Thermal-Hydraulic Phenomena - June 12, 2001
Official Transcript of Proceedings
NUCLEAR REGULATORY COMMISSION
Title: Advisory Committee on Reactor Safeguards
Thermal-Hydraulic Phenomena Subcommittee
Issues Associated with Core Power Uprates
Docket Number: (not applicable)
Location: Rockville, Maryland
Date: Tuesday, June 12, 2001
Work Order No.: NRC-250 Pages 1-244
NEAL R. GROSS AND CO., INC.
Court Reporters and Transcribers
1323 Rhode Island Avenue, N.W.
Washington, D.C. 20005
(202) 234-4433 UNITED STATES OF AMERICA
NUCLEAR REGULATORY COMMISSION
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ADVISORY COMMITTEE ON REACTOR SAFEGUARDS
THERMAL-HYDRAULIC PHENOMENA SUBCOMMITTEE MEETING
ISSUES ASSOCIATED WITH CORE POWER UPRATES
(ACRS)
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TUESDAY
JUNE 12, 2001
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ROCKVILLE, MARYLAND
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The ACRS Thermal Phenomena Subcommittee
met at the Nuclear Regulatory Commission, Two White
Flint North, Room T2B3, 11545 Rockville Pike, at 8:28
a.m., Dr. Graham Wallis, Chairman, presiding.
COMMITTEE MEMBERS PRESENT:
DR. GRAHAM WALLIS, Chairman
DR. AUGUST CRONENBERG, ACRS Senior Fellow
DR. F. PETER FORD, Member
DR. THOMAS S. KRESS, Member
DR. GRAHAM M. LEITCH, Member
DR. VIRGIL SCHROCK, ACRS Consultant
DR. ROBERT E. UHRIG, Member ACRS STAFF PRESENT:
PAUL A. BOEHNERT, ACRS Staff Engineer
JOHN HOPKINS, NRR
RALPH CARUSO, NRR
DONNIE HARRISON, NRR
JACK ROSENTHAL, RES
TONY ULSES, NRR
A-G-E-N-D-A
AGENDA ITEM PAGE
I. Introduction . . . . . . . . . . . . . . . . 4
II. NRC Staff Presentations:
John Hopkins, NRR. . . . . . . . . . . . . . 5
Ralph Caruso, NRR. . . . . . . . . . . . . . 9
Donnie Harrison, NRR . . . . . . . . . . . .66
J. Rosenthal, RCS. . . . . . . . . . . . . 140
III. ACRS Fellow Presentation
Dr. Cronenberg . . . . . . . . . . . . . . 161
IV. G.E. Nuclear Energy Presentation
Introduction . . . . . . . . . . . . . . . 211
P-R-O-C-E-E-D-I-N-G-S
(8:28 a.m.)
CHAIRMAN WALLIS: The meeting will come to
order. This is the meeting of the ACRS Subcommittee
on Thermal-Hydraulic Phenomena. I am Graham Wallis,
Chairman of the Subcommittee.
In attendance are ACRS Members Peter Ford,
Graham Leitch, Robert Uhrig, and Thomas Kress; and the
ACRS Consultant, Virgil Schrock. We miss Novak Suber,
who is usually at these meetings, and we think maybe
he is here in spirit, and at least we will try and
make up for him.
The purpose of this meeting is for the
Subcommittee to discuss potential issues for
consideration by the NRC staff pertaining to its
review of applications for core power uprates.
The Subcommittee will gather information,
analyze relevant issues and facts, and formulate
proposed positions and actions as appropriate for
deliberation by the full Committee.
Paul A. Boehnert is the cognizant ACRS
Staff Engineer for this meeting. A portion of this
meeting will be closed to the public to discuss
General Electric Nuclear Energy proprietary
information. That will be this afternoon.
The rules for participation in today's
meeting have been announced as part of a notice of
this meeting previously published in the Federal
Register on May 30, 2001.
A transcript of this meeting is being
kept, and will be made available as stated in the
Federal Register notice. It is requested that
speakers first identify themselves and speak with
sufficient clarity and volume so that they can be
readily heard.
We have received no written comments or
requests for time to make oral statements from members
of the public. Now, we are going to discuss the power
uprate program and I simply note that these are one of
the events in this year and the near future which is
likely to have a significant effect upon nuclear
generation in this country.
Last week, we heard that the industry
plans to go for something like 10,000 new megawatts of
uprate power. So we are really looking forward to
hearing about this, and I will call upon Mr. John
Hopkins, from the NRC's Office of Nuclear Reactor
Regulation to get us started.
MR. HOPKINS: Thank you, Mr. Chairman. I
am John Hopkins, Senior Project Manager in NRR. With
me at the table are Mark Rubin, Donnie Harrison, and
Ralph Caruso; and we have more staff members seated
obviously.
I appreciate this opportunity to come and
talk to the subcommittee about power uprates. We are
mainly going to focus on extended power uprates today.
Let me briefly again show the main agenda.
As you can see, Ralph Caruso, for Reactor
Systems, will talk about our efforts so far in Duane
Arnold inspection; and Don Harrison will then talk
about PRA risk considerations. Again, mainly focused
on Duane Arnold, but additional.
And Jack Rosenthal, from the Office of Research, will
give a presentation.
We are prepared to answer other questions
that may arise that specific presenters do not cover.
As you mentioned, Mr. Chairman, there are many power
uprates that are going to be coming in.
The staff has reviewed several smaller
uprates, but now the really extended power uprates are
starting to come our way, and Duane Arnold is the
first big one really, a 15 percent.
And as you can see by the review
schedules, all of these reviews are fairly aggressive.
The staff anticipated in a review of our topical
reports that it would probably take us 12 to 18
months to do a power uprate review, and we are trying
to beat that by a few months.
CHAIRMAN WALLIS: And an aggressive review
is one that goes quickly?
MR. HOPKINS: Yes, that's right I meant.
CHAIRMAN WALLIS: Well, it probably should
be aggressive as well.
DR. HOPKINS: Our staff is competent and
I am sure they will be.
CHAIRMAN WALLIS: Thank you.
MR. HOPKINS: Clinton is the last one
mentioned, and that is expected to come in next week
and will be at 20 percent. Additionally, there are
other plants that have expressed interest in extended
power uprates that we expect to come in at the end of
the year, and that have not -- that I have not
bothered to list. Again, Duane Arnold --
DR. LEITCH: These are all boilers, or all
they constant pressure uprates?
MR. HOPKINS: Yes, to my knowledge, these
are all constant pressure uprates.
DR. BOEHNERT: John how many more are you
expecting? Do you have any idea on that?
MR. HOPKINS: I can't recall. Maybe
Mohammed Swaybe could comment on that.
MR. SWAYBE: My name is Mohammed Swaybe.
We are generating -- we have a survey underway right
now, and we will be giving that information to ACRS
hopefully this week.
DR. BOEHNERT: Thank you.
CHAIRMAN WALLIS: Are these all similar
kinds of boilers, or are they different kinds of
boilers?
MR. HOPKINS: They are really different
kinds of boilers. Dresden, Quad Cities, and Duane
Arnold are all fairly similar. But Clinton is
different from them.
DR. UHRIG: That is a later generation?
MR. HOPKINS: It is just the later
generation.
MR. UHRIG: It is a Mark 3 containment.
CHAIRMAN WALLIS: Okay.
MR. HOPKINS: And Clinton is BWR-6 and the
others are I believe BWR-3s, and that's all. If there
are no further questions for me, I would like to start
with Ralph Caruso.
CHAIRMAN WALLIS: What do all those T's
mean up there?
MR. HOPKINS: Target.
CHAIRMAN WALLIS: Oh, target.
DR. SCHROCK: The extended uprate program,
have these same plants had smaller uprates previously,
or these will be the first?
MR. HOPKINS: Duane Arnold, I believe, has
had a smaller uprate previously. I don't believe that
the others, Dresden and Quad, or Clinton, have had
smaller uprates.
MR. CARUSO: Good morning. My name is
Ralph Caruso, and I am the Chief of the BWR Nuclear
Performance Section and Reactor Systems Branch in NRR.
I am talking to you this morning about the audits that
were performed in March of this year regarding the
Duane Arnold power uprate. If I could have the
background slide.
To describe the background here, the Duane
Arnold power uprate was submitted in the fall of last
year. The staff has been performing a review since
then.
The staff review is focused primarily on
determining compliance with the topical report, known
as ELTR2. That is one of the two licensing topical
reports that General Electric has submitted and that
the staff has accepted for use in doing these power
uprates on a generic mission basis.
DR. KRESS: Your title says that this is
an audit result. I am not sure that I know what an
audit is in this sense.
MR. CARUSO: Well, this is an audit
because it was done in conjunction with an ongoing
licensing action, and I will explain a little bit more
as I go along about what the individuals did.
And the idea is that we are trying to
approve a licensing action, and as part of that
approval, we can go to the vendor or to the licensee
site and audit their calculations and their methods,
and their results.
DR. KRESS: Okay.
MR. CARUSO: Rather than relying upon
their submittals, we can actually look at the actual
calculations.
DR. KRESS: Okay. Good. Thank you.
MR. CARUSO: And as I said, this was done
in support of the power uprate, and I think at several
earlier meetings I made a commitment that the staff
would be doing these audits for all of these power
uprates that involve large power increases on the
order of 20 percent.
The audit was performed the week of March
26th by a team of four staff members, and I see three
of them here in the room today, and they are here if
I get into trouble.
CHAIRMAN WALLIS: Ralph, you were auditing
what the vendors do. Is the NRC making independent
calculations?
MR. CARUSO: It would depend on the issue.
We have the ability to do that, but it all depends on
what we find and what we determine is necessary to
complete the review properly.
CHAIRMAN WALLIS: But you have not done
any yet then?
MR. CARUSO: I can't think of any. No, I
don't believe we have done any for this. That's
interesting. I have my staff shaking their head no,
and I have a licensee shaking their head yes.
MR. ULSES: The containment systems branch
is performing an audit.
MR. CARUSO: The containment systems
branch. I don't do the containment portion of it, and
on the reactor system side, we are not doing it. But
I believe the containment people are.a
DR. CRONENBERG: Ralph, is the
documentation on the audit and what your staff finds,
is it part of a particular license application by
Duane Arnold, or will you be documenting it in a
separate report a general audit of calculational
procedures, or is this going to be tied to each
particular plant?
MR. CARUSO: The calculations that are
audited for each licensee will be reported as part of
the SER for that licensee, okay, because the audit is
done to support that application.
We may find issues that have generic
applicability, and we will deal with them
appropriately, but they are properly dealt with for
each licensee as they come up because they are done as
part of that review. The next slide, the audit scope.
This audit considered five issues. The
first was the SAFER/GESTR LOCA methodology, which is
the licensed approved methodology for LOCA at Duane
Arnold. It looked at the implementation of what is
called long term stability operation IV.
BWR stability is an issue that has been
looked at for at least -- well, since BWR's were
developed, but over the past 10 years, a number of
options have been identified for plants to address the
issue of stability, and the detection of stability,
and the suppression of it.
And there are a large number of options,
depending upon the manufacturer of the detection and
suppression equipment that licensees install in their
plants.
Duane Arnold has chosen Option 1-D, which
I believe is the GE Solomon on-line stability
monitoring system; and what we did was that we looked
at how that was implemented for Duane Arnold.
We also looked at the GELX14 correlation,
which is used for GE12 and GE14 fuel, and heat
transfer correlation as part of the design of the
fuel.
We also looked at reactor cordizine
issues, and the methodology and uncertainties used in
the safety limit MCPR establishment, Minimum Critical
Power Ratio.
CHAIRMAN WALLIS: When you looked at these
did it turn out that stability or fuel design were
important issues for operates?
MR. CARUSO: Well, I will give you the
findings for each one of these, and then some of the
issues that came out of them. Actually, these
significant issues. Let's go to the next slide.
For the SAFER code, generally, we found
that the analyses for the rated conditions complied
with the SER, and the codes were appropriately
applied. We looked at the actual calculations, and we
looked at the results, and we looked at the inputs.
DR. KRESS: Are there for the Chapter 15
type design basis accidents?
MR. CARUSO: These are the SAFER/GESTR
LOCA calculations, the licensing basis calculations
for design basis access.
DR. KRESS: Just for the LOCAs?
MR. CARUSO: The LOCAs, SAFER/GESTR;
that's what that is used for. One of the findings was
that there was a question about the use of
uncertainties that are derived from some TRAC
calculations and from full power operations.
These uncertainties were developed for
normal operating conditions, but then they were
applied to analyses of the single loop operation,
which we don't think is necessarily appropriate.
However, when you look at how they applied
them, and the conservative penalty factors that they
apply to single loop operation, we don't think that
this is a significant issue. We will be discussing
this with the licensee and with G.E., but this is not
really a significant issue.
DR. KRESS: How about the LOCA analysis?
They showed that they were still below the limit on
peak clad temperature and oxidation amount?
MR. CARUSO: Yes.
DR. KRESS: But did they approach it very
closely, or did they change --
MR. CARUSO: You mean how close they came?
DR. KRESS: Yes.
MR. ULSES: This is Tony Ulses of the
staff. I can't recall the exact numbers, Dr. Kress,
but I believe there certainly was an increase in the
actual PCT, but I don't know that I would really
attribute that to the actual power uprate itself, as
much maybe to the fuel design change, if anything else
I would say.
But they certainly had a lot of margin to
do the PCTs is my recollection for the Duane Arnold
situation.
DR. KRESS: Yes, the reason that I asked
the question is that if they were already well below
the PCT, and changed 15 or 20 degrees, I am not
worried much about it.
But if they were pretty close to it, and
got even closer, then I might worry about the
reduction of margins beyond something that might be
acceptable.
DR. KRESS: It sounds like it wasn't much
of a change.
MR. ULSES: Yes, sir, that is my
recollection. It wasn't much of a change, and I
believe they still have quite a bit of margin as I
recall.
CHAIRMAN WALLIS: Maybe we can get the
answer from GE this afternoon.
MR. CARUSO: This is realized. This was
not or is not a simple straight power uprate. I mean,
they are changing fuel types as part of this change,
and that will induce its own changes in analysis
results for all sort of different accidents.
DR. KRESS: Plus, we are changing flow,
and are they doing anything to the turbine generator?
MR. CARUSO: I believe they are making
significant changes to the secondary side in order to
be able to use the power that is coming out of the
reactor.
DR. KRESS: So, you know, you get a lot of
things that could affect the whole thing?
MR. CARUSO: That's correct.
DR. SCHROCK: The original licensing of
Duane Arnold was on the old evaluation model prior to
the new rule in '89.
MR. CARUSO: SAFER/GESTR is a -- no,
actually, I believe it is an '83.472 method. It is an
anomaly in Appendix K evaluation model.
DR. SCHROCK: That was my recollection,
but what is the significance --
MR. CARUSO: It is a little bit more
complex than that.
DR. SCHROCK: -- of your second bullet
here; uncertainties derived from TRAC? That conjures
up the new rule in which you have to evaluate the
uncertainties.
MR. CARUSO: Tony, can you explain the
details of that?
MR. ULSES: The best way to describe the
SAFER/GESTR model is that it is sort of a hybrid I
would say, Dr. Schrock. Really, what it is, and just
like Ralph said, is that they are conforming with
Appendix K, but that they are trying to demonstrate a
little more realistically what the actual margins are
in the LOCA calculation by trying to use the code more
realistically.
And when we were working on the review and
approval of the code, one of the ways that they
attempted to try and demonstrate the accuracy of the
method was to compare to some TRAC calculations, but
that certainly was not the only thing that they did.
But they also did the calculations to the
available experimental data, and what really came out
of the TRAC SAFER/GESTR calculations was really
basically the uncertainty term which they are adding
on to the SAFER/GESTR methods as a penalty if you
will.
So I guess I would say that the reliance
on TRAC and the SAFER/GESTR method is actually
reasonably minimal. But I certainly see where you are
coming from. This is not a best estimate LOCA
methodology by any means.
DR. SCHROCK: Well, that is what I am
getting at, is what is it and where are we in terms of
the -- well, I get a little confused on these
acronyms, and SAFER/GESTR gets muddled up in my memory
with GESTAR. Was it that GESTAR came later?
MR. CARUSO: It is all muddled up together
with GESTAR.
DR. SCHROCK: It is, yes. And I remember
that we had an extensive review of the GE methodology,
which was approved in the '80s, late '80s sometime.
I don't remember the date exactly.
But it would be helpful to me to
understand what it is that they are doing now, brand
new core configuration, and how is this new license
going to be qualified against an old Appendix K
approach, and against a new approach, which is the one
that was reviewed by the ACRS some 12 or 13 years ago.
What is it?
MR. CARUSO: This is the approved
methodology as it was reviewed and discussed with the
ACRS back in the '80s, subject to modifications that
have been made over the years to correct errors, and
to make changes as is allowed under 50-46 and Appendix
K.
So it is the approved model, and that
model --
DR. SCHROCK: The model that G.E.
developed was in response as I remember it to a SCS
paper which allowed the first step in applying the
best estimate methodology in licensing.
And it was before the rule change, but it
essentially attempted do something like the -- I am
having trouble coming up yet with another acronym.
In any case, a best estimate application,
as opposed to the old Appendix K. Now what I am
hearing is that, no, this is an Appendix K approach.
MR. CARUSO: No, I think Tony explained
that I think the topical report that you are referring
to, or the Commission paper that you were referring to
was SCS 83.472. That was the Commission paper that
allowed this to be done, and SAFER/GESTR is an 83.472
method.
DR. SCHROCK: And wasn't Arnold licensed
before that took place? When was Arnold originally
licensed?
MR. HOPKINS: I'm sure it was in the
'70s.
MR. CARUSO: That's correct, and it was
licensed before those methods, but it has since
started using the SAFER/GESTR methodology.
DR. SCHROCK: So the new license will be
on the new basis then?
MR. CARUSO: Yes.
DR. SCHROCK: Okay. Thank you.
MR. ULSES: Well, actually, they are
currently licensed for SAFER/GESTR, Dr. Schrock. They
would have come in with a plan specific licensing
topical report, and I would say sometime in the '90s
probably to actually make the change fro the old
evaluation into the SAFER/GESTR method.
MR. CARUSO: We don't know offhand when
they made the change. I don't know if there is anyone
from Duane Arnold who knows that. If someone there --
MR. BROWNING: My name is Tony Browning,
and I am from Duane Arnold. Yes, we converted to the
SAFER/GESTR LOCA methodology in 1986.
MR. CARUSO: Okay.
DR. LEITCH: The term rated conditions as
used on this viewgraph, is that -- are you referring
to the present license level or to the uprated
conditions?
MR. CARUSO: The uprated conditions. When
I say uprated, that means not the nominal full-power
rated conditions. With single-loop operation, you
generally can generate full-power on a single-loop
operation.
DR. LEITCH: These comments all refer to
the uprated conditions?
MR. CARUSO: Yes. These were audits of
the calculations that are used to support the power
uprate.
CHAIRMAN WALLIS: And what is a single
loop operation with a BWR?
MR. CARUSO: BWRs have two recirculation
loops and it is possible --
CHAIRMAN WALLIS: You mean the pumps?
MR. CARUSO: One of the recirculation
pumps will stop.
CHAIRMAN WALLIS: Okay. So it is not
really a loop. It is part of the one loop?
MR. CARUSO: No, there are two loops, each
has a --
CHAIRMAN WALLIS: Oh, they are actually
separate?
MR. HOPKINS: Yes.
MR. CARUSO: Yes.
CHAIRMAN WALLIS: Okay. There is some
baffles or something that separates the loops?
MR. CARUSO: No, they have --
MR. HOPKINS: The loop really does not
isolate. It is just two loops and one pump goes off.
DR. KRESS: And two pumps.
CHAIRMAN WALLIS: The pumps pump through
both loops don't they?
MR. CARUSO: No, one pump in each loop.
CHAIRMAN WALLIS: They are separate,
absolutely separate??
MR. CARUSO: Yes.
CHAIRMAN WALLIS: I'm sorry. But it is
the same circuit? The loop is external, and it is the
external look that you are talking about, and insider
the reactor vessel, there is just one loop, right?
MR. CARUSO: That's correct.
CHAIRMAN WALLIS: So it is different from
the usual idea of a loop in a BWR situation. Well, I
don't know if we want to go on with this, but
SAFER/GESTR has very different models for things like
slip velocity, and so on than TRAC does, and I am not
quite sure how you use one code to estimate
uncertainties than another.
MR. CARUSO: Tony, do you have any
information about the details?
MR. ULSES: Well, what they were really
trying to do if I recall was that they were trying to
sort of bridge the gap between the experimental
evidence, and down to the SAFER/GESTR methodology.
That is my recollection of what they were trying to
do. It has been a while since we actually looked at
the methodology.
But the method is certainly not
exclusively based on the TRAC-SAFER/GESTR comparisons.
It is one, I believe, of eight uncertainty terms that
they add into the results from SAFER/GESTR.
CHAIRMAN WALLIS: I guess what I am
getting at is the rationale for taking the code of a
different structure and using it to estimate
uncertainties in some other code. I am not quite sure
how you justify that with some kind of logical thread
of thought.
MR. ULSES: Well, unfortunately, it is
difficult for me to discuss what they did in 1986, or
actually '83, because I wasn't here, but based on what
I have read in the record, it is basically sort of --
it is not really discussed, the actual rationale.
The assumption really that I made is that
they are trying to sort of bridge like I said between
the experimental evidence down to the SAFER/GESTR
methodology.
CHAIRMAN WALLIS: So they are bridging the
gap with no rationale?
MR. ULSES: Well, I think the argument
would have been that the TRAC method would have been
more accurate, and it would have been based on more
fundamental principles. But that is a little bit of
speculation on my part.
CHAIRMAN WALLIS: Thank you.
MR. CARUSO: The next item that I am going
to talk about is stability, and the auditor, the staff
member who did the audit, looked at the implementation
of Option 1-D to Duane Arnold.
And generally he found that it was still
applicable and still acceptable for use of Duane
Arnold.
DR. UHRIG: Could you describe what you
mean by Option 1-D? What is involved?
MR. CARUSO: Well, once again I am going
to call on my staff because there are a lot of
differences between the different options. Tony, do
you --
MR. ULSES: Yes, sir. The fundamental
principle behind Option 1-D is that you make the
assumption that the reactor will not have an out-of-
phase instability due to the small reactor size. In
other words, it is going to remain tightly coupled.
And so all they do really is they apply an
administratively controlled exclusion region, which
basically tells the operator that you cannot operate
here.
And then they use an on-line monitor, in
which we are referring to in the second bullet, which
is basically a backup, which will tell the operator if
they had an indication of the onset of an instability.
And that is basically the option in a nutshell.
DR. KRESS: And that is a core wide
monitor, and it is not a local monitor?
MR. ULSES: Well, actually what it does is
that it will tell them whether -- it is actually going
to give them an indication of an out-of-phase or an
in-phase instability.
DR. KRESS: But they could see an out-of-
phase instability?
DR. UHRIG: They could see an out-of-phase
instability from something. Actually, what they are
doing is they are actually doing a calculation. It is
not actually looking at the LPM signals themselves.
What is doing is they are taking those as
an input, and it is using the Odyssey code, which they
use for calculating the K ratios to actually make a
prediction of what it would be.
So it is not actually looking at the
signals themselves, which is usually an input into an
algorithm.
DR. KRESS: Does it call for a SCRAM?
MR. ULSES: No, it does not. It does not.
But they rely on the operator to take action in this
particular scenario.
DR. UHRIG: And the fact that this is a
smaller core compared to, let's say, LaSalle, where
there was as I recall a stability incident a few years
ago, is a favorable indication here that there is less
likelihood of an instability?
MR. ULSES: Well, what it tells us is that
there is less likelihood of an out-of-phase
instability, yes, sir, due to the core size.
Actually, in 1988, the LaSalle incident was actually
a core-wide instability.
We had an out-of-phase instability in 1992
in WMB2 as I recall, which again is a larger size
reactor, but if you look at all of the evidence that
we have up to this point, all the evidence will tend
to suggest that the reactor size is a large
contributor to whether or not you have an out-of-phase
instability.
DR. UHRIG: What are the inputs to the
stability monitor? Is it pressure?
MR. ULSES: It is going to take reactor
flow and reactor power, are the primary inputs to the
Solomon system.
DR. UHRIG: Is there a core monitoring
system of any sort of this, a new Trans-lex
monitoring?
MR. ULSES: Yes, sir, it uses in-core
PRMs.
DR. UHRIG: Is this a series of detectors
at different levels?
MR. ULSES: Yes, sir, and also radially
in-core.
DR. UHRIG: And what might the total
number be?
MR. ULSES: I can't recall the actual
number. I would say in the order of 50 max, and that
is an estimate. It is going to depend obviously on
reactor size.
DR. KRESS: When you uprate the power and
up the flow also, does it change the instability
region?
MR. CARUSO: Yes.
DR. KRESS: It does that in an absolute
sense, but does it on a relative sense, relative to
percent power and --
MR. CARUSO: Yes, it does, and that was
one of the findings, was that the instability region
would increase relatively for this reactor, and
therefore, the operator, or this finding that I have
got here, the next finding that I have got here, is
that operators will have to rely more on this on-line
stability monitoring system.
DR. KRESS: And do you have to change the
tech specs also?
MR. CARUSO: I don't know. Well --
MR. ULSES: This would not impact the tech
specs at all, Dr. Kress.
MR. CARUSO: But one thing that is
important is that the operators, because they are
going to have to rely on this system more, they need
to be better trained in its use.
They need to believe it more and they push
a button to get the results and the recommendations of
the system, but they have to start believing that,
because they will find that the --
DR. KRESS: Does that mean that they
didn't believe them before?
MR. CARUSO: No, it is a matter of --
well, how can I explain this. The calculations to
determine the power to flow the regions of instability
are done using a lot of very conservative results.
The on-line stability monitor is actually
using the way the plant operates. The operators may
find themselves in an area where the map says you may
be in trouble, and they will push the button.
And they will have the on-line stability
system tell them, no, your decay ratio is much lower
than those design engineers told you it was going to
be, and they may not believe that. And actually what
they might do is that they come to not believe the
Solomon system because it conflicts with the written
down design details.
So we want to make sure that the operators
use this, and that they believe it when it tells them
that there is a problem, and that they believe it, and
that they do something about it.
DR. UHRIG: Now, is Solomon a brand name,
or is it a specific type of --
MR. CARUSO: Yes, it is the G.E. system
that is installed at Duane Arnold.
DR. UHRIG: Is this a common system
throughout many of the BWRs?
MR. CARUSO: I would have to ask G.E. how
many plants have it installed.
MR. ULSES: It would only be used in the
Option 1-D plants, which is a very small percentage of
the fleet. I believe there are only four plants that
actually would qualify for Option 1 to the reactor
size.
DR. UHRIG: So because this is a small
plant, it is a simpler system than is used in the
others?
MR. ULSES: Yes, sir, because they can
demonstrate that they will have a high likelihood for
having a core wide instability, as opposed to an out-
of-phase instability.
DR. UHRIG: There is an indication here
that the operators are going to have to pay more
attention to this. Does this mean an increase in
their load and the things that they have to do?
