALL is a
useful tool for the applicant to reference during the
license renewal application. We based ours on the
Oconee and Calvert Cliffs, and may not have gotten the
full range of components that they could possibly be
done on a generic basis.
So NEI provided us with some additional
components that they would like to have in the GALL
report and the programs. We evaluated those and
accommodated those types of requests.
Also, in the case of there was comments
from, for example, Union of Concerned Scientists.
They had a few components to add. We also
accommodated those requests.
So there were many comments, and these are
just some of the ways that we evaluated and
accommodated the comments. Is there any questions?
If not, I'd like to turn it over to David.
MEMBER WALLIS: So there were no serious
comments that really changed your mind about anything,
were issues that couldn't be handled this way? I get
the feeling everything worked out fine with the public
comments?
MR. DOZIER: I may have made it sound a
little easier than it was because there was -- we had
several comments we went through. We even had to go
through the escalation process up to the branch chief.
So everything wasn't easy. But we tried to address
the best we could.
Barry has something to address on that.
MR. ELLIOT: We have open issues. Don't
think we don't have open issues. We have open issues.
We are still going, you know, trying to resolve those
open issues. This is just the issues that we were
able to resolve here, but there are still open issues
between the NRC and industry.
VICE CHAIRMAN BONACA: I hope the GALL
report doesn't become a minimum requirement document.
I mean it wasn't intended to be that way.
MR. ELLIOT: We don't look at it as a
minimum requirement document either.
VICE CHAIRMAN BONACA: I'm only saying
that there were some comments that said encouragement
for the staff to put in only the minimum that's
accepted for some programs.
MR. ELLIOT: I can clarify, the in-service
inspection discussion a little bit. The reason we put
the boric acid corrosion in is because we weren't
satisfied with the in-service inspection program
section 11 for corrosion, so we put in this program.
That's why we're taking credit for it, because we told
them that this is what we wanted.
VICE CHAIRMAN BONACA: I understand. My
comment only is because I view over time these would
be probably the main document reference both by the
applicants and the staff. So we have seen the first
applications involving a significant effort of the
applicants to be creating. I mean first BG&E had to
do a lot by itself. Here this is becoming more and
more important because it is going to be the baseline
for the applications.
MR. GRIMES: Dr. Bonaca, I am compelled to
say that by virtue of the Commission performance goals
on effectiveness efficiency and knowing that necessary
burden and so forth, we often describe the regulatory
requirements as the minimum requirement. That's just
by virtue of the regulator is expected to only require
what is necessary and sufficient for plant safety.
So it is appropriate to say these are the
minimum requirements. We would hope that applicants
would establish inspection and maintenance programs
that go well beyond in terms of the scope and the
practices. But that is not to say that we don't feel
very strongly that we have put a lot of attention into
the detail about making sure that we have what we need
to make sure that these are effective aging management
programs. So to that extent, it is an important
baseline.
I think it's also important to point out
that we have tried to avoid making this a catalog of
options because that reduces the opportunity to
standardize and achieve efficiencies by having one way
to do it that everyone sort of gravitates to. So we
did consciously try to avoid going well into what are
all of the different ways that you can manage the
aging effects, because that would then work against
the efficiency aspect of the guidance.
We certainly expected that we are going to
have some departures from this, but we'll try to
discourage that.
VICE CHAIRMAN BONACA: I understand. For
example, on the issue of scoping, that you don't have
in the presentation here, we discussed that before,
NEI pointed out that all you need is to have a
methodology and then the results of the whole process,
including screening. When you do that, you really
have a problem also with navigating through the
application.
Now I expressed a concern we had last
time. I believe that the ACRS probably will encourage
more documentation to make it possible for an
interested individual or the public to find out what
components are in or out. It's not too much to ask.
Now I recognize in the SRP you had to
recognize that that was the requirement of the rule,
so you had to admit it. But you can see how that, in
my judgement, is a minimum requirement for
documentation. By meeting the minimum requirement,
you meet the rule but maybe you don't fulfill the
needs of the public and of the staff and the ACRS
Subcommittee when they try to review these documents.
MR. GRIMES: Point well taken.
VICE CHAIRMAN BONACA: Okay. We can move
on.
MR. DOZIER: Okay. I would like to turn
it over to David Solorio -- Ed Kleeh, I'm sorry.
MR. KLEEH: Good morning. My name is
Edward Kleeh. I am representing the License Renewal
Branch. With me from the Office of NRR, the Division
of Engineering are Mr. Barry Elliot, Mr. James Davis
is coming up, Mr. Frank Grubelich, and from the Office
of Research is Mr. Mike McNeil.
I will present the five NEI continued
dialogue items by stating both the NEI and NRC
position.
Item one is individual plant examination,
IPE, or individual plant examination for external
events, IPEEE, has a source document to consider for
scoping. NEI considers it inappropriate for an
applicant to establish a licensing renewal scoping and
screening criteria that relies on plant-specific
probabilistic analysis like IPE's and IPEEE's since
they are not part of the current licensing basis. Not
only reflect the estimated core damage frequency for
the plant configuration at that time.
NEI contends that IPE's and IPEEE's may
contain recommendations to modify the plant, revise
procedures, or develop training to further reduce the
estimated core damage frequency, but only implemented
after 10 CFR 50.59 or 10 CFR 50.90 reviews.
The standard review plan for license
renewal, page 2.1-3, states that although the license
renewal rule is deterministic, that probabilistic
methods on a plant-specific basis may help access the
relative importance of structures and components
subject to an aging management review by drawing
attention to specific vulnerabilities.
Reviewing an IPE or IPEEE can help a
reviewer determine what equipment is risk significant
and relied on for mitigation of design-basis events.
It provides additional understanding to permit safety
determinations.
VICE CHAIRMAN BONACA: Is this the NEI
position still?
MR. KLEEH: No.
VICE CHAIRMAN BONACA: At which point did
it become yours?
MR. KLEEH: When I got to the part about
with the standard review plan, that was the NRC
position.
MEMBER WALLIS: So the NEI position is
that some information should be ignored?
MR. KLEEH: Yes.
MR. GRIMES: This is Chris Grimes. Let me
explain. This set of issues are issues for which we
have two positions that appear to conflict, but we're
not sure. So instead of appealing the issues, the NEI
working group simply asked of the steering committee
that the staff be available to continue the dialogue
so that we can understand whether or not we have any
disagreement. I think that it is fair to say that on
the IPE issue, the industry's concern is more one of
proximity, having the IPE described in a staff review
that is supposed to be certifying the current
licensing basis relative to the scope of equipment in
an aging management review.
Their concern is that this device might be
used in some way to subvert the current licensing
basis.
CHAIRMAN APOSTOLAKIS: But I'm a bit
confused though. The current rule is deterministic.
It really looks at passive components. The IPEs have
declared the passive components as being so reliable
that they will not put them in the accident sequences.
So how is it relevant? If I look at the
dominant sequences that an IPE gives me, that will
have valves not closing or opening and pumps and so
on. How does that help me? I mean the deterministic
rule says that I should be looking at the passive
components. The others are already under the
maintenance rule and so on, so it really doesn't help
you very much. So I don't even know why it's a
dialogue item.
MR. KLEEH: I have an inspection
background. When you use IPEs and IPEEEs, they tend
to give you a relative importance of what systems have
a safety significance. You can classify and
prioritize them. That's mainly what the NRC is trying
to do here. They are trying to use all the tools
available to be able to classify the safety
significance of systems that they are going to
consider to be scoped under the license renewal rule.
MR. GRIMES: The guidance instructs the
reviewer to use EOPs, the IPE, and other information
about the plant capabilities or lack of capabilities
in order to have them use devices that help them to
poke at the current licensing basis to determine the
completeness of the scope.
IPEs are useful primarily because for
those that still think in a systems paradigm they know
what are the important functions of the system from an
IPE that they then go in and look for that intended
function coming out of the scoping and screening.
So to the extent that it could be useful
for the staff reviewers but the industry concern about
there ought to be more guidance in how not to abuse
it.
CHAIRMAN APOSTOLAKIS: So it's the next
step we discussed this morning, beyond what Hatch did.
MR. GRIMES: Yes.
CHAIRMAN APOSTOLAKIS: But you still
wouldn't look at the active components. Right? You
would look at the systems, but then you would look
only at what's passive. So there is progress. I'm
telling you, in five years, there is going to be a
PRA.
MR. GRIMES: I hope Dr. Bonaca doesn't
expect that in our commitments for future
improvements.
CHAIRMAN APOSTOLAKIS: NEI is concerned
that this might subvert the process?
MR. GRIMES: By virtue of these being
continued dialogue items, I think we need to offer NEI
an opportunity to more clearly articulate what their
real concern is. That's why instead of taking these
issues to appeal at the conclusion of the last
steering committee meeting, the working group simply
said we would like the staff to continue to talk with
us. So we need to better understand what it is they
want us to do differently.
CHAIRMAN APOSTOLAKIS: Now if the IPE,
IPEEEs are used only to add things to scope, then I
can see their concern. But if you use a risk-informed
approach to define SSCs that are within scope, then it
is a different story. They shouldn't really object to
that. So I guess they are afraid that the first thing
is going to happen, like the first 25 years of PRA,
just add to the regulations but never take anything
out.
MR. KLEEH: Item two.
MEMBER SHACK: I'm glad you made that
point, George. It's one we haven't heard before.
MEMBER WALLIS: The thing that intrigued
me was the first 25 years. When did the first 25
years start, George?
CHAIRMAN APOSTOLAKIS: I'm sorry?
MEMBER WALLIS: When did the first 25
years start?
CHAIRMAN APOSTOLAKIS: They are not
biblical years.
Please go ahead.
MR. KLEEH: Item two. Operating
experience with cracking of small board piping. NEI's
position is that inserts inspections ISI and chemistry
control are adequate as aging management programs.
Operating experience does not justify doing more.
Now we get to the NRC position. GALL
recommends a volumetric one-time inspection for
evidence of no cracking to verify the effectiveness of
chemistry control. The one-time inspection augments
the aging management program consisting of primary
water chemistry and in-service inspections for class
I components.
The ASME Code, Chapter 11, requires
service examinations of class I, small bore piping
with less than a four-inch nominal diameter every ten
years.
Are there any questions on that item?
MEMBER LEITCH: Does this issue only
relate to class I small-bore piping?
MR. KLEEH: Yes.
MEMBER LEITCH: Thank you.
MEMBER SIEBER: And it doesn't relate to
fatigue-induced cracking?
MR. KLEEH: It relates to all kinds of
cracking.
MEMBER SIEBER: Not just chemistry?
MR. KLEEH: The cracking is the issue, not
the chemistry.
Item three is management of loss of free-
load of reactor vessel internals bolting using the
lose parts monitoring system.
NEI believes that ISI visual examinations
are adequate for management of loss of pre-load on
reactor vessel internals bolting.
The NRC position is that GALL recommends
that loss of pre-load in reactor vessels internal
bolting be managed by ISI in the loose parts
monitoring system. The NRC staff accepted
Westinghouse Owners Group topical report WCAP 14-5-77
which recommends that the loose parts monitoring
system as one of the surveillance techniques used to
detect loss of pre-load and other aging effects on
certain reactor vessel internals components as part of
several aging management programs.
The ASME code, Section 11, category BN-3
requires visual inspections of core support structures
every ten years.
Are there any questions on this item?
MEMBER WALLIS: How do you tell if the
bolts are loose?
MR. KLEEH: How do you tell if the bolts
are loose?
MEMBER WALLIS: By a visual inspection.
Isn't that what you mean about loss of pre-load?
MR. KLEEH: That is what NEI is
suggesting.
MEMBER WALLIS: How does visual inspection
tell you if you've lost a pre-load?
MR. KLEEH: I don't think I am in a
position to support their argument.
MR. GRUBELICH: Frank Grubelich,
Mechanical Engineering Branch.
We have seen in the baffle bolt cracking
experience where industry has said that they have not
seen this cracking of the baffle bolts that was
experienced over in Europe. However, we haven't seen
it because what they were doing was a visual
inspection. The crack occurs between the juncture of
the bolt shank and the head.
Subsequently, the log took three lead
plants, Westinghouse lead plants, and they did UT
examinations. In fact, they found some cracking.
So our position really is to use loose
parts monitoring. There has been experience with
that, and that is a program that is an ASME standard.
It has been published.
MR. GRIMES: This is Chris Grimes. But
I'll point out that there is an opportunity for
regulatory coherence here because staff just approved
a GE topical that concluded loose parts monitoring was
not necessary.
MR. ELLIOT: Along that line, this is a
PWR issue. In the boiling water reactors, we credit
ISI and water chemistry for the bolting of the
internals. This is only a PWR issue.
MR. GRUBELICH: Part of the discussion
with the PWR is that the point that they were making
is that the flows in the BWRs are relatively low so
that they can't carry the loose parts, and that they
also have limited or restricted flow passages so that
the larger parts will not get into the core.
MEMBER WALLIS: I don't understand the
connection. Maybe I should be quiet. If you have a
loose bolt, it doesn't necessarily wander around. It
has to come out to wander around.
MR. GRUBELICH: You can have both cases.
It can be loose. It can stay in place.
MEMBER WALLIS: I'd think you would be
concerned about it being loose and staying in place.
MR. GRUBELICH: Right.
