Official Transcript of Proceedings
NUCLEAR REGULATORY COMMISSION
Title: Advisory Committee on Reactor Safeguards
Thermal-Hydraulic Phenomena Subcommittee
Docket Number: (not applicable)
Location: Rockville, Maryland
Date: Tuesday, April 23, 2002
Work Order No.: NRC-345 Pages 1-64/89-183/225-273
NEAL R. GROSS AND CO., INC.
Court Reporters and Transcribers
1323 Rhode Island Avenue, N.W.
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(202) 234-4433UNITED STATES OF AMERICA
NUCLEAR REGULATORY COMMISSION
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ADVISORY COMMITTEE ON REACTOR SAFEGUARDS (ACRS)
THERMAL-HYDRAULIC PHENOMENA SUBCOMMITTEE
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APRIL 23, 2002
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The subcommittee met at the Nuclear
Regulatory Commission, Two White Fling North, 11545
Rockville Pike, Rockville, Maryland, at 8:30 a.m.,
with Graham B. Wallis, Chairman, presiding.
Graham B. Wallis, Chairman
Thomas S. Kress, Member
Graham M. Leitch, Member
John D. Sieber, Member
ACRS STAFF PRESENT:
Paul A. Boehnert
Sanjoy Banerjee, Consultant
Virgil Schrock, Consultant
Zena Abdullahi, NRR
Singh Baywa, NRR
Herbert Berkow, NRR
Ralph Caruso, NRR
Richard Eckenrode, NRR
Raj Goel, NRR
George Georgieu, NRR
John Hanon, NRR
Donnie Harrison, NRR
Tai L. Huang, NRR
Thomas Kosity, NRR
Richard Lobel, NRR
L.B. (Tad) Marsh, NRR
Brenda Mozafari, NRR
K. Parczewski, NRR
Dale Thatcher, NRR
N.K. Trehan, NRR
Tony Ulses, NRR
Mike Waterman, NRR
Jim Wigginton, NRR
Cheng-Ju Wu, NRR
Terry Bowman, CP&L
Eric V. Browne, CP&L
Tom Dresser, CP&L
Paul Flados, CP&L
Cornelius J. Gannon, CP&L
Mark Grantham, CP&L
Robert Kitchen, CP&L
Larry Lee, CP&L
Daniel Poteralski, CP&L
Mark Turkal, CP&L
Michael S. Williams, CP&L
Blane Wilton, CP&L
Larry Yemma, CP&L
Fran Bolger, General Electric
Hoa Hoang, General Electric
Carl Hinds, General Electric
Dan Pappoane, General Electric
Jason Post, General Electric
George Strambook, General Electric
Ben Gitnick, ISG, Inc.
Brian Hobbs, VYNPC
Lawrence Lee, ERIN
Emin Ortalan, PSEG
R.H. (Jackie) Wright, TVA-BFN
TOPIC PRESENTER PAGE
Introduction G. Wallis, Chairman 6
Brunswick Steam Electric Plant Core Power Uprate
Carolina Light & Power Presentations
Overview R. Kitchen 8
Plant Modifications for Uprate
Key BSEP Differences from other BWR
Impact on Plant Margins
Core Considerations T. Dresser 33
Fuel/Event response for ATWS & Power
(CLOSED SESSION UNDER SEPARATE COVER)
Reactor Vessel B. Wilton 65
Irradiation-assisted Stress Corrosion Cracking
Reactor Vessel Embrittlement
Reactor Vessel Internal Component Fatigue
Containment Response M. Grantham 103
Impact on Load Limits
TOPIC PRESENTER PAGE
Electrical System T. Bowman 110
Off-Site Power Considerations
Piping Stress Limits L. Yemma 119
Probablistic Safety D. Potealski 126
(CDF, LERF, and CDFs/LERFs)
Operator Actions and M. Williams 137
Brunswick Steam Electric Plant Core Power Uprate
Carolina Light & Power Presentations (Cont'd)
Concluding Remarks N. Gannon 162
Introduction B. Mozafari 178
(CLOSED SESSION UNDER SEPARATE COVER)
PRA Analyses/Evaluation of D. Harrison 183
Licensee's PRA Examinations
Plant Systems Review R. Lobel 242
Concluding Remarks B. Mozafari 259
Subcommittee Caucus 262P-R-O-C-E-E-D-I-N-G-S
CHAIRMAN WALLIS: The meeting will come to
order. This is a meeting of the ACRS subcommittee on
thermal hydraulic phenomena. I'm Graham Wallis, the
Chairman of the subcommittee. Other ACRS members in
attendance are Tom Kress, Graham Leitch and Jack
Sieber. ACRS consultants in attendance are Sanjoy
Banerjee and Virgil Schrock. I'd like to welcome Dr.
Banerjee to this committee. Dr. Novak Zuber
(phonetic) served us very well for many years and
we're looking for a replacement that --
MR. KRESS: That's a hard act to follow.
CHAIRMAN WALLIS: -- that would be the
caliber of Dr. Zuber. There's no way I could compare
you to Dr. Zuber, you're completely different people
but the caliber is certainly comparable. The
subcommittee will begin review of the application of
the Carolina Power and Light Company for a core power
uprate for the Brunswick Steam Electric Plant's Unit's
1 and 2 and the NRC staff's associated safety
The subcommittee will gather information,
analyze relevant issues and facts and formally propose
positions and actions as appropriate for deliberation
by the full committee. Mr. Paul Boehnert is the
cognizant ACRS staff engineer for this meeting.
The rules for participation in today's
meeting have been announced as part of the notice of
this meeting previously published in the Federal
Register on March 20, 2002. Portions of the meeting
will be closed to the public to discuss information
considered proprietary to General Electric Nuclear
Company, Nuclear Energy.
A transcript of this meeting is being kept
and the open portions of this transcript 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 nor requests for time to
make oral statements from members of the public.
We'll now proceed with the meeting. I
would like to finish, if at all possible, the
Brunswick presentation before lunch. We'll have a
break at some convenient time in the morning and then
move to the staff presentation in the afternoon hoping
that that will be over before about 4:00 o'clock. So
without more ado, is Bob Kitchen ready to present?
It's all yours.
MR. KITCHEN: Thank you. Good morning.
I'm Bob Kitchen, the project manager for the power
uprate at the Brunswick Station. I'd like to start
MR. BOEHNERT: Use the microphone, Bob.
MR. KITCHEN: Is that better?
MR. BOEHNERT: Yes.
MR. KITCHEN: I'd like to start first by
giving you an overview of the project for power uprate
at Brunswick and also to give you reference points to
understand the current operation of Brunswick.
Brunswick actually did a five percent uprate several
years ago so our current power level relative to the
original licensed power level is 105 percent.
We also operated on a two-year operating
cycle which, I think, we're the first EPU for the
committee on a two-year operating cycle. Our request
for extended power uprate is actually an additional 15
percent increase from where we currently operate today
and that will put the station at 120 percent operation
relevant to our original license.
The difference from our previous uprate
are one of the more significant ones for us. On our
previous uprate, we did actually raise reactor
pressure in association with that uprate. The
extended power uprate proposed for Brunswick this
times does not include a reactor pressure increase.
The uprate, similar to the others that the ACRS has
seen, will be performed in two steps with a license
receipt. We will implement the first increment of
uprate on Unit 1 to about 112 percent power relative
to our original license. That's limited by our fuel
load for base load operation during the cycle.
On Unit 2, we actually loaded fuel to the
new fuel type that we need for the two-year cycle and
uprate previous outage on Unit 2 so we were able to
take a little bit advantage of that and our first step
on Unit 2 will be a little bit higher in power up to
115 percent relative to original power.
Dr. Schrock: On the pressure, does the no
pressure increase refer to the current pressure rating
or the original pressure rating?
MR. KITCHEN: It refers to the current
Dr. Schrock: Thank you.
MR. KITCHEN: The second step --
MR. LEITCH: Bob, are you seeking at this
time the license increase all the way up to 120
MR. KITCHEN: Yes, sir.
MR. LEITCH: So that in the cycle, the one
cycle, between the first physical work and the second
physical work being done, you would be operating at
approximately 112 to 115 percent but during that
interval, the license would be 120 percent?
MR. KITCHEN: Yes, sir, that's correct.
We're actually limited by balance-of-plant equipment
and I'll show you the modifications that we're doing
and you'll see why that is.
MR. LEITCH: Thanks.
MR. KITCHEN: Just to give you some
reference point on our core operation, originally we
were licensed to 2,436 megawatts thermal. The uprate
that we are proposing would take the plant to 2,923
megawatts thermal. That's a 20 percent increase again
from our original license.
MR. KRESS: Are these identical for both
MR. KITCHEN: Yes, sir.
MR. LEITCH: So when you're talking about
it, you're talking about both units.
MR. KITCHEN: Yes, sir. You can see the
core steam flow, B flow, increase would be
proportional to the power increase and you can see the
pressure change from the previous uprate. We went
from 1020 to 1045 and that will remain constant for
Just to give you, this is our current
power flow operating map. I know you've seen these
before, just to show you where we are operating. The
100 percent on this map refers to current power
operation, 100 percent, so that includes the stretch
uprate to five percent shown in the green band on the
power flow map. The extended power uprate region is
shown in yellow and is the upper 15 percent that we're
talking about on this power increase.
Modifications; we'll refer to the safety
significant modifications that the plant's going to
perform. We need to increase the Boron concentration
in our standby liquid control system to provide cold
shutdown reactivity requirements for standby liquid
control. We'll be doing that prior to the second fuel
load on each unit.
CHAIRMAN WALLIS: Is someone going to
explain that? I read what you intend to do. I didn't
see what -- is there an acceptance criterion you are
trying to meet by this change in concentration?
MR. KITCHEN: Yes, sir, we'll talk about
that a little more later.
CHAIRMAN WALLIS: You'll give us a logical
explanation of why this meets some criterion.
MR. KITCHEN: We'll show you the
CHAIRMAN WALLIS: Okay, thank you.
MR. KITCHEN: We've also -- associated
with this uprate, we've changed our power range
neutron monitoring system. We've gone to digital
instrumentation and that also involves a change from
out thermal hydraulic stability solution. Currently
we operate on one unit, that's stability solution E1A,
that's Unit 2. Unit 1, which was the first unit to
operate, has been converted to -- with the new system,
to thermal hydraulic stability Option III. That
system was installed during the refueling outage that
we just completed on Unit 1 at the end of March.
And finally, we've got unit trip load shed
modification which is an electrical modification to
insure that under accident conditions that we would
maintain the required voltage at our emergency busses.
At Brunswick our emergency busses are fed from offsite
through balance-of-plant busses. This modification is
planned to insure that the required voltage is
maintained under all conditions.
As you've seen, the extended power uprate
really is much more challenging for balance-of-plant
equipment than the previous uprate and more
significant modifications to the plant required our
balance-of-plant modifications and we have quite a
list. The first is the high pressure turbine
replacement. This is required to provide the needed
steam flow for uprate as well as the power generation
Along with that is a change in our
electro-hydraulic control system, EHC, that currently
on one unit we operate on Unit 2 with 3-Arc, we're
going to 2-Arc partial control.
MR. SIEBER: You expect, that means you
have nozzle banks that aren't being used.
MR. KITCHEN: We operate the valves, yes,
steam chest entry is staged with three valves first
and then one valve as we go up in power.
MR. SIEBER: Do you worry about cracking
of the nozzle bore?
MR. KITCHEN: Yes, sir, that's actually
the reason why we changed from a 3-Arc to 2-Arc. As
you mentioned, there is a pulse stimulus on the first
stage high pressure turbine buckets because of partial
arc and GE's design review of that indicated that we
needed to go to 2-Arc which provides more fold around
the nozzle block steam emission and reduces that
MR. SIEBER: All right, thank you.
MR. KITCHEN: Also we need to replace
reactor feed pump turbines to provide -- also to meet
design requirements for bucket loading as well as
horsepower requirements for the turbine, for the
pumps. We've got several feedwater heaters. You'll
see this listed in both stages. Primarily those are
changed because of tube plugging that we'd had over
the years and with the uprate we needed to replace the
heaters to support that.
We've got also some actions that were
taken to improve grid stability under operate
conditions. A couple of things factor into that and
we're going to discuss that more in detail with our
presentation later but as we increase the load on the
units and also as our area transmission load increases
we can effect stability.
A couple of modifications that we're doing
there, we're going to discuss these with you later in
the presentation, is the power system stabilizer which
is a feedback modification on our generator as well as
out-of-step protection to protect not only the grid
but also the generator being installed.
MR. SIEBER: With respect to the feedwater
heaters, these are going to be larger in surface than
MR. KITCHEN: Actually, the feedwater
design that we have for the -- we have five stages of
feedwater heating -- are adequate for uprate. Our
design review indicated those that would be limiting
because of tube plugging or other degraded conditions
in the heaters just from normal service life. And
those are the ones that we're replacing. Where we
replaced them, we're trying to optimize the design.
So, in fact, we do try to use a larger heater and
that's really for efficiency more than uprate support.
MR. SIEBER: But that gives you a plugging
margin, too, right?
MR. KITCHEN: Yes, sir.
MR. SIEBER: Okay, what materials are the
Dr. Schrock: You're not redesigning the
feedwater heating system for higher thermal
efficiency. It's basically the same thermal cycle as
the original one?
MR. KITCHEN: Yes, sir, it's the same
thermal cycle. We're just trying to take advantage of
a new component with larger surface area for better
heating on that heater.
I need to check. I think the tubes are
stainless but I need to check on that.
MR. SIEBER: Were the original stainless?
MR. KITCHEN: I don't remember.
MR. SIEBER: Okay, thank you.
MR. KITCHEN: Yes, sir.
MR. SIEBER: That's not so important you
have to go and check it.
MR. KITCHEN: Okay.
MR. SIEBER: Okay?