Do they monitor this every hour, every day?
MR. CARUSO: No.
DR. UHRIG: Or when there is an alarm?
MR. CARUSO: No.
DR. UHRIG: How do they know to go push
the button?
MR. CARUSO: This is not really a matter
of monitoring on a continuous basis because the only
time they have to worry about stability is when they
are in the region where the instabilities might occur.
And this would be during a power increase,
power ascension, or a power descension, when they are
maneuvering the plant. Normally when they are
operating at full power, they will be far away from
these regions. So they won't have that as an issue.
I don't know offhand what the actual text
spec requirement is when you are operating at full
power whether they have to monitor stability to use
this system. Do you know, Tony?
MR. ULSES: Well, I guess I would defer
more to the reactor operators themselves, but I would
say no, because it wouldn't make a lot of sense to be
looking at this system when you are at full power,
because it is not going to give you any information
that you can really use.
But again I would say that I would have to
defer to Duane Arnold for the answer specifically to
what they do.
CHAIRMAN WALLIS: Do you have something?
MR. BROWNING: This is Tony Browning again
for Duane Arnold. Yes, when you are at full power,
there is not requirement to do the monitoring. As
Ralph said, it is primarily used when you are doing
start-ups and shut-downs.
The system will also automatically
initiate if there is a dramatic change in power. For
example, if a pump trip occurs, the system will turn
itself on, and will start performing the calculations
at that time when it sees a Delta-N power or flow of
greater than a certain magnitude.
DR. LEITCH: Let me make sure that I
understand then. What we are saying is that there is
a region of the power flow map where the operators are
trained to be sensitive to issues of stability,
particularly so when they are in single loop; that is,
when they have lost a recirc pump.
And the Solomon system takes no action,
but just confirms to the operator that he is doing the
right thing. And with this core power uprate, this
region of the power flow map, this region of
sensitivity is somewhat larger than it would be at the
current power levels.
MR. CARUSO: That's correct.
DR. LEITCH: Is the Solomon system -- is
there just one of these, or is there any redundancy in
the system?
MR. CARUSO: I believe there is only one.
DR. LEITCH: And what about its
reliability or availability? Do we know anything
about that?
MR. CARUSO: QA --
MR. ULSES: Well, again, I would have to
defer to the Duane Arnold folks, because the system
has been in use for several years, and based on all
the information that I have, it is a fairly reliable
system. Basically, it is there when they need it.
However, for actually any specific
information, I would say I would have to refer to the
Duane Arnold folks, because they have been using it
for several years.
DR. LEITCH: I guess what I am saying is
that we are saying there is an increased dependence on
it, and there is a bigger area of the core power flow
map that may be -- where stability may be a concern.
I am just wondering about the reliability
of the instrumentation if the operator is going to be
dependent on it to make operating decisions more
frequently than in the past.
MR. CARUSO: Realize that the -- that when
we say that the operator is more dependent upon it, we
mean that during these periods, such as during power
increases and power decreases, which is a relatively
small percentage of the time that the plant is
operating, the operators will have to be more
vigilant.
And this is one of those tools that they
use during those time periods to make sure that the
plant is operating safely. It is a relatively small
window of time, and this is a tool to help them.
DR. UHRIG: Is this a safety grade system?
MR. ULSES: I would say no, but again i
would have to defer to the Duane Arnold folks for a
specific answer.
MR. BROWNING: No, it is not, but the
primary mechanism that the operators use for detect
and suppress are their in core neutron monitoring.
Because we are a 1-D plant, we only see the
fundamental mode of oscillation.
They will see it readily on their core
wide detection system, and that is their primary means
of instrumentation that they will use to take operator
action when they believe they have an instability
event.
DR. UHRIG: So if this system failed, the
operator still has the means of --
MR. BROWNING: Right. This is only a
backup.
DR. UHRIG: It is a only a backup and a
convenient system because of being able to push the
button and get information that would otherwise have
to be discerned by the operator's knowledge of the
behavior of the core?
MR. BROWNING: Right. As Ralph alluded
to, the exclusion zone on the power flow map has a
number of conservatisms built into it to account for
the computer code predictions and other margins.
So it is a fairly large area of that
corner of the power flow map, and a high flow, low
power, region. So during the startup, they have to
maneuver -- normally they try and maneuver around it.
Because of the uprate and the size of the
increase of the region, they are going to be
challenged to be able to maneuver it. So we are going
to have to maneuver through it after the uprate.
Hence, the reason why the increased
reliance on Solomon, because by our tech specs, we are
only allowed to operate in the region if Solomon is
available.
DR. UHRIG: Is this a tech spec
requirement that this instrument be available during
the start up and running through or moving through
this region, as opposed to maneuvering around it?
MR. BROWNING: What we are allowed is that
if the Solomon system is not available, there is an
additional buffer region applied to the exclusion zone
that we have to apply by the tech specs.
So when the back up system is not
available, we administratively increase the size of
the exclusion zone, where we are allowed to steady
state operate. We are allowed to pass through it, but
we just are not allowed to stay there for any period
of time. But we are allowed to operate through it.
DR. LEITCH: Must Solomon be operable
prior to taking the load switch to run?
MR. BROWNING: No, it is not.
CHAIRMAN WALLIS: When they operate
through it what happens? You do get oscillations, but
they never get very big; is that what it is?
MR. CARUSO: You won't necessarily get
oscillations. It is possible and you might. These
are regions where it is --
CHAIRMAN WALLIS: So Solomon tells you if
you have?
MR. CARUSO: I believe it measures decay
ration, correct?
MR. ULSES: Well, actually, it is not
making a measurement at all. It is using an
algorithm, and so it is making an actual analysis
calculation, a prediction of what it thinks the core
decay ration will be.
CHAIRMAN WALLIS: It is testing something
about the stability of the magnification?
MR. ULSES: Yes, sir, and I guess I would
say that I wouldn't expect to see a power loss or
oscillation during a power ascension. That is not the
normal mode of operation for a BWR.
DR. UHRIG: As long as you keep moving
through it, then there is very little likelihood of
any significant difficulty?
MR. ULSES: Yes, sir.
DR. UHRIG: And if you stopped while you
were in this region and operated for a period of time,
then there might be the possibility; is that the
implication here?
MR. ULSES: Well, it is an implication,
but I would say that due to the number of variables
that you have to put into this analysis that there are
a lot of things that you would have to do wrong in
order to have a power oscillation under these
conditions.
DR. KRESS: I don't think it is related
how long you are in there, and the time constant for
setting up this instability is very, very short.
MR. ULSES: Yes, sir.
DR. KRESS: But there has to be a lot of
other things.
DR. UHRIG: At what power level do you hit
this regime; is it 20 percent, or 30 percent, 50
percent?
MR. ULSES: I don't know. Do you know the
actual numbers, Tony? I don't recall what they are.
MR. BROWNING: I generally recall it in
terms of load line than actual power level. The lower
end of the region is about the 75 percent load line,
which is about 50 percent power roughly.
MR. ULSES: Right. It starts off with the
natural circulation line, and then it works right into
the power and up to about that power.
DR. UHRIG: And Duane Arnold operates at
full power all the time, and does not do much
maneuvering during normal operations?
MR. BROWNING: We only downpower
occasionally to do required testing. Our capacity
factors have been pretty high the last few cycles,
above 90 percent, and so we stay at full steady stay
power most of the time.
DR. UHRIG: Thank you.
MR. CARUSO: Any other questions about
stability? If not, the next item is the GEXL14
correlation. This is a correlation used to determine
boiling transition and DWR fuel bundles, and
specifically G.E. 14 and G.E. 12 fuel.
And the staff reviewed the development of
this correlation, and during the course of the review,
we identified that G.E. had used some data generated
by a code called COBRAG, which is the G.E. version of
COBRAG, or COBRA, to add to the GEXL14 database to use
in the correlation.
We are not entirely convinced of the
appropriateness of this data, and we are conducting
discussions with GE right now about whether it is
appropriate and whether it is acceptable, and what has
to be done as a result.
CHAIRMAN WALLIS: Code generated data?
MR. CARUSO: That's why we have a concern.
CHAIRMAN WALLIS: Well, maybe this is the
new world, and codes generate data.
MR. CARUSO: That's why we have a concern.
CHAIRMAN WALLIS: When you say in boring
transition, you mean transition to --
MR. CARUSO: Dryout.
CHAIRMAN WALLIS: DNB; is this what we
call DNB?
MR. CARUSO: No, it is DNB. It is dryout.
CHAIRMAN WALLIS: So it is reduced heat
transfer?
MR. CARUSO: Yes. We also did a review of
core design methods, and the reviewer there determined
that the methods that are being used for cord design
are appropriate, and we also looked at the Safety
limit MCPR which we determined were being used
appropriately.
DR. BOEHNERT: Ralph, before you leave
that, on the GEXL14, what is the outcome of this if
you guys don't like what they are doing by the code
generating data? What happens then?
MR. CARUSO: It would be possible that
-- I mean, I don't want to get into the details of the
discussion between us and G.E., okay? Some of the
potential outcomes are that we could possibly approve
the use of COBRAG to generate data for GEXL.
I think that would require us to do a
review of the code and the way that it is applied.
Another possibility is that G.E. could remove the data
from the database, and that would cause them to take
some sort of a penalty in using the correlation, and
it would increase uncertainty by a certain amount, and
that would be applied.
DR. KRESS: What data are we talking about
that this COBRA is generating?
MR. CARUSO: It is trying to predict
dryout in a fuel bundle.
MR. KLAPPROTH: Ralph, can I make a
statement? This is Jim Klapproth. So that there is
no confusion, there is a lot of test data on GEXL14.
Basically, it is an issue of the power shape. We do
a lot of thermal-hydraulic testing to develop
hydraulic very brisk bundles, using some power
shapers.
What COBRA does is then extend that
database for a different power shape. So it is not
just that we have the code data. We have a bunch of
-- thousands of data points from hydraulic testing,
and we are just extending that data to predict the
response, the GEXL correlation to other power shapes.
DR. KRESS: I am not sure I understand how
the power shape affects this at all. With BWRs, you
have the channels, and so it is not radiation heat
transfer, and --
MR. KLAPPROTH: Well, as we move through
the cycle, our power shape changes, and it will move
from a low of --
DR. KRESS: I understand that, but I don't
understand what that does to the correlation at all.
MR. CARUSO: The correlation takes into
account the nominal code signing shape and whether it
down skews or up skews, where the power has peaked
higher at the outlet or peaked higher at the bottom of
the channel.
DR. KRESS: But doesn't that just
determine the location of where you can do these
things? It doesn't affect the correlation at all.
MR. CARUSO: I have my experts here to
give you some more --
MR. ECKERT: I am Tony Eckert from the
Reactor System Branch. Usually when they develop a
correlation, they take data in what they consider the
operational range of the fuel, and so they look at co-
signed data basically and all down-skewed data, or
they look at the power shape at the bottom end of the
core and at the top end of the core.
And then they correlate to all that data,
and typically what every vendor does, okay? It is
typically what every vendor does. And in this case in
particular, it is important in the top part of the
core because this fuel has poplin rods (phonetic) that
stop about 8 feet up the core.
So you would really like to know what is
going on up there with regard to all kinds of face
changes going on and so forth. So what we found is
that there was no data taken specifically in that part
of the core.
And so what in essence they did is that
they used COBRAG to predict the behavior of the fuel
in what we consider to be a very critical region of
the fuel, which we had not seen there before.
DR. SCHROCK: Isn't the correlation
necessarily employment a subchannel analysis
methodology, which becomes an integral part of the
correlation? Isn't that the way that this works?
MR. ULSES: Well, it has the concepts of
a subchannel code because it does attempt to deal with
the radio power distribution. But what we have seen
in the past is that these correlations have always
been based strictly on experimental data that was
taken from their facility.
But this is the first time that the staff
has specifically encountered the use of a code to try
and augment the data.
DR. SCHROCK: The experiment is incapable
to giving localized thermal-hydraulic conditions
within the rod bundle, and in order to accomplish the
correlation, I think there is a need to operate a
subchannel analysis code, together with -- and put
that together with the experimental data to get what
is the GEXL correlation.
DR. KRESS: That is exactly what was
confusing me.
DR. SCHROCK: So it is a little unclear to
me what the new thing is that COBRA is doing. What is
the subchannel analysis code that normally is a part
of the G.E. correlation scheme, and how this COBRA
application different from that?
MR. ULSES: Well, actually, Dr. Schrock,
I would say that what they do is that they test an
actual prototypical bundle and use electrical heaters.
And when they do that, they can actually
vary the actual local subchannel conditions in the
experimental facility itself. So they are relying on
the experimental data.
DR. SCHROCK: But there is no way in the
world that they would have sufficient instrumentation
to know thermal-hydraulic conditions locally within
the rod bundle and throughout the bundle?
MR. ULSES: Well, that is not what they
are after. All they are after is they are after --
when they see the boiling transition on the thermal
couples, with that, they can tell at what axial and
radial location that happens, and that is what they
are trying to find out out of this correlation.
And they are using information from the
in-let of the channels; is that right?
MR. CARUSO: That's right.
DR. SCHROCK: And correlated against what?
MR. ULSES: It is correlated against the
in-let conditions of the fuel channel, which is a
known quality.
DR. SCHROCK: I think you need to clarify
what the scheme is, and then discuss it in terms of
this COBRA TRAC generated data.
CHAIRMAN WALLIS: Is there some way we can
get the evidence to Dr. Schrock so that he can look it
over and so that he can understand what is really
being done?
MR. ULSES: Well, we don't have it here
ourselves.
DR. SCHROCK: I thought what I did hear
and what I am hearing and that I understand it to be
is that it is not consistent with what I hear.
MR. CARUSO: I don't know how much time
you want to spend on explaining GEXL14 and now it is
applied.
CHAIRMAN WALLIS: Well, if it is
important, and I don't know what yet is important, and
what are the important issues in uprates, but if it
turns out that this is an important issue, then it
should be resolved.
MR. CARUSO: We don't think this is an
important issue for power uprates, per se. It is an
issue for G.E. 14 and G.E. 12 that is used wherever it
is used.
But we don't think that this is a power
uprate specific issue. This is one of those issues
that I mentioned which has generic applicability.
CHAIRMAN WALLIS: Unless in some way the
power uprate was pushing the limits of applicability
of some method.
MR. CARUSO: That we don't think is the
case here. I'm sorry, Tony.
MR. ULSES: Well, what we are seeing with
these new G.E. fuel bundles is that they have more
thermal margin, and they are basically using that for
these power uprates.
So in a sense, it is hard to say in actual
real specific terms whether the power uprate itself is
actually driving this, or whether, say, an operator
who is not using a power uprate might seek to use some
of this margin to minimize the number of bundles they
have to buy, for example.
So I guess I would agree with you that it
is not a power base specific issue, but it has
implications in that direction.
MR. CARUSO: Let us talk about what we can
provide to you, and can I get back to you a little bit
later in the day on this?
CHAIRMAN WALLIS: Sure.
DR. SCHROCK: Is this the new fuel?
MR. CARUSO: Yes.
DR. SCHROCK: This is 14?
MR. CARUSO: Yes.
CHAIRMAN WALLIS: There is nothing in your
list about neutron flux here? Are you getting enough
power to operate? This is achieved presumably by
greater neutron fluxes at various places, and this
changes the fluents and things like value dense? You
have not said anything about those issues.
MR. CARUSO: No, vessel fluids. Is that
what you were --
CHAIRMAN WALLIS: Whatever, but there is
greater neutron flux associated with presumably
greater power.
MR. CARUSO: That's correct.
CHAIRMAN WALLIS: And in some places,
depending on how they flatten the power into the flux
and so on. Are there any effects that need to be
mentioned?
MR. CARUSO: I believe that that was
considered to some extent in the reactor core design
issue. Ed, did you look at flux shapes and flux
calculations?
MR. KINDER: This is Ed Kinder, Corrective
Systems Branch. In our review of both the equilibrium
cycle, which is full G.4. 14 core, and the transition
cycles, which go from the current fuel design, we
looked at flux shapes and power shapes.
And as was mentioned, the G.E. 14 bundle
is designed with more thermal margin. It is also
designed so that the bundle of power itself, and the
radial core power is flatter. And each cycle has a
design enrichments, vendable poisons, and core
loading, to essentially flatten the power.
One of the neutron flux is higher, and the
vessel fluence is an issue which is also looked at in
this area.
DR. FORD: Could I ask a further question?
There is a whole range of materials degradation issues
which could potentially impact on this; fluence use
corrosion, vibration, and there was mention of the
flux at the core shroud, and pressure vessel. Are
these going to be audited at all? Are we going to
hear about that today?
MR. ELLIOTT: Excuse me. This is Barry
Elliott, of the Materials and Chemical Engineering
Branch of the NRR. The issue of neutron irradiation
and embrittlement affects the stainless internals and
the alloy steel pressure vessel.
For the pressure vessel, alloy steel
pressure vessels, the neutron fluence affects the
pressure temperature limits and the upper shelf
evaluation.
But those evaluations are evaluated by our
staff and calculations are done in order to assure
that the pressure temperature limits in the upper
shelf energy for the reactor vessel meets Appendix G,
10 CFR 50 requirements.
As far as the internals are concerned, the
BWR VIP program is carried forward, and whatever the
program has for the fluence and for the vessel would
be the program that we would use for the power uprate.
MR. CARUSO: We have existing programs in
place that account for whatever fluence is generated
by the vessel, by the core, on various structural
components, whether it is internal or the vessel, and
those are accounted for.
At the higher power levels the flux or the
fluents accumulates faster, and that is taken into
account.
DR. FORD: And would the current VIP
methodologies attack, for instance, a radiation that
is cracking at H-4 weld? Would it attack that, and
fluences be expected to have the power uprate and
license renewal?
MR. ELLIOT: The BRR VIP programs are what
they are. I mean, they were approved for -- and as
you run the plant, they are approved for the life of
the plant.
We have approved power uprates and we have
approved license extension 20 years so that it is
built into the program.
DR. FORD: So we are taking into account
the synergistic effect of increased fluents with
license renewal?
MR. ELLIOTT: Yes.
DR. FORD: Plus, increased flux?
MR. ELLIOTT: The documents are evaluating
the impact of fluents, and have an inspection and
repair programs accordingly.
DR. FORD: And how about fluence with
accelerated corrosion and vibration use corrosion,
which have been problems? For instance, Susquehanna
and Calloway power outrates?
MR. ELLIOTT: I have to say that I don't
know all the details that you are describing, but with
irradiation, and since there is this stress corrosion
and cracking issue, it is built into the BWR VIP
program.
DR. FORD: And that is taken into account
in the VIP documents?
MR. ELLIOTT: Radiation assisted stress
corrosion cracking is.
DR. FORD: Yes, but I am talking about
fluence assisted corrosion?
MR. ELLIOTT: I would have to look that
up. I don't have that information. With flow
assisted corrosion, I would have to find out how we
evaluated it as part of the BWR VIP program. I would
have to look at that, at flow assisted corrosion.
DR. FORD: Okay. And the zircloid-F
swelling be a problem?
MR. ELLIOTT: That is considered. It is
part of the BWR VIP program.
MR. CARUSO: You were asking about
zirculoid corrosion of fuel cladding?
DR. FORD: Yes, cladding.
MR. CARUSO: Fuel cladding is considered
as part of the fuel design, and the fuel design --
well, actually, that is a matter of fuel burnup. And
fuel burnup limits are not changing as a result of the
power uprates.
So the fuel that is rated to a certain
burnup level will not be allowed to go any higher than
that as a result of the power uprates. So we are
working within the existing database, and it doesn't
matter if they raise the power.
They might burnout fuel elements faster,
but they still can't burn them beyond where they are
currently allowed to burn them and where the
experienced database ends.
DR. FORD: I am showing my ignorance on
this particular part, but when they come up with a
design criteria, that was made at the time of
licensing, and maybe we didn't understand some of the
phenomena that have since come to the fore.
MR. CARUSO: Are you talking about in
terms of fuel?
DR. FORD: Fuel, or ISEC, for instance. It
was not a known phenomena when these things were --
when the design basis was --
MR. CARUSO: I can't address the issue of
the ISEC, but I can talk about fuel, and I do know
that we are not using fuel acceptance criteria now
that were used in 1972 when the plant was licensed.
We are using current knowledge-based acceptance
criteria, and current standards for fuel.
DR. FORD: Is there going to be a
presentation on these specific TLAs later on today or
not?
MR. CARUSO: No, not on fuel. No.
DR. FORD: Well, on any materials or
construction?
MR. HOPKINS: Well, that's why we had
Barry Elliott here to respond to questions. We didn't
have a specific presentation planned for that area.
DR. FORD: It is a fairly important area
though isn't it, given the fact that for the last 20
years we have had a pretty abysmal record in terms of
materials integrity. We have now started to change
two things, license renewal and power uprate, which
can be synergistic.
We are going to be attacking those two
things in that format, in that synergistic format,
aren't we?
MR. ELLIOTT: I would say that this is a
power uprate portion, and the fluence for the power
uprate is going to be much less than the fluence for
BWRs who have license extension. I mean, that's just
the way it is going to be.
DR. FORD: I guess my question --
MR. ELLIOTT: Ultimately, we are going to
have both added on, and when get to our license
extension, we will address both of those things when
it occurs, but right now we are just power uprate.
And I think the BWR VIP program would
encompass all these issues that have come up within
the last couple of years, and would not be impacted
significantly by the power uprate.
DR. FORD: I guess my frustration is that
I keep hearing these terms, but I don't see any data
and that is my frustration.
MR. CARUSO: Would you like a presentation
on fuels?
DR. FORD: No, not particularly fuels, but
any materials of construction. I would love to hear
an analysis of the expected degradation, time
dependent degradation of the materials of
construction; core-shroud, pressure vessel, weldments,
as a function of increased power uprates.
CHAIRMAN WALLIS: Well, I guess it applies
to all of these issues, and we keep being told that
the methods are being used approximately, and it would
be good if there could be a technical presentation or
something, and where here is a graph of X versus Y.
And this is what you have without power
uprates, and this is where you might be pushing some
limit, and this is where you go with the power
uprates, and sort of a quantitative comparison in some
technical terms.
MR. CARUSO: Actually, I believe you are
going to get some of that later on today from GE.
CHAIRMAN WALLIS: Okay. We will look
forward to that.
MR. CARUSO: Let me see. My last slide is
conclusions, and unfortunately, Dr. Wallis, I am going
to give you a conclusion without any details. That
the approved methods continue to be used appropriately
at the uprated power levels.
That the GEXL14 correlation database
evaluation issue we are continuing to discuss with GE
and the licensee, and we hope to resolve that soon.
We would like to resolve that as soon as possible.
We intend to continue to do these audits
for Dresden and Quad Cities later on, I believe, this
month, and for Clinton later on in the year once the
Clinton application has been received.
CHAIRMAN WALLIS: I don't think it has
come in yet has it?
MR. CARUSO: And we find these to be
particularly useful. And we will probably vary the
areas that we do audits on. This time we did
SAFER/GESTR, and we did stability.
Dresden and Quad Cities will probably do
a different stability option, because I believe that
they may be using a different stability option. We
will look at maybe ATWS, and we will look at other
scenarios. We will look at other issues.
CHAIRMAN WALLIS: I think we are going to
ask questions about ATWS this afternoon, and is that
when we will get the answers?
MR. CARUSO: I see G.E. nodding yes.
DR. UHRIG: This work that you have done
so far has been exclusively Duane Arnold?
MR. CARUSO: It has been focused on Duane
Arnold, but realizing that some of the things that we
look at have generic applicability, like the GEXL14
correlation is not just for Duane Arnold.
It applies to anyone who has G.E. 12 or GE 14 fuel.
CHAIRMAN WALLIS: And the follow on
plants, Duane Arnold, as I understand, is one of the
smallest plants of BWRs, and if not the smallest, and
then the next sort of size up is the Quad Cities, and
then it goes on to Clinton as the biggest.
And size then, is there anything else
besides stability, core stability, that is related to
size? Are there any new issues that you expect to
come up in the later plan reviews that is not inherit
other than the difference in the stability issue?
MR. CARUSO: Off the top of my head, I
can't think of anything, but possibly ATWS
performance, or ATWS response, might be an issue.
Containments. Containment is probably one area where
we should look because that is very plan specific.
The relationship between the size of the
containment and the decay heat loads is very much plan
specific.
DR. UHRIG: It is pretty much related to
whether it is a Mark III or Mark II?
MR. CARUSO: I think it probably depends
on whether it is a Mark I, Mark II, or Mark III, but
it also depends on the actual size, because I don't
think that all Mark IIs are the same size, or the same
sized relative to the power well.
CHAIRMAN WALLIS: If all these methods
continue to be used appropriately, how much uprate is
tolerable, and what limits -- when do we first hit a
limit if we set an uprate to 30 percent or 40 percent,
50 percent? When do we say you can't go any further?
MR. CARUSO: I have a sense of deja vu
when I hear that question.
CHAIRMAN WALLIS: Well, you see, the
methods can still be used appropriately.
MR. CARUSO: Well, I think you will get a
chance to ask G.E. that question this afternoon, and
I think you should ask them that, because we have
asked them that question and they tell us, well, the
first thing or limit that you run into is the turbine
because you can't use the power.
CHAIRMAN WALLIS: So you put in a bigger
turbine. That is not really an issue.
MR. HOPKINS: Let me mention for Clinton
briefly. I mean, they have not made their application
yet, but they are going for 20 percent, and they will
be basically changing out the high pressure and low
pressure turbines, and getting a new main power
transformer, and new reserve alt transformers, and
doing feed water heater work, and doing main generator
work for more efficient cooling.
And doing main condenser work, and all
this is a constant pressure uprate, but all of this is
try to get 20 percent, and it is a substantial amount
of modifications.
CHAIRMAN WALLIS: It is not really an
issue with the right to safety.
MR. HOPKINS: I know, but it has an effect
on dollars and now much you spend for how much you
get.
DR. KRESS: I think the question is more
philosophical along these lines. As you do things
like the power uprates, and license extensions, et
cetera, you do change the margins.
And the Chapter 15 margins on certain
figures of merit and even risk acceptance margins on
things like CDF and LERF, they are changed. Now, the
question that I would have is that I think there is a
question to ask, and that is, is there a significant
decrease in the margins is a question that one would
ask.
Well, what is meant by the word
significant in there? Is the view that as long as you
meet these figures of merit at all, then the change or
decrease in margin is acceptable, and thus not
significant. Is that the staff's philosophical view
on this, or is there more to it than that?
MR. CARUSO: I guess I am jumping to the
middle of Donnie Harrison's presentation, but the
simple answer to that is yes. We have limits that
come from regulations, and we have a 2,200 degree
limit, and we have limits that come out of approved
topical reports, where we approve methodologies.
DR. KRESS: And as long as you meet those
limits --
MR. CARUSO: As long as you meet those
limits, that is the important thing.
CHAIRMAN WALLIS: So that is the answer,
it is not really a philosophical question. You can
keep operating until you hit one of those limits.
MR. CARUSO: Until you hit one of those
limits, yes, and the question is which limit are you
going to hit first. I mean, there may be other limits
that are not necessarily regulatory limits.