MEMBER WALLIS: You won't catch that by
seeing whether it was rattling around somewhere else.
MR. GRUBELICH: Correct. But you also
worry about the part that gets loose and gets into the
core area.
MR. MCNEIL: There's another difference
between the Ps and the Bs. That is, that at the
damage levels that are common in Bs, the radiation-
induced creep is less severe, so you would have less
loss of pre-load simply for the creep effect than you
would in a P. I'm trying to explain the discrepancy
between the position of the GE and the PWR system.
MEMBER SIEBER: But the baffle bolts are
on the outside of the core barrel, right, or the
baffle? So they either go to the bottom of the
reactor vessel or into the steam generator head.
MR. GRUBELICH: There are two different
baffle bolts. There's one on the inner surface, which
is actually adjacent to the peripheral surface of the
fuel -- then on the backside, there is what is called
a core barrel former bolt. So you have both cases.
MEMBER SIEBER: Okay.
MR. KLEEH: Item number four is operating
experience with cracking bolting. NEI's position is
that crack initiation/growth due to stress corrosion
cracking through carbon steel closure bolting is not
an aging mechanism.
Section 2 of the ASME code specifies the
ASA 193 grade B bolting at minimum yields 105 pounds
per square inch, and no maximum yield strength.
MR. MCNEIL: I think that figure of 105
pounds per square inch has to be wrong.
MEMBER WALLIS: 105 ksi. Must be
thousands.
MR. KLEEH: That's what I said.
MR. MCNEIL: I'm sorry. I thought you
said 105 pounds.
MR. KLEEH: If I did, it's supposed to be
105 thousands, and no maximum yield strength.
The minimum yield strength should be
sufficient for normal design loads. The maximum yield
strength preferred by the staff of 150 thousand pounds
per square inch or less ensures the bolt is not too
hard, meaning brittle, so as to be susceptible to
stress corrosion cracking, which is more likely with
moisture in the air and if the brittleness of the bolt
increases.
GALL recommends that cracking
issues/growth be managed by the EPRI bolting integrity
program.
Are there any questions on this item?
MEMBER POWERS: I guess you were just a
little too quick for me. The staff has come back and
said that they don't want a high strength steel is
because of the stress corrosion cracking limitations?
And NEI is saying they are perfectly willing to let
things stress corrosion cracks?
MR. KLEEH: I think what they are saying
is they don't believe that stress corrosion cracking
is going to occur. James Davis can elaborate on that.
MR. DAVIS: They just want to drop that
out of GALL. They wanted to drop that issue out of
GALL. We have a lot of evidence from the past
operating experience that if your yield strength gets
over 150 ksi, they will crack in air. As I said to
the subcommittee, I'm not yielding on this point.
MEMBER POWERS: I guess I wouldn't either.
MEMBER SHACK: No pun intended.
MEMBER POWERS: You're not the only one
that has the experience of cracking in the air on
high-strength bolts.
VICE CHAIRMAN BONACA: Good. Fire
protection.
MR. KLECH: The final item is inspection
of fire protection systems. BI's position is that the
National Fire Protection Association, NFPA, codes are
adequate for managing aging effects in fire water
systems. The NFPA codes do not provide guidance for
assessing internal corrosion of fire water systems
which are not routinely subject to flow.
The NRC's position is that GALL recommends
the single system monitoring, internal inspection and
flow testing of fire water systems to ensure the
corrosion including microbiologically effluence
corrosion mix.
Are there any questions on this one?
That concludes the presentation.
Mr. Dave Solorio will now take over.
MR. GRIMES: While Dave is moving up to
the podium, I want to clarify. These were the -- this
was the subset of industry comments on the improved
renewal guidance that ended up being quote unresolved.
They were originally characterized as potential appeal
items, but when it came time for the industry to
appeal the issues to higher management, they concluded
that they did not want to hold up GALL to try and
resolve these issues, rather they simply wanted the
staff to continue a dialogue because perhaps we
misunderstand their point or they misunderstand our
point.
Barry pointed out this distinction about
loose parts monitoring for PWRs and BWRs. On its
face, has to be explained in a clearer way and perhaps
they simply don't understand the staff's position.
But we will continue to have a dialogue
and we'll report on what we learn in the future. And
with that, David is going to address one-time
inspections.
MR. SOLORIO: Good morning. My name is
Dave Solorio. I work in the Office of Nuclear Reactor
Regulation in the License Renewal and Standardization
Branch.
I'm here today to speak on the subject of
one-time inspections for Calvert, Oconee, Arkansas,
Hatch and GALL.
With me here today is Omesh Chopra from
Argon National Laboratories. Omesh is a Senior Member
from the ONO team that assistant with the development
of GALL and was the lead reviewer for many of the more
difficult chapters in GALL.
I also have to my left here Robert Prato
and to my right, Butch Burton, also from the License
Renewal and Standardization Branch. Bob is the ANO
Project Manager and Butch is the Hatch Project
Manager.
I asked Bob and Butch to sit up here with
me today because they worked so hard in getting me
information to get ready for this. I thought that
they should share in the glory also.
(Laughter.)
Last week, I made a presentation to the
ACRS Subcommittee on license renewal regarding the
one-time inspections for Calvert and Oconee and GALL.
The subcommittee liked it and requested that we come
back for this full committee to expand it to also
cover Hatch and ANO.
I also have another slide after this,
Slide No. 9 that summarizes the one-time inspections
for Hatch and ANO. And also, I want to mention in
case you're wondering what all the acronyms -- I
haven't had a chance to turn to page 10. There's a
definition. They have all the acronyms. I will note
that I left off sodium hydroxide. I apologize for
that.
I guess I want to provide some orientation
here. First off, for those who might not have seen
this before, the left column here are the categories
of the systems as they'd be represented in GALL and
the Standard Review Plan. I felt that a fairly
efficient way to try to group things so that we could
try to draw some comparisons.
I also want to provide a disclaimer for
anyone attending this briefing for the first time who
are unfamiliar with the concept of one-time
inspections. We're not saying these systems are only
inspected one-time. In fact, in the majority of cases
there's an existing Aging Management Program already
looking at a lot of these systems.
I also wanted to mention that GALL has
consistently applied the lessons learned of Calvert
and Oconee regarding one-time inspections. In fact,
as you've heard earlier, many of these one-time
inspections from Calvert and Oconee were incorporated
into GALL, when appropriate, as a starting point. In
developing GALL, we had the experience of Argonne and
Brookhaven National Laboratories helping us get this
information into the GALL report and we also had staff
members associated with the first license renewal
reviews and the on-going reviews looking at the one-
time inspections that were incorporated.
GALL also had the benefit of two public
rounds of comments and an outcome of the public's
participation as GALL now specifies a plant-specific
Aging Management Program be proposed for Calvert and
Oconee, might have proposed the one-time inspection.
A plant specific Aging Management Program
could be a one-time inspection or it could be an on-
going program, an existing program.
At a glance, you can see there's a few
differences in the number of one-time inspections
between Gall and the four plants --
VICE CHAIRMAN BONACA: Before you chance
that, on the issue of the -- it would be valuable for
us to understand why you have one-time inspection of
pressurizer and one steam generator for Oconee, but
there is no inspection for Calvert. Now I know
Calvert has also steam generator inspections.
MR. SOLORIO: I will talk to that.
VICE CHAIRMAN BONACA: Also, why does the
GALL report -- if you could give us some indication.
I understand pretty much the same programs.
MR. SOLORIO: I will do that in a minute.
All I was going to do was put this up briefly to kind
of give everyone an orientation. There's some
differences there. I'm going to go back to this and
then I'm going to talk about what you wanted in a few
more minutes here.
Actually, what I intended to do was go
across for reactor vessel internals, all four plants,
and kind of give you an idea of what they're doing and
I will cover that.
VICE CHAIRMAN BONACA: Okay.
MR. SOLORIO: So there's some differences.
There's numerous reasons that explain those
differences. I'm going to go over a few of those
reasons and then I'm going to talk about -- get to
your question, sir.
One reason there are differences is that
GALL provides one method for managing the aging, that
the staff has determined is acceptable. Applicants
can and have proposed different Aging Management
Programs different than GALL such as the case of ANO's
risk-informed ISI inspection for small-bore piping or
aging management for every piping. The staff has
concluded that these are acceptable alternatives.
Another reason for differences is that
there are plant-specific differences or system
nomenclature differences. For example, Oconee has
several features which are a little too unique, that
we thought were a little too unique to be included in
GALL. That would be some of these systems down here.
They have a Cowamee Dam and it's our emergency power
supply. I know a lot of you have seen it. I have
heard some of you have been there. It was a little
too generic to be included in GALL, so you won't see
a similar one-time inspection in GALL.
Also, Oconee doesn't have Oconee with one
set of steam generators. Isn't going to have a steam
generator blow down system, therefore, you're not
going to see it. At Oconee, another example would be
is that their fire protection system isn't labeled
fire protection. It's actually two other systems.
Low-pressure service water and
high-pressure service water are used to provide fire
protection function there. And so you look at that
and you say where's fire protection for Oconee. Well,
it's there. I could have labeled it as fire
protection, but then I thought that perhaps someone
would have asked me what about those systems? So I
left it as it was.
Another reason was that in many cases
Calvert and to a lesser degree Oconee proposed
one-time inspections without being asked because of
either plant-specific operating experience or because
they wanted to ensure themselves of the effectiveness
of their existing programs, or because they didn't
suspect aging was occurring, but given the remote
potential, they determined it was conservative to look
up anyhow.
Another reason was that there were many
public comments, as you've heard earlier, received by
the staff on GALL and the staff might have concluded
that a one-time inspection was not necessary if an on-
going Aging Management Program was considered to be
adequately managed on aging.
I think last week we talked about changes
to the ECCS, one-time inspection for PWRs because it
was determined that if a licensee had a chemistry
program that matched a GALL chemistry program, the
conditions and the contaminant control and filtering
should be sufficient to preclude the need for a one-
time inspection.
Then I'm just going to get to two more
examples and then I'll get to the question that was
asked. In the case of Hatch, there's a really unique
reason. There could be some differences here. It's
because Hatch took a somewhat unique approach to how
they scoped by function, not by system. And as a
result several systems were grouped together in
unusual ways, for example, one of the in-scope
functions for the feedwater and main steam systems was
reactor coolant pressure boundary. This function is
identified under the nuclear boiler system such as
here. I'll just leave that up.
The nuclear boiler system is lifted on the
first row here. Therefore, main feedwater and main
steam are actually identified as part of the RCS
function instead of the steam and power conversion
function, so you won't see something down here for
main steam and feed water at Hatch.
In the case of ANO, another reason you can
-- you obviously see a number of differences there,
but some of the reasons for why there are differences
is that ANO is frequently doing periodic inspections,
rather than one time inspections. Also, ANO proposed
different types of Aging Management Programs such as
the risk-informed ISI inspections for small-bore
piping as I mentioned earlier.
VICE CHAIRMAN BONACA: So you are saying
that those activities are captured under programs
which already exist and are broader, so therefore you
don't have to have a one-time inspection for that
specific result. That really accounts for the big
difference in numbers of one-time inspections you show
there?
MR. SOLORIO: Yes sir.
VICE CHAIRMAN BONACA: "SH" stands for
what?
MR. SOLORIO: Pardon me?
VICE CHAIRMAN BONACA: "SH" under
Arkansas.
MR. SOLORIO: Sodium hydroxide.
VICE CHAIRMAN BONACA: Okay.
MR. SOLORIO: It's our containment. It's
also my understanding that that subject of one-time
inspections for ANO was previously brought up during
the subcommittee meeting, so you may already have
appreciation for some of the differences of ANO.
Now I'd like to go over a few examples to
explain the transparencies in a little more detail.
MEMBER POWERS: Let me ask one question.
If a licensee has a super water chemistry program, I
mean it's a humdinger, it really cleans the water up
well, does that preclude the need to do a one-time
inspection?
MR. SOLORIO: Well, if the reviewer was
going to use GALL, GALL would tell the reviewer that
if the chemistry program is equivalent to the GALL
chemistry program, there may not be a need unless
there's some specific plant operating experience which
might suggest otherwise.
MEMBER POWERS: The reason I worry about
that is I guess there's some evidence that maybe as we
clean water up we unleash new corrosion mechanisms
because the impurities that are causing are not being
tied by complexing or being captured by some of the
impurities in the water and so
clean-up, good chemistry does not necessarily mean you
don't have corrosion.
MR. SOLORIO: Yes, although in a situation
as that, perhaps there might be operating experience
at that plant that would suggest that their chemistry
program, even though it sounds like a whammo-bammo one
isn't perfect and there might be a good reason -- and
you would expect an applicant to describe that in the
application.
MEMBER POWERS: Yes.
VICE CHAIRMAN BONACA: I'd like to ask a
question about Arkansas. I mean the one-time
inspections are confirmatory in nature, typically. I
mean you are doing it once to verify that, in fact, an
aging effect is not taking place, okay, that's
confirmatory. A program is to address the possible
aging effect that you believe is going to happen, so
you have a programmatic inspection that you do.
So if I look at Arkansas, for example,
they believe, evidently that some aging may occur of
the components that other applications say they're not
going to happen and so they only have one-time
inspection and Arkansas has programs to inspect many
times. Have you thought about that?
Let's take an example of small-bore
piping. The other applicants are saying there's no
aging effect coming from it, therefore, we're going to
look at it once and then forget about it. Arkansas
says no, we're going to have it under a program.