MR. KITCHEN: We're also going to -- our
first uprate we pulsed more power out of the generator
on the bus bars and we need to increase the cooling,
our bussed out cooling, so we'll be doing some
These are the mods that are being done for
the first uprate. The modifications that you see
listed here have been completed on Unit 1. We just
finished a refueling outage at the end of March and
we'll be doing these mods, similar mods on Unit 2 next
For the second uprate on each unit, we
have additional modifications to perform. Our main
transformers become limiting at about 115 percent of
our original power, licensed power. So we'll be
replacing those on each unit as well as putting in new
feedpumps to increase capacity and provide better
margin on our feedwater system with new feedpumps.
We're going to upgrade our condensate pumps and
motors. We want to maintain -- currently we run three
condensate pumps and three condensate booster pumps in
our system with -- we have those three pumps
available. We run two pumps with one standby and our
desire is to maintain a standby pump under operate
conditions. So to support that, we're going to make
some changes in the motors and pumps to enable a
standby pump to be maintained.
And finally, we're going to moisture
separator reheaters. Again, like feedwater heaters,
there's really two drivers there. One is to insure
that we don't have flow vibration problems, although
our review indicated we would not, but also to gain
significant efficiency improvement through the
moisture separator bundles.
MR. KRESS: When you say you upgrade a
condensate pump and motor, does that mean you just
rewind the motor or -- and redo the rotor on the -- or
do you replace the whole thing?
MR. KITCHEN: We would replace the motors
where they exceeded their design rating.
MR. KRESS: But you'd keep the same pump
attached to that?
MR. KITCHEN: Yes, sir, now the condensate
pumps, we would actually make a modification to one of
the stages to insure that we had adequate net positive
suction head. So there are some changes in the pumps
but the overall pump itself remains.
MR. KRESS: Okay.
MR. LEITCH: There's an auxiliary
circulating water system or condensate cooling system
that I read about, are you going to discuss that?
MR. KITCHEN: I hadn't planned to but we
can. We're actually still reviewing the need for that
system. That is a system of heat exchangers which
basically just routes the condensate flow through two
stages of heat exchangers, regenerative and non-
regenerative heat exchangers that reject heat through
a cooling tower system as designed. The driver for
that is condensate temperature and the impact that it
would have on sulfates and chemistry and we're still
working through -- we're actually hopeful that we can
avoid the need for that system and right now looking
hard at whether we'll have to put it in at all.
If we do install it, it will be installed
in the second uprate.
MR. LEITCH: Okay, I guess the -- it
seemed like there was a couple of mechanic draft
cooling towers. Would the plan be like a closed
circulating water system?
MR. KITCHEN: Yes, sir. Actually, the
make-up water, they're water cooled towers. They
would be three towers located on the roof of one of
our buildings in the power block, and the heat
exchangers would reject heat to those towers. The
tower make-up water would come from our county water
system and then chemical control for normal cooling
MR. LEITCH: Okay, but that whole issue is
still -- there still is some doubt about whether
you're actually going to do that.
MR. KITCHEN: Yes, sir. I think probably
we will not need that modification.
MR. LEITCH: Then failing that, assuming
you're not doing that, would the turbine operate at a
higher back pressure? In other words, I'm picturing
a higher condensate, a higher circulating water
MR. KITCHEN: Actually, the system would
not effect our condenser vacuum. It's on the -- the
system is installed on the inlet to our condensate
demineralizer, so it's downstream of the condenser and
it really would not have any significant impact on our
condenser vacuum at all.
MR. LEITCH: Isn't there a concern about
the temperature that the resin would be exposed to in
your filter demineralizers? Where are they in the
cycle? They're --
MR. KITCHEN: Our flow is through -- we
have condensate filter demineralizers first that
filter out particulate as well as some -- they are not
resin coated and then the flow goes through condensate
MR. LEITCH: Oh, deep-bed demineralizers?
MR. KITCHEN: Yes, sir, and you're exactly
right, the concern is how much temperature can you
allow and not cause a chemical release to be a
problem? Sulfates are the only release of
significance there at the temperatures we're looking
And we were hopeful that we're going to be
able to not have to cool that condensate temperature
to maintain appropriate sulfate levels.
MR. BANERJEE: Are you making any
modifications to the chemistry control system for --
MR. KITCHEN: No, we're not.
MR. BANERJEE: Not at all.
MR. KITCHEN: No, sir.
MR. BANERJEE: You're adding zinc?
MR. KITCHEN: Yes, we did. We're going to
talk a little later about our reactor chemistry
control, specifically hydrogen water chemistry
MR. LEITCH: Back on the safety related
modifications, I was wondering if you had to do
anything to the -- to avoid potential instability, if
you had to make any changes. I guess, basically, my
question is, how does Brunswick avoid an instability
region on the power flow map and are you changing that
MR. KITCHEN: No, sir. We changed our
stability solution but it really is a desire to -- for
a couple of reasons on the power range system, the
driver was not the -- that we had to go to a new
thermal hydraulic stability solution. We currently
operate with E1A which is acceptable for power uprate
but it's -- there are a little bit more operational
restrictions with E1A than with Option III.
And with Option III we saw benefits in the
automatic SCRAM protection and the -- a little bit
more flexibility operationally for our situation. In
terms of avoiding thermal hydraulic instabilities, you
saw the power to flow map has not changed. Our
operating regions remain the same. The only change
for us is in the new system and the changes that it
MR. LEITCH: So you are going to what is
called Option 3?
MR. KITCHEN: Yes, sir. In fact, that is
operable on Unit 1 right now.
MR. LEITCH: I see, and tell me again, I'm
a little confused as to exactly what Option III means.
MR. KITCHEN: Option III is a stability
algorithm. If you compare the two stability
solutions, E1A is prevent solution and it has very
large restricted areas or larger restricted areas in
the power to flow map operating region. Option III
also has areas of avoidance of course, but also
provides automatic SCRAM protection based on stability
The one that is safety related is called
a period based algorithm and it looks for frequencies
that are known to represent instability phenomena and
provides an automatic SCRAM if certain threshold
requirements are met. So you've got the operator
manual actions and now also automatic protection.
MR. LEITCH: Okay, and that is active on
Unit 1 right now?
MR. KITCHEN: Yes, sir. We installed the
system on Unit 1 and it is operable.
MR. LEITCH: Yeah, thank you.
MR. KITCHEN: Just to touch on margins,
the overall extended power uprate reduces margins in
the plant and we're going to discuss those in detail
under our fuel design and vessel reviews, et cetera,
but I wanted to also show you the things that we're
doing to try to maintain or mitigate margin reductions
in the plant. We've touched on them in the review
already but the SLC margin, we're going to increase
the Boron concentration significantly.
In fact, right now to meet our SLC
requirements at Brunswick, we require a two-pump
operation. And with the changes that we're making
we'll only have to have one that are accident
situation so that's a bit of a margin gain for the
plant operationally. Also the stability Option III
which we just talked about --
MR. LEITCH: On the Boron, and maybe we're
going to get into this a little more later and if so,
I can defer this question, but I basically, don't
understand what is meant by super Boron and I guess it
-- I thought I read that you don't need to have
heating with it and I'm wondering how the Boron stays
in solution. I mean the problem was we used to have
-- I'm picturing a curve in the tech specs that had
temperature versus Boron concentration and it was very
sensitive to temperature to maintain the right Boron
concentration. It sounds like that's all gone by the
wayside with this super Boron.
MR. KITCHEN: Yes, sir, it's an enriched
Boron solution, atomic enriched solution, so that
effectively it provides more concentration of Boron 10
in the solution. Also the solubility requirements are
less restrictive so the heat trace that we have
currently installed on the system would not be
required with that Boron enriched solution.
MR. LEITCH: So it stays in solution at
MR. KITCHEN: At lower temperatures, yes,
sir. I don't remember exactly the temperature for
solubility but it's much lower.
CHAIRMAN WALLIS: Super Boron has more
Boron tenants (phonetic), is that what makes the
MR. KITCHEN: That's correct.
MR. LEITCH: Why didn't we do this a long
time ago? Is super Boron super expensive?
MR. KITCHEN: Actually, I think it's
called liquid gold but it is expensive. I don't know
how long it's actually been available.
MR. SIEBER: It's been around for awhile
but it is costly.
MR. KRESS: You have to enrich the Boron.
It's an extra step.
MR. KITCHEN: It's significantly more cost
MR. LEITCH: So with this Super Boron and
you only need -- you can -- the standby liquid control
system can do its mission with just one pump then.
MR. KITCHEN: Yes, sir, because of the
concentration increase that we're putting in.
MR. LEITCH: Yeah.
MR. KRESS: The overall concentration of
Boron stays the same.
MR. KITCHEN: It's an effective increase.
MR. KRESS: Yeah, an effective increase of
MR. KITCHEN: Yes, sir. The stability
option we talked about a bit and again, we didn't have
to change solutions but we saw it as an improvement in
operating margin and also it involved no change in
safety margin since there are several stability
solutions all of which are acceptable for operation.
The power range instrumentation, really
the stability solution is a part of that. But the
power range instrumentation also offers advantages to
us. I should change that to say it's really improved
operator interface, the digital displays. Also there
is a bit of a liability because of the self-test
features of the system. There are fewer surveillances
to do, so there's less maintenance activities to do.
It eliminates the half SCRAMs from the
power range that we used to get while testing so there
are several advantages to a system change, and also
for us it addresses an obsolescence issue with parts.
The condensate system we've already
discussed but basically we just want to maintain our
standby pump to get better reliability for the plant
and finally the power system stabilizer which we'll
talk downstream in our briefing here, which improves
the situation on a higher plant load as well as higher
So we've tried to do some things that were
supporting of uprate but also helped us out with the
uprate. Some unique aspects for Brunswick, and again,
we've got an electrical presentation here because it
is a little bit difference for us than some other
plants, depending on your geographic location and
transmission system. So we want to talk a bit about
that with the ACRS. Also I think we're the first
plant with uprate that is hydrogen water chemistry.
We do not use normal metal chemistry. We wanted to
discuss that a bit with the ACRS.
And finally, our energy cycle requirements
are pretty demanding at Brunswick. We -- as I
mentioned, we're a two-year cycle which is of course,
a higher energy load and we operate at a very high
capacity factor. We manage to a 97 percent capacity
factor. So the two combined with an uprate makes for
a very large energy load for the plant.
MR. SIEBER: When you refuel what
percentage of the fuel is new fuel?
MR. KITCHEN: Right now, we load about 39
percent. With uprate, we'll go to about 47 percent
MR. BANERJEE: Does the two-year cycle
effect your cobalt levels radiation fields compared to
MR. KITCHEN: In the fuel itself?
MR. BANERJEE: No, no, on the external
MR. KITCHEN: The shutdown radiation
levels are not significantly impacted. I mean, there
is a radiation impact from operation directly to the
MR. GANNON: Can I make a comment about
the radiation levels? We use -- my name is Neil
Gannon, Director of Site Operations at Brunswick.
We've enhanced our practices with zinc injection and
our experience over the most recent two-year cycles is
about a 15 percent decrease in our radiation levels on
Unit 1. So we're able to manage -- the two-year cycle
has had no impact on dose rates.
Our use of zinc has actually allowed us to
experience a slight decrease in those.
MR. BANERJEE: When did you start using
MR. GANNON: Oh, I think it was about
four, five years ago.
MR. BANERJEE: And it's gone down.
MR. GANNON: Initially it remained flat,
controlled very well and our recent practice to
increase the amount of zinc is -- over this cycle on
Unit 1 showed about a 15 percent decrease in dose
rates in the driver, so this has been our first
experience to actually see it decrease.
MR. LEITCH: Thank you.
MR. KITCHEN: Before we get into detailed
presentations, there are some exceptions. We
generally followed the extended license topical
report. There were a few exceptions that we took in
our submittal. Three of these are related to the
constant pressure aspect of our uprate involving the
thermal-hydraulic stability. The ECCS-LOCA analysis
and reactor transients, and we'll discuss these in
more detail in the closed session that we have later
The last item is large transient testings.
As you know the ELTR requires for 10-percent uprates
an MSIV closure test and for 15-percent uprates a
generator load reject. We are also asking for
exceptions from those tests. I'll explain why here in
just a second but the exceptions that you see here are
all in line with previous uprate submittals that
you've seen for addressing Quad Cities as well, as
The generator load reject test,
unfortunately we had an event at Brunswick in
September of 2000 operating at full power which again,
for us is 105 percent relative to our original
license, where we had a transformer failure that, of
course, resulted in a generator load reject transient.
So that in fact, we've had this transient and that's
our basis for not including it as part of the uprate
The MSIV closure test, we are asking for
an exemption on. And the basis for that are, first of
all the fact that we are maintaining a constant
reactor pressure simplifies the analyses that are done
for uprate as well as minimizes plant changes required
to support uprate.
MR. KRESS: If you had not had this event,
would you still have asked for an exemption on that
large transient testing?
MR. KITCHEN: Yes, sir.
MR. KRESS: But that just gives extra
evidence to it.
MR. KITCHEN: Yes, sir, the ELTR allows
actual events, of course, to be included as a test and
that's our basis but had we not had it, yes, we would
have asked for the exemption.
MR. KRESS: Yeah, I think one of the other
plants, I forget which one, had not had one.
MR. LEITCH: I don't think any of them
MR. KITCHEN: I don't know if Dresden or
Dresden either have had one, I'm not sure.
MR. SIEBER: Dresden didn't and Quad
MR. LEITCH: No, I don't think they did.
MR. KITCHEN: We would have asked for the
generator load reject. We try to avoid these things.
We do surveillances that confirm component
performance. Then when you look at the transient test
and what you're trying to demonstrate with the
transient test, we feel that the component test that
we do adequately demonstrate the components and when
you look at the test itself, what makes the transient
very significant is reliance on the SCRAM from flux as
opposed to the -- we have an MSIV limit switch that
actuates the SCRAM as well and of course, for the test
we would not disable that.