I imagine that there are probably internal
design constraints on fuels that people might run into
before they run into any regulatory limits.
CHAIRMAN WALLIS: But 20 percent seems to
be according to the story here so easy, you wonder why
it is not 30 percent.
MR. CARUSO: I think that is what I was
trying to answer. I think there are practical
considerations for how much you can get.
CHAIRMAN WALLIS: So apparently there is
no limit on the reactor side.
MR. CARUSO: Not yet. My speculation
would be that they will probably run into containment
limits first, because that is not something that is
changeable, and I have seen the curves for containment
performance, and they are very close to the limits.
CHAIRMAN WALLIS: And what has changed
them? Why is it that years ago these were designed,
or they were approved at a lower power level? Has
there been some great new insight into fuel design or
materials behavior, or thermal-hydraulics which makes
it now possible to uprate by 20 percent?
MR. CARUSO: I am not sure which Tony
mentioned it, as there are three Tonys in the room who
have spoken. One of the Tonys mentioned the fact that
we have gone through -- that G.E. has gone to this
better fuel.
CHAIRMAN WALLIS: Is it better fuel?
MR. CARUSO: It is better fuel. It is
designed in a way which allows them to get more steam
out of this bundle.
CHAIRMAN WALLIS: Better fuel in terms of
thermal-hydraulics?
MR. CARUSO: Yes, part-length rods,
cleverness in using thermal-hydraulics.
DR. FORD: My guess is that you are going
to come across a materials degradation problem, which
is going to be limiting, and it scares the pants off
me when I think --
DR. KRESS: Well, the trouble is that
there is a very limited or lack of knowledge on how
power affects what you are talking about, except with
the acceptance of the fluence problem. But the other
degradation problems you can't relate to power very
well.
MR. CARUSO: I know about the fluence
issue because the fellow that does the fluence
calculations used to work for me, and he educated me
on this. And it is -- we do account for that.
DR. KRESS: Yes, it is fairly
straightforward.
MR. CARUSO: They have this bucket, and
they keep throwing fluence into it every year, and
they have to measure the height of the level in the
bucket.
DR. KRESS: That's exactly right. It is
pretty straightforward.
MR. CARUSO: And if you raise the power
the bucket gets full faster, and there is a limit on
how much you can throw in the bucket. And if they run
out of space, that's it. You have to go out and kneel
the vessel or they will have to do something else. I
don't know what.
DR. KRESS: And then when you get to other
materials degradation issues, like intragranial or
stress corrosion cracking, that is hard to relate that
to power.
MR. CARUSO: That I don't know. That is
out of my area of expertise.
CHAIRMAN WALLIS: The thermal-hydraulics,
the outside of the fuel is at about the boiling
temperature and the heat transference is so good. And
if you go to a higher power, does that mean that you
get a higher set of center line fuel temperature, or
is it something done to make that better?
MR. CARUSO: That is a good one. I don't
know the answer.
CHAIRMAN WALLIS: It is a big temperature
drop from on-line fuel to the wall, a huge drop. What
is happening inside this fuel at these higher powers?
MR. CARUSO: I don't know what center line
fuel tempers do.
CHAIRMAN WALLIS: Is that another
criterion of some sort, that it cam go to any value it
likes?
MR. CARUSO: As far as I know, that is not
a regulatory criteria, but I would imagine it is
probably a design criteria that the fuel vendor uses.
DR. UHRIG: But it pushes you towards the
2,200 limit --
MR. CARUSO: Probably, yes, higher lineal
heat generation, right, is going to reduce the margins
if you assume that everything else stays the same, and
it is going to reduce margins, yes.
CHAIRMAN WALLIS: And it makes products
more mobile inside the fuels so they can move around
and accumulate in places? And maybe move to the
outside and maybe holds the cladding?
DR. KRESS: That is one of our questions,
is does the gap inventory increase, for example, and
the thinking was that thermal diffusion might -- in
the first place, you are going to have more inventory
because of the higher uprate of some of the gap --
MR. CARUSO: Actually, inventory depends
on burnup.
DR. KRESS: Yes.
MR. CARUSO: And the burnup limits hasn't
changed.
DR. KRESS: Yes, but normally you reach
the equilibrium with some of the shorter lives, and
things that you worry about, like the iodines, and the
--
MR. CARUSO: Maybe the distribution will
be slightly different.
DR. KRESS: But I don't know of any data
that relates to center line temperature, operating
temperature, to the gap. For example, where you have
might have thermal diffusion pushing things in that
direction.
So that was the nature of one of the
questions that we asked, is there some evidence or is
there a need for additional research on what is
actually in the gap that relates to these higher
temperatures of the fuel. And then the higher burnup.
CHAIRMAN WALLIS: Well, this has been done
before and we know all the answers.
DR. KRESS: Right, or is there some data
that tells us not to worry about it? And is it
important to know what is in that gap from a risk
standpoint?
MR. CARUSO: I don't have an answer for
you on that.
MR. HARRISON: But we will have a slide
for that half-way through mine.
DR. KRESS: Okay.
CHAIRMAN WALLIS: You are taking too long,
Ralph, and we need to move on.
MR. CARUSO: I can talk all day.
CHAIRMAN WALLIS: But talking isn't the
issue. It is transferring information. We could all
talk. Try to get a sufficient transfer of
information. Would it be best to move on, you think?
MR. CARUSO: I think so.
CHAIRMAN WALLIS: I'm sure that we will
come back to many of these questions when we talk to
G.E.
MR. CARUSO: I think so. I would like to
hear G.E.'s answers to some of these questions.
CHAIRMAN WALLIS: We thought you had asked
all these questions before and didn't get answers.
MR. CARUSO: A lot of them, yes, but some
of them -- the fuel center line temperature is one
that I have not heard before.
CHAIRMAN WALLIS: So maybe we should move
on.
DR. LEITCH: Just before we leave, I would
like to go back to the Solomon and the instability
issue for just a moment. If the operator lacks
confidence in this system, it is usually with some
justification if the operator lacks confidence.
Are we saying that this is a training
issue or is Solomon's ability to predict instability
in question?
MR. CARUSO: I am not sure I would say it
is necessarily an ability of the system. I used to be
an operator, and I am a former Navy operator, and I
think about the instruments that we used all the time;
and you watched them go up and you watched them go
down.
You believed them because they moved a lot
and you had ways to check them. The ones that you
never really believed were the ones that sat there in
the corner and never used until the one time that they
went off, and you said wait a minute, that never goes
off.
And you hit it hard. You hit it with
something, and make sure that there is nothing wrong
with it.
DR. KRESS: And which ACRS member is that?
MR. CARUSO: The classic example is the
water level instrument in a PWR. You know, for 30
years it reads peg high, and then one day is comes
down off the peg, and the operator says, wait a
minute, no, no, no, that can't be. It is never like
that. And they don't believe that they have lost the
water level in the core.
CHAIRMAN WALLIS: That's the problem. They
don't believe.
MR. CARUSO: But I don't know how you can
solve that problem except to educate the operators to
think about what it means, and say, well, maybe there
is some other way that I can check this.
And as the Duane Arnold people say, this
system is not the only way that they use to determine
instability. They are supposed to use this system to
tell them when they are likely to have an instability,
and then they are supposed to go look at the actual
power range instruments to determine whether they do
have an instability.
DR. LEITCH: I seem to recall that Duane
Arnold has a plant specific simulator. Is Solomon
stimulated?
MR. CARUSO: I see Tony noddiNg his head
yes. I don't know how to address your -- I think it
is a valid question. It is something that we really
have brought up as part of this, and we think it will
be up to the licensee to try to get the operators to
use the equipment that they have got. And the
operators do strange things. I know because I used to
be one.
DR. LEITCH: I know that it is difficult
getting folks to rely on instrumentation that is
normally out of range, let's say.
MR. CARUSO: Right. But if that
instrumentation is reliable and believable when it
comes down into range, then the operators ought to
believe in their instrumentation.
DR. LEITCH: They should. And I guess my
question is whether it is believable or is it
something that if it doesn't work, then we are
confusing data in front of the operators.
MR. CARUSO: We think it is believable.
We think it is good instrumentation. We think it
should be there.
DR. LEITCH: Okay. So training the
operators to rely on that when it is in range?
MR. CARUSO: Yes, to use it.
DR. LEITCH: Thanks.
CHAIRMAN WALLIS: Would it be best to take
a break now or move on?
MR. HOPKINS: This would be a good time.
MR. HARRISON: We will be moving on to PRA
issues next.
CHAIRMAN WALLIS: How long is that going
to take?
MR. HOPKINS: Oh, 2 or 3 minutes. We
could just mow through it.
CHAIRMAN WALLIS: Let's take a break until
10:00.
(Whereupon, the meeting was recessed at
9:51 a.m., and resumed at 10:00 a.m.)
CHAIRMAN WALLIS: The meeting will come to
order. We are looking forward to hearing about risk
in the next topic.
MR. RUBIN: Good morning. I am Mark Rubin
from the PRA branch. I have someone new to introduce
you to this morning, Donald Harrison, who joined our
branch, the PSA branch of NRR a number of months ago.
And sine the previous reviewer, Sam Lee,
has been made an offer that he can't refuse, he has
moved on to another assignment, and Doug Harrison will
be one of the people working on the risk PRA reviews
for the power uprate plants.
MR. HARRISON: I just want to let you know
what the scope of my discussion will be, will be to
walk through first just some slides on Duane Arnold,
and let you know the information we received from
them, the topic areas.
And then we will proceed right into the
topics and the six questions that were provided by the
ACRS. We are still reviewing Duane Arnold. I just
want to make it clear that this presentation part is
essentially the Duane Arnold information that we have
received, either directly in their submittal, or in
response to questions the staff has asked.
I do want to put us into a perspective
that Duane Arnold in their submitted as made it very
clear that this was not submitted as a risk-informed
licensing action. However, the staff is reviewing it
using the criteria of Delta-CDF and Delta-LERF that is
Reg Guide 1.174.
If we look at the question on PRA quality,
it is really a question of do you reflect the design
and operation of the plant, and Duane Arnold has
submitted that it does reflect their plant
configuration.
They have been through a BWR owners group
peer review, and the staff is considering if we need
to take a look at the peer review to get a good feel
for the areas that we typically look at.
DR. KRESS: Is that peer review different
from the certification process?
MR. RUBIN: No, it is the identical BWR
certification peer review, yes.
MR. HARRISON: There are four areas that
we typically look at; initiating event frequencies,
and success criteria, component reliability, and
operator actions. So we will walk through those four,
and the responses that Duane Arnold has provided.
On initiating event frequencies, Duane
Arnold doesn't expect any changes to that frequency
for those things that would cause reactor SCRAMS or
set point pump failures, and that type of thing.
They have stated that they feel that they
have adequate margin so that they don't expect there
to be any kind of an increase in that area. They are
making modifications and design changes to the -- I
think it is the main transformer, and some electrical
breakers.
And that is to capture margin or extend
the margin that they already have, and because of
that, the potential for, say, a plant loss of all site
power is believed to be not effected either.
DR. LEITCH: Are they taxing the margin in
BOP equipment such as condensate pumps, reactor feed
pumps, such that -- well, let me come at my question
another way.
Often times a plant has enough margin in
those that when you are operating at a hundred percent
power that you can lose a major auxiliary like that,
a condensate pump, for example, and get down under the
capacity of the remaining condensate pumps, and ride
it out without a SCRAM.
Whereas, it seems to me that if you are
operating further up on the capability of those major
auxiliaries that if you lost one of those that you
might be more inclined to take a SCRAM.
And I guess I am wondering is that the
case as you see it at Duane Arnold?
MR. HARRISON: At Duane Arnold? I don't
-- from my part of the review, I have not seen that.
I know at other plants that require, say, adding
another operating condensate pump to get the flow they
need -- and then you may have a run back design change
that you have had to install, that would be an area
where you would then have to look at what is the
effect of a spurious trip, and that would be a new
condition. And I don't believe that Duane Arnold has
that condition.
DR. LEITCH: But by saying there are no
changes in the initiating event frequency, you don't
see any change in that? For example, in the SCRAM
frequency, in the situation that I described.
MR. HARRISON: Right. The projection is
that the SCRAM frequencies would stay essentially
where they are at.
DR. CRONENBERG: What about small break
LOCA, like Susquehanna and the recirculation line
after they had the power uprate there? The initial
interpretation of that even was that it was a flow
induced vibration effect, and hence, in the
recirculation line, and that caused that rupture in
the recirculation line.
Also, to come back to Peter's question,
all of this due to corrosion, and this is a direct
cycle plant, and the main steam line is higher post,
and did you find it that there was a no change
anticipated, and do you find that a little suspect?
How did they calculate the small break LOCA
frequencies?
MR. HARRISON: I don't believe -- and may
I can ask Duane Arnold to correct me if I am wrong
here, but I don't believe that they necessarily went
out and recalculated new LOCA numbers, considering an
increased flow for like -- well, the argument on the
primary system LOCAs is that you have got condition
monitoring programs, and you have got a fact program.
And those programs are being relied on to
maintain the system. Now, you may expand that program
monitor for that, but I don't believe that would
affect the LOCA numbers.
MR. ECKERT: This is Gene Eckert from G.E.
Can I just make one comment and we will talk again
this afternoon, but in the Susquehanna case, they made
two changes, and a little contrary to what our
standard programs have been, that they came in with a
power uprate.
And with an increase in their maximum core
flow allowed for the plant; and then the things that
they got into appeared to be associated with that
increase in core flow above where they had run before.
All the plants like Duane Arnold and the
ones that you saw on the list up here today are coming
into the uprate program without increasing their
maximum core flow, and they are keeping the same
limits on what their external drive loop flows will be
in the recirc loops.
DR. KRESS: Speaking of incidents, has
there been any look at past upgrade uprates? Of
course, none have been as significant as this, but to
see if -- well, for example, the AEOD people, would
they have looked to see if there was any change in
these initiating event frequencies due to the uprate?
I suspect that he experience has been the
other way, and it has gone down, but for other
reasons.
MR. RUBIN: We have not looked directly.
I did talk to the AEOD section chief, Steve Mayes, and
his view was that there wasn't going to be enough time
history to establish anything. So we have not
proceeded on that.
MR. HARRISON: We will touch on that
towards the end of the presentation as part of one of
the questions.
DR. FORD: Could I just make a comment,
and it is more for education on my part. When you are
talking about initiating event frequencies, as I
mentioned before, there is a lot of potential
material degradation issues.
And I say potential, because we haven't
had them occurring so far. But history unfortunately
has told us that it can occur in the future. Does
that proactive future possibility, which can be
analyzed, does that come into your methodology?
Do you understand what I am saying? Such
as the large cracking of large pipes was not
anticipated before they occurred, and then they
occurred, equally you can expect in the future that
there is to be some occurrences of, let's say,
vibration induced or flow induced vibration effects,
and an effect on the CUF.
If you expect there to be increases in
flux, and therefore on fluence, and that might have an
effect, a predictable effect, how does that proactive
thinking come into your decision making?
MR. RUBIN: Well, clearly, there is not a
one to one mapping into the risk models. They don't
have a scope like that. As Donald said, we are
relying on the condition monitoring programs, the in-
service inspection programs, the augmented inspection
programs.
What I would reflect on though is that
-- well, two items. The mechanistically determined
break frequencies on these plants through probablistic
fracture mechanics are generally far below the assumed
LOCA frequencies in the models.
If we started to see a large swing that
would encroach on those differences, I think it would
be probably picked up. But it certainly is an area
beyond the current modeling, and in a sense beyond the
state of the art.
But I have not -- well, I will ask Donald
to reflect on where the small LOCA contributions came
in the risk profile of Duane Arnold. I think it is
probably pretty low.
MR. HARRISON: Yes, there was -- there
wasn't a driver in any of the change in risk that they
reported as part of the power uprate.
MR. RUBIN: How about the residual, the
baseline?
MR. HARRISON: I don't recall. I would
have to look that up.
MR. RUBIN: Would expect it to be quite
small. There are other things driving the risk at the
plant. So it certainly is something that could
conceivably occur, and hopefully through the programs
in place to watch for performance in those areas, it
would be caught and an appropriate response would be
made.
But of course I am hypothesizing there,
but I think the primary issue is that right now with
the current plant profile that the LOCA frequencies as
they are in the model aren't controlling risks, or
aren't driving risks, or other things that are much
closer.
DR. FORD: Just to take Gus' comment a bit
further. For instance, fatigue usage factors. There
will be presumably some flow induced vibrations, and
that will affect the fatigue u sage factor, which will
be even more exacerbated if you go to license renewal.
Now, has that thought process come into these
analyses?
MR. RUBIN: I think it certainly comes
into the analysis from our colleagues in the division
of engineering in assessing the uprate.
DR. FORD: Okay.
MR. RUBIN: And if they would care to
comment on that. Do we have anyone still here?
MR. WU: Yes. My name is John Wu from the
chemical engineering branch. I would like to comment
on this. The flow induced vibrations has been --I
think the gentleman from G.E. mentioned that for this,
20 percent power uprates, and the maximum rate does
not change at all.
So for flow induced vibrations, we have
been closely looking at this phenomena. The maximum
flow rate does not change and so we don't have that
from the flow induced vibration concern.
And the only concern is probably that the
flow goes through the main steam in the free water
line, because of a 24 percent flow increase, and in
this case, there are some vibration concerns because
flow induced vibrations which is proportionate to the
density of the root, also is proportionate to the
square of the velocity.
But for this program, they have some kind
of monitoring program, and so they will monitor this
program very closely, such as inside the containment
there are remotes, and some kind of monitoring device,
vibration sensor.
And outside, they have people walking
around and probably use hand-held monitors to monitor
the vibration level. And their criterion is that any
vibration that occurs besides the audit, then they are
to make sure that the vibration level, the insurance
level, is below the endurance limit.
And the endurance limit is the limit that
the material can vibrate and that there is no concern
about the vibration. And also I think Peter's
comments about the collation between the power break
and license renewal problems.
The license renewal, we have now the 10
limit aging analysis, and it has been very closely
reviewed by the chemical engineering branch. So
nobody is very small, especially for a big usage
factor and it is below .5 and so it is very small for
the intent of the component. And for others, those
are small, and normally we don't have a problem, you
know.
DR. LEITCH: I have another question in
that area. Even with core flow staying constant, the
separator and dryer will see different flows or at
least different quality steam as it comes up there.
Have you taken a look at the impact on the dryer and
separator?
MR. WU: Those separators are -- I think
this is probably alleged, but the point of view is
that it is very, very small with the separator. So we
don't have a big usage problem.
Even the steam flow is higher than the
power uprates. But because there are separators out
there, the insurance level is very, very small.
DR. LEITCH: And how about the dryer? Is
it the same thing?
MR. WU: The dryer is the same thing. The
dryer and the shroud top, they are together and the
same thing, right, and is very small. They combine
with others, and it is very small. So it is not a
concern.
DR. LEITCH: Again, it is a question of
quantification of very small.
MR. WU: I do not recall the numbers of
the quality usage factor, but they did calculate the
usage factor based on the power uprates and especially
for the dryer, and for this higher presentation of the
power uprates.
CHAIRMAN WALLIS: We can get numbers from
G.E., I expect, this afternoon.
MR. WU: Right. It is very small.
DR. LEITCH: Thank you.
CHAIRMAN WALLIS: Again, I would like to
know what very small is, too.
DR. FORD: An initiating event, I assume
that operational performance also comes into that
particular category; is that true?
MR. HARRISON: Actually, not as much as --
you will have a separate look strictly at the operator
response to initiating events. But typically we are
talking about the occurrence of a LOCA, or --
DR. FORD: But the response time will be
shortened?
MR. HARRISON: The response time will be
shortened, and that is on my next viewgraph, or the
one after that.
CHAIRMAN WALLIS: We have spent longer on
the first bullet of the whole presentation than we
were promised the whole presentation would take.
MR. HARRISON: If we can proceed then. On
success criteria, Duane Arnold ran thermal-hydraulic
evaluations, and the result of that rerun was to
establish and confirm that their success criteria was
still the same.
They did not identify any impacts on their
success criteria as used in the PRA.
DR. KRESS: These are things like how many
ECCS pumps get started?
MR. HARRISON: And how many pumps do you
need, and how many RSVs do you need for
depressurization.
DR. KRESS: Right.
MR. HARRISON: Right.
DR. KRESS: And things associated with
containment, like the suppression pool, and --
MR. HARRISON: The heat and the
suppression pool.
CHAIRMAN WALLIS: And temperatures.
MR. HARRISON: Right. They did recognize
plant parameters were changing, and that you will have
more decay heat, and you will be producing more net
than the model.
DR. KRESS: Essentially when you ask the
question about the PRA and how many pumps start and
things like that, the same number would do the same,
would prevent a core melt.
MR. HARRISON: Right. You still end up
with the same success criteria, and you need -- there
could be a change, and like in SRVs, you could go from
needing 3 out of 6 to 4 out of 6. They didn't find
that.
I think that their deterministic analysis
that they do on the DBAs actually did change that.
Their PRA though success criteria shows that 3 out of
6 was still adequate for that.
DR. KRESS: Is there some analysis that
you guys had planned to do with something like the
SPAR models that says that if I had a power uprate of
this much, and X is an unknown quality, then my
success criteria would change so that I have some pre-
conceived notion of when to start really worrying
about success criteria, that is really when you get an
impact on CDF, is when you change those success
criteria.
MR. HARRISON: And actually that is an
observation where at Duane Arnold that they held the
success criteria, and where they would not give them
the power uprate.
DR. KRESS: But that was actually their
condition on it?
MR. HARRISON: That was their condition,
and they saw that as a key point to hold. We don't
have that criteria necessarily, but if the success
criteria did change, we would take a stronger look at
that particular area to make sure what the effects
were and what the change was in the CDF.
DR. KRESS: It would be reflected in your
CDF changes for sure. Okay.
DR. LEITCH: I noticed that the
expectation is that in certain situations that the
suppression pool temperature would be higher.
MR. HARRISON: Higher, yes.
DR. LEITCH: In some plants, I believe
that suppression pool water is used to cool bearings
and other support equipment for ECCS systems. Did you
take a look at whether that impacts the reliability of
IPSY-RIXY or -- well, in other words, is that higher
temperature water from the suppression pool adequate
to provide appropriate cooling for IPSU and RIXY
bearings?
MR. HARRISON: I have not looked at that,
and that is something that I could take back and look
at.
DR. LEITCH: And in fact I am not a
hundred percent sure that at Duane Arnold that is the
source of water for those bearings, but I think it may
be.
MR. RUBIN: I am not familiar with that
cooling mode. If they did employ anything like it,
the suppression pool temperature limits should be
constrained by the design basis requirements for
cooling those systems.
And within that perimeter, I would expect
no impact on reliability, and certainly you would
exceed the qualified temperatures of components, and
then you still have margin to failure off of it, but
I think if you are still within the design basis, and
they would have to be to get approval for the uprate.
I wouldn't expect to see an impact, but if
we started to see it, it would be picked up by the
performance monitoring or the performance indicator
program.
DR. LEITCH: But that supply to the
bearings though, if it exists, is an subtlety that I
just want to be sure has not escaped us in our
thinking.
CHAIRMAN WALLIS: Do seals get involved in
this, too?
DR. LEITCH: Yes.
MR. HARRISON: Bearing seals, yes. As was
indicated, there are impacts to operator response
times. Again, they run the thermal-hydraulic codes to
establish what those times are. Typically what you
see is impacts on the ATWS sequences in dealing with
SLIC initiation, or inhibiting ADS.
As an example, for Duane Arnold that time
changed from -- for early SLIC initiation, it changed
from 6 minutes to 4 minutes, and the human error
probability changed from about 10 to the minus 1 to
about almost .2.
DR. KRESS: They used 10 to the minus 1
for their human error probability on that?
MR. HARRISON: On that one.
DR. KRESS: Good. They didn't use 10 to
the minus 3.
DR. LEITCH: Right.
DR. KRESS: And is this a plant that copes
with ATWS by reducing the water level going into the
core pretty far?
MR. HARRISON: Yes. I don't know how far,
but they do lower water level to control power level.
CHAIRMAN WALLIS: This 10 to the minus 1,
is this just somebody's guess or is there some
evidence on which it is based?
MR. HARRISON: It is using a --
DR. KRESS: Do they use the EPRI model?
MR. HARRISON: I am getting a shake of the
head. Yes, they use an EPRI model for that.
CHAIRMAN WALLIS: Because every time I see
a round number like 10 to the minus 2, or to the minus
1, I assume it is error, and that it is a factor or 2
or 3 anyway.
MR. HARRISON: But I am rounding off.
Their numbers were really 1.1 and 1.8, but --
CHAIRMAN WALLIS: Oh, I see. So they
weren't just one-tenth of something.
MR. HARRISON: Right.
DR. KRESS: Which is false and misleading
in terms of the --
MR. HARRISON: Right. When you are
dealing with these limited times, you either make it
or you don't make it.
CHAIRMAN WALLIS: When they evaluate this
do they actually talk to operators?
DR. KRESS: Well, the models are based on
operator simulation.
CHAIRMAN WALLIS: Simulation responses?
DR. KRESS: Yes.
CHAIRMAN WALLIS: So it is real data then?
DR. KRESS: It is a data based model, but
it really has not been quantified very well, and they
treat them as if there is no error in them.
DR. LEITCH: I assume that Duane Arnold
doe snot have automatic SLIC initiation, or are these
numbers --
MR. HARRISON: Right. These are manual
initiation of SLIC, and they have an early and they
have a late. So if they don't do it early, within the
first four minutes of the power uprate, then they have
until about 12 minutes, which is late for SLIC
initiation.
As part of this, I indicated that it was
driven by the operator actions of an increase in their
CDF of about 10 to the minus 6, and an increase in
their LERF value of 1.39 to the minus 7 per year.
DR. KRESS: Just out of curiosity, what is
the Duane Arnold CDF and LERF?
MR. HARRISON: The CDF at Duane Arnold,
post-uprate, is 1.29, 10 to the minus 5 per year; and
the post-uprate LERF is 9.9 to the minus 7 per year.
So you are getting about a 9 percent increase in CDF,
and approximately a 16 percent increase in LERF.
CHAIRMAN WALLIS: And most of that is due
to ATWS is it?
MR. HARRISON: Most of that is driven by
ATWS. There is some contribution from the transient
non-ATWS, where you have high pressure failure and the
operator fails to depressurize.
CHAIRMAN WALLIS: What is the uncertainty
in the prediction of this water level during the ATWS?
DR. KRESS: It is pretty uncertain because
it is tied into the actual calculation of what power
you have got, and its relationship between power and
water level.
CHAIRMAN WALLIS: And maybe G.E. can
respond to that this afternoon.
DR. KRESS: Well, in fact, there has been
a big argument over the years about how to make that
calculation and what it actually ought to be. So
there is a lot of uncertainty there.
DR. LEITCH: There is also uncertainty in
how the water level is measured in those situations as
well.
DR. KRESS: Yes.
DR. LEITCH: And whether where the water
level is measured is indicative of what is really
happening inside the core is another question.