We're inspecting under ISI. So they must believe
that that's necessary.
Can you comment on that? I mean --
MR. ELLIOT: Arkansas took a little bit of
a unique approach where when they first initiated
their Aging Management Review they identified the
components and the environments and then they
identified all of the maintenance activities that they
do on all the programs that are in place. A specific
program addresses specific aging effect as to whether
or not it's not likely to happen. They still took
credit for that program, where I think some of the
other applicants may not have done that. They may
have said that this is not a practical aging effect,
there's no need for us to commit to doing anything,
therefore, we'll do a one-time inspection to verify
that it is not happening.
VICE CHAIRMAN BONACA: So that you don't
want to place their commitment on the ISI for --
MR. ELLIOT: Yes. It shouldn't be taken
as a recognition that they need to do it. It's just
the fact that they feel that they had a program in
place. There's no harm for them to take credit for it
and instead of going through an exercise with the
staff on arguing whether or not it's likely to happen,
they decided that they would leave it in and commit to
it.
MR. GRIMES: Dr. Bonaca, I think it's also
important to recognize with risk-informed
in-service inspection there were benefits that were
provided by risk-informing the scope, concluded that
there were some things they had been inspecting and do
not now need to inspect. And so when you say that
Arkansas felt that they needed to do this, Arkansas
felt that they needed to have a
risk-informed in-service inspection program and so it
does have the advantage of picking up small-bore
piping, but at the same time it was compensated for it
by reducing inspections in other areas.
MR. SOLORIO: Going to page 8, first row
for reactor vessel internals, reactor coolant system.
For small-bore piping, Calvert and Oconee plan to
conduct a one-time inspection. GALL calls for a one-
time inspection. On page 9, you'll see that ANO isn't
there, but that's because they're doing a periodic
inspection, so they are still looking at small-bore
piping.
For Hatch, small-bore piping inspections
are the subject of an open item. There is still
continued dialogue on that one so I guess you can ask
Butch in a few more months how that ended up.
Moving on to reactor vessel internals.
Calvert has a one-time inspection for CEA shroud
bolts. Oconee does not have a one-time inspection for
similar functioning type of bolts at Oconee because of
a different material. There's not the same concern.
GALL calls out for a plant-specific evaluation for
reactor vessel internal bolts of this nature.
ANO has committed to a one-time inspection
of reactor vessel internals that includes bolts,
baffle bolts. Hatch covers aging management of
reactor vessel internals in accordance with BWRVIP
program. I understand that that's been reviewed and
if you want to ask more questions, that's part of the
reason I've put you up here, to help with that.
So generally, you can see how the subject of bolting
isi being covered there.
Moving on to steam generators, Calvert has
a comprehensive program that includes inspections of
steam generator tube supports at the U-bend area.
Oconee has a different design, but still has a one-
time inspection for some supports due to gamma
radiation concerns that they have. GALL recalls a
plant-specific evaluation. ANO supports -- ANO has
existing programs that cover and support inspections
and of course, Hatch doesn't have steam generators, so
it's not applicable.
Moving on to the pressurizer. Calvert and
Oconee have committed to conduct a one-time inspection
of susceptible cladding locations. GALL requires a
plant-specific evaluation. ANO has committed to
conduct periodic pressurizer examinations, polymetric
examinations. It's my understanding also that ANO and
Oconee are planning to perform one-time inspection of
their pressurizer heaters in conjunction with a BNW
Owners Group program or initiative. Of course, again,
Hatch doesn't have a pressurizer.
Those are the examples I was going to go
over just because of time, we're running late. Of
course, you can ask questions.
MEMBER WALLIS: There doesn't seem to be
much correlation between the entries from the various
plants on the GALL Report.
MR. SOLORIO: Well, I mean I really would
have to take --
MEMBER WALLIS: I don't think we could
possibly go into them all. There just doesn't seem to
be that much correlation. I wondered if there was
some general conclusion you can draw from those.
MR. SOLORIO: I was going to -- look at
aux systems. CC is component cooling. That's
actually covered by the CCCS in GALL.
Service water and salt water, Calvert.
Service water at Oconee. That is an open cycle.
MEMBER WALLIS: It's just given another
name in GALL?
MR. SOLORIO: Yes.
MEMBER WALLIS: Okay.
MR. SOLORIO: I'm sorry. Fire protection
here is equal to LPSW and HPSW there. It's equal to
fire protection here.
MEMBER WALLIS: So it's just a translation
problem.
MR. SOLORIO: That was a big problem
trying to correlate things between the units,
especially with Oconee for me, anyway.
MEMBER WALLIS: It looks like a real
conspiracy against the laity.
(Laughter.)
MR. SOLORIO: I would just like to
conclude my remarks by saying that GALL has
consistently applied the lessons learned of Calvert
and Oconee and also to a large degree at ANO because
the GALL reviewers were also working with ANO too to
cover the one-time inspection subject. While there
are some differences, I hope I was successful in
explaining that they're due to plant-specific nature,
nomenclature, design, periodic versus one time. So
that's how I would conclude this part of the
presentation.
I have one more slide to discuss.
(Slide change.)
Transparency, page 11, here, provides a
conclusion for our presentation. We hope that we've
impressed upon you a lot of work has been done and
while there could be more work done to address the
five continued dialogue issues, we believe that these
documents should be provided as final so that future
applicants and the staff can benefit from the
stability and efficiency they'll provide. Therefore,
we request your endorsement for issuing the final
documents to begin their implementation.
MEMBER LEITCH: Would the -- on the five
issues that we talked about earlier, would the final
documents be issued with being silent on those areas
or with the NRC position on those areas? Is there yet
hope of resolving those issues prior to the issuance
of the final document?
MR. GRIMES: We would expect to issue the
final documents with the NRC position on those issues.
We've agreed that we can continue to discuss them, but
we've taken a position that we're prepared to defend
in terms of what's necessary and sufficient and even
though the industry would like to continue the
dialogue, we're only going to defend the position that
we're putting forth in the guidance right ow.
MEMBER LEITCH: And then I suppose from
reading the preamble of the GALL that if industry, if
on a plant-specific basis they want to take exception
to that, they can always do that and argue that on a
case by case basis.
MR. GRIMES: That's correct. And that's
consistent with any regulatory guidance. Applicants
can always propose to depart from the guidance or
depart from standards and justify it on a
plant-specific basis.
MEMBER SIEBER: It sort of seems to me
that there's a lot of flexibility in the Standard
Review Plan and GALL and so forth and when I review
from my location, the plant application and compare
them with all the regulatory guidance that's out
there, particularly in scoping where some is done by
function, other plants do it by system, it's very
difficult and it just seems to me that it's difficult
to navigate through all this and fully understand what
is going on without access to the FSAR and plant
drawings and in some cases system descriptions, so my
impression is that this is not all that transparent
from the standpoint of public analysis and public
consumption.
Do you agree with that, Dr. Bonaca?
VICE CHAIRMAN BONACA: Yes.
MEMBER SIEBER: In other words, I had
difficulty going through all this and understanding
what fit into what boxes and what plant called what
system or what function by what initials and it's just
hard to do, it really is.
MR. GRIMES: And I would like to emphasize
we've recognized that and as a matter of fact, I think
the illustration of the language barriers that we
continue to face, that Dave described in the one-time
inspection area clearly indicates that there are
things that we could do to improve the transparency of
the process.
But we've been working on this explanation
since before the draft Standard Review Plan was issued
for trial use in 1997 and so while there are a lot of
things that we could do to improve the clarity and
understanding and communication between the interested
parties, the working affected in interested parties or
WAIPs as I like to refer to them, we think that the
substantial -- excuse me, I think that the substance
that we've accomplished in cataloging what's really
important to a decision about the effectiveness of
Aging Management Programs and guidance to the
reviewers on how to wind their way through the various
current licensing bases and different plant
nomenclatures, we think that we've captured a lot of
that and even though there is still navigational
difficulties, that gets me to the response to Dr.
Bonaca's original request and that is I fully expect
to incorporate another round of lessons learned some
time after the demonstration project.
I'm still not clear in my mind what that
time frame is, probably less than a year after the
original issuance. So we don't have time line or
frequency clearly established. I think that the
summer will give us some idea about how soon we might
see the first update to this guidance.
I also don't know at this point whether or
not we're talking about achieving so much transparency
with the original demonstration that we totally
reissue the guidance in plain language, or whether or
not we're going to continue to nibble away at it and
simply issue supplements to the GALL, SRP and
regulatory guide until such time as we really make
substantial improvements and the NRC's ability to
speak in plain language.
The major lesson at this point that I
think that we've learned since the original attempts
to figure out how to draw a license renewal
conclusion, almost exactly a decade ago, with the 1991
rule and I'd say at this point that yes, there's still
a lot more that we can do, but there's so much that
we've accomplished that we would like the ACRS to
endorse the promulgation of this guidance in final
form so that we can start now working on tweaking it
to make it better.
MEMBER LEITCH: By this guidance, we mean
not only the GALL report, the Standard Review Plan,
but also the Reg. Guide?
MR. GRIMES: And its endorsement of NEI
Guide 95-10, Revision 3.
MEMBER LEITCH: Are the differences
between the Reg. Guide and 95-10, Rev. 3 resolved or
is there still some --
MR. GRIMES: There were no differences.
The Reg. Guide proposes to endorse 95-10, Revision 3
without exception.
MEMBER LEITCH: Okay.
MR. GRIMES: There isi guidance in the
Regulatory Guide that gets to some administrative
details about electronic filing and packaging and so
forth, but the Regulatory Guide does not take
exception to the NEI Guide and we have verified that
Revision 3 incorporates the substantive changes
associated with the Standard Review Plan so that those
two guides are not going to obviously conflict with
each other.
MEMBER LEITCH: Okay. One other thing I'd
like to comment on is we haven't talked to anything
about the format of the GALL, but I think this format
is far superior to what we saw four months ago. I
don't know who's responsible for revising it, but it's
much more user friendly than -- to me at least, than
the two-page spread out thing. It's a lot easier to
review.
VICE CHAIRMAN BONACA: With that, are
there any more comments or questions for the
presenters? For Mr. Grimes? If none, I'll give it
back to you, Mr. Chairman.
CHAIRMAN APOSTOLAKIS: Thank you, Dr.
Bonaca. Thank you, gentlemen.
We have the first session of the
afternoon, Safety Issues Associated with the Use of
Mixed Oxide and High Burnup Fuels. There will not be
a presentation by the staff. The subcommittee
chairman will brief us for about 20 to 30 minutes. So
what I propose we should do is start our discussions
after the briefing of the Commission meeting in May,
okay? We will not need a transcription. Would you
please come back at 2:50 because we still have a
session that needs to be transcribed.
And with that, we'll reconvene at 1:10.
(Whereupon, at 12:10 p.m., the meeting was
recessed, to reconvene at 2:50 p.m., Thursday, April
5, 2001.)
. A-F-T-E-R-N-O-O-N S-E-S-S-I-O-N
(2:50 p.m.)
VICE CHAIRMAN BONACA: We lost our
chairman, therefore we --
MEMBER SHACK: That's why we have a vice
chairman.
VICE CHAIRMAN BONACA: That's correct. So
I am starting the meeting again and next presentation
that we have right now is the Thermal Hydraulic Issue
Associated With the AP1000 Passive Plant Design and I
believe that Dr. Wallis is leading this discussion.
Dr. Wallis?
MEMBER WALLIS: Thank you very much.
MEMBER POWERS: Will it touch on the
momentum equation?
MEMBER WALLIS: I guess we can ask
questions about anything we choose to ask about.
The subcommittee met with Westinghouse and
spent about three times as long as we're going to
spend today, but the purpose was really a preliminary
presentation by Westinghouse to let us know what
AP1000 is, how they approached its design and how
they're approaching their application for licensing.
They view this as an informational meeting and they do
not expect us to write a letter at this time.
I would point out that the staff has yet
to begin their review of AP1000. So it's a big
premature for us to reach some conclusions without
some input from the staff.
Without more delay, I'd like to invite
Westinghouse to proceed.
MR. WILSON: Good afternoon. I'm Jerry
Wilson. I'll begin the meeting. I'm with the NRC's
Future Licensing Organization and I thought I'd start
out with a little bit of overview on the AP1000
review.
Last year, Westinghouse approached us and
said they were thinking about seeking design
certification for their AP1000 design, but before
doing that they wanted to determine what the scope and
cost of that effort would be and more specifically, to
get agreement on --
MEMBER WALLIS: Someone has changed the --
I'm sorry, Jerry. Someone has changed -- I introduced
you falsely. Someone changed the agenda on me. I'm
sorry.
MR. WILSON: That's all right, Dr. Wallis.
MEMBER WALLIS: Maybe you should correct
the record.
MR. WILSON: No one would accuse me of
being a representative of Westinghouse.
MEMBER WALLIS: Maybe you should tell the
record who you really are.
MR. WILSON: As I said, I'm Jerry Wilson
and I'm with the NRC staff in the Future Licensing
Organization.
Westinghouse had specific issues that they
wanted agreement on to determine -- that would affect
the scope and duration of a review for design
certification and so we set up a three-phased approach
to do this. The first phase was to determine the
issues we should look at for the
pre-application review and estimate the effort to do
that. We completed Phase 1 last July. Met with the
ACRS in August. Got a letter from the ACRS. And also
in August of last year, Westinghouse decided to
proceed with Phase 2.