And without that disabled, it certainly
minimizes the severity of the transient very much. So
it's nowhere near as challenging a transient under
test conditions as what we use for the analysis. And
when you look at what you are actually testing, the
surveillances that we do on components demonstrates
MR. LEITCH: On that point, I guess what
concerns one in this situation is are the MSIVs going
to be able to close in their required time, usually
three to five seconds with the increased steam flow
and how would you demonstrate that? Is that
demonstrated by one of the surveillance tests?
MR. KITCHEN: Yes, sir, actually it is.
Our surveillance requirement on MSIV is this closure
in three to five seconds. We have a y-type globe
pattern valve with steam flow over the seat so the
steam flow increase actually tends to try to shut the
valve faster. So the concern for MSIV closure would be
We installed the modification several
years ago that with the flow control valve in the
hydraulic actuator is adjusted to set, the closure
speed of that valve -- and by being on the hydraulic
side of the valve it's independent of the steam flow.
In other words, it maintains that constant closure
rate because it's supporting the fluid from one side
to the other. So our MSIV surveillances are performed
routinely and satisfactorily.
MR. LEITCH: Okay, thank you.
MR. KRESS: You check those without any
steam flow though.
MR. KITCHEN: Yes, sir, they're checked
during the refueling outage periods and adjusted, if
required, to put them in the center of that --
MR. KRESS: Have you ever run a test with
steam flow to confirm that steam flow actually doesn't
change the closure rate?
MR. KITCHEN: No, we do stroke testing the
valves at power but not a timing -- not a three to
The other basis for our request to exempt
this is the codes that are used to analyze it are
well-proven. The ODYN is used for the analyses and
has been proven to benchmark against plant transients
and it supports this transient as well. And finally,
as I mentioned earlier, it's not -- it's a severe risk
but it's not something that we would do if we had a
choice. That's all I have on the overview. We're
going to talk next about core considerations.
CHAIRMAN WALLIS: Thank you.
MR. DRESSER: Good morning. My name is
Tom Dresser. I'm with CP&L's DWR Fuel Engineering
Group. I'm going to speak this morning about five
different types of analyses all related to the reactor
core. The first two, the fuel bundle and core design
and the anticipated transient without SCRAM or ATWS
are performed completely consistent with GE's generic
topical for extended power uprate ELTR 2 and 2. The
last three, thermal-hydraulic stability, the emergency
core cooling system, loss of coolant in accident
analysis and the transient analyses each takes some
kind of exception to the generic methodology.
And my presentations will contain material
which GE considers proprietary so it's between the
second and third topic here that we'll need to take a
break to go to closed session. The complete package
of fuel bundle and core design is performed in several
different stages. The power uprate analysis itself
develops the idealize concept of an equilibrium core
where the core operates at full power uprate
conditions for an entire cycle and then the fuel is
shuffled, the same reload is put in again and the
cycle cleanses itself reload after reload.
That equilibrium cycle is not actually
seen often in reality but it's very useful for seeing
what extended power uprate will and can perform
feasibly in your plant and also necessary for
providing to the other work scopes and power uprate
the required fuel related input.
The reload analysis is what's done to
actually develop the blueprints to which the fuel
bundles are built and the loading patterns are
developed and the reload analysis is what develops the
core -- the fuel related operating limits that go into
the core operating limits report.
Also with the reload analysis is performed
a succession of reload cycles to carry us all the way
from the current cycle out to essentially the
equilibrium core. That might be two to four or five
cycles, but that demonstrates that there's a good
success path to carry us from the cycle we're
designing out to the objectives we want to achieve.
Looking first at the equilibrium core design, the
design target for Brunswick are the same as the ACRS
has seen on prior EPU submittals. The one thing as
Bob mentioned in the intro, that's a little bit
different about Brunswick is this should be the first
plant that you've seen with a 24-month operating
Brunswick does operate extremely well with
a load factor in the range of 97 or 98 percent, so a
24-month cycle with a 15-percent increase in the power
generation is a very high energy cycle. To achieve
those targets we had to make a number of changes to
our prior strategy. First was to change the fuel
design from the 9-by-9 GE 13 to the 10-by-10 GE 14.
That gives us the benefit of a lower linear heat
generation rate but even more important than that GE
14 is a heavier bundle. It's got about five percent
more uranium dioxide.
In addition to the more U02, we increased
the enrichment of the fuel in the vicinity of .4
MR. SIEBER: From what enrichment to what
MR. DRESSER: The fuel is built in several
streams. The high enrichment stream went from about
4.0 to about 4.4.
MR. SIEBER: Okay.
MR. DRESSER: The -- I think Bob mentioned
also that the amount of new fuel that we load
increased substantially from about 39 percent of core
to 12 bundles to about 47 percent of the core --
MR. SIEBER: So the discharged fuel is
twice burned, right?
MR. DRESSER: That's right. Now, we had
to essentially do everything, do all the options to
increase the reactivity of the core sufficient to get
the energy out. One thing that had to be done in
compensation for loading so much more reactivity to
get the energy was to make the change to the standby
liquid control system Boron system. In analysis base,
we analyze it as a change in concentration. That's
about a 10 percent increase in concentration.
In practice, we will use the Super Boron
but effectively it's the same thing. A 20-percent
natural Boron or a 68-percent enriched just winds up
being a difference in concentration.
MR. LEITCH: My question concerns this one
cycle of operation when presumably we've approved up
to 120 percent, yet the physical changes have not been
made yet to accommodate that.
MR. DRESSER: I understand. As it turns
out, the changes required to achieve the cold shutdown
and cold shutdown is not driven so much by the power
rating as it is by the overall reactivity of the core
and by the fuel design. This first cycle for Unit 1
will have one reloaded GE14 fuel. The existing cycle
on Unit 2, which won't be operated, also has one
reloaded GE14 fuel. As it turns out for Unit 2, for
our first uprate when we go to 112 to 115 percent and
that kind of range, that is going to require a
modification for the standby liquid control system for
that unit and we have made a licensing commitment that
by this August we'll submit a tech spec change to
require that mod.
MR. LEITCH: I see, okay.
MR. DRESSER: And for this Unit 1 we'll do
the same thing for the following August for the 2004
MR. LEITCH: Okay, thank you.
MR. DRESSER: The actual cycle for Unit 1
Cycle 14 we were able to meet all of the design goals
with a slightly smaller reload fraction. It's about
46 percent instead of 47 percent of the core. And we
did meet all the design targets with our standard
expectation of design margins. This is -- the numbers
that we actually achieved are shown on the slide.
The one thing that's of particular
interest to you, like I pointed out, that a large
amount of margin for the standby liquid control, 1.96
percent, that is with the existing Boron. I think our
requirement will normally be about 1.0, so that's a
lot of excess margin.
MR. SIEBER: Your fuel cost actually goes
up with this kind of a design, does it not?
MR. DRESSER: Our fuel cost goes way up.
MR. SIEBER: Okay.
MR. DRESSER: See those big smiles back
MR. SIEBER: I'm sure you're happy about
Dr. Schrock: My eyes are not good enough
to read the slide. What's the color mean?
MR. DRESSER: The colors, the green on the
periphery is the highest enrichment. That would be
the approximately 4.4 nominal enrichment. The gray is
the next higher enrichment. The yellow is next higher
enrichment. Those colored slots are all the new fuel.
And one thing I'd point out is that if you
look at the interior, the checkboard in the interior
of the fuel is that there's so much new fuel -- well,
in this case, bringing in one Cycle 14, the loading
pattern will actually continue to support our control
cell core but by the time we go to a little bit more,
we will have to go to a conventional core and
sacrifice that control cell.
The largest implication for us of that is
we'll have to do a little bit more control rod
MR. KRESS: How much of your fuel gets up
close to the same megawatt days in metric time, about
as much as a third of it?
MR. DRESSER: No, I don't think as much as
a third of it would drive the pellets up there. I --
a number I'm more familiar with is the batch rather
than the pellet average. I think the corresponding
batch average exposure would be about 50 kilowatt days
per ton and the actual batch average winds up being in
the range of a little bit less than 44.
So you'd wind up losing a lot of
efficiency in terms of the amount of burn-up you'd be
able to achieve with the fuel when you go to these
high energy cycles.
MR. KRESS: Okay.
MR. DRESSER: But one thing you do pick up
and I can't read the slide either as far as the
numbers go so I did use a take-out box to magnify.
The thing I think is most significant about the
loading patterns, that is that the large reload
impressions give us an extremely flat radial power
distribution. I think if we look at the sub-batches
here, the largest average power of recycle is about
1.22 on Cycle 14 and that's going to go down even more
in equilibrium, down to about 1.19. It's very flat.
And as a point of comparison, the last
power point presentation which was showing a similar
kind of effect, the flat core, I think the
corresponding number is about 1.27. So Brunswick has,
you know, a pancake flat radial power distribution and
that's going to effect a lot of things that you'll see
throughout the course of the day.
MR. KRESS: You end up with about the same
MR. DRESSER: It's a slightly more --
because of the higher void fraction, it winds up being
a slightly more bottom peaked axial.
MR. KRESS: Yeah.
Dr. Schrock: I've got difficulty
visualizing what's happening in terms of
redistribution of the total core flow on these higher
power bundles in the periphery and the central region.
It does seem to me without some change in inlet
orificing, which I heard previously is a no, no, that
you don't modify the whole distribution of the core
flow by putting in there higher powered peripheral
bundles which have much higher steam generation.
MR. DRESSER: You're absolutely correct.
It does modify the core flow. It's got some
beneficial effects for us. It --
Dr. Schrock: Well, it could have but I
haven't heard a clear explanation of it, that's my
MR. DRESSER: The --
Dr. Schrock: I think maybe it was clear
to some, but it was not clear enough to me.
MR. DRESSER: Okay, well, the -- let me
give you a 5,000 foot explanation of it and that would
simply be that, of course, the higher power generation
is going to give us more voiding lower in the core, so
you're going to have a lot more two-phase flow over
the elevation. Of course, the two-phase flow is going
to give us much higher pressure drop and that's -- you
know, the overall pressure drop from a core
perspective stays about the same.
So that's going to drive flow from the
higher powered bundles to the lower powered bundles.
Now, with the power uprate like this, we're not
changing our design limits. So the peak generation --
peak power generation for any bundle remains the same.
Heat generation rate doesn't change with power uprate.
MR. SIEBER: That has an impact on your
MR. DRESSER: Absolutely. That is --
that, in and of itself, that is a stabilizing
MR. SIEBER: Uh-huh.
MR. DRESSER: And so what we see overall
is because the highest power bundles remain -- you
know, can't get no higher. They remain at the design
limit. And the core average must go higher to
generate more power, you have the core as a whole,
which is lower than the high power bundle is taking
less of the total flow and the highest power bundles
are getting more of the flow.
So as a core designer, it's a nice
Dr. Schrock: Now, I guess in my mind it
would be more satisfying if I heard some numbers put
to the statements but that may not be possible here.
MR. BANERJEE: Do we have the flow rates
anywhere through the bundles documented what you
expect them to be?
MR. DRESSER: I do not have those numbers.
Perhaps General Electric can give us something.
MR. BOLGER: This is Fran Bolger, General
Electric. When the plant is operating at
approximately 100 percent core flow, which is about 77
megapounds per hour, the bundles are seeing about
10,000 pounds per hour flow through each individual
channel. The total leakage flow is about on the order
of 15 percent of the total core flow. When you go to
power uprate, it does increase slightly, maybe less
than one percent.
You know the plant has some allowable
variation in core flow which can increase it maybe up
to 11,000 or so and slightly less. It doesn't have a
very large range of allowable core flow at the full
power uprate. But if you were to compare the channel
flows at the current rate of power and at the EPU
power, you may only see maybe a two percent variation
in the channel flows.
MR. BANERJEE: Were the bundles -- were
the channels orificed originally to give higher flow
in the central and lower from the peripheral?
MR. BOLGER: Yes, that's correct.
MR. BANERJEE: Is that the same orificing
that would be there now?
MR. BOLGER: Yes, that's the same.
MR. BANERJEE: So how do you keep the void
fractions and flow rates relatively constant, because
you're going to get higher pressure drop now in the
MR. BOLGER: You know, the overall core
pressure drop will go up about one psi and there will
be an increase in the pumping power requirement to
achieve the same rate of core flow.
MR. SIEBER: This kind of a fuel design
seems to result in high affluence to the reactor
vessel; is that correct?
MR. DRESSER: That is correct and I
believe we're planning to discuss that later in the
MR. SIEBER: All right.
Dr. Schrock: In the documents that I've
looked at, there's mention that the inlet orificing is
not the same for these two plants. Could you comment
a little bit about that? I'm not clear about why it
was different, what significance it may have for the
MR. DRESSER: The -- yes, the inlet
orifices on the -- on Unit 1 are a little bit smaller.
On Unit 1 they're a little bit larger. On Unit 2
they're a little bit smaller. The biggest difference
that that makes to the power right now and also the
power uprate is that that makes the thermal hydraulic
instability for Unit 1 a little bit worse than for
Unit 2 with the tighter orificing.
In terms of operation, it doesn't have a
significant effect because the option both -- well,
the E1A option is calculated specifically for the
unit. The regent (phonetic) sizes correspond to the
stability of the unit and for Option 3 the methodology
will work in exactly the same fashion.
Dr. Schrock: What did that difference
accomplish in the original designs?