MR. HARRISON: The final bullet on this
slide is just to recognize that they did look at
external events, such as fires and earthquakes. The
same operator actions carry through into that
analysis, but it has a minuscule contribution.
DR. KRESS: Yes, I guess that is not
surprising.
MR. HARRISON: Right.
DR. KRESS: Did they include any shutdown
considerations in that?
MR. HARRISON: We will get to that.
DR. KRESS: Oh, okay.
CHAIRMAN WALLIS: The next page.
DR. KRESS: I'm sorry. I didn't read
ahead.
MR. HARRISON: Okay. The next category is
component reliability, and again they don't expect any
changes. They maintain functionality reliability by
monitoring programs, and they identify the few there,
such as maintenance rule, erosion and corrosion
program, condition monitoring, similar to the
initiating events, such as the frequency discussion.
On shutdown risks, they did not do a
shutdown risk model. What they did talk about was the
fact that they followed the guidance of New Mark
91.06, where they control the five conditions.
They monitor to get heat removal
capability, and inventory control, and availability of
electrical power, containment control, and reactivity
control.
And they just talk about maintaining those
controls and being aware of the condition they are in
before they remove equipment out of service. The
other point they did make was that at the increased
power level and decay heat, you are going to take
longer to shut down. You are going to have to run
your decay heat removal system longer.
DR. KRESS: That was one of my questions
was going to be; is are they going to use their same
schedule for shutdown maintenance, or are they going
to extend it out based on the new power limits?
MR. HARRISON: The number of hours in
order to get down.
DR. KRESS: So if they wait long enough,
then they are back to the same risk level essentially?
MR. HARRISON: If you wait long enough for
the decay heat to go away, then yes, and that just
seems to be straightforward.
DR. CRONENBERG: Under RAI ability, you
accept that there is no change anticipated, or do you
have additional information pending, or what is the
status of your review on the component reliability?
MR. HARRISON: In the are of component
reliability, we have noticed this I think in the other
reviews that we have done, that there really doesn't
tend to be an impact in this area from these uprates,
and so we have not pursued any additional questions in
this area.
DR. CRONENBERG: Including the balance of
the plan?
MR. HARRISON: And for Duane Arnold, that
is correct. For our other submittals, we are pursuing
as part of initiating event frequencies and related
component reliability of the uprates that they are
doing to the balance of plant site, that could impact
the PRA model.
MR. RUBIN: This is an area where we
really need to see some data if there is an impact,
and we can't identify a mechanistic change, like a
variation success criteria or fluid conditions.
It is really is not possible to predict it
in a way to build it to the risk model. However, if
we do start to see changes, most of these items, or I
think all of these items will be captured by
observations in other programs.
Plant trips will be caught by the firm's
indicator program, and they will be monitored for the
assessment program, and the reliability and
availability of safety systems is monitored through
the maintenance rule as was mentioned, as well as by
the performance indicator program.
I certainly would be very interested to
see the impact, and as was mentioned before, we should
probably at some point in the future follow up to see
if there is a change. But it is not envisioned that
there is right now,.
DR. CRONENBERG: Your response relies on
the monitoring program and after the fact as an
indicator, when you know you have uprates of 17
percent, and 15 percent, and 20 percent, you know that
you are doing changes to your balanced plan before the
systems and so forth.
It seems to me that I would have things on
corrosion and erosion for plants that are 30 years
old, and I would have some questions at to those.
MR. RUBIN: I am sure there are questions
in that area from the division of engineering. It is
not an area where the risk assessment would have it in
the model.
DR. CRONENBERG: Okay. I am asking the
wrong people then, I suppose?
MR. RUBIN: In a sense, yes.
MR. HARRISON: And keep in mind that the
information that I am sharing is strictly a PRA
perspective. You are going to see it on another slide
as to plant systems, and other groups will be tracking
things that we don't track.
This is just a transition slide, and the
next things that we are going to talk about is that we
will quickly talk through PRA quality, and we will
just give you a quick information dump on what we see
as the risk impact that shuts down operations.
And then we will jump directly in to the
six questions from the ACRS. PRA quality seems to be
a topic that is catching everyone's attention these
days, and I do want to point out again that at least
with the Duane Arnold submittal that they made it very
clear that they were not a risk-informed licensing
action.
The staff is reviewing the risk and
pursuing that angle, but just to understand that the
licensees don't necessarily see this as risk informed.
DR. KRESS: Their PRA license
certification process, that gives it some level of
assurance that it is a pretty good PRA.
MR. RUBIN: The certification isn't a
pass/fail. It is a --
DR. KRESS: It gives you a classification
and that these can be used for these things.
MR. RUBIN: It gives you evaluations in
various areas, and I am not sure which -- well, there
is no overall assessment I guess is the way that I
would like to leave it.
DR. KRESS: Well, did you guys go to the
certification review findings just to see what they
said?
MR. HARRISON: That is the last bullet on
this page. We are talking there about possibly
sitting down and taking a look at the peer review that
was performed.
DR. KRESS: I'm sorry, but I didn't read
ahead.
MR. HARRISON: Shame on you for jumping
ahead.
CHAIRMAN WALLIS: I guess our view of
quality in peer review is how much you can rely on the
answers you are getting, and that is within a certain
context. So it is a measure of how uncertain are your
answers compared with how certain you need to be in
order to make a decision.
MR. RUBIN: Right.
CHAIRMAN WALLIS: I don't see that at this
point in your discussion on PRA quality.
MR. HARRISON: The point that I am making
is that I am trying to make that point with the second
one, is that the licensees are still meeting their
deterministic requirements, and they are still
meeting the regs.
They are saying essentially, if I can put
words in their mouth, that they are not relying on the
PRA to make these decisions for that.
DR. KRESS: So you are constrained to have
to go by that, but you have one panel to get a hold
of, and that is that there is a significant risk
associated with that.
MR. HARRISON: We have a way in.
DR. KRESS: You have a way in, and so you
need to see if there are significant risk changes.
MR. HARRISON: Right.
DR. KRESS: You need some sort of PRA.
MR. HARRISON: And that is my third
bullet, that the staff is assuring there is no
significant risk change, and that there is no new
vulnerability identified that we didn't know before.
We want to make sure that we are not on a
cliff and a power uprate takes us from being in a safe
condition to being in an unsafe condition. So that is
a perspective.
DR. UHRIG: Does Duane Arnold have an on-
line risk monitor like some plants do?
MR. HARRISON: They have -- is it ORAM?
I don't think that is on-line, but that is a shutdown
part of the model. I don't think -- I really don't
know.
DR. UHRIG: That is just part of the PRA.
MR. RUBIN: I guess we don't have the
answer to that question. We would have to check with
the plant if they have a real time --
DR. UHRIG: There are some plants that do
have it and use it extensively.
MR. RUBIN: There are also plants that
have fast running models that they can requantify
every morning in addition to the ones that have actual
real time monitors, and I don't know where Duane
Arnold falls. Perhaps we could ask them if they know.
MR. BROWNING: Again, this is Tony
Browning of Duane Arnold. We are closer to the middle
category. We use the PRA to do our on-line
maintenance planning surveillance testing, and we get
a field there for where we are in risk space.
And then it is color-coded, and it is part
of the plan every day when we go out and do
maintenance so that we know exactly where we are at.
And emergent issues that come up can be factored back
into the model and tell us do we need to make changes
from what we planned.
But, no, we don't have the full-blown
continuous on-line risk meter if you will.
DR. UHRIG: This will be upgraded with the
increase in power?
MR. BROWNING: Yes, the models will be
upgraded as we make the changes, and in particular
like they said on their slide, we have a living PRA,
and as the modifications are put into place those
effects will be modeled.
DR. UHRIG: Thank you.
MR. RUBIN: If I could give an observation
that when we were doing the baseline maintenance
inspections, the plants that had the capability for a
quick running quantification PRA model, it was
certainly a significant strain in their ability to
monitor the plant operations. A number of plants
essentially rerun the model every morning.
DR. FORD: If I could make a comment. The
PRA, I recognize that there are limitations with the
PRA methodology, especially when it comes to time
dependent phenomena. And when in the last couple of
months, it has been drummed into us time and time
again that the public perception of this whole
business is very important obviously.
It just concerns me when you look at time
limiting and aging events, which we know historically
occur, and the public knows that it occurs, that I am
not hearing crisp answers to these particular issues
when it comes to aging concerns, and when it comes to
these particular out uprates.
I guess my question is more a comment, but
my question is at what time do we hear crisp answers
to these aging concerns? Like, for instance, an
informed person in the technical public could say that
you should have a concern for fluence corrosion, or
you should have a concern for flow induced vibration.
You should have a concern for irradiation
effects on core shrouds, for instance.
These are all reasonable topics, and they can all be
put to rest.
MR. RUBIN: Well, they certainly are.
They are in the areas of materials, chemical
engineering. We have a group that is involved in the
review, I think, and perhaps we should get their views
--
DR. FORD: I guess my question is when do
we hear it.
MR. HOPKINS: I guess I thought we had
already made a presentation on erosion and corrosion
previously to the subcommittee.
DR. FORD: I apologize to the group then.
DR. KRESS: He was not here during that,
but you did make such a presentation.
MR. HOPKINS: I think a better answer is
the staff has to complete its review of Duane Arnold's
submittal before we can really give that answer to
you, per se, and we are still reviewing that.
DR. KRESS: I think that your answer is
that you are concerned with those things, and you have
programs to look at them. There are concerns for
operating reactors that aren't being upgraded, but the
question is does an uprated power do significant
change to those.
And the answer that I am hearing is
probably not, but we don't have good data to back that
up on some of them. Some things like chemical
effects, we don't know if a power uprate is a
significant effect.
We know how to deal with flow accelerated
corrosion to some extent, and we know how to deal with
fluences, but intergranular stress corrosion cracking,
I don't know power uprate would do that.
So the answer is that I think that you are
concerned with it, and you have programs looking at
them, and the power uprate may not significantly
change the concern. You are still concerned, and I
don't know what else you can say about it.
MR. HOPKINS: Well, to some extent a power
uprate is different from license renewal. I mean,
they each have the same concerns, but some are more
concerned about power uprate than they are with
license renewal, let's say.
So there are separate concerns, and in
each case we look at those issues, be they time aging,
or increase in fluence, or a small increase in
fluence, and increase in flows, and that sort of thing
for each review, to reach a satisfactory answer.
Duane Arnold is the first extended power
uprate review, and we are not complete. So I guess I
am still back to when we complete the Duane Arnold
review, that is when we are in a better position to
decide.
DR. FORD: I guess it is a question of
timing that I was bringing up, you know. I don't
doubt that these questions are being addressed that we
brought up, but you are saying that this is going to
be finished in the year -- well, later this year,
2001.
MR. HOPKINS: Yes.
DR. FORD: So when it comes to this
committee, is it not a wee bit late for us to be
saying suddenly, well, what about this, or what about
that? Doesn't that completely put a stone in the
works as far as timing is concerned?
MR. HOPKINS: Yes, it may. But I don't
see any way around it. The staff has to do its review
when we do our review. The fact that the licensee may
have requested a schedule and trying to meet it, and
how much time we have to present to the ACRS, I think
the ACRS should take its time to consider things that
they can.
But we can't work faster than we are
working. So I'm sorry about that.
CHAIRMAN WALLIS: I am not suggesting
that. I was wondering when you were asking for crisp
answers if you were asking about the confidence in the
expertise of the staff in evaluating things.
DR. FORD: No, I am not questioning the
competence of the staff.
MR. WU: I will try to answer Peter's
question. This is John Wu again. I think I mentioned
before, sir, about life extensions in the power rates,
and the corrosion between them. Peter mentioned the
corrosion and erosion, and also mentioned the flow
induced vibrations.
In the life extension programs, the review
includes, for example, the corrosion and erosion, and
also review the aging management program, which is
management controlled or managed by inspection, and
also the chemical control.
And in flow induced vibrations, we look at
the usage factor. Say the usage factor now and then
for 60 years, and see how much it is going to be, and
what is the factor and we are including that in the
review. So that has been done. The review has been
done.
DR. CRONENBERG: Why don't do you a
cumulative usage factor for power uprates?
MR. WU: We do have the cumulative
factors. You mean including the lab extension?
DR. CRONENBERG: No, not for lab
extension.
MR. WU: For the power uprates, yes.
DR. CRONENBERG: As part of the review
procedures for licensing, do you have to do a time
aging analysis.
MR. WU: If they have the power uprates,
they also include in the reviews for the time limiting
aging reviews, aging analysis. They include it in the
usage factor.
DR. CRONENBERG: I looked at a number of
reviews, like in the '90s when we did 4 or 5 percent
type of increases, and I never saw a cumulative usage
factor estimate in those reviews. It is something new
for these major, major increases.
DR. CRONENBERG: Is this something that
you knew that the licensee is required to do for the
15 percent?
MR. WU: Are you talking about the
extension, the lab extension?
DR. CRONENBERG: The time limitation on
the CUF factors or estimates, cumulative usage factor
estimates. I never saw them before.
MR. HOPKINS: I don't know. We don't have
Barry Elliott here anymore, and this may be more in
his bailiwick.
DR. CRONENBERG: They certainly weren't in
the SERs that were talked about.
MR. WU: I will find out about the lab
extension on this cumulative factor, but for the power
uprates, we have reviewed the cumulative usage factor.
DR. CRONENBERG: And it is based on --
MR. WU: On 40 years.
DR. CRONENBERG: -- historical data and
number of plants, and --
MR. WU: Yes.
DR. CRONENBERG: -- all those sorts of
things?
MR. WU: Yes. Yes, that's right.
DR. CRONENBERG: And that is impacted by
the uprates?
MR. WU: Yes, sir.
MR. HOPKINS: Well, I think we got a
little sidetracked, but I am back to the staff trying
to review Duane Arnold and the staff is doing that as
efficiently and as fast as we can. And I think maybe
to give you more specifics, we have to complete that
review.
DR. KRESS: Do you have a standard review
plan for power uprates?
MR. HOPKINS: No, we do not. We
considered that and at this time we have not felt it
to be worth the effort, but no.
DR. KRESS: But with all these predictions
about what might come in for power uprates, are you
thinking about reconsidering that?
MR. CARUSO: Dr. Kress, BWRs have approved
topical reports when you describe the uprate process.
DR. KRESS: Well, actually we reviewed a
couple of those.
MR. CARUSO: Right, and those serve the
same purpose as a standard review plan for BWR power
uprate reviews. They identify the key issues, and
they identify what has to be looked at, and what has
to be done by the licensee by the vendor, and by the
staff.
So to a certain extent, for the BWRs, yes,
we do have -- we don't have an actual standard review
plan, but we have a surrogate.
DR. KRESS: This almost looks like a
standard review plan.
MR. CARUSO: That's why I say it is really
the substitute surrogate.
DR. KRESS: And you don't expect this
magnitude of power uprate for PWRs do you? Aren't
there limitations there that keep them down a little
lower maybe?
MR. HOPKINS: Yes. I think most PWR
uprates will be on the order of five percent and it
maybe if they replace steam generators, it might be 10
or something.
DR. BOEHNERT: Yes, some are coming in at
10 or thinking about 10.
MR. HOPKINS: But aren't those that have
replacements involved?
DR. BOEHNERT: I think so.
CHAIRMAN WALLIS: We seem to be falling
behind.
MR. HARRISON: Okay. I will pick up the
pace. The last part is just to let you know that the
staff is looking at the change in CDF and the change
in LERF.
Most of these -- some of those we expect
them to have peer reviews done on them at some level,
and there is always the option for us to review either
the peer review or the PRA itself.
MR. RUBIN: Perhaps I should ask the
committee if they want to go through each of the
questions, or do you just want to select some that you
want to hear? We were planning to go through them, of
course, but to save time --
DR. KRESS: There are some interesting
questions here.
CHAIRMAN WALLIS: Well, I guess since we
asked them, and you can answer if you like.
MR. HARRISON: Okay. I will run you
through shutdown real quick, and then we will jump to
the questions. You are going to get increased decay
heat and so that is going to extend the time the KE
heat removal system is going to have to run, and
remain in service.
As a result of the increased decay heat,
you are going to have reduced upper response times.
There is going to be a lower time to boiling. The
main effect is to PWRs that have a mid-loop operation,
where the time is restricted to start with.
Those operations would be a higher risk
than for BWRs that tend to have more inventory and
more time to respond to things.
CHAIRMAN WALLIS: Is this a significant
change in the stored energy?
MR. HARRISON: In the stored energy?
CHAIRMAN WALLIS: Well, the fuel is
hotter.
DR. KRESS: It is almost a percent change,
and not quite, but you can almost do it that way.
DR. SCHROCK: What I heard them say is
that the linear power is not changed. They are just
getting a higher power through flattening. So if the
linear power is unchanged, then the center line
temperature is unchanged.
CHAIRMAN WALLIS: But there is more stuff
on the outside that is hotter than it was before. So
there is integrated decay and also integrated --
DR. SCHROCK: The average temperature is
higher than it was, right.
MR. HARRISON: And I believe it is
considered proportional to decay heat.
DR. KRESS: The decay heat is
proportional.
CHAIRMAN WALLIS: And so all the effects
are the same.
MR. HARRISON: Right.
CHAIRMAN WALLIS: Because it is a shorter
duration.
MR. HARRISON: Right. I will skip the
next slide. It just lists the six questions that the
ACRS asked, and I will jump to the first question.
The first question basically was asking if
we needed additional acceptance criteria to address
the frequency of releases of all magnitudes, and just
to state that Reg Guide 1.174 philosophy is that
increases in CDF and risk are small and consistent
with the Commission's safety code policy.
DR. KRESS: Well, the intent of the
question was to challenge the Reg Guide 1.174
philosophy.
MR. HARRISON: I think we were aware of
that.
MR. RUBIN: Well, we certainly concurred
with the advisory committee when they endorsed the
criterion in the reg guide. To look at it now for
uprate, I don't think we see anything that calls the
reasonableness of those criteria to question.
DR. KRESS: Well, let me ask a couple of
questions about that since this is one of my
questions. Let's talk about LERF. Now, LERF was in
the Reg Guide 1.174, and there is an acceptance
criteria that is based on the actual absolute value of
LERF.
You know, the closer that you get to the
absolute value, the more regulatory attention one
pays. And that absolute value that they stuck in
there was a surrogate for fatalities.
Now, if you uprate the power by, say, 20
percent, and if you also have maybe three plants or
two on a site, that is a 40 percent uprate on site
power.
So to me that means that the consequences
or the probability of -- well, they are not exactly
linear, but the probability of fatalities has gone up
to 40 percent at that site.
And it would make sense to me to reduce
the acceptable LERF value to be a surrogate for that
by 40 percent. So I am questioning, number one, here
you have a fixed LERF as the acceptance criteria, when
in reality the LERF ought to depend on the power. So
that is question number one.
And question number two is LERF and CDF
don't capture all your risk matrix, and it doesn't
capture any suicidal risks, in the sense of total
deaths or land contamination. And it doesn't capture
releases of fission products of all frequency, short
of causing deaths.
And one of the studies in Europe showed --
and I forget which plant it was for, but it showed
that there was a significant increase in fission
product release at lower frequencies, although it
would not have affected LERF at all.
It was a significant concern to them, and
so those were the nature of the questions that were in
my mind when this was formulated, and it is actually
challenging the 1.174 guidelines and criteria, and not
that I don't think that they are relatively good, and
I do support them.
But I am not sure that they are
universally applicable under all conditions is my
problem.
MR. HARRISON: I think we would agree that
of course they are not universally applicable. But
within the bounds of the issues that were considered
when the criteria were developed, I think they are
still applicable for a power uprate of this kind, and
I will be more specific.
When the 1.174 criteria were developed,
whether with absolute criteria, or really guidelines
rather than criteria, but absolute guidelines,
percentage guidelines.
A lot of things were debated, and a number
of members here were in on those debates. And the
ultimate decision was to have guidelines that were
site and plant independent.
And within the spectrum of the currently
operating power plants, we have plants at 700
megawatts, electric, and ones at almost 1,200. And
the risk between those two plants will be -- the
differential will be larger than what we are talking
about here for the uprated plant.
Does that mean that we are not considering
the relative risks? Well, there is a lot of margin in
the safety goal between many of the plants with the
frequencies of large release and core damage.
I think that you will find that a lot of
the boilers have themselves on the lower end of the
spectrum on overall core damage frequency. Sometimes
initial containment failure tends to be somewhat
higher.
But we still are seeing a lot more
variability on just the range of currently operating
plants than in the change that we would be applying
here.
DR. KRESS: That was another debate that
we had. The line that was drawn through the pump
fatality scattered curve was the mean, and we wondered
whether that might not be somewhat higher. I mean,
not to capture more of the plants. But that was the
-- it ended up being the mean.
MR. HARRISON: But I think the underlying
assumption is that regardless of where your plant is
sited, and regardless of what your base risk is, that
the increases need to be small.
DR. KRESS: And I think that is a good
guideline, and the other that I was actually expecting
you to say is that the rest of 1.174 says that you
meet all the other regulations.
And since this was a non-risk informed
submission, clearly it meets all the other
regulations, because that is the philosophy behind
that.
And that would control in my mind these
lower frequency releases for this particular
application. But the question was more general; that
if you actually had a risk informed application would
you have problems along those lines somewhere.
MR. HARRISON: I think if we started to
see power uprates well beyond the upper range of
currently operating plants, and well above 3,900
megawatts, that might be the time to maybe take
another look at the LERF guideline to see if it needed
to be reassessed.
And in fact if you look at the upcoming
revision to Reg Guide 1.174, you will see that concept
reflected in that.
DR. KRESS: That's right. We are dealing
with a revision aren't we?
MR. HARRISON: Yes, sir.
DR. KRESS: And I look forward to seeing
that. But anyway essentially 1.174 is all you have
now, and so you are pretty much constrained to say
that is what we would use.
MR. HARRISON: And if you want, we can
jump to the very last slide on the study that you --
DR. KRESS: I think that was the one that
I referred to.
MR. HARRISON: It is the very, very last
page of the package there. They did a 15 percent
power uprate and they stayed the same four areas as
the NRC does in the area of PRA upper reactions, and
success criteria, issuing event frequency, et cetera.
The one thing that the regulator did was
put a hold on success criteria and said that it will
not change. You will lower your power level if it
does, and so that was one condition that they put on
there.
DR. KRESS: What do you think about that?
You don't have a position on that?
MR. RUBIN: No, but if it was a
significant change, it would be reflected in the risk
analysis, and then we would be in a position at least
to know what the impact did, and to make an educated
decision.
DR. KRESS: Rather than just absolutely
making --
MR. RUBIN: It could be a trivial change,
and it could be a significant change. I think
modeling it and looking at the impact makes more
sense.
CHAIRMAN WALLIS: But that's if LERF stays
the same, but the release goes up, and the overall
risk does go up by something like -- well, more, and
how do you assess that?
MR. HARRISON: What this study gave was a
frequency, a time, and it wasn't really a frequency.
It was a time period of a period content, and so the
inventory goes up, and it gets released a little
earlier.
So you have a shift, and so what they did
find was none of the release categories changed. So
late stays late, and early stays early, and small
stays small, and large stays large.
Everything just kind of shifts a little
earlier, and you are getting a 15 percent increase in
inventory. So, yes, there is an absolute --
CHAIRMAN WALLIS: So with the effect of
public safety, what is the measure of small? It's not
that it goes up by 25 percent, but it goes up by
something, and integrates overall frequencies and so
on to get some measure of change in public risk, and
how much does it go up?
MR. HARRISON: This study did not take it
to that level. It did not take it to a dose
consequence.
CHAIRMAN WALLIS: Then how do they know it
was small then?
MR. HARRISON: We are talking about --
CHAIRMAN WALLIS: The overall risk, and
looking at all possibilities and all frequencies, and
all releases, what is the net change by some measure?
They don't do that?
DR. KRESS: There is no acceptance
criteria that I know of.
CHAIRMAN WALLIS: Well, there might be one
in this one.
DR. KRESS: Well, the Swedes have an
actual acceptance criteria based on frequency of
release of all risk, and there you have something to
gauge to, but we don't have anything like that.
MR. HARRISON: Right. What they did show
was that when you go through the level two analysis
that the binning stays the same, and so your release
categories don't change. Your exit sequences don't
change. It is a matter of timing and just basic
inventory.
CHAIRMAN WALLIS: Well, when you have
release increases of 25 or 30 percent, what does that
-- how does that affect your conclusion about overall
risk? There must be some mathematical way of going
from 25 to 30 percent to something which you think is
small?
DR. KRESS: Well, it is not linear, and
the consequences are -- well, this is related to
consequences, and they have already said the frequency
is not going to change very much.
So it is frequency times consequences, and
the consequences of that kind of increase is not
linear at all, but you could almost say that it is
bounded by 25 or 30 percent.
CHAIRMAN WALLIS: So it couldn't be bigger
than 30 percent?
DR. KRESS: It can be, but it is not much
bigger. It is all in your consequence model, and what
iodine does to you, and things, but it is going to
increase at least 30 percent and you can say that, but
that is not much of an increase if you are already
down to 10 to the minus 7.
And a 30 percent increase in 10 to the
minus 7 is not --
CHAIRMAN WALLIS: I would like to have
that sort of rationale than just a statement that it
is small.
MR. HARRISON: And again I would say that
the definition that they use for risk is increase of
source term, and it is not necessarily a dose to
somebody. It is really just a stretch of the level
two.
DR. KRESS: Yes.
CHAIRMAN WALLIS: Yes, but I think the
answer should be crisp rather than discursive. That
there is some sort of rational mathematical model that
gets you from the 30 percent or whatever you use as a
button line --
DR. KRESS: It is a delta-LERF is what it
is.
CHAIRMAN WALLIS: -- to say that he
overall risk is small.
DR. KRESS: Well, they use delta-LERF and
that's it.
CHAIRMAN WALLIS: And it is not affected
at all by the release.
DR. KRESS: It's probably not, that's
right.
MR. RUBIN: That is the point of the
question, Dr. Kress.
DR. KRESS: And that is basically the
point of my question.
MR. RUBIN: In a sense, it is a limitation
of the method, but it also reflects the reality that
the source term is just the same as a source term for
a similar power plant next door that was running at 70
megawatts higher of power.
DR. KRESS: But I don't like that
question, because a source term is fraction of
inventory, and that is not a good answer I don't
think.
MR. HARRISON: And the overall result of
that study was basically the conclusion that they were
-- that this risk increase is still within the
uncertainty band of the phenomenology.
DR. KRESS: That's for sure.
MR. HARRISON: So we are going to have to
have a much larger increase impact than that to even
get outside of the --
CHAIRMAN WALLIS: So what you are saying
then is that you apply the rule that everything is now
fine, and you are a little bit uncertain about how you
take care of this thing, which is not really accounted
for by the rule, but you are not really too worried
because the effect is not really big as far risk is
concerned.
DR. KRESS: And they still meet all the
figures of merit in Chapter 15, which is a level of
comfort to some extent with respect to this.
CHAIRMAN WALLIS: So question two.
MR. HARRISON: We will go back to question
two. Question Number 2 dealt with margins.
DR. KRESS: I think you basically answered
my question on that one, and that is the bottom line,
that you can use margins all the way up to the limit.