Now in Phase 2, Westinghouse requested
that we evaluate these four issues. Is the test
program that was performed for AP600 sufficient to
support the AP1000 application? They've submitted two
reports as you see here on the overhead. We're in the
process of getting ready to start that review. NRR is
going to be the lead in this review and we're seeking
assistance from Office of Research.
The next issue is applicability of the
AP600 analysis codes to the AP1000 design review.
Westinghouse has yet to submit the code applicability
report to us. We see this as a key part of our review
and that's the part that will make our assessment when
we officially start the review and so we're waiting to
get that information.
They also are seeking additional use of
design acceptance criteria beyond what was done in
AP600. They made a submittal on that area and the
staff has begun its review in that regard.
Finally, we have to look at the exemptions
that were granted on AP600 to see if they would still
be granted on an AP1000 review.
Now we've estimated that it's going to
take approximately 9 months to do this review.
Although we haven't officially started the review, I
would for planning purposes tell the committee that I
anticipate in approximately 6 months we'll be back
with our recommendations on the Phase 2 results. We'd
like a letter from the committee at that time. We'll
also be preparing a letter, a SECY paper to the
Commission, advising them of our recommendations on
Phase 2 and once we hear from the Commission on that,
then we plan to send a letter to Westinghouse, giving
them NRC positions.
And Mr. Chairman, that's all I had for
this overview. If there's any questions I can take
them now.
If not, then I'll turn the meeting over to
Mr. Corletti of Westinghouse.
MEMBER WALLIS: Thank you very much.
MR. CORLETTI: Thank you. Good afternoon.
My name is Mike Corletti. I'm with Westinghouse
Electric Company. Thank you for having us today.
(Slide change.)
MR. CORLETTI: Our agenda, we're going to
be speaking, you see here, I'm going to be talking
about really our purpose for this
pre-certification review and give you an integral NSSS
overview, overview of the NSSS. Then Terry Schulz
will be talking about our passive safety systems
design and analysis. He'll be focusing on the plant
description and analysis report that we submitted in
December, that included a description of the AP1000
and preliminary safety analyses that were performed,
using the codes that were developed and approved for
AP600.
Bill Brown will then be discussing our
PIRT and Scaling Report that we submitted last month.
We really see that as the first key deliverable for
the codes and testing issue because before we can get
to the detailed review of the code, we really have to
come to agreement that the tests that were used to
validate the codes for AP600 are also applicable to
the AP1000. And that report provides scaling to --
our scaling approach is outlined in that report. I
believe you've all received that.
Finally, Mr. Gresham will get up and speak
with regards to our planned approach for codes. Our
plan is to the use the codes that were approved for
AP600 and we owe a code applicability report that is
due out mid-month and Mr. Gresham will speak to that.
Finally, the other issue is that of design
acceptance criteria and Richard Orr will speak about
our approach for design acceptance criteria and also
talk a little bit about some seismic analysis that had
been completed already for AP1000.
(Slide change.)
MR. CORLETTI: As Dr. Wallis said, this
meeting is basically an informational meeting. It was
not our intent to ask for a letter at this time and
really to introduce ACRS to AP1000 design, how we've
gone about designing the plant based on AP600. The
objectives of the pre-cert review, I believe Jerry's
covered those already and then our proposed approach
resolving these issues.
(Slide change.)
MR. CORLETTI: We came to the staff last
year about around this time talking about the AP1000.
We had worked on it for some time since we had
completed AP600. When we completed AP600 in the
commercialization of that, the market has changed
significantly from the time that AP600 was initiated
and this is what is driving towards developing the
AP1000. Basically with the approach of using the
AP600 as a basis, we can use the design, the detail
design that we developed on AP600 and really, we're
developing the AP1000 within what we're calling the
space constraints of the AP600.
(Slide change.)
MR. CORLETTI: You'll see here -- no you
won't. When we say the space constraints of the
AP600, you see here's the AP600 and AP1000 side by
side. So if you look at a plan view, the plants are
essentially the same, the same structurals generally.
The steam generators are somewhat larger to account
for the higher core power. But really, from this view
it looks, it basically is the same view.
(Slide change.)
MR. CORLETTI: When you look at the
section view, the containment has grown to accommodate
both steam generator removal and the larger mass
energy releases associated with the larger core power.
(Slide change.)
MR. CORLETTI: On the AP600 or AP1000,
basically we're also trying to use the same components
as much as possible, use proven components that have
been used at Westinghouse plants and others. By using
this approach, we retain the basis for the cost
estimate, the number of components are the same, the
same configuration essentially. Some of the
capacities are increased, but the number of components
and the way they're all put together are essentially
the same.
With our approach we're also -- the key to
this is for AP1000, is to meet the regulatory
requirements that we encounter for the passive plant,
so really, we're adopting all the passive plant issues
and also part of that is preserving the large safety
margins that the passive plant had with AP600 and in
our reports that we've sent in today, or up to this
date, have tried to demonstrate that with a
preliminary safety analysis that we've shown to
illustrate the large safety margins that we're
preserving with AP1000.
MEMBER WALLIS: So 1000 was just chosen as
a nice round number, rather than some optimum and why
isn't it 1200 or 1500?
(Slide change.)
MR. CORLETTI: Well, basically, the next
slide here, next two slides, we wanted to stick with
a proven core design and so we went to -- for AP1000
we went to a 14-foot core, longer fuel assemblies. We
have 14-foot cores in our South Texas designs and also
in Doel and Tihange, two plants that are in Belgium.
And those plants, actually have 157 fuel assemblies
which are the same as AP1000 so the core design is
essentially the same. Now those plants, the Belgium
plants are at 3000 megawatts thermal. AP1000 has
been, the core power has been increased to the same
level from a power density as our operating three loop
plants.
So that was what basically sized -- we
didn't want to make the vessel bigger in diameter. We
made the vessel longer to accommodate the longer fuel
assemblies, but we didn't want to make it, to grow in
diameter, because that would have affected the
structures.
MEMBER WALLIS: Not longer than South
Texas?
MR. CORLETTI: Not longer than South
Texas. We wanted to keep within an experienced basis
that we had with South Texas.
(Slide change.)
MR. CORLETTI: You see some of the key
comparisons of the 600 and 1000. As I said, the
reactor power is increased from 933 megawatts up to
3400 megawatts thermal. The hot leg temperature has
been increased from 600 to 615, but that again is
within our operating experience.
The number of fuel assemblies is
increased. Also the number of control rods is
increased from 45 to 53. The reactor vessel ID is the
same. It's the same ID, again, it's grown in length.
The steam generator, the steam generator
surface area has been increased to 125,000 square
feet. It just so happens that as we begin the AP1000,
our steam generator design group had just completed
design and actually has set the steam generators to
the Arkansas units which were a generator of about
1500 megawatts per generator, about this size. We
based the design largely on that design. Since then,
we've merged with Combustion Engineering which has
more experience with designing steam generators at
this power level. The team has been working together
to finalize the design of the AP1000 steam generator.
Essentially, we'll have the same
performance requirements with the low moisture
carryover of the delta 75 that we had on the AP600,
Iconel 690 thermally-treated tubes.
MEMBER LEITCH: Are there any AP600s
actually under construction now?
MR. CORLETTI: No sir.
MEMBER LEITCH: So your plans for the
AP1000 don't depend upon building any AP600s,
necessarily?
MR. CORLETTI: That's right. We're still
basing it on proven components. We're not relying on
this to be a follow-on to AP600. It would be
available, essentially if a customer wanted to
purchase a plant, we believe we can the schedule that
we could do almost either one within the same time
frame.
MEMBER LEITCH: Okay, thanks.
MEMBER POWERS: Why the 690 alloy for the
steam generator?
MR. CORLETTI: That is what we've been
using on their most recent steam generators.
MEMBER POWERS: That does not speak highly
for it. I mean it's not immune to stress corrosion
cracking.
Why not go with the 800 alloy?
MR. CORLETTI: I believe that the
operating experience with the 600 has been very good,
690. And they basically have not seen the need to
change. They've had very low incidents of any tube
plugging with this material. It has excellent
operating experience.
MEMBER SIEBER: Do you have any Iconel 600
anywhere in the reactor coolant system pressure
boundary?
For example, it's extensively used in
current PWRs on the head, some weld filler materials,
etcetera, pressurizer.
MR. CORLETTI: No. I cant speak to -- I
can't speak to that. We've been using the approved
materials that we used on the AP600 which more the
Iconel 690 and I know the materials that they selected
were basically in accordance with the latest EPRI
guidelines on materials selection.
MEMBER SIEBER: On the other hand, your
Tihange temperatures went up by 15 degrees which puts
it into the sensitivity zone, so the operating
conditions are different than the AP600. I'm just
wondering if you made a change to materials in any way
to account for that?
MR. CORLETTI: No. It will be the same as
AP600.
MEMBER SIEBER: Okay. You also state that
the reactor vessel diameter is the same?
MR. CORLETTI: Yes sir.
MEMBER SIEBER: But there is 12 extra fuel
assemblies in there? How do you accomplish that?
MR. CORLETTI: I don't have that, but
basically on the outer periphery, at the north,
southeast and west of the core, there was room for
three additional assemblies. It's essentially the
same as our three loop plants now that have 157
assemblies. They were eliminated on AP600.
MEMBER SIEBER: Okay. So that should
improve the neutronics efficiency a little bit as
opposed to making a 14-foot core reduces your
neutronics efficiency? Does that come out as a sort
of a fuel cost balance or do you know?
MR. CORLETTI: I don't know.
MEMBER SIEBER: Thanks.
MEMBER WALLIS: Well, the power rating per
area of fuel is higher?
MR. CORLETTI: Yes, it is. AP600 had a
very lower power density core. You see it's 4.1
kilowatts per foot. We've increased it up to the
level that we have in our operating three loop plants.
MEMBER WALLIS: That's the main way in
which you get the extra power?
MR. CORLETTI: Yes sir. And increasing
the length. One of the consequences to go to the
higher power, we had to increase the capacity of the
reactor coolant pump. The reactor coolant pump is
increased from 51,000 gpm to 75,000 gpm flow rate and
the head is increased from 240 feet to 350 feet of
head.
In order to minimize the impact to the
motor, we've gone to a variable speed controller.
That's only used during shutdown. When you start the
pumps up in cold water, that is the largest draw on
the motor and that's typically what the reactor
coolant pumps, Westinghouse's reactor coolant pumps
are sized for. With the variable speed controller it
allows you to start the pumps at low speed in the cold
conditions. When the fluid is heated up to operating
conditions, then that is disengaged.
MEMBER SIEBER: Is that an electronic
controller?
MR. CORLETTI: Yes.
MEMBER LEITCH: Mike, you said used during
shut down. Do you mean start up?
MR. CORLETTI: Right. That's right. Shut
down operations is anything called low temperature.
And then again, the pressurizer has been
increased with respect to the AP600.
MEMBER SIEBER: Do you expect that the
higher flow rates you have at the additional steam
generator tube vibration or fuel vibration?
MR. CORLETTI: The fuel vibration you have
to look at the upper guide supports.
MEMBER SIEBER: Right.
MR. CORLETTI: Because the one that's
right in front of the hot leg is the most and we have
looked at that and we've looked at where we were on
AP600 and we do have sufficient margin, but that is
the most susceptible.
On the steam generator tubes, we've
increased the number of tubes, so that the velocities
through the tubes is not appreciably larger.
MEMBER SIEBER: Thank you.
MEMBER LEITCH: Mike, to go back to the
question of hot leg temperature. I noticed that South
Texas has a hot leg operating temperature of 624 with
Iconel 690. That's apparently a fairly new steam
generator, is that --
MR. CORLETTI: Yes. We just replaced that
steam generator.
MEMBER LEITCH: I was wondering, is that
design temperature or --
MR. CORLETTI: That's the operating
temperature. And the units at Doel and Tihange are at
very high hot leg temperatures also. There's many
units, I think you see in the table there that have
operating temperatures.
DR. ROSEN: The South Texas Unit 1 steam
generators have been replaced. The Unit 2s have not
yet been replaced. They'll be replaced in 2002.
MEMBER WALLIS: Any other questions for Mr
Corletti?
MR. CORLETTI: Thank you. The next
presentation is on the passive safety systems and
Terry Schulz is going to present that and basically
our design approach to designing the AP1000.
Thank you.
MR. SCHULZ: Good afternoon. My name is
Terry Schulz and I will be talking about the passive
safety systems and our design approach to those
systems and try to give you some insights into how we
have come to the sizes and capacities that we've
selected.
(Slide change.)
MR. SCHULZ: First of all, the approach is
to use the same configuration, as Mike pointed out, as
AP600, same arrangement. However, in the passive
systems we know we have to increase the capacities in
some areas and we've selectively looked at where we
think we need to do that to maintain adequate safety
margins.
We've considered both deterministic and
PRA conditions and we've also given consideration for
applying margin, as we did in AP600 to where there was
test or computer code uncertainties.
The process we used is an iterative
process and we've actually done this a couple of times
already, where we looked at basically a hand
calculation type, sizing, estimating of the
performance using first principle type hand
calculations which are largely independent of test and
analysis.