MR. DRESSER: I am not -- I would have to
look into that. I would expect. I'm kind of
speculating here but I would expect that when one unit
was built, it had some difficulty achieving as much
core flow as we would like and so the orifices were
relaxed slightly for the other unit to reduce the
MR. FLADOS: Paul Flados here, I'm with
the plant. The original arrangement of our units was
that Unit 2 went on line first. There was some
transition between 7 by 7 and 8 by 8 fuel. At one
time we had changed out the orifices on one of our two
units. It was a fairly expensive mod but we
physically had to, to meet licensing requirements. By
the time we got to the other unit, we had changed fuel
designs and done other implementations that allowed us
to not change our the orifices. So that's how the
designs ended up different.
CHAIRMAN WALLIS: You have actual
variations. You have actual variations in enrichment
and as burn-up proceeds the flux distribution changes
and so on.
MR. DRESSER: That's correct.
CHAIRMAN WALLIS: When you do something
like an ECC analysis, does everything get smeared out
there or do you look at the details of these things
which are different at different times in the cycle
and so on? How do you decide which is the place where
you're most likely to have DNB and all of that. It
must be changing.
MR. DRESSER: Right, it changes through --
it does change throughout the cycle and I believe that
the analysis is done to select the most limiting point
in the cycle and that's been -- the LOCA is done just
at that one point.
CHAIRMAN WALLIS: But knowing which is the
most limiting point must itself involve some rather
MR. DRESSER: Right, there is a -- the --
well, I guess I would not like to describe LOCA
calculations. I'm going to ask Dan Pappoane from
General Electric to describe that.
MR. PAPPOANE: Yes, this is Dan Pappoane
of GE. I'm the LOCA process lead and with respect to
the axial power shape, the location of -- when we're
looking at the early boiling transition part of it,
that -- we're looking at whether or not the high
powered node in the axial peak goes into a early
boiling transition. That's really more sensitive to
core flow than it is to axial location.
So when we look at increased core flow
versus the lower core flow MELLLA, when we get to the
MELLLA low core flow point, that's where we're more
expecting to see that early boiling transition in the
high node and the axial location doesn't make that
much of a difference. But we have looked at the axial
power shapes and we're -- over the cycle and the shape
that we're using in the analysis gives us the highest
When you get to the end of the cycle and
you have a top peak, the -- you may have bundle power
on critical power limits but you don't have the linear
heat generation rate on the -- on its thermal limit
and it's really the -- the linear heat generation rate
is the primary driver for the PCT. So we end up with
a power shape that gives us a bounding calculation in
CHAIRMAN WALLIS: So this MELLLA line is
actually moving around.
MR. PAPPOANE: The MELLLA line is fixed.
It's the core flow -- the core flow that we're
analyzing is --
CHAIRMAN WALLIS: It's an envelope of a
whole lot of calculations, the MELLLA line, is it?
MR. PAPPOANE: The MELLLA line itself is
a generic licensing boundary. It approximates that
power flow relationship that you get if you ran back
the recirculation flow but it's not a bounding line in
the fact that we don't go and analyze all the
variations throughout the cycle but we draw the line
and then the plant has to operate to the line.
CHAIRMAN WALLIS: I guess what I'm getting
at is how detailed is this analysis? You don't have
-- you don't analyze very bundle. You don't have a
model for the core that breaks it up into all these
separate bundles and then does a complete thermal-
hydraulic calculation for everything. That would be
an extraordinary number of nodes, wouldn't it?
MR. PAPPOANE: Not yet. We're working on
that one but the safer model that we're using now
models a hot bundle and an average bundle. The
average bundle feeds the overall core conditions and
provides boundary conditions to the hot bundle and
then we assume that the hot bundles on both the
critical power limit and the LHGR limit and we've got
that bounding power shape in it. So we're doing a
single bounding bundle for the calculation.
CHAIRMAN WALLIS: So knowing which is the
hot bundle requires what sort of knowledge?
MR. PAPPOANE: Well, we start with --
well, since we were defining the limits for that hot
bundle, the operational limits for that hot bundle,
the part that we do need is coming out of the steady
state thermal hydraulic calculation and there we model
a bundle the same way. We've got the full core
designed, the 100 and whatever bundles usually grouped
into three regions and from that we get the flow
We'll have a peripheral region and an
average core region and the hot bundle, and from that
we get the flow distribution of what the flow is to
the hot bundle versus the average bundle and that's
what's used to initialize the steady state.
CHAIRMAN WALLIS: I guess what I'm trying
to look at is, you've got this much fire power
distribution and you've got this very sophisticated
fuel and then you say there's a hot bundle. It would
seem that there could be quite a few bundles competing
for this hot bundle status --
MR. PAPPOANE: Right, and that's --
CHAIRMAN WALLIS: -- in different parts of
the core and how do you deal with that?
MR. PAPPOANE: That's where the steady
state flow distribution comes in and if we have more
of those bundles essentially at that hot power,
effectively what's happening is the average -- you end
up with the hot bundle looking more like an average
bundle and when you look at the flow distribution, its
parallel resistance problem you've got essentially the
same pressure drop across the core and as the
resistance -- the flow resistance in the hot bundle
and the average bundle come closer together, the flow
distribution comes closer together.
So you'll end up with more of those hot
bundles. The bundle that we're analyzing as the hot
bundle will look like a larger percentage of the
population. When we go through the LOCA the PCLAD
(phonetic) temperature that we calculate will be
representative of more bundles in the core.
But again, because we're setting that one
hot bundle on limits and those -- we can't -- we're
not going to allow any of the other high powered
bundles to exceed those limits. We're still analyzing
that one hot bundle.
MR. DRESSER: One place where that effect
does show up more is in the safety limiting CPR
because we do have more bundles that are operating
closer to its limit, the safety limit must go up in
order to keep the same number of bundles from going
into the departure for nuclear boiling machine to 99.9
percent and so the effect Dr. Wallis, that you're
referring to will result in the safety limit going up
for this cycle from about 1.10 to 1.12.
That's included in the thermal margin of
7 percent here. If it hadn't been for that, we'd have
had 9 percent margin.
CHAIRMAN WALLIS: So some day you're going
to give us a calculation which treats all the bundles
MR. PAPPOANE: Not all of them. When we
get to the track model, when we get to that
methodology, we'll be modeling more bundles. We'll
have more bundles in the separate regions.
Dr. Schrock: On the neutronics
calculation, how large a node is used?
MR. BOLGER: There is 25 axial six-inch
nodes for each -- each channel is modeled separately.
Dr. Schrock: Every channel is a node,
MR. BOLGER: Fran Bolger from GE. Each
challenge is broken up into 25 nodes axially.
Dr. Schrock: Axially, but in the cross
section, every bundle is a separate node.
MR. BOLGER: That's correct.
MR. DRESSER: Well, this has been a
fruitful slide. If we don't have any more on this --
CHAIRMAN WALLIS: How are we doing with
time? Are you on time?
MR. DRESSER: We'll be eating a late lunch
at this rate. No, I'm not planning to spend long on
CHAIRMAN WALLIS: Well, maybe you can move
MR. DRESSER: We'll conclude the fuel
bundling core design. We're using the same current
design tools and processes. We've got the same margin
expectations and with that, it doesn't require any
change to the fuel design limits to satisfy the
extended power uprate design.
The thermal limits monitoring threshold,
the tech spec changed from 25 percent to 23 percent,
that is just to maintain the same absolute bundle
power as is used throughout the GE link at 3.35
megawatts. So as far as the neutronic design goes,
there is adequate margin demonstrated for the first
operated cycle, all the transitions and the
The second topic is ATWS. The methodology
that's used for Brunswick is the same as described in
the generic ELTR. The four limiting ATWS transients
were analyzed for the plant and the results -- I'll go
over the results in just a moment.
The procedures and training at Brunswick
for the actions taken by the operator are based on the
BWR owners group emergency planning guidelines, the
optimum mitigation strategy approach, where water
level is maintained between the minimum steam cooling
water level and two feet below the feedwater spargers.
The actions that the operator takes are based on
observing the condition of the core and reacting with
the mitigation strategy.
Since neither the symptoms nor the actions
the operator takes are changed from a big picture
perspective, there is no impact on the operator
MR. SIEBER: What about the timing of
operator actions, does that change?
MR. DRESSER: Yes, the actual time at
which the operator takes actions will change and I
believe we're planning to address that later in the
day in some detail, but yes, things will happen at a
different rate but the operator will see symptoms and
react the same way.
MR. SIEBER: Okay, so that changes the
probability of the operator making an error, or does
MR. DRESSER: Well, I'm going to say no
because the operator -- the assumptions at the time
the operator needs to respond in are still the same.
He does not need to respond quicker to be successful
even though events might be happening quicker.
MR. SIEBER: All right.
MR. DRESSER: The standby liquid control
system Boron modification is not required for the hot
shutdown for the ATWS transients. The current levels
are quite conservative for hot shutdown and finally,
a calculation was performed for Brunswick for the
relief valve for the standby liquid control. It was
done for the worst ATWS transient and with very
conservative assumptions including extremely rapid
response from operator's action time and it verified
that the pressure remained low enough the relief valve
does not have to lift.
This is the results of the ATWS analysis
together with a sensitivity study for the original
license thermal power. The peak vessel bottom
pressure goes up to 1487 pounds, that's 13 pounds
below the ASME service level during the 1500 pounds.
From a licensing perspective, that's okay, as long as
it's below the limit. I guess as an engineer, that
seems like it's fairly close and so I wanted to
observe that this calculation has a number of -- it's
a transient but it doesn't use nominal best estimate
values for how the plant operates.
It's got a number of conservative inputs.
Maybe the most dramatic one is that the SRV is very
important to this event. They're assumed to pass only
90 percent of their actual capacity and also one of
the SRVs is a soon to be out of service.
CHAIRMAN WALLIS: Were they tested at full
scale, full pressure? How do you know the flow rate
through these SRVs?
MR. DRESSER: Paul Flados will answer
MR. FLADOS: Paul Flados again. These are
standard industry target safety relief valves. The
original sizing and the design of them actually
performed field testing of this type of valve,
certified what the flow was, the ASME methodology then
had them rate the valve at 90 percent of what it
CHAIRMAN WALLIS: So it's based on real
experience with real valves, with real pressures and
all right --
MR. FLADOS: Absolutely.
MR. BOEHNERT: Can you tell me what the
PRFO acronym is?
MR. KITCHEN: Yes, excuse me, that's the
pressure regulator failure open position.
MR. BOEHNERT: Okay.
MR. KITCHEN: MISVC is the main --
MR. BOEHNERT: Yeah, thank you.
MR. KITCHEN: -- closed.
CHAIRMAN WALLIS: Now, this MSIVC whatever
it is, that's what a one-shot thing or something? Why
is -- why are these different pressures? The tech
specs is 1325 and this is -- some of them goes up to
MR. DRESSER: Right, the tech specs is
based on 110 percent of the design. I think they have
different acceptance criterions for the different
severity of accidents or frequencies.
CHAIRMAN WALLIS: Oh, frequency.
MR. DRESSER: Yeah, the 110 percent design
is what the tech spec is based on. That was -- is a
much less expected type of an occurrence. The one
other thing that provides a lot of conservatism in
this particular calculation is that the open model was
used. That's a lot more -- a lot less real, a lot
more conservative than a TRAC G calculation would have
been which would have given us more than 100 pounds of
CHAIRMAN WALLIS: What's the difference?
MR. DRESSER: Well, I'll let GE respond.
TRAC G is a much more realistic and much more
CHAIRMAN WALLIS: So there's some, what,
MR. BOLGER: This is Fran Bolger of GE.
As the problem changes to an ATWS type of event where
you have a transient that does not have a SCRAM and
void feedback is very critical to the response, the
TRAC G model has a 3-D kinetics capability and with 3-
D kinetics, you get essentially a credit with high
power channels. As they begin to void, as you
pressurize, you get void feedback. That type of
feedback is not seen as significantly with a 1-D
transient model such as ODEN (phonetic.)
As you get down more into nominal
conditions with faster SCRAMs, more of the type of
scenario where the Peach Bottom Turbine Trip
benchmarks occur, then you start seeing that the
models respond very similarly.
MR. BANERJEE: And the thermal-hydraulic
model is similar to drip flux or what type of models?
MR. BOLGER: The ODEN is a drip flux type
model and the TRAC G model is a two-fluid model.
MR. BANERJEE: Are there any significant
differences in the voiding rates that you see on the
MR. BOLGER: No, the codes will predict,
given the same channel, seeing the same type of
pressure trajectory, they're predict similar type void
MR. DRESSER: The other criterion for the
ATWS have substantially more margin. The peak
suppression pool temperature, you'll note that design
limit that CP&L placed was not 220 but 207.7. That's
to keep the design base accident LOCA as the limiting
event for that temperature. The containment pressure
there is allowable margin to the design limit.
The peak cladding temperature that is seen
goes down to 1309 pounds, way below the 2200 degree
design limit and that -- I believe that it was
mentioned earlier about the axial power shape and some
of the impacts we might see from that, the power shape
being much more bottom peaked and the hot peak clad
temperature occurring much lower in the core in this
event, you get much better heat transfer to the water
with less void and that's why this temperature goes
down so much.
CHAIRMAN WALLIS: Are you taking any
credit for this alternate rod insertion system?
MR. DRESSER: We take credit for recirc
pump trip but we do not take credit for the ARI.
CHAIRMAN WALLIS: I was intrigued by that
because it gets mentioned but you don't tell us much
about what it does or maybe we should just ignore it,
but I mean, is that an important design change to have
an ARI system?
MR. POST: This is Jason Post with GE.
That was the original design requirement of the ATWS
modifications. If we took credit with it in our
analysis, it wouldn't effect the peak bottom -- the
peak vessel pressure very much. It would have a
dramatic impact on suppression pool temperature. It
would be a very mild event and so, therefore, we don't
MR. DRESSER: In conclusion, on the ATWS
all the criterion are met, including the 10 CFR 50.62
of course, which are less stringent than some of
CP&L's design criteria. And the mitigation strategy
for ATWS to comply with the emergency planning
guidelines is unaffected by power uprate.