MR. CARUSO: One of the questions that you
raised during the earlier session was about fuel
center line temperature. We talked a little about
that at the break and these power uprates are not
raising fuel center line temperatures.
What they are doing is they are flattening
power profiles throughout the core so that you don't
-- so that the limiting bundle is still operating
where it was before.
But what you are having is that you are
having other bundles which were previously well below
that operating much closer to that limiting value.
And the other question you raised about
operating. Even if you were operating with a higher
center line temperature, fuel melting is not allowed.
There are design criteria that prevent that, and we
were also thinking about the fact that even if you
were operating with higher fuel temperatures, realize
that through its life that the fuel doesn't maintain
its monolithic character. It fragments quite a bit.
So it is not clear to us how much
additional release of fission products you would have
from the fuel because you are operating a little bit
hotter, because I would have to go back and see how
much additional fragmentation would occur.
And I am not sure that the increase in
that temperature really would increase the fission
product release into the gap by that much other than
the linear race due to the fact that you are burning
up faster, and so you would have a higher inventory.
And other than that, I am not sure that
the power uprates are really changing gap activities.
DR. KRESS: The gap activity is probably
not risk significant anyway. I mean, it has to do
with operational things, and how fast you close
isolation valves and stuff like that.
But it is probably not a risk significant
thing, unless you are talking about PWRs, and if the
gap inventory actually has some effect on the iodine
spike, and you have a steam generator to rupture,
which is all speculation on my part that it would. But
I can't see any problem with BWRs frankly.
MR. HARRISON: And we will hit that
portion, and I think that is question number four on
the gap fraction of the iodine spiking.
DR. KRESS: The other thing about the
margins that occurred to me when we asked this
question was you have margins now for these figures of
2,200 degrees, and that are met generally well below
the value, and it has been deemed an acceptable margin
because you have some idea that the calculations to
get those involved build in conservatisms.
And as you approach that margin more and
more, I think that your level of comfort about what
those built-in conservatisms do for you, since they
have never really be quantified about how much
conservatism there is added into the calculation, that
your level of comfort about having conservatisms in
your calculations is eroded somewhat.
And to me it says that when we get closer
and closer to those margins, maybe we ought not to
rely on Appendix K, and ought to go to the best
estimate approach. And actually quantify the
uncertainties.
MR. CARUSO: That is what is happening.
DR. KRESS: And once you quantify the
uncertainties, then I see a missing element, and that
is how to factor that in to how close you can get to
these many figures of merit.
I don't see that missing link, you know.
I have got the conservatisms, and I have got a
calculation of the mean or the distribution and how
close it is to the margin. So now what is acceptable
to me.
CHAIRMAN WALLIS: Well, you are getting at
the bottom line here. I think what the bottom line
says is that they control up to the -- well, it is not
really limits on margins. The limits are on things
like temperature, like 2,100 degrees.
But there is nothing that says that you
have got to have a margin of so much, which is in some
approved way.
MR. CARUSO: Margin was used to establish
the limit.
CHAIRMAN WALLIS: Margin simply means that
the prediction is below the limit, that's all.
MR. CARUSO: The prediction is below the
limit.
CHAIRMAN WALLIS: And there is no
quantification of margin whatsoever in the
regulations.
MR. CARUSO: It depends on what it is that
you are calculating. As I said, we are seeing more
and more people trying to do statistical
quantifications.
The SAFER/GESTR method actually is a very
early attempt to do that, and if you look at the
SAFER/GESTR methodology, you will find that they meet
the 2,200 degree limit, but the staff has imposed
actually I believe a 1,600 degree limit on SAFER/GESTR
on a separate non-licensing calculation as part of
SAFER/GESTR, which is called the upper bound PCT,
which includes a certain uncertainty factor.
So it is a way of -- I don't want to get
into the details of explaining this, but they have two
limits; one which is much lower, and which is where
they actually believe the plant operates.
But then they take a penalty because of
difficulties in quantifying the uncertainty to make
sure that they stay below 2,200.
CHAIRMAN WALLIS: So does anything change
with uprates then? This is what you have been
accepting. Is there anything different about uprates?
Are their margins significantly reduced or anything?
MR. HARRISON: They are coming closer to
these limits.
CHAIRMAN WALLIS: But not by much. Are we
going to hear that from G.E.?
MR. HARRISON: I think so.
CHAIRMAN WALLIS: From my reading of it,
it didn't look like much of a change, but I am not the
regulator. You are much more experienced than me
about whether it is significant or not.
MR. HARRISON: Well, one of the things
that -- well, remember what I said when I started just
now was the peak limiting bundles on changing, and
what they are doing is flattening the power shape
throughout the core.
And so there are lots of areas in the core
right now that aren't carrying their loads so to
speak.
CHAIRMAN WALLIS: I guess the think that
-- the question really to ask is not what the
licensees and vendors are doing, but what you will
decide to accept as a margin. What is your criterion
for accepting a margin, and not what the licensees and
vendors are controlling.
MR. HARRISON: Well, we have one li mit in
Appendix K, and the other limits come from reviews of
the topical reports. We had some old limits that were
very deterministic, and very conservative, and now we
depend on the vendors and the licensees to come to us
with proposals and we talk to them.
CHAIRMAN WALLIS: And you negotiate?
MR. HARRISON: And we negotiate.
CHAIRMAN WALLIS: And you use your
judgment?
MR. HARRISON: That's right.
CHAIRMAN WALLIS: But you don't have a
sort of spelled out --
MR. HARRISON: And we call on our friends
in the Office of Research to help us, and we call on
our friends in the ACRS to help us.
CHAIRMAN WALLIS: But you have not got
spelled out criterion for margin approval?
MR. HARRISON: You would have to look at
the details of each individual topical report.
DR. SCHROCK: Is it true that the limiting
bundle power isn't changed? That implies that all the
flattening is radial and none axial.
MR. HARRISON: I think there is also
flattening in the axial direction.
DR. SCHROCK: Then there would need to be
a higher bundle power.
CHAIRMAN WALLIS: We will get that from
G.E., I guess.
MR. HARRISON: I am hearing only radial.
CHAIRMAN WALLIS: Well, it's not too
obvious from this material here. I mean, if that is
what they are doing, then it needs to be said up
front, because then you stop asking all the questions.
We probably need to move on. We are not making much
progress with margins.
DR. SCHROCK: Marginal progress.
MR. HARRISON: Question Number 3 was a
question relating to the need to reflect the increase
burnup.
CHAIRMAN WALLIS: There isn't any
increased burnup is there?
DR. KRESS: There is an increase in the
average burnup, but they are still within the limits.
MR. HARRISON: And also if you changed
your operating cycle or whatever, and to extend the
cycle, then that would have an effect on your burnup
as well. But it is indirect, and not a direct effect
of the power uprate.
The use of the thermal-hydraulic codes
that are used to establish the success criteria and
the operator timing, the staff feels that should be
reflected what your core is. That is part of PRA
quality; do you reflect your current design or your
projected design in operating conditions.
However, I will point out, and as I think
you are all aware, that the delta-LERF will probably
not reflect the increase in inventory and that is the
prior question.
DR. KRESS: That is the same thing you
said before. I was wondering if -- well, it does give
a potentially bigger insult to the containment.
MR. HARRISON: Right.
DR. KRESS: And that is calculated.
MR. HARRISON: That would be calculated.
That would be passed through from --
DR. KRESS: So, delta-LERF would reflect
that.
MR. HARRISON: Right. And actually on
Duane Arnold, even though the CDF went up by 9
percent, the LERF went up by 16 percent, and it had to
do with the predominance of it being ATWS events. So
that pushed you -- you had a disproportional amount of
the scenarios being pushed earlier.
DR. KRESS: And ATWS is the dominant
sequence for doing Arnold isn't it?
MR. HARRISON: Yes, it is.
CHAIRMAN WALLIS: I am sort of assuming
that you are going to be finished by 11:30, and then
we can have Jack Rosenthal so that we can get to lunch
before noon?
DR. KRESS: It all depends on us.
MR. HARRISON: We only have two more
questions really. So we if can walk through them
quick. And question four had to do with the impact on
the design basis analysis source term.
As we said before the fission product
inventory will increase. There was a question on gap
fraction, and it is considered -- well, the power
uprate has no direct impact on the gap fraction. It
is a function of the burnup of the fuel.
DR. KRESS: And it doesn't have any effect
on the gap fraction, but it does have an effect on the
total amount.
MR. HARRISON: On the inventory. And on
the second part of that dealing with the iodine, I
think it was mentioned earlier that the appearance
rate and spiking factor are based on the tech spec
equilibrium activity, and I believe the staff
believes that the 500 times multiplier that is used
compensates for any uncertainty that is in the iodine
spiking.
DR. KRESS: Well, that is one of the
things. This was Dr. Powers' question, that part of
it anyway, and that is one of the things that he will
stand up and make a few statements about.
We had a lot of discussion about this 500
with respect to the differing professional opinion,
and we weren't very pleased with it. But that is all
you can have is what is in the books, and it is not a
question related to Duane Arnold. It is something for
the future.
MR. HARRISON: I think there is a plan to
reevaluate the iodine spiking.
DR. KRESS: Yes.
MR. HARRISON: The last two slides.
Operator time required. I think we have made it clear
before that this is the one area that really does get
impacted by a power uprate. You end up with shorter
response times that are available, and that results in
a larger error probability for the operators.
DR. KRESS: And when I heard you
generally using .1 for the error probability, that
gave me a lot of comfort with respect to this
question.
MR. HARRISON: Okay.
CHAIRMAN WALLIS: You get confident when
the probability of error is 10 percent?
MR. HARRISON: No, it gives him confidence
that the results aren't artificially low.
DR. KRESS: That's right.
CHAIRMAN WALLIS: I would hate to be an
airplane with that sort of human error probability.
MR. HARRISON: Again, that particular
scenario was the early initiation of SLIC. I think
you only had under the uprate, there is only four
minutes, and that's why you get --
DR. KRESS: It was originally six.
MR. HARRISON: It was originally six and
so you didn't gain that much. You didn't lose that
much, but you still have that. Are there any
questions on operator actions?
CHAIRMAN WALLIS: Well, to solve this
problem could it be reduced by better training?
MR. HARRISON: In the modeling?
CHAIRMAN WALLIS: No, in reality.
MR. RUBIN: They are trained. They are
trained well, but it is a very short period of time,
and to diagnose an ATWS is, I guess, somewhat complex
in a cognitive sense, and that's reflected in the
model.
CHAIRMAN WALLIS: So you are reaching the
limit of human capabilities here, and it is not a
question of better training?
DR. KRESS: You are getting close. You
have four minutes to decide if you have an ATWS, and
go to the emergency guidelines and do what it says to
do for an ATWS. That is getting pretty close.
DR. LEITCH: They are trained on it on
almost every training cycle.
DR. KRESS: It is training as soon as you
can.
DR. LEITCH: I think the problem is as was
indicated, that it is relatively short time, and also
somewhat counterintuitive, in spite of your training.
DR. KRESS: It is one of those places
where instead of saying get water on the core, it is
going ahead and lower the water level.
MR. CARUSO: Well, I guess it is figuring
out if you have an ATWS or something else going on,
and diagnosing what is happening.
DR. KRESS: That is part of it, but I
think that ATWS gets to be pretty clear very fast.
CHAIRMAN WALLIS: You would say a minute
maybe that you know that you have got an ATWS?
DR. KRESS: Less than that.
MR. RUBIN: The first thing they do is
check the bottom lights.
DR. KRESS: That is a pretty good
indicator.
MR. HARRISON: And given that you do know
that you have shorter time, there is actually almost
an argument that it has got your attention. For
example, in shutdown operations, if you are in mid-
loop shutdown operations, you know you have only got
a few minutes to do things and you are going to watch
it a little closer.
So you can almost have an improvement on
operator performance in some situations.
DR. LEITCH: In some plants, ATWS is
automatically initiated, where there is a SCRAM
signal, and if the power is not down in five seconds,
in goes SLIC.
MR. HARRISON: I just put up this last
slide on question 6A, which was the need to assess
operational data. Again, licensees currently track
and trend their operational data, and they have the
maintenance rule, and they have a corrective action
program, and they have condition monitoring programs.
The staff believes that any significant
impact resulting from a power uprate would be self-
revealing. If Duane Arnold starts getting 3 or 4
trips a year, it is going to catch someone's
attention.
If all of a sudden pumps start becoming
unreliable, it is going to get somebody's attention.
And the staff is --
DR. KRESS: How many trips per year is in
the performance indicator now?
MR. RUBIN: I didn't bring the little
chart with me, but to get red, you need 20.
DR. KRESS: And to go out of the green,
you need three?
MR. RUBIN: Yes, three. I think it is
three.
MR. HARRISON: But the point is that the
staff is trying to figure out a way to use the
performance indicators and the monitoring programs to
look back and see are there any impacts. We don't
expect there are, and the PRA says there is not, but
we still need some kind of confirmation to look back.
So we are talking and discussing on how we
can use that to get an early indication that maybe
there is an impact that we hadn't expected to see.
DR. KRESS: That is a great idea, I think.
DR. LEITCH: I think the -- if I am not
mistaken, I think the present criteria is a three year
rolling average, too. So you may early on in the
process want to take a look and see whether there is
something more immediate happening.
Sometimes a three year rolling average can
sort of disguise something that is going on.
MR. HARRISON: And we do have the -- I
believe in looking at the cute little charts that you
can actually get where they are at that point. So you
can break down the data to see that Duane Arnold is
going from 1-to-2-1/2, or 1 to 2.
It is really not the initiating events
that would be -- those I really do believe would be
self-revealing. The harder ones would be component
reliability, where you may be taking a pump down for
maintenance more than you were before, and that is a
harder one to get the information to track.
MR. RUBIN: But they do have the
maintenance rule on availability criteria, the A1A2
demarcation, and maintenance unavailability will be
flagged directly if they exceed their goal.
CHAIRMAN WALLIS: Are we at the end of y
our presentation?
MR. HARRISON: I am at the end.
CHAIRMAN WALLIS: I would ask Mr. Hopkins
if we can have a summing up from you, and would you
prefer to do it now before we hear from RES or do we
need to hear from RES before we hear from you again?
MR. HOPKINS: I could do it now and it is
very short. I understand the questions and mainly
from our perspective in reviewing Duane Arnold, and
that is the first extended power uprate, that we are
trying to work the Duane Arnold schedule of completing
it by October, which would be a full committee
briefing in September.
And so we are trying to have as much
communication with ACRS to get this done as we can,
and I understand some of the concerns and questions
here today.
CHAIRMAN WALLIS: Well, it's not really
where the ACRS is on this. It seems to me that you
are still reviewing and some of these questions have
not been resolved, and until we see something more
definite, I am not sure that we want to write a
letter, because your opinion may change.
And we don't want to write something on
this that is not based on something that is -- well,
that is based on something that is too uncertain at
this point.
MR. HOPKINS: Right, and I wasn't trying
to insinuate that.
CHAIRMAN WALLIS: And so you don't want a
letter from us. I think it would be inappropriate for
us to write a letter now until perhaps you have
reached some firm conclusions on these points. Is
that a correct assessment?
MR. HOPKINS: I agree with that
assessment, yes.
CHAIRMAN WALLIS: And so you are going to
appear before the full committee?
MR. HOPKINS: Yes.
CHAIRMAN WALLIS: Is that what we plan to
do? And do you somehow have to shorten this
presentation to something that the rest of the
committee needs to know?
DR. BOEHNERT: We can discuss what we want
to do as far as having them come before the committee
next month. There are some issues that --
CHAIRMAN WALLIS: You do need to focus on
some other issues that we need to worry about. That
is the important thing. Otherwise, it is really a
question of whether you are on track with your review,
and that is more of a management issue for you folks
than it is for us. We may have an opinion, but it is
not really our job to plan your activities.
MR. HOPKINS: Yes.
CHAIRMAN WALLIS: We may catch you in the
hallway and say something about that and say whatever.
MR. HOPKINS: I understand that it is a
management decision, and new priorities are looked at
continuously. All I can say is that the Duane Arnold
power uprate is a high priority.
CHAIRMAN WALLIS: I think we need to be
somehow assured that the bases are properly covered
and that things are done by October and something is
not overlooked, and that is the sort of thing that we
worry about.
MR. HOPKINS: I appreciate that.
CHAIRMAN WALLIS: Is there anything else
from the other members of the committee at this point?
Can we move ahead then. Is this Jack Rosenthal?
MR. HOPKINS: Yes.
CHAIRMAN WALLIS: Thank you very much.
MR. ROSENTHAL: My name is Jack Rosenthal,
and I am the newly appointed branch chief of the
safety margins and systems analysis branch. Farouk L.
Quila (phonetic) is my division director.
DR. KRESS: Is that a new branch? I have
never heard of that branch?
MR. ROSENTHAL: No, it is Farouk's branch.
Farouk was promoted to be the division director.
DR. KRESS: I knew that and we need to
congratulate him I guess. Did you change the branch
name or --
MR. ROSENTHAL: No, no, the branch has
always been the same, but it was Farouk's branch.
This is a reorganization from a year ago March, and
about every two years we reorganize. So Farouk became
the acting division director, and I became the acting
branch chief for a while.
DR. KRESS: And how it is no longer
acting.
MR. ROSENTHAL: Right. And I am not
pretending either. And although I am speaking from a
branch perspective, I did coordinate what I have to
say with the risk assessment people, and also with the
division of engineering.
And we do fuels, thermal-hydraulics, and
severe accidents, and consequence analysis. And I
don't mean this to be -- I won't dwell on the point,
and I don't want to be overly scholastic, but we see
lots of system interactions that we can think of, and
I have yet to come up with what I consider synergy.
And let me explain what I meant. I went
to my fuels expert, and he says, gee, if you run the
fuel a little bit harder, or a little bit hotter
temperature, don't you release more fission and gas,
and he said, yes, we have known that for 35 years, and
it is a sensitive function of the temperature.
And if you go to higher burnup, core
average burnup, because you still want the same
overall fuel cycle, don't you end up with a bigger
fission -- and he said, yes, we know that also.
And I said, well, is there a situation
where 3 percent and 3 percent ends up as 9 percent
rather than 6 percent, and the answer was no. So that
we sort of know these effects.
And so I have yet to come up with what I
consider a synergy. And distinct from that, we know
of lots of interactions. I mean, we clearly know that
the fluents goes up and the effect on the vessel,
which is small for a boiler --
DR. KRESS: Was this Ralph Myer that you
were talking to?
MR. ROSENTHAL: Yes, sir, who is part of
the branch. Some of the phenomenological interactions
are things like the effect on the core instabilities
that would be the result of -- well, as it turns out,
if you have an ATWS, you trip the recirc pumps.
And once you trip the recert pumps,
automatically you fall into the unstable breaches as
it turns out, but what that would mean in terms of
fuel performance is an outstanding question.
DR. CRONENBERG: Let me give you a synergy
there, Jack. Flow assisted corrosion. Corrosion by
itself will take a certain amount of time.
MR. ROSENTHAL: Right.
DR. CRONENBERG: And flow by itself would
rip away material from a piping wall.
MR. ROSENTHAL: Right.
MR. CARUSO: But corrosive products with
added flow could be a compounding effect. So you
asked Ralph for a quick answer, and maybe you should
have asked some materials people, and you might have
gotten a different answer.
MR. ROSENTHAL: Fair enough.
DR. KRESS: And I think that Ralph is
basically correct on those things that you said.
MR. ROSENTHAL: Okay. It is also somewhat
of a management challenge for us, which we will
address, to face up to some of these issues, because
they are truly interdisciplinary, and I will give you
an example.
Yesterday, I was talking with a true
expert in thermal-hydraulics, and I said, you know, if
you push harder on the generator and you have not
changed the generator, you will get more power and
fewer BWRs, and he said what is a BWR.
So I raised my right hand and I said a BWR
is -- and he said, oh, I remember. Okay. And the
point is that what we need to do in this search for
interaction synergies is to go across disciplines, and
I will get back to that specific example in a moment.
And what I am trying to do is describe in
fact researcher's plans, and that we are not currently
doing a project, although I do owe my boss a formal
memorandum of plan with tasks, and I owe that this
month.
We intend to be quantitative in our
assessment, and we have the ability to run codes like
TRAC and we have coupled three, or it is now a module
of TRAC, and so we can do 3-D based on kinetics.
And we intend to use that capability for
things like ATWS, and it is because we believe that
when we do the analysis that we learn a lot by doing
some quantitative work.
CHAIRMAN WALLIS: So when will you do
this?
MR. ROSENTHAL: In Fiscal 2002 and 2003.
CHAIRMAN WALLIS: But they want an answer
by November of this year.
MR. ROSENTHAL: This is a generic, and not
a --
CHAIRMAN WALLIS: So it is a long term
anticipatory research?
MR. ROSENTHAL: Yes, sir. We will start
with boiling water reactors. I think if there are
some questions on PWRs and again involving ATWS, where
there is the potential for more positive MPCs that we
would like to look at.
But to the extent that we are dealing with
real boiling water reactors, we are asking for
extended power uprates, and that is where we should
look first. But we will do some PWR work later on.
We are going to not focus on the Chapter
15 analysis. The licensee, the vendor, and NRR are
pressing those issues; but rather to at least have our
focus being on success criteria in --
DR. KRESS: I think that is really a good
choice for you guys, because I think you can rely
mostly on this staff's review of the licensees for the
design basis stuff, and this is added value here.
MR. ROSENTHAL: Thank you. And we also
would like to look at some of the generic issues and
severe accident issues that would be part of -- or may
not be part of and addressed otherwise. As I said,
this is a two year effort.
Farouk did speak before this committee
several months ago, and we have been through a budget
cycle, and it is now as we see it a currently budgeted
activity. We do intend to do the work, and distribute
it at least amongst three branches.
So how will I -- well, this is a search
for issues, and there may not be any. I do not have
a smoking gun, and if I did, it would be my obligation
to notify NRR.
So if we could look at this list, and we
will look at blackout and loss of heat removal, and I
think we will look at loss of coolant, because it is
of interest to us, even though we recognize that in
most PRAs that loss of coolant actions are not
scenarios.
We want to also -- and I will say review,
less significant accident sequences, and ask ourselves
the question could these sequences -- because the
success criteria may change -- become more important.
And the example that I could use, and it
is only as an example in my thought process, is large
break LOCA and boiling water reactor is clearly not a
risk dominance sequence.
If we were to somehow conclude that with
the flatter power distributions, core spray now is
very important, and the core spray distribution is
very important, and if there is a problem with it,
then --
DR. KRESS: How would you look at that?
Would you just go in with your code and arbitrarily
say or do some power metric studies on the
distribution and see what it does to success?
MR. ROSENTHAL: It is a capability that we
have developed with TRAC, and put in a flat power
distribution which we think is representative of what
is going on. We won't know anything more about core
spray distribution.
DR. KRESS: No, but you could arbitrarily
vary that.
MR. ROSENTHAL: Yes, sir.
DR. KRESS: And the bypass amount that you
get is okay.
MR. ROSENTHAL: And see if it affects the
results. And it is conceivable, although I don't
expect, that there is some problems with the success
criteria.
If it were, then it would make something
that is not risk dominant, and make it very important.
That is the type of search we would like to do.
DR. KRESS: I think where your problems
are going to be are in the carryover term, and I don't
know how you deal with that. When you increase and
flatten out the profile, I don't know what that does
to carryover. But that is the only place I see where
that could make a lot of difference.
MR. ROSENTHAL: Yes. But we think we
ought to be looking at those, and not just -- well, at
least do some looking, and we will do definitely some
quantitative analysis, and we will do some reviewing
of the less sequence and think our way through it.
I think we want to also review some of the
prior generic issues. We put in this power/flow
stability issue in that category, but there were other
things that the agency faced and resolved in the past,
like the hydro-dynamic loads on the Torus, which would
be different now.
And we would intend to go back and look,
and in fact what I intend to do is go down the list of
generic issues that we have resolved and think our way
through which things might be different at the higher
power.
CHAIRMAN WALLIS: Do you know you have the
-- coupled with the neutrionics code, does it predict
flow stabilities? Do we know that yet?
DR. KRESS: I don't think it does.
MR. ROSENTHAL: I don't know.
DR. KRESS: I don't think it does.
MR. ROSENTHAL: As I said, what I have
brand new is this 3-D spaced on kinetics capability
that we now have.
DR. SCHROCK: What is the name of that?
MR. ROSENTHAL: Well, it is a module, and
we have made it into a module of TRAC and its parts,
and that is from Purdue.
CHAIRMAN WALLIS: So one success that you
could establish would be that you could model power
flow stabilities with these codes, that would be a
success if it hasn't been done before. I don't know.
DR. KRESS: Well, they have models.
CHAIRMAN WALLIS: And if you have a model
and the codes can't do it, that's not so good. It
would be better if the code did it by itself.
MR. ROSENTHAL: Well, then you have to
know whether you trust what you have got. But in that
case, it is an area that we would like to explore and
we think it is appropriate to explore this area.
I have a related area, and that is that
again it is ATWS, where the concern is to have a
rewetting of the clad, and will the temperature of the
clads go up. And for that, we are actually looking at
-- we have a fuel code called PROCTRAN (phonetic), and
we are working with of all things the Fins on a
subchannel code called GENFLO, and that will allow us
to look at that phenomena.
And we can couple that with the TRAC work,
but we want to look at other potential generic issues.
DR. LEITCH: I assume -- and not to pick
on the words, but when you say Torus, I suppose that
applies to other kinds of suppression pools as well?
MR. ROSENTHAL: Yes, to the extent that it
was an issue.
DR. LEITCH: And so pool snow and all
those hydrodynamic effects are also in Mark Iis?
MR. ROSENTHAL: Yes.
DR. LEITCH: Okay.
MR. ROSENTHAL: And we would also like to
go back and revisit some of what I will term severe
accident issues. You have the Mark I liner melt
issue, and you are now potentially putting down more
material with more decayed heat in it, and will it
move out further across the floor and affect the
liner.
That is something that we ought to look at
as an example of a severe accident issue that we put
to bed and that we could take a look at.
DR. KRESS: That was put to bed by the
peaponus (phonetic) methodology.
MR. ROSENTHAL: Yes. I doubt if you could
factor into that the increase through the power level.
It is well -- well, the uncertainties are well beyond
what you get out of that. I don't know how you would
do that, but that is your problem.
CHAIRMAN WALLIS: They can try.
MR. ROSENTHAL: I know what you are
referring to, but I think we have an obligation to try
to look at the sphere of consideration.
DR. KRESS: Well, you quantify how much
melt is going to come down.
MR. ROSENTHAL: Right.
DR. KRESS: So you might change that by a
ratio of 20 percent.
MR. ROSENTHAL: But once it is on the
floor, it has got more decayed heat.
DR. KRESS: Yes.
MR. ROSENTHAL: And the severe accident,
the containment venting size for certain power, and we
can go back and look if it sized with greater power as
being representative issues that we thought that we
would rethink.
Now, to whatever degree that has already
been rethought, we don't have to instill again. But
that was the scope of the kind of places that we
thought that we would look to identify issues within
the success criteria, and within the previously
resolved generic issues, and within some of the severe
accident issues.