These calculations are typically not a
transient, but a point in time that we select based on
our experience and understanding of the plant. Then
we kind of check that and verify it using the computer
codes, again, at this point in time AP600 computer
codes, the same ones we used in the SSAR analysis.
These are not intended or portrayed to be Chapter 15
final analysis. They're kind of check calculations.
They're obviously able to look at the transients, the
integrated effects of the plant response. We've not
done all the events we would eventually do in a SSAR,
but we've looked at what we consider limiting events.
And another factor that does affect our,
in some cases what we chose to do, was constraints in
the plant. As Mike pointed out, physical constraints
in the plant can affect the design, the design
approach that we have.
MEMBER WALLIS: Did your thermal draw
code analysis lead to significant changes in the
design or did the eventual thing look just like what
you had in your hand calculations?
MR. SCHULZ: Well, for example, in the
passive RHR, our initial idea was to increase the pipe
size and not to change the heat exchanger because that
was minimizing the change to the plant and we thought
we had -- and that would give us maybe a 25 percent
increase in capacity, heat removal capacity which is
not nearly as much as the power increase, but we
thought we could compensate for that by having much
more mass in the steam generator. And for some
events, in fact, that was adequate.
However, for other events like a steam
generator tube rupture, it didn't work as well as we
wanted it to, so we introduced another change, was to
increase the capacity of the heat exchanger. So in
fact, there are cases where -- when we went through
the computer analysis, we learned things that we
didn't have in hand calculations and in some cases it
was just other events that we hadn't considered when
we did the hand calculations. In other cases, the
hand calculations are, of course, very simple,
relative to the computer and not as accurate.
MEMBER WALLIS: Well, yes, okay.
(Slide change.)
MR. SCHULZ: The first feature I would
like to talk about is the passive RHR and the
configuration of this heat exchanger and system is
exactly the same as AP600 in terms of valves, the
arrangement of the pipe of the heat exchanger, the
elevations, in fact, are the same. We did increase
the pipe size from 10 inch to 14 inch and we increased
the surface area by adding longer horizontal tubes and
a few more tubes. I think the heat exchanger surface
area increased about 22 percent.
(Slide change.)
MR. SCHULZ: We did some hand calculations
on both the AP600 and AP1000 which -- and this hand
calculation is actually fairly sophisticated in this
case and using the same correlations we use in our
computer codes. It's to calculate the heat transfer
in the AP1000. It is almost as much as the power
increase with the changes of both the pipe size and
the surface area. Not quite, and you see the time to
match decay heat is a little bit longer. If you also
consider what's going on in the secondary side of the
plant, Mike Corletti pointed out we have these larger
steam generators.
We've also applied more water mass on the
secondary side per megawatt than AP600. So at the
beginning of a transient, we've got like 36 percent
more water per megawatt. At the end of the transient
when we've boiled off some of that water, we have
almost twice as much water. So even though our heat
exchanger is a little bit smaller, the net effect of
having more mass in the steam generator means that
we've got even more margin relative to heat removal
capabilities.
So from this point of view in terms of say
a hand calculation, we expect the plant to have
increased margins.
(Slide change.)
MR. SCHULZ: In addition, we have done a
number of transient analyses. I'll show you the feed
line rupture. We also looked at loss of feedwater in
steam generator tube rupture. It's a little hard to
tell which plant is which here, but you can see this
is plotting the saturation pressure versus the -- on
the high side there and the hot leg and cold leg
temperatures down below. And the general trends are
similar. The AP1000 temperatures are a little bit
higher, so the subcooling margin is slightly less, but
it is still very significant, 140 degrees at least in
AP1000.
Current operating plants, this temperature
tends to go back up and come within a few degrees of
saturation, not that that is an unacceptable
situation, but it's a measure of safety that we use in
this type of a transient. So our conclusion here is
that AP1000 behaves very much like AP600 in terms of
a transient response.
(Slide change.)
MR. SCHULZ: The next thing I'd like to
move on to is to talk about the passive safety
injection features. And this includes the
accumulators, the core makeup tanks, the ACS system
and the IRWST and recirculation.
Again, the configuration, if you look at
this same sketch for AP600, they look exactly the
same. A number of valves, the way the valves are
connected is exactly the same. The elevations are
almost the same except for the pressurizer is a little
taller, so some of those valves are up a little
higher.
The core make up tank has been increased
in size about 25 percent and the flow capability has
been adjusted by adjusting a flow tuning orifice so
that the flow is also 25 percent more. So we're
getting a bit more core makeup tank flow. Accumulator
capability has not been changed and I'll speak to that
in just a minute. Fueling water storage tank, the
injection lines, the containment recirculation lines
and the ADS stage 4 pipes have all been made bigger to
make, to increase the capability of IRWST injection
and recirculation. I'll talk about each of these in
turn.
(Slide change.)
MR. SCHULZ: At the time I have this up I
want to also have this slide up here so I can -- so I
have on the left slide here, a margins assessment,
again a hand calculation type thing, for each of the
key features, the accumulator, for example, core make
up tank and so on, where we've tried to get a measure
of how AP600 and AP1000 compare.
For the accumulator, we did a kind of
ratio on power density and time to refill the core and
ratio to peak clad temperature. So this is not a
sophisticated, large LOCA analysis. It's a simple
ratio of the fact that AP1000 has the higher power
density. We expect the core to heat up faster in the
reflood stage. And so we think that the peak clad
temperature might be something around 1940 degrees as
opposed to 1640 for -- and these are basically -- the
AP600 number is the best estimate LOCA with
uncertainty as quantified in the SSAR for AP600.
And as I mentioned the flow capability of
the accumulator was not changed. And the tank itself
is constrained by concrete walls on the sides and the
floor. It's already a spherical shape so it would
have been pretty challenging to make that tank bigger.
The other factor is that there are a
number of operating plants that have large LOCA peak
clad temperatures that are as high and higher than the
1900 and of course, the licensing limit is 2200. So
we feel comfortable with that result.
The core makeup tank, I mentioned we
increased it by 25 percent both in flow and volume.
What you see here is a comparison of the flow
capability of the core makeup tank as opposed to a
calculated requirement at the point in time when the
accumulator would empty in a direct vessel injection
line break.
This is, in our experience, the most
limiting condition for core makeup tank because in a
direct vessel injection line break, one of the tanks
spills, the other one injects and so it has to perform
the whole duty. And you see here the margin of the
design versus this requirement is a little bit less on
AP1000, but it still looks comfortable in this
situation.
ADS stages 1, 2 and 3 we have not changed
for the AP1000. It's exactly the same, pipe sizes and
valve sizes. And we think that that is adequate for
AP1000 because at the higher pressures that this
system is important at in terms of the initial
depressurization, we can get adequate flow. So even
though the AP1000 has more power and a bigger reactor
coolant system volume, that this system will perform
adequately and in our computer analysis shows that.
On the other hand at ADS stage 4, we've
significantly increased the capacity. I mentioned the
pipe sizes go up from 10 inches to 14 inch for each of
the ADS stage 4 lines and there's four of those. And
if you look at with the same delta P across the
system, the flow would go up about 89 percent versus
AP600. That's, of course, not saying it's enough, but
it's giving you a feeling for how much flow capability
we've added to the system.
Now the ADS stage 4 works very closely
with IRWST injection and later on, containment
recirculation. Both of those, we've also increased
substantially by making the pipe sizes bigger and in
the case of containment recirculation, we've done one
other thing which is to change the alignment of the
normal RHR system.
The normal RHR system is not a safety
system. It doesn't have to work, but it is suggested
in our emergency procedures that the operator should
turn it on because it adds a level of defense. It
also, in the case of a direct vessel injection line
break, would tend to increase the rate at which the
IRWST drains down because it's going to spill more
flow if it's running than if it's not running.
This is all accounted for in AP600, but in
AP1000 we changed the normal water supply from the
IRWST which is inside containment, to another supply
outside containment. So if the pump works, it will
actually make things better instead of making things
a little worse. And that gave us a somewhat less
severe condition for AP1000. So it's another change
we made to improve the situation for that design.
(Slide change.)
MR. SCHULZ: If you look at -- and again,
we've done the analysis of several small LOCAs for
AP1000. This is a direct vessel injection line break.
And it's showing you the upper plenum mixture levels.
It's kind of a little hard to show this. This spike
early on is actually AP600. AP1000 doesn't behave
quite the same way and it doesn't mainly because
AP1000 is a little bigger plant and it's the same
break size, so you don't get quite as much rapid blow
down early on.
Later on, the response is actually fairly
similar, not exactly the same. AP600 has a little dip
in here when fourth stage is trying to get the
pressure down for IRWST injection. AP1000 actually
has IRWST injection starting a little bit earlier, but
it's not continuous. That's why you're getting some
of these spikes.
MEMBER WALLIS: Those periodic spikes,
what are they for? What are they due to?
MR. SCHULZ: You're getting intermittent
IRWST injection and when you get the --
MEMBER WALLIS: Then it gets starved and
then you --
MR. SCHULZ: So when you get injection,
the level goes up, but --
MEMBER WALLIS: But it seems to go down --
MR. SCHULZ: You can't quite keep the
pressure down, so the injection slows down and the
water level comes back down again. We saw things like
that at OSU and it's something that the plant, AP600
is doing some of it also, not as pronounced.
MEMBER WALLIS: You see spikes like that,
though you wonder about the peer program because the
turn around, it's like the stock market. It's headed
for disaster there and then somehow it turns around,
but the accuracy with your computer program has
something to do with the depth of the spike there.
MR. SCHULZ: Yes, yes.
MEMBER WALLIS: That makes one a little
bit concerned. Things happen so quickly in the spike.
MR. SCHULZ: We've got several feet here
and this time scale, of course, is a very long time
scale.
But that's something that certainly,
should be looked at in more detail when we get into
real safety analysis.
DR. ROSEN: What does ADS stand for?
MR. SCHULZ: Automatic depressurization
system. I moved my slide. But there are valves
connected to the pressurizer which are stages 1, 2 and
3. These are all sequenced to give you a staged
depressurization. Stage 4 is actually connected on
the hot legs and goes directly to containment. Stage
1, 2 and 3 go from the pressurizer into a sparger in
the IRWST. And those valves are all staged so that
the transient on the reactor coolant system is less
severe.
MEMBER WALLIS: Going back to the spikes,
this is sort of the place where you'd like to do some
sensitivity studies to see if you have a sort of
somewhat different disengagement model for the vapor,
whatever the model is. I was sensitive of these
things to those features in the code and you want to
know there are some assumptions you make which would
make those more exaggerated.
(Slide change.)
MR. SCHULZ: Yes. In summary, in terms of
safety margins, I haven't talked about the loss of
flow, but that's when the reactor coolant pump inertia
is important. And you can see AP1000 may be a little
bit less margin than AP600, but both will be
comfortably more than the typical operating plant.
Same with the feedline break subcooling
margin which I talked about. Steam generator tube
rupture analysis, AP600 displayed a significantly
enhanced behavior relative to operating plants which
did not require any operator action to mitigate a
steam generator tube rupture. We've done some
preliminary analysis on AP1000 and had the same
result. We don't need operator reactions to mitigate
a steam generator tube rupture.
Small LOCA, we've done several. Not the
full spectrum, but several breaks for AP1000 and we're
getting no core uncovery for these smaller breaks like
AP600. I've already talked about large break LOCA.
That's the same result you saw before.
MEMBER LEITCH: Isn't that 300 degree
increase and decladding temperature surprising? I
mean when I look at the data I was surprised by that
much of an increase.
MR. SCHULZ: Realize where this is coming
from. This is basically taking AP600 very carefully
detailed calculated re-flood temperature rise and
rationing that temperature rise based on the higher
power density of AP1000 and that's where that number
is coming from.
MEMBER WALLIS: It's not a thermal
hydraulic code calculation?
MR. SCHULZ: It's not a thermal hydraulic
code calculation, but we would expect it to go up.
Now whether that's where we end up, we won't know
until we actually do the detailed large break LOCA
analysis. But this kind of a manipulation is we've
done it before on new plant designs and it's something
you can get a reasonable handle.
MEMBER LEITCH: Yes, I see. Thank you.
MEMBER WALLIS: If it wasn't the criteria,
do you think you might tweak your design to get the
desired PCT rather than finding what PCT you just
happened to get?
MR. SCHULZ: Well, we actually considered
running the accumulators faster. We can do that.
However, they also empty quicker and there's other
transients, especially in PRA space where the
accumulator is say the only means of defense at high
pressure because we've had common mode failure of the
core makeup tanks which is not a design basis
consideration, but it is something we consider in the
PRA.
And running the accumulator faster there
is not good in terms of the balance of safety here
between large break LOCA and small break LOCA. So
after considering that the PRA sequences, we felt that
it was better to run the accumulator the same speed
and take a little less margin in large break LOCA and
again, it says good or better than a lot of operating
plants. So we don't feel uncomfortable with the large
break LOCA.
MEMBER WALLIS: But generally speaking,
you are asking for somewhat less margin in all of
these areas than you have with AP600?
MR. SCHULZ: No. I don't think that's
true.
MEMBER WALLIS: Aren't all the numbers --
MR. SCHULZ: Well, small break LOCA, we're
basically saying they're the same. If you look at the
capability at stage 4 at IRWST injection and
recirculation, we think we've actually added more
margin into the design and so we'd expect that
performance to be probably a little better.