That's all I wanted to say about ATWS and
so I'm about ready to go into my final three topics
and some of these do contain GE proprietary
MR. BOEHNERT: Okay, we'll go -- I'm
MR. LEITCH: Just before you get there,
can I just ask a question? I'm not sure if this is
the right part of the presentation, but I'm still a
little confused as to the status of Unit 1 at the
moment. Have all the modifications and the current
reload been designed such that we're now in a
situation where the only thing that prevents you from
going from a -- up from 112 to 115 percent power is
the licensing situation?
In other words, as soon as you get NRC
permission to do that, what do you do? Are you ready
MR. DRESSER: That is -- well, yes, the
core is designed and it's ready to go. What we would
need to do is simply to install the operating limits
for the fuel into the process computer and change the
core operating limits report from the current power to
the rated power and the core would be ready to go.
MR. BOLGER: This is Fran Bolger from GE.
The reload licensing analysis were done assuming full
MR. LEITCH: Okay.
MR. DRESSER: So licensings basically go
to 120. It's balance-of-plants that will hold us back
to 112, 115.
MR. LEITCH: So then in a practical sense,
once you've made these modifications to the computer,
which can all be done on line, then what you do then
is go over to the recirc pumps and increase the speed
of the recirc pumps and see -- make sure you have
enough feedwater pumping capability and that's what
the limit is? I mean, you just go --
MR. DRESSER: Well, there's some testing.
There's quite a bit -- I mean, from my perspective as
a core designer, that's all there is but actually from
plant operation there's a lot more.
MR. KITCHEN: This is Bob Kitchen. The
modifications have been incorporated in the plant.
They were performed during the refueling outage we
just completed. Once we receive the license, as you
mentioned, we can -- the license would allow operation
to 120 percent. The plant modifications are in place
to allow the plant to operate to 112 percent.
And we would implement that --
MR. LEITCH: When you say it's been a
physical limitation, your ability to pump feedwater?
MR. KITCHEN: Actually, the limitation
would be for base load operation, fuel load itself.
And ultimately the main transformers would limit us to
115 percent of our original license power or less.
But we could -- we'd have to make some set point
changes. We're going to talk about the testing that
we have to implement the license later but we would
have to go through that process and very -- increase
power very slowly monitoring plant components and
various points we stop and run testing to verify plant
MR. LEITCH: Okay. I may have some more
questions in that area later but basically what I'm
getting the picture here is we're on the critical path
here. In other words, you get this approval, you can
basically come up to 115 percent --
MR. KITCHEN: Yes.
MR. LEITCH: -- on Unit 1.
MR. KITCHEN: Yes, sir, that's correct.
MR. LEITCH: Okay, thank you.
MR. BOEHNERT: All right, then we'll go
into closed session. I would ask anyone who doesn't
have an agreement with GE to hear proprietary
information to leave the room. The transcriber can go
to a closed session transcript.
(Whereupon, the subcommittee went into
closed session at 9:45 a.m.)
(On the record at 10:31 a.m.)
CHAIRMAN WALLIS: We're back in session.
And this is a non-proprietary session; is that
MR. WILTON: That's correct.
CHAIRMAN WALLIS: Go ahead.
MR. WILTON: Good morning. My name is
Blane Wilton and I'm the Supervisor of Reactor Systems
at Brunswick Nuclear Plant. Today, I'd like to
discuss the reactor vessel and internals with you.
The areas I'll be covering are the scope, the EPU
effects and impact, our preservation/mitigation
strategy that we use, monitoring aspects. I'd like to
go into a little bit on steam dryer and then the
The scope of the internals in reactor
vessels include all the components that were
identified in the license topical report. All of
those were considered within the scope for Brunswick.
Implementation of the EPU includes the evaluation of
the components, inspection, as well as mitigation.
One thing I do want to point out is that no
modifications were required as a part of power uprate
to support for the reactor vessel or internals, to
support the implementation of EPU.
Degradation modes that were addressed
include stress corrosion cracking of both IASCC and
IGSCC, fatigue and embrittlement. Effects and
Impacts, our PT curves, our pressure temperature
curves, were impacted by extended power uprate. Our
current curves that we're operating on today have been
approved for use with extended power uprate through
March of 2003. We're developing new curves right now
and we plan on submitting those curves in June of
2002, this year with updated fluence methodology in
accordance with Reg Guide 1.190, as well, as including
instrumentation uncertainty in the curves.
And like I said, that will be issued in
June of this year. Fluence was effected by power
uprate. The fluence impacts were not directly
proportional to the power increase which is what we
kind of expected initially going into this. The
reason for that as Tom eluded to earlier in his
presentation on the core, we flattened the power shape
out and move a lot more power out to the periphery of
the core, so therefore the fluence increase was
greater than the power increase.
CHAIRMAN WALLIS: In your case, the
fluence actually went up.
MR. WILTON: Yes.
CHAIRMAN WALLIS: In one of these other
operators, we had, yes, you'd expect it to go up but
because of an improved method of calculation it
actually went down.
MR. KRESS: Well, that's his other one
that he just covered on the previous slide.
CHAIRMAN WALLIS: Yeah, so you're going to
recapture that with the RG1.190, okay.
MR. WILTON: Yes.
CHAIRMAN WALLIS: Okay.
MR. WILTON: Embrittlement, 10 CRF 50
Appendix G requires that your upper shelf energy be
75-foot pounds initially and you must maintain 50-foot
pounds through end of life. Our plant does not have
full Sharpy curves; therefore, 10 CFR Appendix G
allows for an equivalent margins analysis to be
That analysis was also effected by power
uprate. That analysis has been recalculated and we're
within our margins on that. So there really was not
an impact on embrittlement, but we did have to redo
that calculations on that.
MR. KRESS: When you say your plant
doesn't have full Sharpy curves --
MR. WILTON: Yes.
MR. KRESS: -- that means you don't have
the specs on the materials?
MR. WILTON: The materials weren't tested
over a full range of temperatures.
MR. KRESS: The full range of
MR. WILTON: Yeah, that you need to be
able to show compliance with the 50-foot pounds.
Therefore, we use the equivalent margins analysis.
MR. KRESS: I understand that.
MR. WILTON: Okay. Let's see, fatigue;
another factor that was impacted as far as power
uprate. All the components were addressed for fatigue
and what we found is that all components remained
qualified through end of life.
I'd like to go into our preservation and
mitigation strategy. We protect our reactor vessel
and internals against IGSCC. Brunswick implemented
moderate hydrogen water chemistry as our strategy for
protection back in 1989 on Unit 2 and in 1990 on Unit
1. Current injection rate will be maintained as part
of power uprate. Right now we inject at 39-1/2 SCFM.
That same rate will be maintained.
Our post-EPU protection will be as good or
better under power uprate conditions with the same
flow rate. We've done extensive modeling of our core
using the BWRVIA software which is an industry
developed code for modeling the radiolysis effects as
well as the ECPs in our core. And the model shows
MR. BANERJEE: Where is the hydrogen
MR. WILTON: It's injected in the
MR. BANERJEE: And it goes through the
sparger and mixes.
MR. WILTON: Yes, it goes down through the
bottom and up through the center of the core.
MR. LEITCH: And depending upon the amount
of hydrogen that's injected, varies the -- I say the
depth of protection. Have you been able to protect
all the vessel internals with your present hydrogen
MR. WILTON: No. We probably should go to
a backup slide on that, starting with this one.
MR. KRESS: Let Darrin help.
MR. WILTON: When we laid out our
mitigation strategy, what we -- the area highlighted
here in yellow is the area that we determined that we
wanted to try to protect with hydrogen, okay? And
what we've got is we are able to protect most of that
area at minus 230. Some areas are above that, but
those areas are typically areas that you couldn't
protect regardless of how much hydrogen you put in,
just because of their locations.
MR. LEITCH: I see. But the core -- okay,
MR. WILTON: This is the outer by-pass
region of the core. This is the inside of the shroud
but external of the fuel channel. Okay, so that was
one of the areas that we say we were trying to
protect. And we are a 1.0 to 1.5 PPM plant. So you
can see the levels. That's the bottom curve on this
and we're down in the minus 270 range, in that region.
The -- if you look at another area that
we're trying to protect, this is the downcomer region.
This is the area external of the jet pumps and the
annulus area of the core shroud. And you can see that
at the very top part of the core, which is the first
part, up in this are, regardless of how much hydrogen
you put in, you're just not to get it negative enough
to protect that area.
MR. LEITCH: Uh-huh.
MR. WILTON: But it all drops off and
we're operating along this curve here which is down to
the minus 320 range, that area.
MR. LEITCH: Okay.
MR. BANERJEE: Is that -- the effect due
to incomplete mixing on the downcomer? What do you
think it's due to, that you're not getting --
MR. WILTON: You're talking about the
region up in here? It's the height. This is what I
believe it is. It's you're outside of the influence
of the flux up in that area. You're above part of the
MR. BANERJEE: Right, yeah.
MR. WILTON: And flux actually makes the
recombination reaction a lot more efficient. So
because you're outside of the region of the high flux
areas, then it becomes inefficient in that area and
that's why you see the levels go up.
MR. BANERJEE: And the previous slide that
you showed --
MR. WILTON: Yes.
MR. BANERJEE: -- are there areas which
are inefficient there as well?
MR. WILTON: Well, this is inside the core
shroud and it runs from below the core plate down to
above -- I'm sorry, above the core plate to the bottom
side of the top guide and just because of its
proximity to fuel, you see in this region here at the
very beginning up at the highest portions, you're
seeing that it is going up and it's pretty stable
along the entire region of the fuel.
Another area we're trying to protect is
the inside of the jet pump area to mitigate that and
you can see here that along this curve we're down
around the minus 350 region. So again, we have
protection. The last area that we're trying to
protect here is the lower plenum, the bottom head
region. And again, you can see where we're down low
and it tails up. This area here is as it goes through
the core plate and you can see the levels are starting
to rise again.
MR. KRESS: You calculate these with TRAC?
MR. WILTON: No, we calculate these using
what's a computer code called the BWRVIA model.
MR. KRESS: It's the VIA.
MR. WILTON: Yes, the VIA model that was
developed and benchmarked on initially, I believe 23
MR. KRESS: It has to have flow
MR. WILTON: Yes. And what we have here
is this is not a generic model. We took the model and
we took the Brunswick specific inputs for both
geometry flow, we included the equilibrium -- this is
for an equilibrium core, so we took the equilibrium
core from the power uprate and used the actual fuel
information and this is a Brunswick specific model
that was developed for our plant.
MR. KRESS: This is the VIA model the flux
MR. WILTON: Yes, yes, that's a separate
input to the model.
MR. KRESS: It's an input.
MR. WILTON: Yes.
MR. KRESS: Okay.
MR. LEITCH: And these curves are
relatively unaffected by the power uprate.
MR. WILTON: Well, actually, I don't have
the curves here for where we are today, but what we
saw is, is uniformly, we saw a shift more negative
with power uprate because the flux out in the
periphery of the core is actually going up, so
therefore, the effect is becoming more efficient. So
power uprate is actually giving us better protection
with the same amount of hydrogen.
Let's see. Okay, our mitigation strategy
is one that is also supported by BWRVIP-62, which is
the technical approach for relief of inspections using
hydrogen. So the point I wanted to make here is we're
not doing something different than what has been
looked at. It is in accordance with the industry
developed guidelines for a moderate hydrogen water
chemistry plant. And what we're showing is that with
moderate hydrogen water chemistry, we are protected in
the areas that we're trying to protect.
MR. KRESS: Why did you decide that those
were the areas that you wanted to protect?
MR. WILTON: Well, the only other areas
that you can get into area areas like above top guide
which no amount of hydrogen -- and if you look at the
protection that you get from chem in that area, it's
limited if -- the fuel itself which is something that
is changed out on a cycle by cycle basis.
MR. KRESS: You don't even need --
MR. WILTON: The areas, you really don't
need the protection in those areas. So we're trying
to maximize the protection.
MR. KRESS: In fact, you may be even worse
off with the hydrogen on the fuel.
MR. WILTON: Yes.
MR. BANERJEE: Do you have coupons
(phonetic) or anything that would actually show you're
getting this or you're doing some monitoring?
MR. WILTON: Yes, yes. We do monitoring
but our monitoring is actually our inspection program.
Okay, we also have -- another part of our mitigation
strategy is our water chemistry. We maintain water
chemistry in accordance with the EPRI guidelines on
water chemistry and our conductivity is kept low.
It's on the average of .09 on an average for the
To make sure that our mitigation strategy
works, we have a monitoring program. Our monitoring
program confirms that our mitigation strategy is
adequate and also provides feedback to us in case that
we see something that we don't expect. It gives us
time to adjust our program. Our inspection program is
in accordance with the guidelines of the BWRVIP.
Our re-inspection results have shown no
new crack initiation with moderate hydrogen and the
crack growth rates for existing flaws is well below
what's expected. You know, GE -- the NRC accepted
number is minus five inches per hour which has been
reduced for certain locations down to 2.5. We're
actually seeing growth below the error band in the
inspection equipment of what we can see.
We also are monitoring on fatigue. We've
done our fatigue updates for post-EPU for limiting
components for both units. We just completed detailed
fatigue updates. We do those on a 10-year cycle. We
also do interim updates following every outage to
project where we think we'll be. The fatigue updates
have been extrapolated through end of life plus 20
years and using EPU conditions and all components have
been found acceptable through end of life plus 20
Monitoring for embrittlement, we are a
member of the VIP and therefore, we are also a member
of the integrated surveillance program. Each utility
in the program -- to be part of that program, each
utility must comply with the specific requirements of
the two documents which control it. VIP-78 is an
overall, just a program, describes the program and
BWRVIP-86 is actually the implementation plan. We are
members of VIP and, therefore, we are part of this
Select utilities will pull test coupons.