And let me go outside my branch a little
bit, and some of these things I found interesting.
Let me get back to the generator again. If I am
pushing more power through VARS, and in fact I have a
somewhat less stable system electrically.
And if I am tripping 120 percent power
offline rather than a hundred percent offline, that
potentially also affects the grid. So I discussed
that with the PRA people, and they said, yes, those
things are true, but we don't know how to quantify
them, or at least now we don't know how to quantify
it.
It would be something that we ought to
look into, and that the risk may be dominated, a
blackout, by harsh weather events, or external events,
like seismic events in the past, and so these things
may not be important.
But that is a good illustration of where
the -- of the feedback between the electrical
discipline and the thermal hydraulic systems.
CHAIRMAN WALLIS: VARS are reactive -- you
have kept us in suspense by saying that some thermo-
hydraulists don't know what VARS are.
MR. ROSENTHAL: We also would like to look
at the possibility that just electrical equipment is
going to be running hotter throughout the plant. So
the division of engineering is interested in that.
And the division of engineering is
interested in loads and vibrations, and fatigue, and
thinning, and corrosion, although just as you heard
just a little while ago, we don't have a good link
between those issues and the ability to quantify them,
which maybe be a capability that we would like to
develop.
With the primary system, we will look at
things like the vessel, and we will attempt to think
our way through on piping loads. On containment
systems is where I meant to have the cable, and where
we already have experience.
I remember Pilgrim ended up baking a lot
of cable up in the upper head and having to replace
cable. Now, on one hand, just as you heard earlier
from NRR, there were programs in place to monitor, and
when people find that stuff no longer works, or it
gets changed down, that doesn't mean that there is a
safety issue.
But nevertheless we think there are going
to be issues of thermal fluences and running hotter in
containment. I meant to have a bullet under
containment on the cables specifically.
And then of course we are interested in
the higher pool temperatures and the effect on NPSH of
equipment. There may be control systems issues that
we didn't recognize, in terms of things like steam, to
condensers, and if that fails, you are pulling more
steam out and how does that affect the thermal-
hydraulics.
And the PRA people will look at the human
response times. So that is for the human error rate.
So that is the scope of the considerations that RES
would like to do.
CHAIRMAN WALLIS: It sounds big to me. It
sounds like a large scope. What is the funding that
is anticipated?
MR. ROSENTHAL: The scope of the FY '03
budget is not out yet.
CHAIRMAN WALLIS: Is this going to be done
in-house or are you going to hire some consultants?
MR. ROSENTHAL: I have an FTE in the
branch and some contract dollars that would be a
little more outside than inside, but yes, we will do
some of the work inside in-house, through the other
divisions.
CHAIRMAN WALLIS: Do you have the
capability to model these systems with your codes and
computers and it is not a big struggle to get all the
information that you need to do that?
MR. ROSENTHAL: There is always a loop
around, and there is always the struggle to come up
with DAECs.
CHAIRMAN WALLIS: Is G.E. going to give
you DAECS, or is something going to give you DAECs?
MR. ROSENTHAL: We are planning on using
an existing one, and for some of these other issues
that involve that involve either the PRA group or the
division of engineering, it is obvious that there are
concerns, and I don't know how we are going to go
about quantifying them.
CHAIRMAN WALLIS: I think you have a
management concern. You have got so many issues that
you might involve, let's say, a dozen people.
MR. ROSENTHAL: Yes.
CHAIRMAN WALLIS: And you are going to ask
for a few hours of a dozen people to make an
assessment which is not superficial, and which is then
going to be coordinated by some people who can put it
all together and figure out if it means anything.
DR. KRESS: Jack can do it.
CHAIRMAN WALLIS: So you are going to be
the guy doing the work and not managing it?
MR. ROSENTHAL: Within the branch which I
control, we do intend to do it. I have somewhat
dedicated resources to work, on at least the thermal-
hydraulic issues.
CHAIRMAN WALLIS: And when they come in
front of this committee are they going to give crisp
answers and not waffle?
MR. ROSENTHAL: The intent is to give yo
numerical answers.
CHAIRMAN WALLIS: Good.
MR. ROSENTHAL: The last part, you had a
discussion in terms of the source terms and
consequence analysis,and we do have the capability to
generate source terms, and we do have the capability
to run consequence analysis using math and that was
not in my mental larva of what we would do at this
time.
CHAIRMAN WALLIS: I think we should keep
this piece of paper.
MR. ROSENTHAL: And you are going to hold
me to it?
CHAIRMAN WALLIS: Absolutely. I will put
it up on my wall. When are you going to come and tell
us, in 2002 or 2003, and we will have a reorganization
by then, and you won't be in charge.
MR. ROSENTHAL: I would prefer that the
next time that we would come before the committee
would be sometime in late Fiscal 2002, when we had
results of something to show you.
CHAIRMAN WALLIS: Yes, this is a very
ambitious program.
MR. ROSENTHAL: As distinct from a -- you
know, I can share the -- well, as I said at the
beginning, I have to write a program plan, and that I
would be perfectly willing to do.
CHAIRMAN WALLIS: Well, we see a lot of
plans, and results are what really matter.
DR. KRESS: I would like to see your
plans, too.
CHAIRMAN WALLIS: Oh, I know that we would
like to see plans, but --
DR. CRONENBERG: But this is really one
FTE, right?
MR. ROSENTHAL: No, no, no. My branch is
one FTE, and --
DR. CRONENBERG: And so all the other
branches have some money for this? What is the total
program?
MR. ROSENTHAL: As Farouk said, it would
be 850K and --
CHAIRMAN WALLIS: That's big.
DR. CRONENBERG: That is significant.
CHAIRMAN WALLIS: So it is going to be a
big fat new Reg report that addresses all these
issues?
DR. KRESS: Well, that can be decided
later.
CHAIRMAN WALLIS: Well, there is the
opportunity to do something like that, and put
together some really authoritative report which
addresses all these issues, and finds out the ones
that are important and gives us some good answers.
MR. ROSENTHAL: I just hope that I have
not been overly enthusiastic enough. The thermal-
hydraulic analysis we can clearly attempt to do, and
we will do it and get the results, and we will write
the report on that.
CHAIRMAN WALLIS: Is that first?
MR. ROSENTHAL: On some of the other
issues like if there is a small incremental change in
the grid reliability can you actually ever quantify
what that is, and can you put that back in your PRA,
I can't make promises on that. That is really state-
of-the-art.
And putting in pipe degradation back in
the PRA is state-of-the-art stuff. So that is much
harder for me to make promises on that.
DR. LEITCH: Professor Wallis, I think we
can deal with additive things intuitively, but I would
hope that if there are some subtle synergistic effects
that come to light that we would be made aware of
those prior to late 2002.
And if there are such things that surface,
that we be notified, because we have been doing a lot
of thinking about these things ourselves, and we have
a concern, but I am not sure that we have identified
any specific synergistic issues.
But should there be some, I for one would
like to be aware of it as soon as you have a sense as
he does.
MR. ROSENTHAL: At the beginning, I said
that I have no smoking gun. If we found a technical
issue, we would feel obligated to --
CHAIRMAN WALLIS: Well, I don't know if it
is a smoking gun. Smoking guns are usually after the
event. It is more like a smoldering fire or
something. It is something that could grow into
something important.
So thank you very much, and you have
helped us to get to go to lunch before 12:00 noon. So
we will reconvene at one o'clock.
(Whereupon, the meeting was recessed at
11:58 a.m.)
A-F-T-E-R-N-O-O-N S-E-S-S-I-O-N
(1:01 p.m.)
CHAIRMAN WALLIS: We are now going to hear
a presentation by ACRS Fellow Gus Cronenberg, who has
studied the matter of power uprates for a period of
time and is going to give us some insights on his
conclusions.
DR. CRONENBERG: Okay. I have two
presentations, Graham. I went through this last week
at a full ACRS meeting, and so what I plan to do is go
through the margin reduction estimates fairly quickly,
and then go to the review of some LERs operating
experience for power uprates for a number of
incidents, such as the Wolf Creek incident, and Maine
Yankee, and some of the pipe ruptures that we saw.
And some safety implications of those
operational events. So I will run through this fairly
quickly, but this was a chart that ACRS gave me at the
beginning of the year to try to figure out what are we
talking about, and their concern about margin
reductions for the significant power uprates that were
coming in this year.
My overview is basically a little bit of
margin reductions in the regulatory process, and I
will go through that real fast; Estimates for power
uprates, and estimates for renewal, and findings.
I think everybody here knows what we are
talking about when we talked about margins, and it is
always used in a general sense.
For example, when a design criteria in
10CFR50, it says reactor core and associated coolant,
control, and protection systems shall be designed with
sufficient margin to assure acceptable design limits.
And we have other various criteria
throughout Appendix A of 10CFR50. Again, in
containment also, including access openings,
penetrations, et cetera, shall be designed without
exceeding leakage rates and with sufficient margin.
So that basically the rule of law says
that there shall be some margin that shall not be
exceeded in nuclear power plant designs.
These margin requirements are more
explicitly spelled out in regulatory guidance and the
standard review plan, and basically the standard
review plan for the construction permit essentially
defines what the margin shall be.
Basically, there are pressure limits,
pressure temperature limits, stress limits, ductility
limits on cladding, and allowable materials that can
be used, and then those go down into the ASME, for
example, and --
CHAIRMAN WALLIS: Gus, limits are not the
same as margin though are they? I always thought they
were two distinct things.
DR. CRONENBERG: Well, basically there is
allowable margin if you don't exceed these limits. It
is basically what the regulatory inspection says, and
that if you don't exceed a design parameter, then they
say you --
CHAIRMAN WALLIS: Well, yes, that is one
view of margin, that it is built into the limit, and
the other view of margin is that even if you stay
below the limit, then you have some extra margin, and
that is the margin that is often discussed; is the
margin between where you are and where this limit is,
which itself has a margin.
DR. CRONENBERG: Well, maybe the best
thing is by example then, and basically a licensee
will come in with an application and say I have a
pressure in this -- that my pressure in this piece of
piping is a thousand psi, and the design limit for
that by the ASME pressure vessel code is 1,250 psi.
Therefore, I have adequate margin.
And that is basically all that he will
say, and the same thing with ductility limits on
cladding. I predicted for this amount of burnup and
I will not exceed 14 percent cladding oxidation, and
the cladding limits are 17 percent on station limit,
and I have sufficient margin.
DR. KRESS: But I anticipate that they are
going to come in and say that the design pressures --
I don't remember what number you said, but --
DR. CRONENBERG: Well, 1,250.
DR. KRESS: And I anticipate that they are
going to come in and say that our calculations show
that our pressure is 1,249. Therefore, we have
adequate margin.
DR. CRONENBERG: Well, they will never get
quite that close, but they will always say in the
application that we have adequate margin.
DR. KRESS: But that is an example of what
I think is going to happen, and what should be the
response to that is that they probably do have
adequate margin because it is built into the design
limit like you said.
DR. CRONENBERG: Well, that is for you
people and the staff to negotiate what that should be
if it came that close. And I will show you an example
where the margin was exceeded in the design.
DR. KRESS: And my own feeling is that
whether that is adequate margin or not depends on the
uncertainty of the calculation. There is a large
uncertainty in that calculation.
Maybe they don't have adequate margin, and
I think the staff tended to agree with that view and
said that's why they want to see more, and the closer
you get to that margin, they want to see more
uncertainty analysis.
Or the flip side of that coin is the
design pressure for a piece of pipe that is 1,250 psi,
and yet that piping broke at a thousand psi because it
had the flow assisted corrosion or something.
So, you know, those things do happen, and
we just passed Aconie, and said there was plenty of
margin left in the control rod housing, and six months
later they found cracks. So even when we think we
know everything, sometimes we don't.
Okay. Impact of power uprates on plant
operating conditions and margins. Basically, for a
power uprate, you have a coolant enthalpy changes, and
flow rates, and coolant temperatures, and fuel
temperatures, and then you have usually some major
changes to operating conditions on the secondary side.
Here are some examples, and as I said, I
am going to run through this quickly because ACRS has
already seen this. What we are talking about here is
a fleet of aging plants, 25 or 30 years old, that are
coming in for major power uprates.
So this is why the ACRS asked me to look
at this question of what we are talking about as far
as pushing these plants further out for license
renewal, and power uprates, the same fleet of plants
that have been around for quite a while.
And what are we talking about in terms of
margins. I used as a case study, and I only looked at
one, and I am not talking about Duane Arnold today.
I looked at a case study, the Hatch,
because the Hatch had two power uprates. Hatch is
under current review for license application, and
Hatch was also a lead plant, Monticello and Hatch, for
the G.E. extended power uprate program.
It is an older plant, an early '70s
vintage plant, BWR-direct cycle Mark-I containment,
two power uprates in '95 and '97. And it is also
under current review for license application.
So I looked at what the impact of those
two separate actions on the plant, and basically we
have a direct cycle plant, and so what I did was march
around the primary system, and the secondary system,
and see what I could see as far as design parameters,
and changes in design parameters, and therefore
changes in margins.
For recirculation, piping, the feed water
piping, the primary steam piping, and that sort of
thing, and what was the impact of the power uprates
and the license renewal on those kinds of systems.
Okay. Here is -- and I don't know if you
can see that clearly, but these are the powers for
unit one and unit two. They are sister units, and
essentially the same power, and what was changed. For
example, the steam flow rates were increased from an
original 10 to 10.6, to 11.5; and steam dome pressure,
the original was 1015 and then it jumped to 1050, and
then a constant pressure type of uprate to 1050 again
on the second power uprate.
The temperatures changed from the first to
the second, and of course the feedwater flow rates and
temperatures increased progressively as you went up in
power.
There were two types of margins, and I
wrote down operational conditions, and then also what
are the changes in margins for design basis LOCA
conditions; and that I also looked at fatigue
estimates for the license renewal from the time
limited aging analysis.
My margin was based on what I would call
a definition of -- well, it doesn't say there shall be
adequate margin, and that is what the rule says, 10
CFR 50.
Basically, I said that you can't exceed
the design limit from the ASME pressure vessel code.
So the operating parameter scaled to the design
pressure, or design temperature, or whatever.
Okay. The main steam line pressure, we
saw that increase from 1015 to 1050, and the design
limit for that piece of piping is 1250 psi. So we had
a margin of 18 percent when we built the plant, and
reduced to 16 percent.
So there is a 2 percent degradation in
margin, and one would say that is not much of a
decrease in margin. The same with steamline pressure.
The design pressure or design limit for that piece of
piping is 1575, and we go from 546 to 551.
So we go from 5 percent to 4 percent
margin, and of course, from what Dr. Kress said, there
is also excess margin above the ASME allowable design
parameters.
Feed water piping, and 1650 is the design
limit, and we go from 1130 down to a lower pressure,
and then the feedwater piping temperature we increase.
So we go from 30 percent margin to 28 percent margin.
So nothing major so far here as far as
operational conditions. However, if we start looking
at LOCA conditions, things change a little. The
reductions in predicted margins become greater, and
when I get into my next set of slides, we will look
at, for example, the Maine Yankee experience, which
was not a very pleasant experience.
But that was as you know related to a
power uprate for Maine Yankee. They could not quite
satisfy their LOCA conditions, and I will get into
that story in a little while.
DR. SCHROCK: And when you are talking
about percentages, they are based on what?
DR. CRONENBERG: Just the design limit
over the value, and how the value changed as a
function of power. We went from whatever it was --
well, from 392 to 4000.
DR. SCHROCK: And do you need sort of an
absolute number denominator?
DR. CRONENBERG: Yes, it is. It is the
562. It is the design limit.
CHAIRMAN WALLIS: And we could make it
degrees --
DR. SCHROCK: Yes, that is what I was
getting at. You can get a different answer if you use
--
DR. CRONENBERG: Oh, I see. I just used
-- it is specified in terms of degrees fahrenheit, the
design limits, and so that is what I used it as.
DR. SCHROCK: You probably shouldn't
express it as a percentage.
DR. CRONENBERG: Well, this is just a
signature. I am trying to give a feeling for what
things are changing, and --
DR. SCHROCK: I know what you are trying
to do, but the significance of the number should not
be dependent on an arbitrary choice in the system of
units that you want to use.
DR. CRONENBERG: Well, margin is in and of
itself kind of an arbitrary term used in the
regulatory process, and we will never find a
definition of you can't exceed a parameter by .2
percent or something.
You do have things in terms of allowable
dose limits, and that sort of thing.
The only things that we have are design
parameters in the boiler and pressure vessel code, or
curies, or dose, or something like that.
Okay. Here is some predictions for the
Hatch plant on the design of LOCA calculations. For
example -- I wanted to go to the primary system first
-- here is one for the vessel shroud and support weld,
the vessel shroud and head bolts, and the access cover
plate.
All right. The vessel access cover plate,
et cetera. Now, all these numbers I got from the
licensee's own submittal, okay? The safety analysis
report, the SAR, and the SER. I didn't go beyond
that. I just used the licensee's own numbers.
And, for example, the predicted stress at
the original power at the support welds was 8.9
kilopounds per square inch, and it jumped to a 9.05.
So not much change in margin there. The same for a
head bolt.
Now, this access hole cover plate is an
interesting comparison, because it looks like with an
8 percent power uprate; that between the first uprate
and the second uprate that there was an 8 percent
power increase.
The predicted stress jumped from 64 to 90,
but that is a little unclear because -- and one of the
conclusions that I am going to make in my
presentation today is that I don't think either the
safety analysis report, nor the NRC's safety
evaluation report, the SER and the SAR, give you
enough detail and enough information to do a good job
on margin assessment.
I don't know if it is the number one bolt
in the first calculation, and the number six bolt in
the second calculation. I don't know if you had
superimposed loads. I don't really know if one was a
seismic induced and one was not a seismic induced.
You don't get in the SAR a picture of the
EISO bars for the stress predictions for all the
components. All you get is a little summary table
saying that these were my predicted stresses for these
5 or 6 components.
And then the SER basically says that we
had no problems or we requested information on this
particular number.
So if ACRS is asking for a detailed
assessment of the impact of a power uprate on margins,
I can't pull it out from the data that I worked out
from the historical FSARs.
And there is no defined criteria; that
this piece of information shall be given for this
component every time you do an uprate, so that you can
compare apples and apples, and so you can get an
historical picture of what is happening to this
reactor over time, and for the various licensing
actions
Also, you change models and you change
calculational procedures, and there is not enough
detail in what we get I believe from the applicant, or
what I can find out in the evaluation report by the
agency.
So I don't know how we are going to get a
good handle on margins if that is what this committee
is concerned about, and that will be one of my
conclusions. The information base to me is sketchy.
DR. FORD: Just to go back through that,
did you ever resolve the question of whether the --
DR. CRONENBERG: No, I looked back and I
couldn't tell which bolt it was for, and I couldn't
tell the exact details of the boundary conditions on
the stress calculation. There was not enough detail.
What I can tell you is, and what I told
you before, that access plate was replaced because of
what was found at Peach Bottom. They found stress
corrosion cracking in the welding of that plate, and
then the NRC required that they do inspections at each
outage.
And the licensee, because the inspection
program was going to cost them so much, they decided
to just replace that access cover plate. I don't
think it resulted from these kinds of numbers.
But from my reading, I couldn't get a good
indication of what are the boundary conditions in the
stress calculations. They are not discussed in the
submittal, and they are not really discussed in the
evaluation report.
But all I saw was tables and these are the
numbers, and it is probably hard to go back to
something in '95 and ask for that contractor report.
Sometimes it is not even the licensee.
The licensee will go to G.E., and G.E.
will go to Structural Analysis Associates, and I will
show you some of what you have to backtrack to pull
the information out when we get to the time limited
aging analysis.
It was not easy to pull information to get
these numbers. And then we had the same thing on the
margins on the LOCA conditions for the containment,
and for the drywell pressures, we go from a 14 percent
margin down to a 10 percent margin.
In some cases the peak drywell gas
temperature exceeds the design limits, but you look at
the calculations, and it is for a short period of
time. So the NRC says that's fine.
It is only for a short period of time, and
it is basically a few seconds in this calculation
during the flow-down, and the exemption is still
granted, and you can't go up in power.
And then the same suppression pool
temperature, of course, and the temperature goes up
because you have higher power, and the margin goes
down.
But there is nothing major here so far,
except for what we saw for that access cover plate.
Since I am interested in the license renewal, I think
you can get a better handle on margins. There is more
requirements that go into a license renewal
application going from 40 to 60 years operation
conditions.
We have a standard review plan that is
based on several years of agency efforts between the
staff and ACRS going back and forth on what will be
required for an adequate submittal on license renewal.
And there is a lot of calculations there,
and you can calculate margin, and it is more clearly
documented. It is easier to pull out something on
margin reductions if it is more clearly documented.
Basically, I looked at the time limited
aging analysis, and we talked about this this morning,
and the cumulative usage factor for the questions of
fatigue that Peter was bringing up.
And we heard a response from the NRC staff
that for these uprate applications that the staff is
requiring some cumulative usage factor estimates.
And then I said that was the first time
that I had seen from the applications that I looked at
in the past, and I never saw any cumulative usage
factor estimates for pipes or any real components.
And this was new to me, and I think it is
a good way to at least get a handle or a feeling for
degradation and the effects of increased flow, and
increased vibration, aging, and that sort of thing.
And accumulative usage factor is just a
fatigue estimate, and basically it is based on
historical data, and then projecting that out in time.
And we can see what the estimates are for
the heat removal suction piping at 40 years, and
basically you can't exceed one, and if you calculate
one, then you have to do something for that component.
It is essentially from the agency's point
of view it has filled up its bucket as far as fatigue
in Ralph's analogy of a bucket. So we have some
buckets for irradiation induced embrittlement, and we
have buckets for fatigue, and so forth.
We have some buckets that we fill up for
pressure temperature limits, and for license renewal,
I don't know how many buckets we look at for the power
uprate. It is not as clearly defined for me.
And then you can estimate it for 60 years,
and so your residual margin here went from 43 to 23,
and feedwater piping has a margin of 39 percent down
to 17 percent.
It looks like if this is an accurate
prediction of what is happening over time, then you
did increase your fatigue on that piping, and you
reduce margin.
It is something anyway, but to get these
estimates, these cumulative usage factors will not or
are not part of the licensee submittal. They are not
a part of appendix material.
This was referenced in Appendix C of the
license submittal. I asked for these numbers from the
staff, and we couldn't find them. I had to go back
and go through Brent Busher, and he had to go back to
the licensee.
And the licensee had to go back to the
subcontractor, to G.E., to get these numbers. That's
why I am saying that sometimes it is hard to pull this
information out.
If this committee wants to know something
and this agency wants to know something about margins,
it is going to have to define what is required and
what kind of information we are going to keep. Right
now we don't have a clear definition of that.
The pressure temperature limits were in
the Appendix E of the license renewal application for
the Hatch plant, and we did have those numbers in-
house.
And basically that if you have a certain
pressure of a piece of piping, you have to have a
certain temperature to keep that pipe ductile enough.
And because of irradiation embrittlement
the ductility is going down with irradiating dose and
time, and so the temperature has to get and higher,
and higher, and higher. So these are estimates in
Appendix E of the license renewal for 36 effective
full power years, 40, 44, 48, 50.
We go from a margin of say about 30 to
half that at 60 years. So to me there is a clearer
indication of margins and how they are affected for
the license renewal, because we thought about it, and
we thought it through over a number of years, and we
know something about aging, and fatigue, and flow
assisted corrosion.
And we asked the licensee this is what you
have to submit to us to show that this plant will be
good for another 60 years, and have we clearly thought
that through for significant power uprates for an aged
fleet of plants, and that is the kind of question that
I think is really before this committee. What does
this agency need to be looking for.
Okay. These are just data sources.
Again, I wanted to really indicate to you that you
have to look at a lot of different data sources. It
is not easy to pull all of this together, because
every licensing action is an individual action.
We look for a power uprate in an
individual way. We look for extended fuel burnup as
an individualized licensing action. We look for a
license renewal in that individual licensing action.
No one puts this all together in terms of
margins for the plant as a whole. The point of this
slide is that this is all the information that I got
out and it was proprietary information as an appendix
to the LOCA calculations for the Hatch SAR, and these
were the stress calculations.
It is a summary table and very little is
told you about the boundary conditions, the models,
and so forth that I used in there. So it is hard to
predict from one power uprate to another, because they
will give you different components or different bolts,
or whatever.
So the task that you asked me to do was
almost an impossible task to give you a clear answer,
because we don't have clear dictates on what is
required on calculational results.
It is just tell me what the maximum stress
is for a couple of components, and that is basically
what you get in a summary report. The analogy to me
is when we went to the IPEEE process. We didn't ask
for the dependency tables in the PRA.
All we asked for is a summary report, and
then we tried to glean information out, and it was
hard to pull, and then we started asking questions.
Well, what does this mean. Well, we only have summary
reports and we don't have dependency tables.
DR. FORD: So do the stresses change?
DR. CRONENBERG: The loads are different
because the blowdown loads are different because of
the power increase. The coolant enthalpy is increased
and the blowdown loads are increased.
DR. BOEHNERT: Gus, you should probably
pull that slide. That is proprietary material and we
are in an open session.
DR. CRONENBERG: Okay. Sorry. And a lot
of this information is also proprietary. All right.
Summary and observations to date. Safety margins are
used in a very broad sense and in the regulatory
process.
And there is a lot of difficulty in
getting consistent data to assess the margin impact.
Different models change, and things that are looked at
change from one uprate to another.
There was some success nevertheless from
Hatch, and that's why I titled my talk "Signatures of
Margin Estimates and Margin Reductions." We get some
sign posts here and there of what is going on but we
don't have a good integrated assessment of what the
margin impact is for that whole plant.
You can't tell if it is a synergy and you
get it for a piece of pipe or a bolt, or something,
but it is not the plant as a whole. Generally though
as you might expect from the start before we even
looked at this, that there is some reduction in
margins because you increase power and you increase
LOCA based stresses.
And you increased pressures and
temperatures on piping and that sort of thing. So
there is some indication of a degradation in margin
from design limits.
And also I believe the SARs, and what we
are requiring in the SARs and the SERs do not appear
to be of sufficiency, detail, and consistency to make
a good assessment of a margin impact on this
particular licensing action.
I think that the data is too sketchy to
give you a good feeling for margin. Basically you
will see in the SER and what -- and basically all the
agency is required to do is to assess the current
regulations are satisfied. That is what we regulate.
The kinds of concerns that this committee
has, you go, well, will we be caught in the Maine
Yankee situation, and you look at it in a little
broader sense.
What is the real safety impact, and so the
questions asked by this committee are probably a
little different than the questions asked by the
staff.
And to answer the questions that the
committee has asked me to look at is -- well, you
can't get a clear answer as to that. I do have some
suggestions on power uprates, and these are
observations, personal observations and suggestions
that tell me what should be asked for.
Basically, the NRC uprate review process
centers on the assessment of current regulatory
requirements are satisfied. There is no requirements
for risk impact, margin reductions, or impact of
multiple licensing actions and synergies.
It is just that the current regulatory
requirements are satisfied, and that is rightly so
what the staff should be looking for. Nevertheless,
I endorse prior recommendations from the Maine Yankee
lessons learned report.