Some of the other cases, yes. Feedline
break is a little bit less, but again, it's much
better than operating plants.
I need to wrap up pretty quickly here.
(Slide change.)
MR. SCHULZ: The containment comparison,
as Mike showed, we've made the containment higher.
It's about 22 percent bigger in free volume. We've
also increase the design pressure from 45 psig to 59
psig. It's a steel shell containment so we're getting
that pressure increased by increasing the thickness a
little bit, changing the material and we've also
increased the amount of water that's on top of the
containment so that we can account for the increase in
decay heat.
MEMBER POWERS: Did you change your
configuration around there, the hatchway?
MR. SCHULZ: You're talking about the
containment hatch?
MEMBER POWERS: Right.
MR. SCHULZ: We actually ended up making
the hatch smaller.
MEMBER POWERS: It looks like it.
MR. SCHULZ: Yes. This hatch is sized to
remove a steam generator. Because our steam
generators got so big that we've decided that's not
practical to remove the steam generators out the side
and we would have to cut a hole in the top of the
containment and remove it through the containment
shell.
MEMBER POWERS: So your vulnerable
location around the hatchway is not so bad now?
MR. SCHULZ: That's right.
MEMBER SIEBER: The containment itself has
no sizeable concrete structure on the outside, I take
it?
MR. SCHULZ: It's a steel pressure vessel
that's 1-3/4th inch thick. There is a separate shield
building, a concrete shield building that's offset
from that and that actually in our case provides the
air inlet which comes down outside of a baffle that's
in between, turns and goes up closer, with closer
spacing relative to the containment and that's part of
our passive containment heat removal.
MEMBER SIEBER: How thick is the concrete
in the wall there?
MR. SCHULZ: It's about 3 feet.
MEMBER SIEBER: So it has the equivalent
shielding capability for severe accident capability?
MR. SCHULZ: Oh yes, for severe accident,
missile shields, radiation shielding, yes.
MEMBER SIEBER: Thank you.
DR. ROSEN: Have you actually done a steam
generator removal study for the AP1000?
MR. SCHULZ: I think so, yes. Yes, we
have. Yes.
(Slide change.)
MR. SCHULZ: And the final slide I have
here speaks to the containment performance. We looked
at both large LOCA and large steam line break. The
large LOCA has a very similar response to AP600 where
the first peak is significantly below the design
pressure. The second peak is also well below design
pressure, assuming more realistic steam generator
energy input. This was an issue discussed a lot on
AP600. Our SSAR results show a much higher second
peak, but it has a very overly conservative sort of
unmechanistic transfer of heat from the steam
generator into the reactor coolant system.
The steamline break is limiting in this
plant. However, it's a much simpler analysis in that
it happens early and the passive containment cooling
is not really much of a factor in this peak. So how
well the passive system performs is it's just more
simple volume and some passive heat sinks involved.
Are there any questions?
MEMBER SIEBER: Do you use sprays to
control the containment pressure?
MR. SCHULZ: No. There are no sprays in
the plant from a design basis point of view. So all
the heat removal is through the passive containment
cooling system and the passive heat sinks in the
plant. There is a connection to the fire system, but
it's a sort of PRA-type severe accident capability
that takes manual alignment and it's a long-term type
operation. It would not be effective in a short-term
peak pressure situation.
MEMBER WALLIS: Okay, shall we move on?
MR. SCHULZ: Yes.
MEMBER WALLIS: Thank you very much.
MR. SCHULZ: You're welcome.
(Slide change.)
MR. BROWN: Okay, we'll move on to --
MEMBER WALLIS: This is an open session,
is it?
MR. BROWN: Yes, there is nothing
proprietary here.
I am Bill Brown from Westinghouse and I'll
be going over the AP1000 PIRT and scaling assessment
that was done.
(Slide change.)
MR. BROWN: We had already submitted our
report and last month here we met with the Thermal
Hydraulic Subcommittee and I made a rather lengthy
presentation on that of which I will try to go through
quickly.
The main goals here was to try to
determine the extent to which AP600 could be used for
AP1000 and our main goal was to be able to use this
database for code validation in accordance with 10 CFR
Part 52.
The basic steps we used was first, take
the PIRTs which identify all the phenomena, have them
reviewed again by several experts for application to
AP1000 and then take the results of these and look at
the high ranked, important phenomena and then assess
that relative to AP1000.
(Slide change.)
MR. BROWN: This gives you a quick idea of
some of the experts that we talked to, Dr. Bajorek,
Dr. Bankoff, Dr. Hochreiter from Penn State, Dr.
Peterson from UC and Dr. Larson and Mr. Wilson from
INEEL. The main result of this was that we really
found that there was very, very few changes
whatsoever. Large break LOCA indicated that core
entrainment was a little bit higher and in the small
break LOCA we found that entrainment again in the ADS-
4 two-phase pressure drop was increased and we had no
changes whatsoever for the containment and/or for the
non-LOCA transients. So essentially, we're looking at
really virtually no change for the AP1000.
(Slide change.)
MR. BROWN: We addressed quite a
significant amount of phenomena here and this gives
you kind of a flavor for the types of things that we
looked at: reactor vessel inventory, core exit
quality, ADS floor, injection through the sump and the
CMT, containment pressure, the heat and mass transfer
to sinks on containment. We looked at these more from
what I would call a system level top down and then
sort of bottom up we looked at some more detail or
local phenomenon such as entrainment, surge line
pressure drop, phase separation and so on.
(Slide change.)
MR. BROWN: The basic approach in the
scaling that we used for assessment was we focused in
on the high-ranked phenomena especially for the areas
in AP600 where certainly major interest would seem to
be the small break LOCAs since we were interested in
the core cooling and the vessel inventory, and then of
course, containment pressure and steam line break.
Areas in which we already have data that
are found in convention PRW data bases such as large
break LOCA phenomena, blowdown and steam generator
recirculation, things like these, we didn't really
look at these. We looked at the things which were
unique to the passive plants and which we were
interested in making sure that we could use the data
from AP600. And we did not go in and assess things
that were of low importance. We focused on the high
level.
(Slide change.)
MR. BROWN: So we started from using our
AP600 scaling analysis as our basis. We tried, of
course, to learn from what we had discovered from
AP600 and tried to look at the major features which
were different such as the things you've heard before
earlier discussed about core power, volume, the
automatic depressurization system area and how these
things would compare.
And what we essentially found for the
separate effects type test we really look at the
operating conditions and the geometric similarities
with those. When we got into things such as the
integral effects tests, we really had to do some
supplemental scaling analysis.
(Slide change.)
MR. BROWN: To give you an idea, a flavor
of the type of -- again, the number of tests that we
looked at in AP600 which was something in the
neighborhood of a $40 million program, quite
extensive, we had a couple of integral effects tests,
SPES, OSU, ROSA-AP600 which was NRC funded.
We had a large scale test facility for
containment and we had a whole host of separate
effects tests for the automatic pressurization system,
the core makeup tanks, the passive RHR heat exchanger
and numerous containment tests for the heat and mass
transfer for the plates that we had and their vertical
surfaces in containment, the water distribution and so
on. And for all of these, we provided an assessment
and for several of these we actually did a new scaling
analysis for.
MEMBER KRESS: I don't recall the
University of Wisconsin Condensation Test.
MR. BROWN: Yes, that was the condensation
tests that were done at -- with the Coradini people up
there.
MEMBER KRESS: The effects of non --
DR. ROSEN: That was the flat-plate tests.
MR. BROWN: Yes, that was the flat-plate
tests, yes, right.
MEMBER WALLIS: I was thinking about the
scaling analysis. You showed us a lot of comparisons
with just sort of this effect versus that effect and
their imbalance about the same in the experiment is in
the real thing and there was a number that should be
1 and it's 1.1 or something you showed us. But those
were sort of pair by pair and something like OSU, OSU
actually tries to model the whole thing and you've got
many things that interact during the whole transient.
I think your scaling analysis was more pair by pair,
so you wouldn't be able to -- OSU was design to model
AP600 everywhere.
MR. BROWN: It's an integral effects test.
MEMBER WALLIS: OA models AP1000 every --
it may have -- this pair of effects may be in balance,
but when you put the whole thing together, it's not
going to be quite a model of AP1000, is it?
MR. BROWN: There will be as any of the
integral effects test facility, there are things of
lower importance of which are not in exact balance and
part of the premise of this was that we had
established by going through AP600 very painfully that
there was a number of things in there which don't
become important and some of them simply because
they're not active.
For example, once the automatic
depressurization system goes off, the passive RHR, the
core makeup tanks, for example, can essentially be
drained and it was found both numerically doing the
analysis as well as though the tests that the energy
removal of these components is very small. You can go
ahead and scale them, but they're not very
significant.
MEMBER WALLIS: That was not very clear.
You looked to scaling as CNTs and injection from the
IRWST, all of these. If you scaled each one of those
phenomena, but in the whole transient, they're all
interdependent. At the starting point for one phase
is where you've finished at the previous phase, the
effects go through the transient. Really, you have to
run the code or something to get the whole system
effect.
MR. BROWN: We do break the scaling up
into phases, yes. We do not have, if you're looking
for an analysis which would start from time zero and
look at the whole snapshot, yes, we do, we do break
them up.
MEMBER WALLIS: OSU is sort of trying to
scale everything after a certain time.
MR. BROWN: We find OSU is particularly
good once the system is low pressure. It's a low
pressure facility and not surprisingly you find that
it's very well scaled once the system is depressurized
to low pressure.
MEMBER WALLIS: The thing I'm getting at
is that the interactions between the systems, other
than in pairs really has to be modeled by something
like a thermal hydraulic code for scaling analysis
balances.
MR. BROWN: Yes, you get to the point with
scaling where you very quickly and I think Dr. Zuber
found this out in AP600, although he had the vision of
this, you pretty quickly get to the point that in
order to be able to work with the set of equations
that very quickly you put the complexity in where you
now need a code to solve them and you no longer have
a scaling analysis.
But one of the things that I think we've
gone to be able to help that out is one knowing, for
example, that no all, even though we have all of these
passive components, potentially available, not all of
them are operating at each phase during a small or
LOCA transient. Not all of them are always
significant. And you can also determine that by
scaling and the testing to bear that out. I mean, for
example, we have a small break LOCA, that's a one inch
or a two inch break.
It's very important during the blow down
phase and during natural circulation, once you open up
this huge hole, we call on automatic depressurization
system there. Suddenly, the mass and energy out of
this break becomes nothing, so I could continue to
scale this for you, but we find it's not significant
and that's why I didn't bother focusing that in this
report. We focused on the things that were important
when they were important.
And we have reams and reams of notebooks
in AP600 that were submitted and we went through that
process significantly. I attempted to do that and put
all the components in each particular phase that were
all active. In many cases, I painfully found out that
many of them were just simply not important.
There was questions like, for example,
momentum distribution effects once the ADS system went
off and we pretty much found that maybe other than the
surge line which leads up to the ADS 1, 2, 3, it's
pretty much their pressure distribution around the
system. It's not very significant while the system is
in critical flow.
Okay?
MEMBER LEITCH: There's a statement in the
executive summary of the blue book here that puzzles
me a little bit. Basically it says that starting with
the AP600 and then demonstrating through scaling that
the -- I'm sorry, starting with the AP1000 and then
demonstrating through scaling that the AP600 program
applies to the AP1000 and therefore that the AP600
analysis codes are applicable to the AP1000.
It seems to me that you're saying through
scaling the test programs are comparable or can be
scaled?
MR. BROWN: Yes.
MEMBER LEITCH: And then you say and
therefore the analysis codes can be scaled. That's
not intuitive obvious to me.
MR. BROWN: I guess we need to restate to
what was probably intended is that if we have a set of
scaled facilities and through scaling we determine
that they cover the most important phenomena that we
expect to see in the full-scale test and we have
demonstrated though scaling that these test facilities
are applicable to the
full-scale plant and therefore we say now if the codes
which in AP600 they were, the codes were then
validated to that database, and if the scaling still
exists between the test facilities to AP1000
therefore, we should be able to use those same
validated codes because now we're validating to the
same data base and we're saying as long as it's still
applicable and that's the key, if through scaling it's
still applicable, therefore the codes are also now
validated for an AP1000.
So you're basically saying if my codes can
predict the test facility and the test facility is
sufficiently scaled to the plant, I can use them to
predict the plant performance. That's the philosophy.
That's what was done in AP600 and we're taking the
same philosophy here.
MEMBER LEITCH: Okay.
(Slide change.)
MR. BROWN: So the major results that came
up here, similar to AP600, we were able to find at
least one integral effects test facility for each
phase of a small break LOCA transient which was able
to address the important phenomena to AP600 to that it
was suitable for code validation and we found
specifically that, for example, the SPES facility was
acceptable through the high pressure phase of a
transient, but it became distorted after the ADS 4
which is our biggest flow path would open up and goes
to subsonic.
But on the other hand, we were able to
cover that because we've got OSU which is good at the
low pressure phases.
MEMBER KRESS: When you say distorted, the
time rate of change of things are different.
MR. BROWN: Yes, like for example, you do
get a -- because of the vent area relative to the
volume, for example, you can get a distortion with
that.
MEMBER KRESS: But you go through the same
set of phenomena.
MR. BROWN: Yes, you do.
MEMBER KRESS: So you don't distort the
phenomena.
MR. BROWN: Yes.