We are not one of those. We will be using data from
a sister plant. VIP guidelines require licensee to
calculate neutron fluence using compatible
methodologies to be able to use a sister plant and
we've already done an update per reg guide 1.190 to be
able to do that.
Let me talk a little bit about steam
dryer. We inspected the steam dryer on Unit 1 during
our last refueling outage. We did observe minor
cracking. This cracking had been previously
identified back in 1988. We have cracking -- what we
saw as cracking in our dryer bank vertical welds. We
do not have drain channel cracking at this time. Our
plan, we -- the cracking had grown from eight inches,
which is what we initially found in '88 to about 11 to
12 inches in 2001.
We performed a conservative analysis that
showed that the cracking is fine for continued
operation for multiple cycles. Our plan is to go back
in following uprate at our next outage and reinspect
to see, just to verify that the power uprate is having
no detrimental effects to our steam dryer.
MR. KRESS: Do you have any problems with
the vessel supports. I mean, this is internal things
MR. WILTON: Right.
MR. KRESS: Because of embrittlement?
These are Mark 1's.
MR. WILTON: Do you want to take that,
MR. YEMMA: This is Larry Yemma from CP&L.
I'm not sure I understand the question.
MR. KRESS: There was some question one
time about radiating the structures below the vessel
on the supported --
MR. YEMMA: Oh, the vessel support?
MR. KRESS: Yeah, not be deteriorating.
MR. YEMMA: Unfortunately, that's out of
MR. WILTON: We, essentially, from the
safe ends into the vessel and just the internals
CHAIRMAN WALLIS: Those cracks are due to
vibration or something? What is the cause of the
MR. WILTON: The cracking was believed to
be IGS60 initiated. In conclusion the RPV and
internal components have been assessed for impacts of
EPU. Our site program documents have been revised to
include the impacts of the power uprate and all
components remain qualified through end of life.
MR. KRESS: You don't have any pressurized
thermal shock problems.
MR. WILTON: No.
MR. LEITCH: Blane, this auxiliary
condensate cooling system which I now understand is
likely not to be installed but one of the things that
was concerning me when I read about that initially was
particularly the tube material and I guess it would be
the non-regenerative heat exchangers. I'm picturing
this non-regenerative heat exchanger as having
basically river water on one side of it and then used
on an intermittent basis a couple months a year at
And I guess when you were talking about
condensate conductivity, obviously, it speaks well of
your main condenser. If we introduced this non-
regenerative heat exchanger into the cycle, a tube
leakage there would -- could be a significant problem
and I think there is a propensity for those tubes to
leak in that kind of service. But obviously, if you're
not going to do it, you're not going to have that kind
of problem. But I think if you do move forward with
that, you have to be very careful about the selection
of material for tubing in that non-regenerative heat
MR. WILTON: Agreed.
CHAIRMAN WALLIS: Thank you very much.
MR. GRANTHAM: Good morning, I'm Mark
Grantham. I'm the Design Superintendent on our EPU
team. I'll be talking about our containment responses
to include a review of the methodology used for our
containment analysis, the containment analysis
results, impact on Mark 1 hydro-dynamic loads and as
well as impact on MPSH for our emergency core cooling
The containment analysis was completed
using the methodology that's currently approved in the
ELTR. The analysis is actually broken down into a
short term and a long term analysis. As short term,
that's really the first 10 seconds of an event. The
short term analysis, the focus of that analysis is on
drywell temperature and pressure; whereas on the long
term analysis the focus is on wetwell pressure as well
as suppression pool temperature.
The short term analysis is completed using
the LAMB code which is using Moodies (phonetic) slip
critical flow model to develop blow-down flows and
that's used as an input into an M3CPT code.
The long term analysis is using the Super
HEX code. All of those codes are approved and the
Brunswick power level for EPU is within the range of
applicable -- that's applicable for those codes. This
provides the actual containment analysis results for
DBA LOCA. The first data column there actually
provides the current UFSAR values containment analysis
parameters. For power uprate, a new analysis was
performed using the same methods for uprated
conditions as well as current rate of thermal power
conditions. All of these are done at the 102 percent
of thermal power.
So a comparison between the current
methods, the current license thermal power and the EPU
numbers will give a true indication of what the actual
change is due to the power level increase. If you
look at this for containment pressure, the peak value
for EPU is 46.4 PSIG versus an acceptance limit of 62.
The drywell air space temperature for DBA LOCA, 293
degrees, versus an acceptance limit of 340.
Wet well pressure is 31.1 PSIG versus an
acceptance limit of 62. And suppression pool
temperature, the peak value of 207.7 versus an
acceptance limit of 220 degrees. So all these values
are well within the acceptance limits. For the Mark
I hydro-dynamic loads, we reviewed the pool swell,
vent thrust, condensation oscillation, chugging and
SRV discharge loads and for SRV discharge that
included the initial actuation as well as subsequent
reactuations. And all of those loads for EPU were
within the original definition, load definitions that
were established as part of the Mark I long term
MR. LEITCH: You have a HPSI and a RCIC
that discharge into the tarus.
MR. GRANTHAM: Takes suction for the
tarus, that's correct.
MR. LEITCH: It takes suction from the
MR. GRANTHAM: And a discharge into
MR. LEITCH: I mean the steam for the
MR. GRANTHAM: Yes, discharges into the
turbine, or tarus, correct.
MR. LEITCH: To the tarus, yeah. So I
guess the operation of HPSI and RCIC is unaffected by
MR. GRANTHAM: That's correct, for DBA-
LOCAs HPSI and RCIC are essentially assumed not to
operate. The pressure goes down quickly enough to
where you're essentially below their range of
effective operation almost immediately.
MR. LEITCH: Okay.
MR. GRANTHAM: Due to the changes in
suppression pool temperature, we had to look very
closely at our NPSH, net positive suction head.
Brunswick is currently committed to safety Guide 1
which does not allow credit for containment over
pressure. As a result of EPU we will now require
containment over pressure for adequate NPSH and that
is an allotment that is made in the ELTR 1.
For the NPSH evaluation, we looked at that
short term and long term -- or short term, and that's
the first 10 minutes of an event. We looked at the
conditions where the core spray and RHR pumps are
essentially in run-out conditions, where no operator
actions for throttling them back is credited. Under
those conditions, there's adequate NPSH available
without any credit for containment over-pressure.
The long term NPSH evaluation after 10
minutes, the peak value required -- peak over pressure
required is 3.1 psig. The available over pressure at
that point is 11.3 psig and as apart of this license
submittal, we're actually requesting credit for 5
MR. KRESS: Those numbers are at the same
time in the transient.
MR. GRANTHAM: Yes, yes.
MR. KRESS: So --
MR. GRANTHAM: What we did for the ECCS
evaluation, we made, I guess, a conservative analysis
in that we took a combination of containment sprays as
well as direct pool cooling. For suppression pool
pressure, we assumed the containment spray case which
gave us the lowest pressure.
MR. KRESS: Which gave you the lower
MR. GRANTHAM: For suppression pool
temperature, we assumed the direct pooling, pooling
case which gave us the highest temperature. So really
MR. KRESS: So really you combined those.
MR. GRANTHAM: Right, to get a worst case
combination and --
MR. KRESS: So I don't have to ask what
the uncertainty is in this number because --
MR. GRANTHAM: Right, and we --
MR. KRESS: -- you know which side of the
thing it's on.
MR. GRANTHAM: Correct, and we plodded it
out versus time and pick the worst case.
MR. BANERJEE: Do you have a plot of the
changes with time, pressure and available -- what you
MR. GRANTHAM: I have a graphical
reference. Yes, we do have that.
MR. KRESS: Could we see that some time
because I've often wondered if there was some area in
the timing associated with these things?
MR. GRANTHAM: Yes, I can show you that
maybe at a break or something. We have -- I don't
think we have a backup slide on it but we do have
CHAIRMAN WALLIS: Maybe right after lunch.
MR. GRANTHAM: Yeah.
MR. LEITCH: I guess it had been my
understanding that the NRC was reluctant to approve
credit for containment over pressure; is that -- I
guess that's more a question for the NRC, but do you
know if any other BWRs have --
MR. GRANTHAM: I know most BWRs credit
containment over pressure. Ralph --
MR. CARUSO: This is Ralph Caruso from the
staff. And this is just -- I'm in the Reactor Systems
Branch. We don't review this but I have some
knowledge of it. And generally what the staff does is
controls this very carefully. They do a very detailed
thorough review of requests to use that over-pressure
in order to make sure that it isn't used creatively.
MR. LEITCH: Okay, thanks.
CHAIRMAN WALLIS: But it has been granted
for other plants.
MR. CARUSO: Yes.
MR. BOEHNERT: Oh, yeah, Duane Arnold
(phonetic) got it for their uprate.
MR. CARUSO: And not just for power
MR. GRANTHAM: And conclusions for the
containment analysis, the containment temperatures and
pressures remain within existing design limits. The
Mark I containment hydro-dynamic loads are within the
current load definition and adequate NPSH margin
exists with the available over-pressure.
MR. BOWMAN: My name is Terry Bowan. I'm
the electrical project engineer for power uprate. I
want to spend a few minutes talking about the impact
power uprate had on our power systems and how we are
addressing that impact.
In Bob Kitchen's introduction he mentioned
that we were replacing our main power transformers and
we were upgrading our isophase coolers and that's
pretty typical of plants that are uprating and you'll
see that, that it's pretty common. But in our
situation we also determined that there were two other
areas that we need to evaluate and that's generator
and grid stability and the voltage adequacy of offsite
power, so I want to spend a few minutes talking about
those two areas. They are somewhat unique to
The first area that I want to talk about
will address the stability and with our increase in
power output, our stability studies indicate to us
that our stability margin would be reduced somewhat.
So there are two modifications that we will be
implementing to compensate for this reduction in
stability and they are the out of step protective
relaying modification and also implementation or
installation of power systems stabilizers on our main
MR. SIEBER: Does that mean if a generator
on one unit slips poles that that unit trips?
MR. BOWMAN: With the out of step
protective relaying which I'm going to address in the
next slide, yes, to answer your question.
MR. SIEBER: Which will cause the other
unit to probably slip, too, right?
MR. BOWMAN: No.
MR. SIEBER: You're sure?
MR. BOWMAN: I'll first talk about out of
step protective relaying which I hope will address
your question there. This is a two-piece scheme, if
you will. One portion of the scheme will trip the
generator on a major out of step event, a very severe
event on the grid. And what that does is it does two
things for us. One, it protects our generator from
slip pole, the damage, but it also prevents cascading
Whenever you have a machine that's on your
grid that falls out of synchronism, it's very
important to get it off very quickly. It's not going
to regain synchronism, so you have to trip the
generator. So that will help prevent any cascading
grid outages. It will help prevent that machine from
dragging down the rest of the grid.
The second piece of this is to help
preserve off site power during an out-of-step event
and the way we're going to accomplish this is the use
of out-of-step blocking relays. There will be out-of-
step relays located on the end of each transmission
line, the remote end and the plant end and they will
be monitoring for an out-of-step event out on the line
in the sense that they will block tripping of those
lines. That's very important because if we do trip
our main generator, (tape fades) and so that increases
MR. SIEBER: Now, what do you say --
whether you prevent the adjacent unit from tripping or
not, depends on how many cycles you go through and how
tightly -- how low the impedance is between the two of
MR. BOWMAN: That's correct and the --
this scheme has a very fast tripping ability. It's
not -- it is conventional and out-of-step tripping but
it also has another aspect, it's called anticipatory
out-of-step tripping. It looks for closing faults
that could cause that event and trips it very quickly,
so the other generator does not go out of sync.
MR. SIEBER: Okay.
MR. BOWMAN: So that's the first mod that
we're implementing. The second modification is the
installation of the power system stabilizers on each
of the main generators. These power system
stabilizers sense changes in generator speed and power
and using these inputs, they provide feedback to the
generator's excitation system. And with that
feedback, the regulator will actually produce a torque
which is in opposition to the torques that are caused
by the grid disturbance. So it has an ability to
dampen out the oscillations that would occur after
your disturbance of the grid.
MR. LEITCH: Is there under and over
frequency protection on these machines?
MR. BOWMAN: There are volts for hertz
protection on our main generators, but this is
MR. LEITCH: I guess I'm always concerned
about these large machines operating at other than
very close to 60 cycles, particularly vibration
patterns that can be set up on the turbine blades. In
other words the turbine blades carefully designed
assuming that at power, the machine is going to be
operating very close to 60 cycles. Does any of this
allow -- permit operation further from 60 cycles?
MR. BOWMAN: I believe the power system
stabilizer, what it will do is it will bring the
machine back quicker. If you did have an instability
event, it would actually bring it back quicker.
MR. LEITCH: Bring it back quicker.
MR. BOWMAN: Yeah. What typically happens
is the machine is trying to catch up with the system
so to speak, so, you know, as it's falling of
synchronism, then it tries to overshoot and this will
help dampen out those overshoots so that you can get
back on line with the system.
MR. SIEBER: The transients that you're
talking about here, they're all system generated
transients as opposed to station generated transients.
MR. BOWMAN: That's correct. It may be an
external fault somewhere on the system. It may be a
lightening strike or some kind of heavy switching
that's taking place and the power system stabilizer
would help prevent the ringing or oscillation that
might occur under that situation.
MR. SIEBER: How many transmission lines
do you have coming into the station?
MR. BOWMAN: We have four transmission
lines coming into each unit. The units are not tied,
the switch arcs are not tied but we have four coming
into each one.
MR. BOWMAN: I'll turn my attention now to
voltage adequacy of the offsite power system. As we
are adding load to our electrical distribution system,
as a result of power upright there will be a number of
loads added. That reduces our available voltage down
to our sector laid loads. We have more voltage drop
down for our distribution system and especially, you
know, if it's feeding from offsite power, if it's
feeding from the start-up transformer unit, ops
transformer, it's all in the unit trip, we will see
significant change in voltage there.