You know about the Maine Yankee history
here, and one of the principal conclusions of the
lessons learned was that we need a standard review
plan. We need some sort of guide post, and the G.E.
uprate and extended power uprate is one step in that
direction.
And basically for the PWRs, the last thing
we had on the power uprates was for guidance, and we
never had a guidance from CE, and we never had
guidance from BWR, and we only have a W-Cap report
from 1984 for the Westinghouse.
And that is the last time that we had
guidance come in from vendors on what it takes to do
a power uprate for a PWR. PWRs still follow the W-Cap
guidance from 1984 that Westinghouse provided, which
is a very minimal -- it is like a 10 page report. It
just lists the kinds of things that you might look at.
Also, Scitech did a review for research,
or it was for NRR or research, but it was a contractor
report, and to do a review of the uprate applications
to that time, and the Scitech conclusion also
concluded that this agency would be better served if
it had a standard review plan.
It looked at large variances for one
upgrade application to another, and the review
procedures, and there was no clear definition of
acceptance criteria, and why you looked at this
control rod drive.
In one case, you didn't look at control
rod drive calculations, and on another you looked at
fuel behavior effects, and on another you did not.
Scitech's conclusion was basically that there was no
clear guide posts for a review of uprate applications.
And they also endorsed a standard review
plan, and the same with my 1999 recommendation, I also
thought that this agency would be better served if it
had a standard review plan in place for power uprates.
DR. LEITCH: In spite of all those
recommendations, we seem to be moving forward without
such a standard review plan.
DR. CRONENBERG: Partly because most of
them, I guess, are for G.E. so far, and G.E. is ahead
of the other plants.
DR. LEITCH: Yes, but the recommendations
stemmed largely from Maine Yankee, which -- and as you
said, it is more applicable to BWRs.
DR. CRONENBERG: Again, an uprate standard
review plan might include a standardized listing of
all system structuring and components subject to an
uprate review. It kind of mirrors the kinds of things
that we have in a license renewal application.
Assessment of impact on system structures
and component margins for both operational and DBA
conditions. A clear definition of methods to be used
and acceptance criteria that the staff will review
that application.
That is the kinds of things that we have
in the license renewal application. We don't have a
clear definition of, for example, acceptance criteria
for the staff to review.
We have input from G.E. on what they will
submit, but do we have a clear definition that this
committee is comfortable with as far as acceptance
criteria for the review of that application.
I also talked about something that I
called the legacy tables, and it is some sort of time
line or history of what is happening with that plant
as you go on in time, and as you uprate power.
Right now we don't have that a licensed
application for an uprate will include what was on the
prior power, and what was on the original FSAR, and
what changes were made as far as fuel burnup, and how
that might have impacted the same components, and
structures, and systems that are impacted by the power
uprate.
And a standardized table for DBA predicted
loads. We do have these kind of standardized formats
that one has to follow in our license renewal process.
We don't have it for the proper uprate process.
So that is basically what I wanted to say
about margins, and then I have a second talk that I
was asked to do on looking at uprates, and past uprate
applications, and events that occurred for plants that
had received uprate approvals.
And so are there any questions at this
point on margins? Now, this work I did back in '99,
and again I was asked to review uprate applications
and see if there was a potential synergistic safety
issue.
And the way I approached that is that I
looked at operational events for uprated plants. I
will review some of those applications and NRC review
procedures, and altered plant conditions, events noted
for uprated plants, potential synergistic safety
issues, and observations and recommendations.
And some of this I guess I can skip here.
These are the uprate applications up until the early
or mid-1990s. I think there was something like 21
uprates, and most of them are 4 or 5 percent power.
Those are the kinds of applications we
used to see in the mid-1980s and early '90s.
DR. FORD: You have Oyster Creek there and
there are three really quite big ones. Any reason why
those are big ones and how they got through at that
time?
DR. CRONENBERG: Well, Maine Yankee was
one, and Indian Point.
DR. FORD: Indian Point was PWRs and that
was 10 or 11 percent?
DR. CRONENBERG: Some of them, and I am
not sure, because it has been a while, Peter. But
some of them were asked to go to a certain power
level, even though the design base or the FSAR
calculations were all based upon higher power levels.
And I would have to go back and look and
see which of those plants were, but some of them --
all the FSAR calculations were done at a certain power
level, and their original operating license was for a
lower power level than their design basis
calculations, and they are allowed to step up to
those.
DR. BOEHNERT: Certainly Oyster Creek was
one of those, and I bet you that the other two were as
well. Indian Point was the other one, and Maine
Yankee.
DR. CRONENBERG: I don't need to go
through that plant. Okay. What I am going to
concentrate on are the power uprate events. Now,
maybe I shouldn't use this term, but these events that
happened for power uprated plants, whether they were
due to the uprate or something else.
It is not always an easy story to pick
out. The first one you know about, the Maine Yankee
one, and that went for two power uprates. There was
a deliberate faulty LOCA analysis submitted by the
licensee that involved the critical heat flux and
alteration of the decay heat models.
It was a whistle blower type of notice
that came before the agency. The whistle blower went
to the State Agency, and the State Agency came to the
NRC after the uprates had been approved. There was
two of them.
Both incorporated faulty analysis, which
was not caught by the NRC and only after we received
insider information from the whistle blower.
Wolf Creek and North Anna, both of those
had uprates, and there were control rod insertion
problems noted in high power hot, and high burn up
assemblage. And we will go through that.
There was the Callaway and Susquehanna,
which were pipe ruptures, and a long history of all
kinds of pipe ruptures in nuclear power plants, and I
will go through some of that.
Brunswick was a faulty use of DBA
criteria, and then we have Limerick instability
problems. Okay. In Maine Yankee, we had allegations
of a deliberate faulty LOCA analysis submitted by the
licensee.
The DBA declared limit of 2,200 was
exceeded for uprate conditions, and the LOCA analysis
was performed for altered decay heating critical flow
models.
The NRC did not question the licensee's
analysis, and there was no really audit calculations
using our own audit codes of the licensee submittal.
However, after the allegation was submitted to the
agency, we did an internal study and we verified that
indeed there was a faulty analysis submitted by the
licensee.
Maine Yankee was shut down and never
operated again. The lesson learned from Maine Yankee
was a need for independent staff analysis or audit
calculations, some of which Ralph talked about this
morning, and that the NRC at this time is aggressively
doing some audit calculations for these type of power
uprates, and which was not done during the time frame
of the Maine Yankee.
DR. LEITCH: Just one point of fact. When
you say it was shut down and never operated again, it
was reduced to the pre-uprate power level and did
operate at that power level for quite some time.
DR. CRONENBERG: Okay.
DR. LEITCH: And for quite some time I
mean a year perhaps.
DR. CRONENBERG: A year, and then they had
to upgrade their ECC and they decided not to do it for
one reason or another and the plant was shut down.
DR. UHRIG: I thought it was steam
generators.
DR. LEITCH: There were a number of
issues.
DR. CRONENBERG: And I think that the
injection system was not adequate for the LOCA.
DR. LEITCH: Yes.
DR. CRONENBERG: Wolf Creek and North
Anna. Wolf Creek had a --
MR. ROSENTHAL: Can I just interrupt for
just a moment, please. Jack Rosenthal. I was on the
Maine Yankee independent safety assessment, and I led
the team at Yankee Atomic while most of the team was
up at Maine Yankee.
And we reviewed all different sorts of
analyses, the higher scope of Chapter 15 analyses, and
were generally satisfied with a broad range of
analyses.
And I believe, or from what I understand,
that the reason that Yankee did not ultimately
continue operation were questions concerning its steam
generators, and it had done a hundred percent plugging
of the sleeving of the steam generators.
And they were faced with a financial
question about replacing the steam generators, and
cable separation issues that dated back a long period
of time, and they were faced with a large cost of
replacing the steam generators.
It was in a State in which there had been
referendums in the past on whether the plant would be
allowed to run a lot. So there was a great deal of
financial uncertainty associated with the plant, and
so they made a business decision to shut down the
plant.
And in fact if it was only the LOCA
analysis, that would have been readily overcome by
either them doing the analysis or going to still a
third party.
And their large break LOCA analysis was
always a combustion evaluation model. It was a small
break LOCA issue. So I think in the characterization
of Yankee, it would be fair to say that they
ultimately made the decision to shut down the plant
for commercial reasons.
DR. CRONENBERG: My point was that the
small break LOCA calculations were submitted, and we
accepted them, and then after we had the allegation,
we audited those calculations and found that, yes,
indeed the models were altered.
And we didn't catch that in the review,
and that was my main point. The Wolf Creek and North
Anna, we had an uprate in 1996, and this is PWR plant,
with Advantage 5H type of fuel assemblies, and
basically they had a control rod insertion problems
for the high power, high burn-
up assembly, and basically the thimbles swelled due to
irradiation growth mode, and then the control rod
couldn't be placed down into those thimbles again.
I would like to read you what was -- well,
because it happened in high power, high burn-up
assemblies, it could have been reviewed as part of the
power uprate application and I just wanted to read
here what was in the SER on the control rods.
The only thing that was looked at was the
control rod drive mechanisms as far as the
documentation of the review. The licensee evaluated
the adequacy of the control rod drive mechanisms by
comparing the design basis input parameters with the
operational conditions for the proposed uprate.
The licensee stated that he uprate
conditions would have an insignificant impact on the
original design basis analysis for the control rod
drive mechanism.
The staff has reviewed the licensee's
evaluation and concurs with the licensee's conclusion
that the current design of the control rod drive of
the control rod drive mechanism would not be impacted
by the uprate.
That is the only thing on control rods
themselves, and at least from the review procedures
the thimbles the irradiation growth. There is nothing
telling me in here, and it just says the staff
reviewed the licensee applications.
I had no idea of what the acceptance
criteria of that is. It just said we reviewed it and
find it acceptable. I think with a little more
tightened review procedures, where we define what the
acceptance criteria are, just like we do on a
construction application.
And that we would be better served, and
that the staff will have a better guidance as to what
is acceptable and what isn't acceptable. So we had an
incident at Wolf Creek, and all you can say that it
did happen, and with the high power assemblies it
might have been a review question, but we looked
mostly at the control rod drive mechanism.
We didn't say anything about irradiation
and induced swelling of zurcoroid guide thimbles. And
maybe if we had a standard review plan we would say
that this is what you have to look at, and these are
the kinds of calculations that you have to make with
fluence.
And you have to monitor and this is the
acceptance criteria, and you shall not have such
swelling, and so forth, and so on. On North Anna, we
had -- and this is again a PWR, and we couldn't insert
new rods into assemblies that were being stored in the
spent fuel pool.
They tried to bring in some new control
rods, and insert them into the assemblies that they
had in the spent fuel pool, and those guide thimbles
were also warped, and we couldn't temporarily store
the new control rods into those assemblies.
Neither uprate SER addressed changes in
fuel rod or control rod performance for high burner,
high power conditions. The lesson learned here again
is that maybe we need something -- a tighter review
process for power uprates.
Okay. Pipe ruptures. We talked about
corrosion and erosion problems, flow assisted
corrosion. We had many pipe ruptures. We have 53.
There is an IPEEE report, a detailed IPEEE report on
pipe ruptures, and we have 53 pipe rupture events for
pipings greater than 2 inches in diameter.
Most of those were attributed to an
erosion/corrosion mechanism as Peter noted this
morning, and erosion is a flow, a flow synergism, and
corrosion is an aging phenomena, and here we have a
synergism or a linkage with enhanced degradation of
flow assisted corrosion process.
Empirical evidence for flow/aging effects,
lessons learned, is a need for a staff review of
potential synergisms, and this is --
DR. FORD: The 53, is that 53 between how
many plants?
DR. CRONENBERG: I have a table coming up
on that. Basically, I just took that from an EPRI
report. It is not anything that I did.
Nucleonics Week. I just wanted to talk
about the Susquehanna shutdown, and this just came up
this morning, and there were some statements that it
was more than just maybe a flow associated vibration
effect.
But I just wanted to quote the headlines
from Nucleonics Week with respect to Susquehanna. "A
recent Susquehanna-2 forced outage could be the result
of weld fatigue from increased vibrations from a power
uprate in 1995, and NRC is looking at potential
generic implications for other uprated BWRs."
"BWR uprates have increased the speed of
recirculation pumps and caused increased vibrations in
the recirculation systems, said the NRC resident
inspector at Susquehanna."
The reason that I put this slide up is
that this is the only time that I see anyone really
stating what they believe is a direct linkage between
an uprate and a pipe rupture.
MR. KLAPPROTH: This is Jim Klapproth with
G.E. I would like to comment on that. We saw that
article come out and we do not agree with that
position. Really, there was an increase of flow, and
Susquehanna moved to an increased core flow
concurrently with the power uprate, but it was not
specifically a power uprate issue. It was increased
core flow.
DR. CRONENBERG: Okay. But the --
DR. FORD: Well, 53 is an astounding
number.
DR. CRONENBERG: And 53 isn't just from
flows. I put this up because this was a statement by
an NRC official that an event, an LER to uprate.
MR. KLAPPROTH: I understand, but I would
just like to go on record as saying that G.E. does not
agree with that position.
DR. CRONENBERG: I understand, but you do
agree that it was a flow enhanced flow, but the flow
was not dictated by the power uprate?
MR. KLAPPROTH: It was not due to power
uprate, yes.
DR. CRONENBERG: And here is a piping
rupture mechanisms through 1995, and basically EPRI
did this for the Swedes. The Swedes wanted some
information on pipe ruptures, and what are the
mechanisms.
And so they did it for a range of piping
sizes. It was according to small piping, larger than
2 inch piping and that sort of thing. Erosion and --
DR. LEITCH: This surely isn't primary
system.
DR. CRONENBERG: No, this is all piping in
the plants.
DR. LEITCH: This is piping in nuclear
plants that ruptured?
DR. CRONENBERG: Yes. And the EPRI report
is a real detailed report on pipe ruptures in nuclear
power plants, but you can see the highest here for
vibrational fatigue and erosion/corrosion, both of
which one might expect vibrational fatigue for
increased flows, and erosion/corrosion for higher
powers and higher flow rate that might accompany a
power uprate.
To me, this indicates that most from our
experience to date, that most of our ruptures for
large piping, and this is 2 inch and above piping, are
for kinds of phenomena that we would see in an uprate;
vibrations due to flow, and flow assisted corrosion.
DR. KRESS: If I have got a hundred plants
out there, and I look at vibration frequency, and
there is one a year?
DR. CRONENBERG: Yes, one a year.
CHAIRMAN WALLIS: I am trying to relate to
your previous thought. You said it was erosion
problems, and presuming it was carbon steel pipes,
right?
DR. CRONENBERG: Yes.
CHAIRMAN WALLIS: And yet you said there
were 53 events of erosion/corrosion of carbon steel
plants.
DR. CRONENBERG: Well, 53 events for pipe
ruptures greater than two inches. That could e all
types of ASME type designations of all kinds of
piping. Basically, it is steel piping, but 53 large
pipe breaks. Now, on this slide --
DR. LEITCH: And worldwide presumably,
because you have a foreign plant listed there.
CHAIRMAN WALLIS: That's right.
DR. CRONENBERG: Yes.
DR. KRESS: And if I add up all of those
listed over there, I don't get 53.
DR. CRONENBERG: This is just the
breakdown of where you see these breaks, okay?
DR. KRESS: But those are just U.S.
plants.
DR. CRONENBERG: I have to go back. I
don't know if they are just U.S. plants, Tom. I have
to go back into the EPRI database. They did it for --
I can get you a copy of that. They did it for the
Swedes. It might have included other plants.
DR. KRESS: But if you add it up and
multiple it by a hundred plants, it doesn't add to
very many.
DR. CRONENBERG: No.
CHAIRMAN WALLIS: Three a year.
DR. KRESS: I forgot about multiplying it
by the number of years.
DR. FORD: Previously, you said that
Callaway and Susquehanna, and I assume you are
referring to erosion/corrosion problems in the carbon
steel pipeline, and you said Guillotine pipe failures?
DR. CRONENBERG: Yes. Well, no. Did I
say Guillotine?
DR. UHRIG: Yes, you did.
DR. CRONENBERG: Sorry. Susquehanna was
not a Guillotine. Susquehanna was on a line to the
recirculation system. Callaway was a large pipe --
somehow will have to help me. Do you know what the
Callaway was again? I will have to go back and give
you an answer on Callaway.
DR. FORD: Maybe you could relate to how
many gallons per minute you are losing in heat.
DR. UHRIG: It is Callaway and Susquehanna
guillotine pipe rupture.
DR. CRONENBERG: Yes, Guillotine should be
out of there. And in the DBA analysis of the wet weld
design limit is 220 and NRC did not challenge the
licensee's evaluation at 220. However, the real
number should have been 200.
So it was just an oversight that got
through, and the licensee then came back and said,
sorry, it should have been 200 and not 220. It is
just an example of something that we didn't catch.
Where if we had a more detailed or
checklist, and again I am trying to say that we would
be better served if we had a tighter process, a
standard review plan, and maybe these kinds of numbers
would be in there, and we would not have been caught
in this type of situation.
And where we didn't catch it and the
licensee had to come back and say that we didn't catch
it, and you didn't catch it, and we did catch it.
And then Limerick, and we have these --
well, when we restart, we have these instabilities
that we see for BWRs, where the predicted Delta-K over
K is different from the measure, and it gives the
operator a little bit of heartburn when he sees that.
And then we have to back off on power, and
then find out what was wrong with our calculations,
and then start up again.
DR. UHRIG: I didn't understand that. They
are not determining a design limit are they?
DR. CRONENBERG: Which one do you have
questions on?
DR. UHRIG: On Brunswick. You had
licensee based on wet weld design limit of 220, and
NRC did not challenge the 220. I thought the NRC
would set the limit.
DR. CRONENBERG: In the FSAR, the design
limit for the wet weld for that plant was 200 degrees
F. The analysis was based at if the design limit was
220, and it was submitted by the licensee.
We believe that our design limit for a wet
weld is 220, and NRC went and said, yes, we reviewed
the application, and you are below 220. It is fine.
A couple of months later, the licensee came back and
said, oh, sorry, I told you the wrong number for the
design limit. The design limit was 200.
What I gleaned from looking at some of
these LERS, license events for uprated plants besides
the generic implication of a need for a tightened
review process, and a standard review plan, is that
maybe there are synergisms.
For example, rod fretting, and flow
induced rod vibration, leading to contact wear with
adjacent structures, and increased core flow at
uprated powers, and zry-irradiation growth. We know
that there is irradiation growth, which may lead to
some fretting problems.
Axial power offset. We know about the
axial power offset problem, and boron added to
compensate for excess reactivity for high burn up and
high enrichment, crud buildup for long fuel duty
times. And boron is gettered.
There seems to be evidence of boron
gettering by the crud, and we have an axial power
offset. The effect is compounded, and it seems to be
the evidence that it is compounded at high-power core
locations.
DR. UHRIG: Where is that evidenced? I
have not heard that before.
DR. CRONENBERG: The boron?
DR. UHRIG: No, the effect that it is
compounded by high-power.
DR. CRONENBERG: Mostly, they find it at
the high-power central locations and don't find it at
the lower power assemblies. It is something that we
look at for high burn up assemblies.
Other synergisms, and Jack talked about
these, and looking at cable degradation, insulation
breakdown due to irradiation effects, and that is
exacerbated by elevated temperatures.
We do have cable aging type of things in
our license renewal requirements. However, if we are
talking about higher temperatures for power uprates,
and for plants that are 30 years old, maybe we should
be looking at those sort of things on power uprates,
too.
And so forth and so on. And of fluid
mechanical components, and degradation of elastomers
at higher temperatures, and those are the kinds of
things that maybe if we had a more detailed assessment
of the impact of power uprates on a checklist, or a
standard review plan, we might need to look at it.
So I had some recommendations which are
not too dissimilar from looking at margins, and
looking at licensee event reports, and current
application review processes, and reevaluation of
design basis conditions, and uprated conditions, and
there is essentially no requirements to look at
synergistic effects.
We review based upon current regulatory
requirements. Events show indirect evidence of
potential synergisms, and the agency, I believe, would
be better served if we had a standard review plan for
power uprates for BWRs.
And G.E. goes a long way to that goal, and
the NRC needs to do something on acceptance criteria,
I believe, for the PWRs. It has been a long time
since a licensee or a vendor did anything on power
uprates, and basically we are still dealing with the
1984 W-CAP report. And that is basically all I want
to say.
DR. LEITCH: Gus, your third bullet down
there says that that standard review plan for power
uprates is in progress. These slides are a couple of
years old. Is that still true?
DR. CRONENBERG: The standard review plan
is still an on-the-burner sort of issue that -- well,
at this point, the agency is not doing a standard
review plan, and maybe the staff can answer that.
CHAIRMAN WALLIS: Did you have a comment
on that, Ralph?
MR. SWAYBE: This is Mohammed Swaybe
again. No, we are currently pursuing a standard
review.
DR. KRESS: I am intrigued by your bottom
bullet, and intrigued by the fact that you added QHO
in parentheses there. Do you have any ulterior motive
for that?
DR. CRONENBERG: I just put that in for
you, Tom.
DR. KRESS: Thank you. I appreciate that.
DR. CRONENBERG: We don't have any
requirements for license renewals particularly, but
anyway something about that. PRAs can give you --
well, you know, you believe in PRAs, and it gives you
some sense of a holistic integrated assessment of what
things are.
We talked about a raw risk aversion LERF,
and not a risk aversion LERF for a component, but a
risk aversion LERF for a system, and all these issues
are before the ACRS. And some thinking needs to go
into how we get a better assessment of how systems
behave as a whole, rather than components, or how the
plant behaves as a whole.
DR. KRESS: You know, the reason that I
wanted that QHO over there is you are actually talking
about power uprates, and you ought to refer back to
the QHO itself rather than LERF, because what we are
doing is changing the source term.
And LERF is dependent on the source term,
and of course I think there is enough site dependence
of things that we really ought to revert back and see
what we are really doing instead of using LERF.
DR. CRONENBERG: Well, maybe we should
like at something like a QHO, and the source term is
changing, but core damage frequency doesn't tell you
always the whole story as you know. It doesn't tell
you anything about consequences.
DR. KRESS: And I don't think that LERF
tells you enough of the whole story.
DR. LEITCH: I have heard a couple of
times today that the G.E. topical reports are to
perhaps stand in place of the standard review plan.
Yet, there are a number of the issues that you talk
about here as being potential effects that are really
behind G.E.'s scope of supply; electrical cables, and
cement control systems, and so forth.
So I guess I just don't understand that.
Also, I don't understand why the real recommendation
coming out of Maine Yankee is that there be a standard
review plan for power outrates, and why aren't we
doing that.
You know, we are looking at a whole bowel
wave of power uprates here, and what are we going to
do to them? Is it on an individual basis, and looking
at them as though each one is a new case?
Isn't there some benefit that could be
achieved by having a standard review plan, rather than
considering each one as a separate issue?
MR. SWAYBE: This is Mohammed Swaybe
again. I can't speak too much on a standard review
plan, but I know that was considered and right now we
are not pursuing a standard review plan.
However, as far as future power submittal
applications, and what we are doing, and the ones that
are ongoing right now, for the major extended power
uprate applications, we are considering the Quad
Cities, Duane Arnold, Dresden, as first of a kind.
We are going through those and we will be
having a public workshop after the completion of
those. We are also going to be looking for ways to
get information out to industry, in terms of how they
should be submitting these applications, and format,
and getting the information that we need out to
industry so that they know what to submit.
It is not a standard review plan, but it
will provide some guidance.
CHAIRMAN WALLIS: What form will it take
then?
MR. SWAYBE: I am not sure at this point.
We are considering several options. It may be a RIS,
and it may be through workshops, and it may be through
webpage. We are not really sure at this point.
DR. LEITCH: It just seems to me that we
all learned some pretty painful lessons at Maine
Yankee, and we are kind of flying in the face of that
experience.
MR. SWAYBE: I think one of the
recommendations may have been a standard review plan,
but there have also been some other lessons learned.
And I remember in working in the reactor
systems branch that there was guidance given down to
the reviewers, in terms of the kinds of things to look
for that came out of Maine Yankee.
I mean, there was more than just a
standard review plan recommendation for that. There
were some letters that came down from management that
said that this is what we learned from Maine Yankee,
and be sure that you are looking for this kind of
information when you do your reviews.
DR. LEITCH: Yes, that is good for those
specific things, but what I am saying is that the way
that we improve is by institutionalizing some of this
experience, and capturing it, and getting smarter as
we go along; a little bit like we have down in the --
well, at least I think we have done and are maybe
continuing to do in the license renewal process.
But here it seems like we are starting
each one kind of with a blank sheet of paper.
MR. SWAYBE: Well, I think on the first
few that you are probably right. We do think of them
as first of a kind, the first few. You know, 15 or 20
percent. But I think after that, that you will see
that we will provide some guidance and hopefully
things will be a little more standard.
CHAIRMAN WALLIS: This will be a sort of
lessons learned from Duane Arnold, Dresden, and Quad
Cities.
MR. SWAYBE: Okay.
CHAIRMAN WALLIS: Anything else? If not,
it is probably better if we take our break now before
we hear from G.E. so we don't interrupt your
presentation.
Well, I guess we will do your introduction
first and then we can take our break. Let's do that.
DR. FORD: Mr. Chairman, I have to say
that I have a conflict of interest here, being an ex-
G.E. member, and as I understand the rules of the
game, I am allowed to comment, but not judge.
DR. KRESS: Only on factual matters and
not expressing opinions.
CHAIRMAN WALLIS: You can ask questions
and we can judge the answers. It would be very useful
if you would ask the right questions. So let's
proceed with the open part of G.E.'s presentation.
MR. KLAPPROTH: Okay. My name is Jim
Klapproth, and I am the manager of engineering and
technology in San Jose, and I would like to thank the
committee for an opportunity to come and give an
update from our perspective on power uprate.
We have not been in front of this
committee since 1998, and I think that as we have seen
here there is a lot that has transpired in the last 2
to 3 years, especially with the extended power uprate
sitings.
And it is very timely for us to have an
opportunity to have this discussion. I have two ot
her individuals here with me that I would like to
introduce.
Israel Nir is on the far left, and he is
the power uprate process project manager at G.E., and
he will be speaking primarily about the constant
pressure power uprate approach, which I believe the
committee has had an opportunity to at least look at.
And also to my immediate left is Gene
Eckert. Gene is the engineering fellow for transients
and reactor systems control, and he will be speaking
primarily to a lot of the issues that have come up
today relative to the special topics and synergistic
effects.
As an aside, I would like to note that
this is Gene's 65th birthday today, and I couldn't
think of a better present than to have him here today.
So, anyway, I will run through a quick
introduction here. We will have some opening remarks
and then I will turn it over to Gene to kind of go
through an introduction and give you a little history.
We have heard a lot today about the G.E.
topical reports. I want to step through the five
percent stretch power uprate, and then move to the
mid-1990s and to the extended power uprate in the 5 to
20 percent uprate.