MEMBER KRESS: You just distort the --
MR. BROWN: The timing.
MEMBER KRESS: The way timing goes.
MR. BROWN: Yes. And I think that's
sometimes a bit of an issue with the consultants at
times with the scaling and I would say that really if
you want to go back and take out time in here, we're
very well scaled. I mean even better. But when you
actually factor in the timing in here which I've done
as well, you can find that maybe some of the
facilities are better scaled with actually preserving
the time in which you would --
MEMBER WALLIS: This would really muddle
the phenomenon, the timing wouldn't be important.
MEMBER KRESS: That's right. That's what
you're saying. You know the timing is going to be
different anyway for the scaled test.
MR. BROWN: It's hard to preserve.
MEMBER KRESS: You can't preserve the
whole thing.
MR. BROWN: Right. It certainly helps if
you can get the timing as well. That's certainly a
bonus if you can do that, yes.
That's really the only difference. I
think that's the best way to think about this plant
really. You're really boiling down to things like
volume and area and power and you're talking about
timing. I mean really we're not talking about any
different phenomenon. That's why our position on the
codes are, we have the same phenomena. Our experts
tell us we have the same phenomena. We have it
covered in the tests and we're really talking about
the rate at which it happens. That's it.
And if we can't model volumes and areas
and powers, I think we probably better quick. It
should be --
MEMBER KRESS: You have to get to the
momentum equation.
(Laughter.)
(Slide change.)
MR. BROWN: We found also over our
Separate Effects Test also again covered our ranges
and we've got the same phenomena, so we think that
those are applicable.
With regard to some pass of the
containment cooling system, with regard to this
pressure transient issue which you just mentioned, Dr.
Kress, we still found we have our large scale test
facility for containment is very good for evaluating
heat and mass transfer correlations, but because of
the power to volume distortion, if you will, the
timing of the pressure transient is not perfectly
preserved to an AP600, so it's not a good
representation of a pressure transient, but it
certainly has the appropriate phenomenon to use for
heat and mass transfer correlations.
MEMBER KRESS: When you get a condensation
on the walls of something like that, actually the rate
of condensation gets to be important in terms of the
effect of noncondensibles. I was -- my question on
that is were your separate effects test able to cover
the same rate of condensation that you expect to get
here, rate per unit area isi what I am interested in.
MR. BROWN: Yes. We have the -- if you
want to look at heat flux, we looked at things like
the Reynolds number of the film, that type of thing.
Yes, we're still -- in the AP600, we did a very good
job, I think, of being able to cover the range because
were trying to anticipate a very wide variation in
these things. So there is a very significant range
that's covered in those tests. Very large range. And
it's in some of the tables in that report if you look
back in the containment section you'll see the large
range that was in there. I didn't think we had enough
time to go through that here.
We also had done some CFD analysis which
was very simple. It was a 2-D slab. We weren't
trying to claim that this was -- you're shaking your
head already.
MEMBER WALLIS: Unacceptable.
MR. BROWN: What we were trying to address
here was the height to diameter effect. I mean
because one of the questions I think that we asked
ourselves right away was well, mixing and
stratification was of interest in AP600. This is a
very big plant. And we were increasing it by 25 more
feet and we wanted to ask ourselves well, given
whatever AP600 is, how do we compare to this? So we
used this as a tool.
When we presented this to the Thermal
Hydraulic Subcommittee, Dr. Wallis asked us if we
could just simply rotate this in 3-D and see whether
or not we could look at the three dimensional effects
as well. I see he's still shaking his head.
MEMBER WALLIS: It's a different problem.
I mean drawing of a plank is different from drawing a
log. Cylindrical geometry is not a plane. It's
different.
MR. BROWN: I agree. The attempt was to
try to look at what the --
MEMBER WALLIS: I think the attempt was
good. Now you have to -- right.
MR. BROWN: That's a start.
MEMBER KRESS: If you're just validating
that your containment is well mixed, I think the
ability to well mix 2-D is harder than to well mix the
3-D and if you can do it with the 2-D, you ought to be
able to do it with the 3-D.
What do you think, Graham?
MEMBER WALLIS: I don't know. Maybe
you're more easily convinced than I am.
MEMBER KRESS: I say that because --
MEMBER SHACK: It's only a 2-D problem.
It's just an axis symmetric 2-D problem not a plane 2-
D problem.
MEMBER WALLIS: So just use
polycoordinates and solve the equations. It's simple.
MR. BROWN: All right. We can scale it.
MEMBER WALLIS: I don't know, what fluent
does is simply says are you using polycoordinates or
Cartesian. You say one or the other and it solves it.
You just have to make that decision, that's all.
MR. BROWN: There's a lot of mesh
generation, a lot of babysitting.
MEMBER WALLIS: Well, most CFD codes just
generate the mesh for you. You should do it.
MEMBER KRESS: You should do it just to
satisfy the naysayers. It's good for your soul.
MR. BROWN: Okay. Comment received.
MEMBER WALLIS: Hit me with the bottom
line. Is it well mixed or just stratified?
(Laughter.)
MR. BROWN: Well, what we found, what we
saw in the 2-D was we really saw virtually no
difference. It was very well mixed. In fact, it was
probably better mixed. It was almost -- when you got
to the near last several inches of the boundary there,
you couldn't see any gradient whatsoever. It was very
well mixed.
MEMBER KRESS: As I casually mentioned in
the subcommittee meeting, you're better off if it's
not --
MR. BROWN: Say it a little louder.
Right, that was good.
(Laughter.)
We're really trying to say is if we allow
the steam to even allow it to stratify, it's even
better because we have this nice Raley-Bernard
convection problem with this very cold surface on top
of a hot surface, which you would expect would mix
pretty well.
(Slide change.)
MR. BROWN: In conclusion then, we found
that -- we think that the phenomena looks similar to
AP1000. We think we have the test, both separate
effects and we can find at least one integral effects
test to cover each phase of the AP1000 small break
LOCA transient and therefore our analysis codes can be
validated here and therefore are applicable to AP1000
and so therefore we should have a sufficient database
for code validation in accordance with the
requirements of 10 CFR Part 52.
MEMBER WALLIS: Now that may be a
reasonable conclusion. It doesn't mean to say that
you'll reach the same conclusions about AP1000 that
you did about AP600 when you actually run the codes
because it may turn out that these small changes in
geometry and the mass, be more mass here than there
and so on, actually have fairly significant effect on
something that matters when you go from 600 to 1000.
MR. BROWN: I agree with you. And all
we're saying is we can use the same tool to predict
that, that's all we're trying to get across here. We
agree that the answers could look a bit different and
I would be a little worried if they didn't probably if
they looked exactly -- we really expect that we're
saying is we have the same similar phenomenon so
therefore we can use the same tool.
MEMBER WALLIS: When we look at those
answers and we look at sensitivities, it may be that
you have to get something righter than 1000, let's say
like entrainment from the vessel or something. You
have to model something better with 1000 or maybe
less, less well.
MR. BROWN: We need the approved Dr.
Graham Wallis correlation first to do that because
what else is out there isn't --
MEMBER WALLIS: I haven't had correlations
for some time.
MR. BROWN: We need another one.
(Laughter.)
MR. BROWN: What's out there right now.
Any other questions?
DR. ROSEN: The stage 4 operation of the
ADS, how does one test that during normal operation of
the plant?
MR. BROWN: Terry could probably address
that, Terry Schulz.
MR. SCHULZ: This is Terry Schulz from
Westinghouse. The stage 4 valves are squib valves.
So they're not cycled in the plant. The ASME code
addresses squib valves in terms of in-service testing
and what they allow you to do is to remove
periodically and this is on like a 5 to 8 year basis
the propellant that would actually operate the valve
and that's the main question about the operability of
the valve because everything else is pretty passive
and simple in terms of the operation.
And you remove that after it's been in
service and you go into a test fixture and actually
fire it in a test fixture and determine if it would
have operated. And by doing this you can then and
also in terms of the quality and QHX on the
propellants that you trace through the life from when
you first made the propellants until you've checked
it, that's what you would do.
You would also do some inspections to make
sure the pipes are not plugged up or something like
that, but the geometry is very simple in the stage
four. It's not very complicated at all, very short
pipes, big pipes. The main thing is whether the valve
would operate or not and that's addressed in ASME
code.
DR. ROSEN: What size valves are those?
MR. SCHULZ: In AP600, they're 10-inch.
On the AP1000, they're 14-inch.
DR. UHRIG: Terry, on the squib valves, do
you do continuity testing on the circuitry from time
to time?
MR. SCHULZ: I know we discussed that on
AP600 and I'm trying to remember what we concluded.
I think we concluded that we would at least
periodically do that, like when we change the
propellant. We would not do it continuously. I don't
know if there's anything else we committed to do.
DR. UHRIG: I'm just wondering because you
say 5 to 8 years. I'm wondering just like every year
or something, you might test the conduit of the
circuit to make sure that's --
MR. SCHULZ: I'm not 100 percent sure of
what we committed to there.
DR. UHRIG: Thank you.
MR. BROWN: Any other questions? Okay.
Thank you.
(Slide change.)
MR. GRESHAM: Good afternoon. My name is
Jim Gresham. I'm with Westinghouse and I have just a
few slides here to give you an overview of the
approach on codes and analysis for AP1000.
(Slide change.)
MR. GRESHAM: As has been mentioned at
least twice already today, probably more, we're
starting with the computer codes that were used for
AP600 and approved for that application and just
assessing the differences in the plant and design test
and so forth. So from that starting point we're
confirming the adequacy of these codes for the AP1000
design and I have another slide that talks about the
steps in that.
Any potential concerns that there are in
that review we'll have to address and as well as that
in the AP600 review and in the AP600 FSER, there were
some concerns with the codes mentioned. We are
addressing all of those.
MEMBER WALLIS: I wonder how you can do
this ahead of time. It seems to me that you have to
actually exercise the code for AP1000 and see what
kind of things you're getting from it and if you find
something which concerns you, which didn't concern you
with AP600 then you're going to have to say it's not
quite the same. I don't think you have a carte
blanche that says because it worked for 600, it must
work for every aspect of 1000.
MR. GRESHAM: I would agree with that.
Some of the items that were mentioned on AP600 I think
we have to deal with up front. But you're right in
that as you look at the analysis results you'll see
things and you need to understand why.
MEMBER WALLIS: So I don't know that we
can -- you can reach consensus on this as a starting
point. I don't think we can reach consensus early on
about acceptability until we see how it works.
MR. GRESHAM: Yes, I agree with that
statement.
MEMBER WALLIS: Thank you.
(Slide change.)
MR. GRESHAM: The steps that we used or
are using to confirm the adequacy of the codes is
first to look at the important phenomenon that exists
in the plant and this has been done through the PIRT
in the scaling report which Bill already discussed
with you.
We need to identify the correlations and
the models that are used in each of the codes to
analyze the important phenomena in the design and
since we're starting with the AP600 approved codes and
have confirmed the phenomena are the same, that's
already been done in the AP600 design certification
process. We're relying a lot on that information.
Then demonstrate that the test data are
adequate and for validation of the codes and that has
been demonstrated in the scaling in the PIRT work and
then as I mentioned we have to demonstrate that the
limitations that have already been identified are
being adequately addressed.
MEMBER WALLIS: And to reiterate, there
may be some other limitations that emerge when you
start working on AP1000. We don't know if there will
be, but there might be.
MR. GRESHAM: Yes, there might be and --
MEMBER WALLIS: Just the fact that you
have addressed the AP600 ones doesn't mean that you've
found all the ones that might apply to 1000.
MR. GRESHAM: Yes. We have some
confidence as we proceed through here because nothing
is identified in the PIRT or the scaling work, but
certainly all the way through here, we need to be on
the look out for that.
(Slide change.)
MR. GRESHAM: There are several ways that
we may choose to address these limitations. And these
include, there may be one or more of any of these, but
it's possible to change the design. Terry talked
about some of the changes in the design that has led
to actually more margin in some cases.
We may find the phenomena that we feel
like we need to do some additional validation to test
to understand the effects better and then complete the
story relative to the codes.
Just by evaluating that there's a lot of
margin in some area may be, may go toward addressing
limitation in the code.
We will do in some cases additional
analyses such as the CFD calculations that we already
discussed to address a limitation for a code or in
some portion of the code, either a portion of the
transient where different phenomena are occurring or
a particular model that the code has to be able to
show that we have some concerns about. And use this
analysis not as the safety analysis in the SSAR, but
as additional information to show the effects that
will occur in the plant that are predicted to occur in
the plant. And there may be some cases, we have not
found any yet, but there may be some cases where we
believe that we need to make changes to the codes.
MEMBER WALLIS: Well, there's carryover
into the AS fall line, carryover -- do you have a
bigger radius for it, do you have higher velocities,
maybe? I don't know what you have.
MR. GRESHAM: It isi larger. The ADS is
10 to 14 inch.
MEMBER WALLIS: How well do you model that
actual entrainment to the Aegis fall out?
MR. GRESHAM: Yes. I'm not sure about the
velocities.
MEMBER KRESS: I was about to say it's
still sonic velocity.
MEMBER WALLIS: No, no, it's actually at
the hot leg.
MEMBER KRESS: It's about the same
temperature.
MEMBER WALLIS: It's about the same?