So to accommodate that, to compensate for
it, we are implementing a modification called the unit
trip load shed modification and that will help restore
the margin. This modification provides selected load
shed of balance-of-plant motors and in order -- they
would receive the signal on a LOCA and/or unit trip.
So we're in effect, dumping some of our load on our
distribution system to improve the voltages down to
the emergency busses and safety loads.
And that will help insure adequate post-
unit trip voltages available at emergency busses.
MR. LEITCH: Terry, as I understood this,
there was a selection that could be made and at
various points along the way here, depending upon
whether you're in Phase 1 or Phase 2 of this uprate
program, the operator would administrate -- the
selection of loads that would be shed would be
MR. BOWMAN: They will be procedurally
MR. LEITCH: Procedurally controlled.
MR. BOWMAN: That's correct.
MR. LEITCH: After the second phase
modifications are done, in other words, you're humming
along at 120 percent, would they still be under
administrative controls or would they be permanently
locked in one particular position?
MR. BOWMAN: It would continue to be
MR. LEITCH: Would here be --
MR. BOWMAN: And that's to give you
flexibility. For instance, initially we have two
heater drain pumps that will be shed on the unit trip
signal. We have three pump motors and one is
basically a backup. So you need some flexibility to
be able to swap which one is being shed. Two out of
three operation, we will be able to have two that are
shed. The third one doesn't need to be shed. It
MR. LEITCH: But wouldn't you get to a
situation where the loads to be shed could be
permanently selected rather than procedurally
MR. BOWMAN: In essence that's what's
happened. Our initial load shed of the heater drain
pumps, that will be from here on out. We have -- we
also have built in the ability to shed other loads in
the future if necessary, if the grid conditions
warrant that kind of thing. As load continues to grow
on the grid, the ability to maintain offsite power
voltage and adequate voltage is more difficult to
achieve and so to compensate for that we may elect at
some point in the future, to give up another load.
MR. LEITCH: I'm just a little concerned
with procedural controls rather than something that
could be permanently built into the system.
MR. BOWMAN: They are key locked so that,
you know, somebody can't get in and inadvertently
manipulate one of these things.
MR. LEITCH: They are key locked.
MR. BOWMAN: They are key locked and also
there is a second verification that's performed when
they put these in a load shed position.
MR. LEITCH: Okay, thanks.
MR. BOWMAN: That pretty much concludes
what I wanted to talk about. Implementation of these
three mods, load shed modification, out-of-step
protective relaying and the power system stabilizer
will help us insure the adequacy and reliability of
MR. BOEHNERT: Will these be tested or
have they been tested somewhere before so you know
what to expect from them?
MR. BOWMAN: You're referring to the unit
trip load shed?
MR. BOEHNERT: Yeah, the first two in
particular, the out-of-step and the trip load shed.
MR. BOWMAN: They were tested, out-of-step
protective relaying was tested on Unit 1 this past
outage. It was implemented and then there was very
extensive testing on it and unit trip load shed was
also tested. And we will periodically -- actually, on
unit trip load shed, we will periodically test that as
well and out-of-step protective relaying, they will
test that when they test the other protective relaying
for offsite power.
MR. BOEHNERT: Thank you.
MR. SIEBER: Those are pretty common relay
schemes anyway. It doesn't involve anything new as
far as the relay.
MR. BOWMAN: And the Switzer (phonetic)
relays are very commonly used for that system.
CHAIRMAN WALLIS: Okay, thank you very
much. We'll move right along.
MR. YEMMA: Good morning. My name is
Larry Yemma. I'll be talking this morning about flow
accelerated corrosion and piping in general. I don't
believe I'll bring anything new to the table this
morning on these two topics. Brunswick is fairly
typical when it comes to flow accelerated corrosion
and their piping analysis. I'll talk about the
program overview and then we'll discuss EPU impacts
Brunswick meets the generic guidance of
Generic Letter 89-08 and NSAC/202L. We use the
Checkworks software program as a tool to predict and
track areas of significant wear. Additionally, we
regularly check the industry OE data base for events
in the industry that apply to Brunswick just from a
fact point of view. These tools with program manager
engineering judgment allows us to run an efficient and
effective FAC program.
Brunswick typically inspects between 75
and 100 components each outage and since we have a
dual unit, it comes out to be about 100 components a
year, 100 components a year, correct. We do have a
large data base of information. And the overwhelming
majority of the wear rates that we see are
conservatively predicted by Checkworks.
MR. LEITCH: Have you found any wear in
the feedwater flow venturies. I guess picturing --
well, the BWR powers but usually inferred from the
feedwater flow --
MR. YEMMA: We do see --
MR. LEITCH: What I'm saying is if you've
got higher flow assisted corrosion in the feedwater
venturies and wear some of that away, could you get a
false indication of feedwater flow being somewhat
lower than it really is?
MR. YEMMA: To my knowledge, we don't see
anything unusual in the feedwater venturies.
MR. GRANTHAM: This is Mark Grantham. I
think the feedwater flow venturies are actually
stainless steel which are not susceptible to FAC.
MR. LEITCH: I think that's right, yeah.
Yeah. That's good, thank you.
MR. BANERJEE: But you can get some
deposition on them, so that depends on the coolant
chemistry. That's a slightly different problem but
have you ever had a direct check on the flow
measurements. This is power or this is some other
means of tracking the flow. There's a way of doing it
with radio nuclides to see how accurate the flow
measurement is. Are any such tests being made?
MR. GRANTHAM: This is Mark Grantham
again. I think, it was about three or four years ago
on both units we had an ultrasonic test that was
performed using, I think it was the ABB system.
MR. BANERJEE: It was quite accurate?
MR. GRANTHAM: Correct, it compared very
accurately back to our original weigh tank testing
that was done at Alton (phonetic) Labs.
MR. BANERJEE: Okay, thanks.
MR. YEMMA: Okay, as you know, Brunswick
went through a five percent uprate about six years ago
and the results of that associated with flow
accelerated corrosion showed no measurable increase in
wear at any point. And as you can see, the flow
increase of approximately 15.3 percent and we have a
maximum temperature increase of six degrees
fahrenheit. The impact on feedwater piping which we
consider one of our more interested -- we're more
interested in feedwater than in a lot of other
Essentially because we have changed out
extraction steam lines to the three and four heaters
with chrome moli so we don't have any problems there
any more. And the extraction steam to the five heater
is of sufficient quality steam that our actual flow
rates are predicted to decrease -- wear rates, rather.
And then that concludes my presentation on
CHAIRMAN WALLIS: About how thick is this
pipe that's losing 20 mils a year?
MR. YEMMA: The feedwater pipe is
approximately an inch and a half in thickness.
CHAIRMAN WALLIS: So it's going to lose a
significant amount in a few years.
MR. YEMMA: It's predicted to but we've
seen -- our actual wear rates are a lot lower than
CHAIRMAN WALLIS: How big are the actual
MR. YEMMA: They're within single digit
MR. KRESS: Checkworks is set up so you've
got -- basically, in a sense you feed back in the
actual wear rates?
MR. YEMMA: Yes, there are ways to modify
the inputs and to tweak it to come closer to what
you're actually seeing, yes.
MR. KRESS: You guys do it that way.
MR. YEMMA: We haven't --
MR. KRESS: I was trying to understand
your statement about the estimated wear rates being
bigger than the actual.
MR. YEMMA: Well, it's due to the
inspection. We go out and inspect a lot of components
and we're not seeing what they're predicting.
CHAIRMAN WALLIS: Then you'd revise
Checkworks I would think.
MR. YEMMA: Well, that's the way -- yes,
that's what we plan on doing.
MR. BOEHNERT: Have you had to replace any
MR. YEMMA: Not due to -- not to my
knowledge, in fact.
CHAIRMAN WALLIS: Checkworks is operated
fundamental. It relies on a lot of experience.
MR. YEMMA: That's correct, and we use the
standard EPRI inputs so -- and they're very
Okay, onto piping. Piping analysis is
pretty typical for Brunswick as well. We have gone
through the same steps as we went through in the five
percent uprate. The piping was included in the five
percent uprate actually bounds the scope of this
uprate since this is a constant pressure uprate. So
we don't look at anything other than what we looked at
in the five percent uprate, which I just said here.
After we select the piping of interest, we
gather the peak stresses for each line and we take the
increases caused by the uprate, the temperatures
mostly since there's no pressure increase, and we
scale the stresses up, the combined stresses up in
accordance with the increase in the impact of EPU and
we just compare the increases with the code allowables
and the results of that was everything was fine.
Everything is below allowables.
We also evaluated nozzles, penetrations
and pipe supporting systems as well with the same
conclusion. In addition, we looked at high energy
line break and no new break locations were identified.
MR. LEITCH: When I think about Brunswick,
it brings to mind some pretty major problems that you
had with pipe supports, maybe 10 years or more ago,
where pipe supports were tied into block walls.
MR. YEMMA: Well, you sound like you have
experience in that area. We did have challenges.
MR. LEITCH: I guess I'm wondering, it
that problem all well behind us now?
MR. YEMMA: Yes, as a matter of fact, I
was involved in reconstitution of the piping stress
analysis about 12 years ago, and we went through every
safety related system in the plant and upgraded it to
the latest requirements; three dimensional
earthquakes. And we replaced a lot of supports and we
went through the whole system.
MR. LEITCH: Okay.
MR. YEMMA: So that's all behind us.
Okay, the results that I show here is for a line
that's inside containment. The lines outside
containment show a similar -- there are some similar
lines on the outside of containment that I didn't put
down here but the stress ratio is very similar. We
were up in the .8, .9 range for some of the lines.
And for feedwater, that came up to about
a 2.2 increase, percent increase. In conclusion,
piping and safety related components are -- related
components are acceptable for EPU.
MR. BOEHNERT: Are you -- maybe you'll
discuss this in your testing. Are you planning to do
any vibration monitoring on the lines and so forth?
MR. YEMMA: Yes, yes, we -- the lines in
Unit 1 are now instrumented and we will be -- it's
feedwater and then main steam.
MR. BOEHNERT: Thank you.
MR. YEMMA: Uh-huh. Okay.
CHAIRMAN WALLIS: Thank you.
MR. YEMMA: Thank you.
MR. POTERALSKI: Good morning. I'm Dan
Poteralski, Manger of the Nuclear Fuel Manager and
Safety Analysis and I'm going to describe the results
of the probablistic safety analysis for extended
operate uprate for the Brunswick plant. Sitting next
to me, I'd like to introduce Larry Lee from Aaron
(phonetic) Engineering. Larry was one of the
principals in the performance of the analysis for the
extended power uprate.
The purpose of the analysis is to provide
confirmatory insights and insure that no new
vulnerabilities are created by extended power uprate.
Extended power uprate is not a risk conformed
submittal. However, the ACRS has requested a reg
guide 1174 risk analysis for power uprates in excess
of five percent.
MR. KRESS: Did the ACRS request that or
did the staff?
MR. LEE: This is Larry Lee. The staff to
support the risk application.
MR. KRESS: Yeah, I didn't think the ACRS
made a request like that.
MR. POTERALSKI: I apologize. The
analysis was performed to determine the risk impact of
extended power uprate implementation. Based upon a
comment that was made before the break, I would
propose that -- I was originally going to talk about
the scope of the analysis, the methodology, results
and conclusion. I can skip over the methodology which
will eliminate about five slides from the presentation
or I can go through them. It's your pleasure.
MR. KRESS: Which five are you talking
MR. POTERALSKI: The ones that are titled
-- I would skip the five that are titled methodology
at the top, go right from scope to --
CHAIRMAN WALLIS: We're doing fairly well
on time, so maybe you're skipping, you could just go
very quickly through those slides.
MR. KRESS: I wouldn't want you to skip
the one on success criteria.
MR. POTERALSKI: Okay, I'll go through
MR. KRESS: And operator responses.
MR. POTERALSKI: Okay, the scope of the
analysis was to analyze internal events using the
Brunswick PSA model. We did both a Level 1 and Level
2 analysis. Level 1 --
CHAIRMAN WALLIS: You need to advance the
MR. POTERALSKI: Thank you.
MR. KRESS: Is your PSA, has it been given
the industry peer review?
MR. POTERALSKI: Yes, it was peer reviewed
in September of 2001 after the submittal was made to
MR. KRESS: And it was qualified for what
level of usage?
MR. POTERALSKI: The qualification
statement basically says that the PSA can be
effectively used to support application involving
absolute risk determination when combined with
deterministic insights. This corresponds to an
overall grade of 3 on a scale of 1 to 4, 4 being the
MR. KRESS: Okay, that's good for power
uprates, I understand.
MR. POTERALSKI: Right. And we submitted
the results of the certification review in an RAI to
the staff on November 30th, 2001. Level 1 addresses
core damage frequency or CDF. Level 2 calculates
large early release frequency or LERF. The external
events portion was done based upon the original IPEEE
study which was more qualitative in nature than the
The results of the valuation were for fire
was viewed to be non -- was determined to be non-
significant. The seismic margins assessment had no
effect. The other included external hazards such as
tornadoes and hurricanes and they had negligible
impact. We also did a qualitative assessment of
shutdown risk and it was also assessed to be non-
significant with a change according to the image
frequency of less than one percent.
In order to evaluate the impact of
extended power uprate on PSA we considered a number of
things. We verified that the hardware changes that
were mentioned by Bob Kitchen earlier did not
introduce a new accident type or increase the
frequency of challenges to the plant. The hardware
had negligible impact because it was either a
replacement or upgrade of existing equipment, except
for the standby liquid control system where a system
modification described by Mr. Kitchen to meet cold
shutdown requirements for future core designs as
described by Tom Dresser.
There are no changes to the PSA were
identified as a result of potential emergency
operating procedures severe accident management
guidelines. Set points showed negligible impact. The
power level had an impact on the timing of short term
important operator actions and these were addressed in
the human reliability analysis.