The third step in our progress has been
the thermal-power uprate program, or thermal-power
optimization, which takes advantage of the improved
water flow on certain need characteristics so we can
realize a 1-to-1-1/2 percent power uprate.
And then finally the constant pressure
power uprate, which we will focus on. Then we would
like to go into closed session and really get into
more details and specifics about what the impacts of
power uprate are.
And before I turn it over to Gene, just a
couple of opening remarks, and basically these five
bullets are the key messages of our presentation.
First of all, there has been an extensive amount of
experience with extended power uprates.
And there are five plants, and it says
four here, but there are four utilities, and actually
five plants that are currently operating under
extended power uprate conditions; three domestic and
two overseas.
And in addition, we have completed the
analysis and it is currently under staff review, of
power uprate programs for an additional five plants.
DR. KRESS: Who reviewed the overseas
plants?
MR. KLAPPROTH: KKL.
DR. KRESS: Was their review as extensive
as the ones that our staff does?
MR. KLAPPROTH: I believe so, yes.
DR. BOEHNERT: Were those 20 percent or
higher uprates? What was the uprate on those?
MR. KLAPPROTH: I think it was 117.
MR. ECKERT: KKL did a five percent
somewhere to our original uprates, and then they did
this additional 14-1/2 percent. So they are close to
120. And the KKM plant is up around 114, above the
original.
DR. SCHROCK: Is that the way that you
calculated it; that it is based on the percentage of
the original?
MR. ECKERT: That is the way of keeping it
in our books for sanity since they are going in
different steps here, yes. These are the numbers that
they give you and they are right around 119.
something. They are not above 120 from originally.
They were 104.2,. and then 114, or
something like that.
CHAIRMAN WALLIS: And was that the
Leibstadt one?
MR. ECKERT: Yes, that was the Leibstadt
one, the bigger one, yes. A bigger uprate.
MR. KLAPPROTH: In fact, I think we have
a chart later in the presentation.
MR. ECKERT: We have information from
their program.
MR. KLAPPROTH: The second major bullet,
we have had a lot of discussion today about margins,
and from our perspective, the safety margins are
maintained.
And both Ralph Caruso, who I think back in
December when he was in front of this committee, the
deterministic licensing criteria are maintained for
power uprate. There is no request for any relaxation
of the deterministic licensing criteria.
In other words, we believe that all the
safety margins are maintained. I think a lot of the
discussion we have been having previously is relative
to performance margin, and operating margin, and there
is a slight impact in some cases on operating margin,
and we understand that.
And relative to safety margins, we believe
that there is no impact on safety margins for power
uprates, especially under the constant pressure power
uprate approach, which is a no pressure increase.
And you will see as we go through the
presentation in the closed session the impact on plant
systems, and on plant response to events, such as
design basis accidents, and transients, is fairly
benign relative to prior pressure increase power
uprates.
So again we believe that the safety
margins are not impacted for extended power uprates.
and power uprates.
DR. CRONENBERG: When you say that, what
about, for example, like the feed water line? Do you
view that as a non-safety impact, and design loads,
and even the operating conditions are higher flow
rates and higher temperatures on the feed water lines.
MR. KLAPPROTH: We have a specific
example, and we will discuss that in the closed
session, but basically our position will be that as
long as you stay under the 1250 limit, anything
underneath that is additional margin over and above
the safety margin.
DR. CRONENBERG: Okay. So you are
defining safety margin as anything above the design
limit?
MR. KLAPPROTH: Exactly. And I believe
that is consistent. I think if we go back 10 years,
I believe -- and, Tony, you can help me on this, but
in the improve tech spec role, I think NEI and others
took a very close look at what the definition of
safety limits and safety margins are.
And I think there was some guidance put
together by NEI which was accepted by the staff on
what the definition of safety margin is relative to
operating margin.
MR. ECKERT: And all the appropriate code
equations were checked again for the new operating
conditions, and any temperature change that took
place, and the flow changes that took place, and in
compliance with all the appropriate code equations for
the piping was done for each small uprate or big one.
DR. CRONENBERG: So when we see something
in an SAR that says the safety margin is not changed,
what we are really talking about is that you are below
the design limit?
MR. KLAPPROTH: Right.
CHAIRMAN WALLIS: Could you say more about
Bullet 3?
MR. KLAPPROTH: The constant pressure
power uprate bullet?
CHAIRMAN WALLIS: Yes, without getting
into something which is proprietary. It is not just
constant pressure. You get your power uprate by
flattening the power distribution of the core without
changing to the maximum temperatures and all those
things which -- well, if you had just taken and raised
the power everywhere, you would be changing those
things.
But you have done some clever engineering
to keep other things constant other than just
pressure. Can you talk about those now or is that
something that is more proprietary?
MR. KLAPPROTH: I think we would prefer to
talk about that in the closed session.
MR. ECKERT: Well, on the pressure side,
we control pressure independent of power. I mean,
they interact, but we have a pressure controller that
keeps the pressure where we want it, and that this
plan for our uprate, we make sure that when we get to
the new higher power level that we have the same
reactor dome pressure that we had before.
CHAIRMAN WALLIS: Well, if we had that, it
would just draw out more water at the same pressure.
MR. ECKERT: Basically, yes. And we have
a control system that will hold it where we want it.
CHAIRMAN WALLIS: And you achieve that by
not -- without raising this sort of maximum fuel
temperatures and things like that. So there must be
some engineering done to distribute the load more
evenly across the core.
MR. KLAPPROTH: Well, we will talk about
that.
DR. KRESS: When you say constant
pressure, you are talking about the pressure in the
dome or --
MR. ECKERT: The reactor dome pressure,
yes.
DR. KRESS: Which means that you are
blowing more steam, and so the resistance between
there and the turbine has to be less?
MR. ECKERT: Well, it is built already.
The resistance is there, and so at the turbine, we
actually drop pressure a little bit at the higher flow
rates.
CHAIRMAN WALLIS: So you need an even
bigger flow rate to get the power uprate?
MR. ECKERT: We have to build the turbine,
and the MODs get a little tougher by holding this
pressure philosophy. But inside in the primary part
of our system, and the whole pressure boundary, it
becomes much simpler, and that is what we will talk
about.
DR. KRESS: Okay. We will wait until
then.
MR. KLAPPROTH: And in general, for
example, on the LOCA analysis, we will show that the
power uprate, really the effects of LOCA, the effect
of power uprate is very minimal on LOCA analysis.
CHAIRMAN WALLIS: And you still have the
vessel at the same pressure and so you make a hole in
it?
MR. ECKERT: It is the same sized pipes.
CHAIRMAN WALLIS: And that sort of
overview needs to come forward so that someone who is
looking in from the outside can understand how you
achieve it without it being too proprietary.
MR. KLAPPROTH: Okay. The fourth bullet,
the high volume EPU review request anticipated. There
was a question this morning on how many do we
anticipate over the next year or so.
Right now the staff has Dresden and Quad
Cities, and Duane Arnold reviews in progress. We
anticipate between now and the middle of next year
that there will be another five plants submitting for
power uprate, and extended power uprate applications,
using the constant pressure power uprate approach.
And beyond that our projections are over
the next several years that we would expect at least
another four plants per year coming to the staff.
That's why we think it is appropriate to move to a
streamline approach, which is again linked to our
constant pressure power uprate.
And actually we will be meeting with the
staff tomorrow and getting the initial feedback on the
topical report that I believe the staff has seen on
our constant pressure power uprate, and hoping that we
would have a safety evaluation issue by the end of the
year.
DR. KRESS: Do you think we have reached
the limit of power uprates, or is there a potential
another round? How far can we go? I know that there
are different things that limit --
DR. SCHROCK: Isn't it limited by your
radial peaking? I mean, all you are doing is taking
advantage of the fact that the older plants are more
peaked, and now you are flattening it.
But there is a limit to what you can get
if you spread it uniformly --
MR. KLAPPROTH: Well, at this point, we
are really where we want to go at this point, which is
20 percent. We have not really looked beyond 20
percent in the NSSS environment to say what is the
next limit.
Ralph mentioned this morning a limit.
However, that is based on current licensing analysis,
and I think we have moved to more realistically track
the analysis, and we will find that we have some
additional margin that may allow us to go higher.
There may be some related issues that we
need to worry about when we go above 20 percent, but
we frankly have not done a study to say, well, we can
go to 129, or we can go to 142.
DR. KRESS: That is something that we
don't need to worry about right now. We are not faced
with that.
MR. KLAPPROTH: So, with that, I will turn
it over to Gene to walk through some of the background
information if there is no further questions.
CHAIRMAN WALLIS: I think it will be
interesting. Maybe it is not G.E.'s job to look at
one of these things and say with a pressure vessel,
and core geometry, what do you do to get more power
out of it, and presumably we circulate more water and
things like that.
And maybe you are not asking for it and so
you don't want to get into the details, but it is kind
of interesting for some HD student or someone to look
at one of these things and say, well, here are all the
things that we could do.
We could get a hundred percent more power
out or what, and I would be interested to see that.
Please go ahead.
MR. ECKERT: And we may be asked to answer
that question as good engineers by our managers. This
is a brief run through, and we have been with you
before, and especially connected with the extended
power uprate power program, and it is one of those
generic topical reports that were put together back in
June of '98.
We had some follow-up meetings with you in
July, answering some questions that you asked. It was
built off to 5 percent in an earlier program, and
keeping as Jim was saying the criteria for
acceptability of the plant was to be kept the same,
and that we were not changing the criteria that we had
to meet.
We expected this to be handled pretty
well, and it has been holding up pretty good, and we
can see that we are getting close to some things, and
that's probably it is not an automatic answer that we
go beyond 20 without some changes in the NSSS.
The balance of the plant did need
significant changes, and we recognize that, and the
utilities struggle with what is it worth, and is it
worth that investment at our plant, and many of them
are deciding, yes, it is.
I have this bullet about MELLLA. We are
throwing acronyms out here. This is a term that G.E.
has used over the years to describe the operating
domain that we use on our map.
We call it a power versus core flow map,
and we have defined the range of operability at which
we call normal operation, and it has expanded over the
years up to this title called, "Maximum Extended Load
Line Limit Analysis."
Load line meaning the rod line, flow line,
and that if we change core flow power, it moves up and
down with core flow, and that is a common way we
change power in the plants.
We don't change our rod patterns up at
high power generally. We change core flow to do that,
and we will see some pictures of it in the rest of the
presentation.
CHAIRMAN WALLIS: Are you going to show us
the stability and instability region?
MR. ECKERT: We will talk about which
region is most at risk for stability considerations
and what happens there. When we went to extended
uprate, we constrained ourselves in the utilities not
to go above the previously licensed boundary, and that
was an important term relative to the stability
question, because we did not want to push ourselves at
that time, or now, beyond that line for these basic
extended upright plants.
And so there may be some plants that were
not licensed all the way to this line before, but the
fleet had examples of every product line that had gone
up to this boundary, and so some plants are moving up
to the previously licensed boundary, but none of them
-- and what we are calling the extended power uprate
program -- are going beyond this previously licensed
boundary on the power flow map.
And you can think about it as a power flow
ratio kind of boundary that we have agreed to remain
constrained within. There is a combination of things
that came out of this effort, which is partly generic,
and partly plant specific.
And that was differentiated and defined as
we went into our topical reports that tried to
establish the guideline that this is needed to be done
plant by plant because it has some unique features.
And that these are things that need to be
done even cycle by cycle, which is pretty costly
coupled to our GESTR effort for reloads, and there
were some things that we could handle generically and
say that all BWR4s are bounded by this one analysis,
or all BWR6s can be bounded by this one analysis. And
wherever possible that was included in our generic
material.
CHAIRMAN WALLIS: So this mellow boundary
is independent of the fuel or the flux distribution?
MR. ECKERT: It is applicable to all of
our fuel types, and plants operate up to that
boundary, and we will look at it in detail.
CHAIRMAN WALLIS: And the boundary is
somehow independent of fuel and so forth?
DR. KRESS: When you decrease flow, if you
had the same power, you would increase the void
fraction?
MR. ECKERT: Correct, which unbalances the
reactivity.
DR. KRESS: And so the reactivity comes
down.
MR. ECKERT: It pushes you back down.
DR. KRESS: And this MELLLA line is the
description of that effect?
MR. ECKERT: And it is almost -- you know,
for the first rule of thumb, it is a constant void
fraction line. It is not perfect, but it is basically
that the reactor forces us to stay at the said void
fraction when we have the same rock pattern.
DR. KRESS: So it is a natural --
MR. ECKERT: It is a basic physical
characteristic.
DR. KRESS: -- physical characteristic of
all the reactors?
MR. ECKERT: Of our wonderful machine,
yes.
DR. KRESS: I think that is useful for
this committee to understand.
MR. ECKERT: We will have more detail
later, Tom.
DR. KRESS: So it would depend on your
fuel in some way wouldn't it?
DR. KRESS: Well, it really does depend
some on that, yes.
MR. ECKERT: We calculated for different
fuels, and it is amazing how close it follows, because
it has got the thermal-dynamics of the constant void
fraction built into this.
DR. KRESS: It is really the effect of
void fraction on the neutrons, and it is almost
independent of the kind of fuel it is. Not quite, but
almost.
MR. ECKERT: All of our fuels have strong
negative void reactivity characteristics, and so it
forces us back to very close to identical void
fraction, which is --
CHAIRMAN WALLIS: Which shuts itself down,
and moves it around.
MR. ECKERT: We submitted two different
topicals basically. One we call ELTR1, and that had
followed our previous generic document LTR1, which was
the 5 percent uprate, and this is the bigger uprate,
but it was basically a guideline document.
Here is the scope of what needs to be
looked at and here are the key criteria that we are
going to commit ourselves to. We reviewed that with
the staff, and we reviewed it with you, and we reached
agreement on that.
And then ELTR2 is the place where we have
documented generic topical material that can be used
by different plans, and as generic, we think that this
issue can be settled this way, and a plant simply has
to confirm that we are within the generic package that
you have submitted before.
For the big uprates, obviously there were
a few less generic things that we could do than we did
for the smaller uprates, but we still had this
advantage to the total program.
We presented this and reviewed it with
you, and coupled very closely with the Monticello
extended uprate. So it was a BWR3 and then it went up
6.3 percent above what they had started operating
their unit at.
And then very closely coupled after that
were the Hatch 1 and 2 submittals that followed this
program. And we had questions from you, and tried to
and did resolve that, and have received acceptance of
that program. And that has led to all the activity by
the utilities.
CHAIRMAN WALLIS: And this concluded --
you are saying that ACRS concluded or you concluded?
MR. ECKERT: Well, mutually we concluded
it, and we are moving ahead.
DR. KRESS: We actually had a letter on
this.
MR. ECKERT: The staff has given us
approval.
CHAIRMAN WALLIS: Well, we certainly
approved it, and so I was wondering if we used these
exact words?
MR. ECKERT: I think these are my words.
And I am not too much of a salesman, but I have a
little. There is some terminology that we wanted to
make sure that you understood, and we have probably
since then, by using the term stretch power uprate a
little more than we did back then.
And that meant this early program that was
up to about 5 percent uprate, and it was basically
already built into most FSARs, and it was just that we
were not licensed there immediately, and we just went
up to it.
And it is based on percent of original
licensed in most of our discussions. Extended means
the step that could up to the 20 percent level above
the original license.
All plants are not choosing to go that far
based on what their economics are for their turbine
generators, or whatever their system might be. It
might be that they don't have room for another pump to
go in, or would need it, or whatever.
So economically each customer will look at
that, and pick a point to shoot for. And just
recently you are seeing the ones that are coming close
to saying, hey, we think we can get darn close to 120.
DR. LEITCH: Gene, just a terminology
question here. If I say the term extended power
uprate, that generally means that there is an increase
in pressure; and if I say the term constant pressure
power uprate, I understand what that means.
MR. ECKERT: That's a good question. In
the past, our EPU program included the potential to go
up in power and pressure, depending on the balance of
design trade-off's that would go on.
And by going up in pressure, we could save
a little bit in our turbine MODs and things like that.
So the general program in 1998 had the option of
pressure increases, as well as power increases, and
you will see those topicals discussed it.
The CPPU, constant pressure power uprate,
fresh stuff coming at you now, is to constrain
ourselves to keep that dome pressure constant, even
though we may be going up as much 120 in power.
And that is the more recent path, and even
the ones that have done power uprates we will talk
about in a little bit. Many of them, if they have
gone up in pressure, they haven't gone very far, and
then they decided to do most of their uprates without
raising pressure because of saving lots and lots of
extra considerations for the primary boundary.
CHAIRMAN WALLIS: Do you have figures for
the cost per installed whatever, megawatt or whatever,
whatever the capital cost is for this uprate? I mean,
you are not buying a new reactor. You are just buying
some balance of power.
MR. ECKERT: You are asking the wrong guy.
CHAIRMAN WALLIS: Well, that is the motive
for this isn't it?
MR. ECKERT: Yes, it helps. It helps.
Some of it is avoiding just calculational costs, and
lots of paper, but there could well be some real hard
work changes, too, for the pressure change.
And that is these extra bullets here, the
different phases of uprate that have been coming at
you. There is one that we call thermal power
optimalization, and you may know it better just as an
Appendix K uprate.
In the sense where the better feedwater
measurement and equipment could get another 1 or 1-1/2
percent power by sneaking up closer to the analysis
that was done traditionally at 102 of the rated power.
And we have a parallel program for the
BWRs, and the staff has received a generic topical
that tried to scope out what was involved in doing
that type of uprate. That is not our main discussion
here today, but we wanted you to know that was also
coming along.
DR. BOEHNERT: Does that mean that someone
can go to 121.4 or 5?
MR. ECKERT: Well, that is a good
question, and we haven't really faced it. In theory,
the answer would be yes, but in practice, most of us
are being pretty cautious about saying that.
In reality, it says that if my license is
here, and my safety analysis is here, can I creep
closer to it because I have less power uncertainty,
and in theory the answer is yes.
I already have it basically. I do a 120,
and it says that I am going analysis at 123-1/2
already. So I would vote yes, but I have more
cautious people behind me.
And we are not forcing you to say, yes,
you can go beyond 120 that way. Some day somebody may
come and ask for that.
DR. BOEHNERT: So you have not made a
decision one way or the other, I guess?
MR. ECKERT: The topical that we have
submitted says that if a plant is already upgraded
five percent or whatever, they can abide this thing.
So in theory if somebody had really gone all the way
to 120, we would say it is theoretically possible.
We don't have a project pushing for that at this
point.
DR. BOEHNERT: Okay. Thank you.
MR. NIR: We recommend that the customer
will analyze and perform the analysis at 122, or 2
percent above 120.
MR. ECKERT: All of the new ones are being
done under the old rules with respect to power
uncertainty, and none of the new submittals to you or
the staff at this point are saying we are going to an
uprate, and we are only doing it with this tiny
uncertainty factor.
And in the constant pressure one, we will
talk about more during the presentation, and we have
already touched on that; that it just involves being
constrained, and constraining ourselves that dome
pressure does not go up with the power, which we can
control.
That is our common control system for all
our plants, and it is constrained by our tex specs.
We will talk a little bit about on-line
implementation, which is something that maybe wasn't
as actively on our table with you when we were here in
'98.
And that we have now come up with some of
the better ways to implement uprate as we go through
the licensing approval process, as well as the
practical parts of doing plant MODs, and so forth.
CHAIRMAN WALLIS: You don't just suddenly
throw a switch and the power is 20 percent bigger?
MR. ECKERT: Right. These give you more
details about these different parts of the program,
and what was called the stretch, and the five percent
one, and it introduced this idea of LTR1, and LTR2.
And there was good communication between
us and the staff, and I thought a good exchange, and
a good challenge to each other. The standard was
similar and built on it, and here are some dates at
which these things were submitted, and when our
plants, the lead plants for this program made their
submittals.
I think Fermi-2 was the lead plant at the
five percent part of it, and Monticello and Hatch were
the lead plants on the larger ones, even though they
didn't go all the way to 20 percent.
On the so-called TPO or the small uprate,
this gives you a few details on the way that we were
doing this, and we are in the process of reviewing.
We have received some RAIs from the staff and are
responding to them and moving toward approval of this
half we hope.
I think there will be some plants that
follow this lead, or a couple that are submitting such
submittals to you independent of our topical approach,
and in some manner this will be merged together as the
staff reviews the process.
Basically, we are trying to take advantage
of everything that was already done at the 102 or more
above today's license, and to identify pretty clearly
what ought to be reviewed because it was done back at
a hundred percent.
Things like ATWS were agreed upon to be
done back at a hundred, for example, and so we talk
about what happens if we were up a percent or a
percent-and-a-half above that.
MR. KLAPPROTH: I think the only other
point that we should make here is that last bullet.
We do expect three submittals by the first quarter of
next year on a TPO approach.
CHAIRMAN WALLIS: And that involves some
different instrumentation then?
MR. KLAPPROTH: Better instrumentation and
measuring feed water flow, which is a primary element
in our power uncertainty calculation.
CHAIRMAN WALLIS: And is there certain
technology being used for that flow rate, flow
measuring?
MR. ECKERT: The technology has been
reviewed by the staff and has gone through the ringer.
Caldon is one of the suppliers, and I think ABB has a
system.
CHAIRMAN WALLIS: So anyone who can prove
itself is?
MR. ECKERT: Yes, and we are saying that
based on whatever they claim, you can creep ahead
following this guideline of scope of work.
DR. UHRIG: This is with the original
single pass system from Caldon, and the newest X
system?
MR. ECKERT: We have written our work that
says that we are not claiming what the improvement is.
We have said that if you can defend a claim of a
percent improvement, here is the safety work that
would be needed.
The CPPU you will hear us talk about quite
a bit today, and we hope that it facilitates the
future applications. It takes a lot of work out of
the process because we aren't pushing temperatures and
pressures harder in lots of the equipment.
It remains functioning at the same
pressure temperature conditions that it is operating
at today. It gives us another vehicle to work with,
and our utilities to accomplish the uprates without
extra work involved that the pressure change would
have.
We have submitted this topical generic
approach to this earlier this year, and so we are in
the process of that review. Tomorrow is a meeting to
discuss this, and keep communicating about what needs
to be done to reach agreement on what should be
included in this approach. We will hear more later
and it involves some other recommended improvements
just in the process of going through the uprate
programs.
This little chart talks about the on-line
implementation IDF, which is trying to decouple the
moment we actually have approval on an SER from the
staff, and to say, yes, we agree, and you can go up in
power.
And from when outages are for a given
plant, and so the outages give the utility the time to
do any MODs that are needed, and they will do that in
a series of changes maybe for larger uprates.
But they would introduce some MODs and an
outage in anticipation of getting approval during the
cycle, and having submitted it to the staff for review
and resolving questions, and getting approval mid-
cycle.
They are prepared to at least take
advantage of part of that approved new power level
during this first cycle that the approval is received.
The approval doesn't have to come
immediately at the time of a start up from an outage,
and that helped quite a few ways. There are some
things that you have to wait to get changed out here
perhaps.
But part of the uprate can be taken
advantage of right away, and it helps in the
scheduling of all this stuff with utilities and
ourselves, and with the staff.
It takes a little bit of heat off the
staff, and they don't have to be right there on the
day they want to pull rods and come out of an outage.
And so it made it more practical for all of us.
This chart -- we keep showing you these
with the list of plants, and the list keeps growing.
The column on the left are the plants that have
basically done uprates in the past and have included
some pressure increase in their plant.
And part of our discussion with you today
is especially aimed at helping you understand the
constant pressure path that we think that everybody
else will be on.
Some of the plants on this column even
might have uprated or had increased pressure during
part of their uprate, but not all of it. Like this
plant in Switzerland, the Liebstadt plant, when they
did their first 5 percent uprate, they did the uprate
and pressure as well, and it was 20 pounds or
something. It was some amount.
But then when they went to the big uprate
that followed, they adopted our constant pressure
thing just for practical reasons of their own. So
they have gone the last 15 percent or 14 percent
without raising pressure.
But they did some analysis with the
pressure increase, and they looked back and said, hey,
I would rather try to do it without all those set
point changes, and all the other changes that are
needed, and they also have gone a long ways without it
for the second half of their uprate.
It is a pretty big list over here of
plants that have already or are planning to go up in
power using the constant pressure approach. And the
starred ones are the ones still in process, and
including the ones that we talked about before.
And Cofrentes is a plant in Spain that has
done a small amount of uprate and are going to bigger
uprates in the process of that. We show the Brown's
Ferry units on here that weren't on the previous list,
but we have been working with them and aiming at a
target up here, and they are present in the crowd here
today.
And they are very interested in seeing the
same program, and there are others that we are talking
to. The last chart there is the real benefit for all
this that we are all seeing as an industry, and we are
trying to accomplish wisely and safely.
There are pretty big numbers starting to
add up here. Completed uprates in the neighborhood of
1,250 megawatts. There is some differentiation in the
charts here. The first block are the five percent
uprates, and then there is the little chunk on top of
here that are the EPUs, the bigger uprate programs
starting to be shown on the map.
CHAIRMAN WALLIS: I don't understand that.
Are you referring to total megawatts of?
MR. ECKERT: This is the added megawatts
to the fleet. It is not an individual plant, but this
is the sum of the plants that have uprated. And these
are the ones in process, and these are almost totally
the extended uprate plants that are part of our plan.
We are estimating from the year 2001 to
2003 that we will get these additional uprates and a
little bit coming in as part of what we are calling
thermal power optimization. Not as big, but still
vital power for these people.
DR. KRESS: Now, going from the second
column to the third column, does the third column
include the bottom of the second column that are in
progress?
MR. ECKERT: No. These are contracts in
hand, and --
DR. KRESS: They are expected to be
finished before you get to this other?
MR. ECKERT: Yes. And this would be even
our estimate out further.
DR. KRESS: So those are all new
megawatts?
MR. ECKERT: Yes, each column is
independent.
DR. CRONENBERG: And is Brown's Ferry in
the forecast?
MR. NIR: I believe it is in the third
column, 2001.
MR. ECKERT: Yes, at the time that this
chart was made.
CHAIRMAN WALLIS: And that is equivalent
to five new plants?
MR. ECKERT: Five, 930 megawatt plants.
CHAIRMAN WALLIS: And the problem is that
the 930 is so close to the 960 and the 1100, do you
think that you are talking about individual outrates?
MR. ECKERT: Yes, that is what is sounds
like, but it was just a way of expressing it. We
believe that we are consistent in supporting what the
staff requirements are in terms of supporting the
plants for additional power.
CHAIRMAN WALLIS: And this is your
contribution to the 10,000 --
MR. ECKERT: We just need some longer
extension cords to reach California though, and we
can't avoid the fact that this is giving high volume
work here through the process to the staff, and as
well for us, and for the utilities, too.
CHAIRMAN WALLIS: Are we through with the
open session?
MR. KLAPPROTH: That is the end of the
session, yes.
CHAIRMAN WALLIS: So let's take a break
and I think we can come back at five after, and that
will give us a 12 minute break.
(Whereupon, the Open Meeting was recessed
at 2:54 p.m. and the proceedings resumed in Closed
Session at 3:05 p.m.)
Page Last Reviewed/Updated Tuesday, August 16, 2016
Page Last Reviewed/Updated Tuesday, August 16, 2016