MR. SCHULZ: This is Terry Schulz from
Westinghouse. The connection to the hot leg is
actually an increase from like 12 inches to 18 inches,
so it's gone up more than the power has gone up.
MEMBER WALLIS: So you've got more than
the hot leg.
MEMBER KRESS: You get more flow.
MR. SCHULZ: No, the hot leg is 31 inches
in diameter.
MEMBER WALLIS: It's a different diameter
ratio of hot leg to ADS fall line?
MR. SCHULZ: Yes.
MEMBER WALLIS: So you might have to do
something about modeling that. It is different
geometry than the fall.
MR. SCHULZ: Yes.
(Slide change.)
MR. GRESHAM: We are working on a report
to give to the staff, the Code Applicability Report
where we will discuss the important phenomena,
referencing back to the work that was done on the PIRT
in the scaling, to provide a description of the codes
that we're using to analyze the different accidents
for AP1000 and look at the code applicability of the
AP600 codes for application to AP1000 and much of the
information is in the FSER and some of the documents
that we provided in support of that and the
limitations that were identified are also discussed in
the FSER and we will go through each of these and
describe how we believe that we're addressing those.
MEMBER WALLIS: Now you said you'd supply
a code description. The staff has been actually
asking for the code itself from other applicants and
has been getting it and that's something that this
committee is much in favor of, actually having the
code itself examined and run by the staff. That gives
assurance that it's user independent. You get the
same answer and you can investigate things.
Everything is in the open. It would be very desirable
if that could happen here.
MR. GRESHAM: Well, we're asking the staff
to look at the code applicability report when they get
it and discuss --
MEMBER WALLIS: It's all based on
submissions by Westinghouse.
MR. GRESHAM: Sure.
MEMBER SIEBER: When you're all through
with the phenomenon logical modeling that you're doing
here, you have the capability to determine the
uncertainty in these phenomenon logical codes?
MR. GRESHAM: Not entirely, no. In the --
we're using the best estimate, large break LOCA
methodology using the COBRA track code for the large
break and the quantification in the convolution of
uncertainties is certainly involved in that.
In most of the other safety analyses,
we're using a bounding approach where we're
demonstrating that we have a conservative calculation
of the consequences of the different accidents and so
we're covering the uncertainties in that regard, but
in terms of quantifying the uncertainties, we won't
have that.
MEMBER SIEBER: So you really won't know
how much margin you have either.
MR. GRESHAM: Just lots.
MEMBER SIEBER: I'm not sure that makes --
lots and great are about the same kind of term.
(Laughter.)
MR. GRESHAM: Yes.
MEMBER SIEBER: So the answer is probably
won't have very much way to quantify margin and
uncertainty when you're --
MR. GRESHAM: That's right. We won't have
a quantification.
MEMBER WALLIS: So on the issue of
supplying the code to the staff, is that something
which is still under negotiation?
MR. GRESHAM: Yes, it is.
MEMBER WALLIS: Have you folks seen the
light yet?
MR. GRESHAM: It's still under
negotiation.
Any other questions?
DR. ROSEN: The ADS, as I understood it,
the stage 4 is different in AP1000?
MR. GRESHAM: Yes, it is.
DR. ROSEN: It's not in AP600?
MR. GRESHAM: No, it is in AP600, but it's
larger in the -- I'm sorry, larger in the AP1000.
Stages 1, 2 and 3 are the same size, but stage 4 is
larger in AP1000.
DR. ROSEN: Does the AP1000 have a
different estimated core damage frequency than the
AP600?
MR. GRESHAM: I don't believe we've
calculated that yet. We have not done the PRA.
MR. SCHULZ: This is Terry Schulz from
Westinghouse. Jim is right. We have not calculated
that number, but the design approach that we are
taking relative to PRA is to size the components and
arrange the systems in terms of the same arrangements,
same number of valves, same type of valves, so that
the reliability of the system would be expected to be
the same.
We're trying to from a preliminary design
point of view, have the same success criterion in
terms of the number of ADS valves, number of
components required, so we've actually done some
preliminary T & H analysis with multiple failures to
try to check our success criteria. And that's not
been done formally and that's not going to be part of
this Phase 2 staff review of AP1000, but our design
approach is to try to end up with the same core melt
frequency by using the same configuration, same type
of components and same success criteria.
DR. ROSEN: Of course, the ADS valves are
larger for AP1000 than they are for AP600 so their
reliability might be different.
MR. SCHULZ: That's usually not a strong
factor in the quantified reliabilities of components
within some limitations, of course.
MEMBER WALLIS: Can we move on?
MR. GRESHAM: Okay.
MEMBER WALLIS: We're a little bit behind,
Mr. Chairman, but I think we have a little elasticity
in the schedule that's coming up.
VICE CHAIRMAN BONACA: Yes, we do.
(Slide change.)
MR. ORR: My name is Richard Orr and at
Westinghouse I'm responsible for the design of the
structures and the seismic analyses and I'll cover
very briefly some of the evaluation of the structural
changes and then get into the discussion of the
approach to design certification.
(Slide change.)
MR. ORR: As Mike and Terry have
described, we have attempted to keep the configuration
as close as possible for AP1000 to AP600. The
configuration was described in a report submitted to
NRC at the end of last year. From a structural point
of view, the main differences are the height of
containment and associated with that, the height of
the shield building, so going from AP600 to AP1000,
everything above this elevation moves up 25 feet.
In plan view, everything looks the same so
the major change, as I say, is just this increase in
elevation.
We have evaluated these differences and
concluded that we can accommodate them in the
structural design.
MEMBER POWERS: Not everything is the
same, down below there, though, is it? Aren't the
steam generators --
MR. ORR: As far as structure is
concerned, it is identical. The steam generators are
bigger.
MEMBER POWERS: But that's not identical.
MR. ORR: Let me get directly to my next
slide.
(Slide change.)
MR. ORR: In our evaluation of the
changes, we have conducted a seismic analysis of the
nuclear island and used methodology identical to
AP600, adjusted the models for the changes for AP1000
and this includes raising the shield building 25 feet,
increasing the shield building roof, the PCS tank from
540,000 to 800,000 gallons. We include in the
analysis the containment vessel which is a little bit
taller and an increased thickness. We include the
structures inside containment.
The only changes in the structures there
are the shield walls around the steam generator and
pressurizer have been extended upwards a little bit
for shielding. And we include in the analysis the
reactor coolant loop which has been modified to
include the bigger steam generators and the bigger
pumps.
All of these items are included in this
single model and I'm showing here some typical
results. There's a lot more results. All I want to
do is highlight three of them here that I've marked.
MEMBER WALLIS: Excuse me. North,
southeast, west has something to do with steam
generators.
MR. ORR: No. North, southeast, west is
strictly an orientation we've established for the plan
view of the AP600. North is towards the turbine
building.
MEMBER WALLIS: So the difference is that
the steam generators are on one side or something?
What's different about it?
MR. ORR: About?
MEMBER WALLIS: The two axes, what's -- it
looks sort of -- it's a symmetrical building, isn't
it?
MR. ORR: No, the footprint, the shield
building and the containment sit on a base mat and are
integral with the auxiliary building.
MEMBER WALLIS: Okay, that's what makes
the difference.
MR. ORR: The long access is the
north-south axis. The short access is the east-west
axis.
If we look first of all at the seismic
response at the highest elevation at the top of the
shield building, the acceleration and this is for a
three-tenths g input on a hard rock site, the
acceleration response increases from 1.47g to 1.54, an
increase of about 5 percent. And this is really the
one that controls the design of the shield building
roof and the 800,000 gallons of water. We have,
indeed, done preliminary design of the shield building
roof and demonstrated that yeah, we can add some
sufficient reinforcement. There's no problem.
Next one I want to show is what we term
base shear. This is sort of the shear force at grade
elevation that is very significant in the design of
the shear walls, the shield building and the walls in
the auxiliary building. Here, the shear in the north-
south direction which is the one that increases the
most, increases from 37.5 to 46.8 which I think is 20
percent if I recall, 25 percent, sorry.
And the other one I want to point out is
the overturning moment, again, at grade elevation and
for about the north-south axis which is the shorter of
the axes, it increases from 4100 to 5500 which is a 33
percent increase.
We have looked at the effect of this on
design of the structure. We find no problems in sort
of the design of AP1000.
I should just point out one of these
numbers is higher. About the east-west axis, I
haven't identified that as a problem. This is the
long axis of the building and it's much easier to
accommodate in the design.
MEMBER SIEBER: None of this includes the
effect of soil liquification?
MR. ORR: These are all for hard rock.
MEMBER SIEBER: Hard rock.
MR. ORR: We have a site interface
established that says there shall be no soil
liquefaction. That is something the combined license
has to demonstrate for his site.
MEMBER SIEBER: So that means if you build
a plant like this, you put it on franky piles or
something like that to get the hard rock support?
MR. ORR: Not necessarily.
MEMBER SIEBER: That would be a way.
MR. ORR: A hard rock site is acceptable.
Something like 50 percent of the existing nuclear
plants are on rock.
MEMBER SIEBER: Yeah.
MR. ORR: A good soil site, there would be
no problem. There are one or two soil sites that
would sort of require fairly extensive foundation
work, but then they did for the existing units that
are there already.
MEMBER SIEBER: I was thinking that a lot
of the sites may be half or built on river banks which
is usually silt.
MR. ORR: Yes.
MEMBER SIEBER: Which is pretty liquid.
MR. ORR: The interface we established on
AP600 and would be applicable here as well, is a shear
way velocity for the soil greater than the thousand
feet per second.
That excludes one or two of those real
soft sites. It basically means you've got to dig it
all out and replace it by competent material. Certain
existing sites have had to do that.
MEMBER SIEBER: Right. Is there a
difference between East Coast and West Coast where a
plant like this might be precluded --
MR. ORR: We have established the seismic
input design level at three-tenths g which does
exclude California for the standard design.
MEMBER SIEBER: Okay, thank you.
MEMBER KRESS: What moment can the
containment stand before it buckles? Have you
determined that?
MR. ORR: The critical condition for the
containment is not internal pressure. It's the
combination of external pressure and safe shutdown
earthquake. External pressure is a situation where
you basically trip the reactor on an extremely cold
day and pull the temperature of containment down
fairly rapidly and for AP600 that is something like
negative pressure of 2.5 psi.
We designed for an external pressure of 3
psi and then we combined that with the safe shutdown
earthquake and we were able to demonstrate for AP600
adequate margin. The critical location is at the base
of containment. I think, if anything, we'll have a
slightly greater margin because we've increased the
shell thickness two inch and three quarter versus inch
and five-eighths. So it's an evaluation that still
needs to be done and it will be included in the Phase
3 part of NRC's review, but I don't expect it to be an
issue.
DR. ROSEN: What is the diameter of this
containment at the operating floor elevation?
MR. ORR: It's 130 feet. I did check the
configuration. It's very, very similar to the
dimensions of Comanche Peak. Comanche Peak is 135
foot ID. This is 130 and then the shield building is
further out and the total height is almost identical.
MEMBER SIEBER: What's the space between
the containment liner and the inner surface of the
concrete?
MR. ORR: From the inside surface of the
containment vessel to the inside surface of the shield
building is a nominal 4 feet 6 inches. So it's got to
4 feet 4 and a quarter.
MEMBER SIEBER: All right, thank you.
Which is enough for a stairwell, right?
MR. ORR: Oh yes, you can get in there.
In fact, we have designed the air baffle to be removal
for inspection and maintenance purposes.
For AP600, we did extensive seismic
analysis and structural design. Clearly, sort of for
AP1000 we do have some limited resources and there's
some, much higher priority safety analysis being
performed. So we have suggested, proposed to NRC that
we would use design acceptance criteria for the
detailed structural design and seismic analyses at
soil sites. This approach has been used on other
certified designs, not quite to the same extent.
We would be using the same criteria and
methodology and these will be documented in the AP1000
design certification document and we will be
identifying certain other key information,
constructural configuration which we've described
here. We will present results of the seismic analysis
for hard rock and present a design of the containment
vessel in the design certification document.
This approach was described in a report we
submitted to NRC earlier this year. We have had one
meeting with them to discuss it. The detailed design
analysis would be performed by the combined license
applicant, would be presented to the staff at the time
of the combined license application, so it would be
reviewed and accepted by NRC prior to start of
construction.
Once the combined license is issued, then
there would still be on-going construction and there
would still be the same inspection and acceptance
criteria as we have used for AP600.
Thank you. Any questions?
MEMBER WALLIS: Any questions? Any final
words from anyone?
MR. CORLETTI: We have no more words, so
if you have any more questions.
MEMBER WALLIS: I thought you were going
to give us some final words.
MR. CORLETTI: No, not really.
MEMBER WALLIS: A finale. Well, thank
you, Westinghouse very much.
If the committee has no more questions,
I'll hand this back to the chairman.
CHAIRMAN APOSTOLAKIS: Thank you, Graham.
Thank you, gentlemen.
Now we're scheduled to break and work on
preparing draft reports. I'm willing to break, but
I'm not sure we need to prepare any reports. Is
anybody working on a report? I would rather come back
here and read the first draft of what we have and give
some advice to the authors and then move on and
revisit maybe the Commission meeting or do other
things. So why don't we break until 4:50 and then
we'll come back and read this.
(Whereupon, the proceeding went off the
record at 4:35 p.m.)
Page Last Reviewed/Updated Monday, August 15, 2016