MR. KRESS: In the IPEEE where you were
talking about external events, did that include an
analysis of a Class 5 hurricane hitting the site or
were the analysis bounded by an earthquake bounding,
MR. LEE: This is Larry Lee from Aaron
Engineering. Yeah, the IPEEE evaluated all types of
high winds and hurricanes and found the plant to be
MR. LEITCH: It seems to me you're in a
zone there where you could have --
MR. LEE: It probably would be evaluated
as a very low frequency event.
MR. LEITCH: Very low frequency.
MR. LEE: Yes.
MR. LEITCH: Well, yeah, but you're -- it
seems to me you're in an area there that is
susceptible to hurricanes. Is that not true?
MR. LEE: That it true. We can -- if
needed, we can relook at exactly what the submittal
says to see what the frequency of a Class 5 tornado
would be compared to the IPEEE core damage frequency
guidelines. Usually if it's below 1 E-6 frequency of
event, then it's considered below the margins
requirement, below the screening criteria.
MR. LEITCH: Yeah, okay, thank you.
MR. KRESS: Are these plants located near
MR. POTERALSKI: Yes.
MR. KRESS: So they're susceptible to
MR. POTERALSKI: Yes.
MR. LEITCH: That includes storm surge, I
MR. LEE: Well, I don't know if it
includes exactly storm surge, but it does include,
yeah, all high winds, hurricanes, tornadoes.
MR. LEITCH: Okay, I guess I'm really a
little off the point anyway. All of this has nothing
to do with power uprate anyway.
MR. LEE: Right.
CHAIRMAN WALLIS: Power uprated hurricane.
MR. POTERALSKI: I'd now like to describe
the Brunswick PSA model. It was a -- again, we looked
at both Level 1 and Level 2. We analyzed internal
events, including flooding. The model has been --
MR. KRESS: When you say Level 2, does
that include fission products? Level 2 usually
includes fission products but when you're just doing
a LERF it doesn't usually.
MR. LEE: Well, the Level 2 does include,
yeah, the release from containment but it doesn't
evaluate in terms of consequences with a Level 3
analysis. It was just Level 2 LERF in terms of large
MR. KRESS: Yeah, but you don't -- maybe
I'll ask it another way. Did you use MAP for that?
MR. POTERALSKI: Yes, we used MAP.
MR. LEITCH: Okay, that will answer my
MR. POTERALSKI: The model has been
maintained up to date. It reflects the current plant
configuration. It was based upon the original IPE
model that was developed in response to generic letter
88-20. The model has been updated in 1993, 1996 and
2000 and underwent an NEI peer review in September of
2001 as I mentioned previously.
The process used to evaluate the impact of
extended power uprate included an independent peer
review of the PRA technical elements that were derived
from the NEI RPA peer review guidelines, specifically
MR. KRESS: When you say independent, does
that mean that you've brought in outside experts?
MR. POTERALSKI: That's correct. Before
we started the analysis, we brought in a team to
review the model before we did the analysis, before
the submittal and then a few months later, we actually
had the full peer review completed.
We looked at initiating events, success
criteria, systems, data, operator responses, accident
sequences. We evaluated the impact on thermal
hydraulic parameters using the MAP code and then
compared the results against the reg guide 1.174
criteria for core damage frequency and change in large
early release frequency.
The impact on the human reliability
analysis was developed utilizing the criteria of risk
importance and short time to complete. The evaluation
identified 42 significant operator actions; however,
only four operator actions impacted by extended power
uprate due to reduced time to perform certain actions.
All of them involved level control during anticipated
transient without SCRAM ATWS.
MR. KRESS: You did Fussel Vessley
importance of operator action?
MR. POTERALSKI: Yes.
MR. KRESS: Did it come out to be --
that's not surprising I guess, it's that important.
That's CDF Fussel Vessley, right?
MR. POTERALSKI: Yes, we did a Fussel
Vessley on the base Level 1 PRA model to see what
operator actions were above Fussel Vessley of 5E-3 and
in addition we looked at all short term operator
actions below 30 minutes.
MR. KRESS: Okay.
MR. POTERALSKI: Operator actions
necessary do not change due to extended power uprate.
The time to perform the operator actions probably does
not change significantly and the operator responds to
the observed symptoms. The time available window does
reduce from 30 to 24 minutes based upon the MAP
thermal hydraulic calculations and the PSA postulates
and increase in human air probability due to the
reduced time available.
CHAIRMAN WALLIS: Could you tell us what
these operators are doing while they're controlling
MR. LEE: While they're controlling level,
they're going through the procedures to make sure that
they lower water level in response to the fail to
CHAIRMAN WALLIS: Well, are they
continuously lowering or do they lower it once or do
MR. LEE: Well, they're going lower it and
then try to control it at a lower level.
CHAIRMAN WALLIS: So their attention is
focused very much on this level during that period of
MR. LEE: Yes, it is.
CHAIRMAN WALLIS: And they're actively
controlling some valve during that period of time.
They're not just doing it once. They're doing it
MR. LEE: Yes, they're controlling
injection flow for either HPSI or RCIC, depending on
which system they're using.
CHAIRMAN WALLIS: And is there any idea of
how easy it is to maintain the level within required
MR. LEE: Well, the operators are
extremely trained on this type of event. We believe
it is more difficult to control HPSI just in terms of
the higher flow rate compared to RCIC, but for HPSI
based on information from the operators, the time to
get to this step and be able to control level near TAF
would be approximately five minutes. And for RCIC
it's an easier time so -- or an easier procedure, so
it's estimated at approximately two minutes.
CHAIRMAN WALLIS: So how many corrections
do they make during that period of time?
MR. WILLIAMS: This is Mike Williams. I'm
operations manager at Brunswick. The response to the
ATWS, it's not going to change as part of power
uprate. Now, the response would be what we do is we
lower level down till we meet certain conditions and
we establish a level control band so there's really no
set number of times at which you'd have to change or
take different directions but you would lower level
down until a specific set of criteria is met and
establish a level control band and maintain level
within that band.
CHAIRMAN WALLIS: This is a pretty benign
transient. It's not as if this level is bouncing
around and then trying to control it. It's actually
trending in a fairly slow way in some direction or
another, is it?
MR. WILLIAMS: Depending on the severity
of the ATWS, if you do 100 percent rod pattern very
high power ATWS, it moves -- the level will move
around pretty quickly but it's consistent. It's not
-- it's not moving all over the place. So you'll be
able to set a band and control level. The way we do
these in the simulator is pretty consistent in that we
have high power ATWS is MSIVs closed and the operators
are well trained to get level --
CHAIRMAN WALLIS: And you get simulation
with the extended power uprate?
MR. WILLIAMS: I'm sorry?
CHAIRMAN WALLIS: Have you run the
simulator under EPU condition?
MR. WILLIAMS: We have ran the simulator
with extended power uprating, compared the old model
with the new model and there's very little difference.
There's some but it's not significant difference.
CHAIRMAN WALLIS: Thank you.
MR. POTERALSKI: There is very little
impact on the risk profile. Specifically there was a
slight change in risk importance of the four operator
reactions. We adjusted the human error probability of
the four impacted actions and then resolved the model
to get new values for core damage frequency and larger
early release frequency.
There was the same relative significance
to the risk profile. There were no new significant
actions due to extended power uprate and no actions
became non-risk significant because of extended power
MR. KRESS: Do you use the EPRI models of
the human error function of time?
MR. LEE: Yes, for the operator actions we
used the EPRI HCR/ORE methodology and also the EPRI
time cause based approach for the diagnosis error.
Then we used the THIRT methodology from NUREG 1278 for
the execution error.
MR. KRESS: Okay.
MR. POTERALSKI: The results of the
analysis are shown on the next slide. There's no
change in system success criteria, no new action
sequences identified, no significant impact due to
procedural changes, no significant impact due to
hardware changes. And there was a slight decrease in
time available for four operator actions.
MR. KRESS: Is one of your success
criteria have to do with opening release valves?
MR. LEE: In terms for ADS for
MR. KRESS: Yeah.
MR. LEE: Yes, the success criteria for
Brunswick is to open three SRV valves for
MR. KRESS: And that didn't change with
MR. LEE: It didn't change. In fact when
we ran the MAP code, it looked like even two SRVs
would be successful, so we maintained the three SRV
MR. KRESS: When these open, do they open
and close, do they chatter or do they open and stay
MR. LEE: I would believe for the
depressurization function they would just remain open.
MR. POTERALSKI: The results of the
analysis when compared to the Reg Guide 1.174
criteria, for extended power uprate, there was a
change in the core damage frequency of 4.0E-7 or about
1.6 percent. This represents a very small change and
puts us in Region 3 of the delta CDF versus CDF
criteria. For large early release frequency, the
change due to extended power uprate is 1.9 E-7 and
that correspondence to a small change or puts us in
MR. KRESS: Let me ask you that then.
That 4.46 absolute value of 10-6 on your LERF, is that
the sum of the LERF for both plants?
MR. LEE: That's for a single unit.
MR. KRESS: Why wouldn't you sum the two
plants because you're changing the LERF for the site
equally for both and why wouldn't you double both the
delta and the actual LERF for comparison? I guess
this is a question to the staff more than to you
because I don't think it's clear in 1.174 what you do
with multiple sites, but clearly to me it's -- LERF is
a cite characteristic and your actual LERF for the
site ought to be doubled and your delay LERF ought to
be doubled. And I don't know where that puts you in
If you're already in Region 2 it's getting
you up closer to Region 1. I don't know if it does or
not. That's a question to the staff, I guess.
MR. LEE: The border between Region 3 and
2 for LERF is IE-7 so we're still at the lower border
of the region for Region 2.
MR. HARRISON: This is the slide --
MR. KRESS: What I was concerned with if
you take your 4. -- 4.6, E-6 LERF and double that,
that gets you up to almost 10-5 and you're just above
the 10-7 which puts you close to the really dark area
there in Region 1. See, my problem is, I don't think
we're using 1.174 correctly but still this is a
question to the staff.
MR. HARRISON: Yeah, this is Donnie
Harrison from the PRA branch and I remember this
question has come up in the past and there's been
questions on the scale that if you should adjust the
scale on the bottom line as well, and but again, I
don't recall the full answer to your question. But I
do recall this question from three or four months ago.
MR. KRESS: Yeah, I've asked it before and
I will ask it again until I get the right answer.
CHAIRMAN WALLIS: Well, do we know the
MR. KRESS: The right answer is, yes, you
should double and --
MR. HARRISON: And there is a revision of
the reg going on but I don't think they're going to
MR. KRESS: If we get to review it.
CHAIRMAN WALLIS: Do we agree that you
should double? I mean, you've also doubled the
benefit and there must be some kind of cost benefit
here. It's not purely risk.
MR. KRESS: Oh, now you're getting too
CHAIRMAN WALLIS: I'm thinking too deeply
MR. KRESS: Yeah.
CHAIRMAN WALLIS: Oh, okay, then I'll
MR. KRESS: You're really correct. You
should adjust the -- you're saying you should adjust
the pump safety go depending on the benefits you're
getting and that's probably true but nobody's going to
MR. HARRISON: And Dr. Kress, partly the
answer in the past has been is this is, if you will,
a generic plot. It didn't take into account
populations densities and that's part of the problem
MR. KRESS: Oh, absolutely and I think
that's part of the answer. The other part of the
answer is, of course, that they've changed the SLC and
they actually get a decrease in both of these which
makes it fine with me on this thing. I just wanted to
raise the question because it's going to come up again
some time and --
CHAIRMAN WALLIS: Well, the SLC has a big
MR. KRESS: Oh, yeah, it has a better --
bigger effect than the uprate, I think. But, you
know, if I double both your delta and your actual
absolute value, that puts you right on the line of
that Region 1 and, you know, that bothers me but it
doesn't bother me because I agree that changing the
SLC offset this and gets you down in the right region
CHAIRMAN WALLIS: So if you had four
units, you'd say they were in real trouble.
MR. KRESS: Absolutely.
Dr. Schrock: Does the reg guide a require
MR. KRESS: No the reg guide is silent on
CHAIRMAN WALLIS: Let's move on. We know
that this is an issue we've raised before and we'll
raise it again.
MR. POTERALSKI: With that lead into the
next point I'm going to make, with the standby liquid
control system modification, the success criteria
improves due to single train operation where we only
need to credit one out of the two trains.
MR. LEITCH: Let me make sure I understand
correctly that last slide. The bottom line there is
EPU with the SLC modification.
MR. POTERALSKI: That's correct.
MR. LEITCH: So the net effect is an
MR. POTERALSKI: Improvement for core
damage frequency and it's an improvement of nine
percent for LERF it's an improvement of 28 percent.
MR. LEITCH: And you are committing, I
think one of the other speakers said, to the SLC
MR. POTERALSKI: Right, with the second
load of the --
MR. LEITCH: In my reading, it was still
questionable, I guess, whether you were going to do
that or not, so there is every intention of doing that
or a commitment to do that now.
MR. POTERALSKI: That's correct.
MR. LEITCH: Yeah.
MR. POTERALSKI: In conclusion, based upon
the current reg guide 1.174 criteria there's a very
small risk increase in core damage frequency of about
1.6 percent, a small risk increase with large early
release frequency of 4.5 percent. The qualitative
assessment shows no significant risk impact on fire,
seismic or during shutdown. When the changes in the
shutdown -- excuse me. When the changes in the
standby liquid control system success criteria are
included, the impact is a reduction in both core
damage frequency and large early release fraction --
frequency. That concludes my presentation.
CHAIRMAN WALLIS: Thank you very much.
MR. BANERJEE: What about early fuel
storage, the fuel has more radioactive material, so is
there any sort of risk associated with that?
MR. LEE: Risk related to shutdown. So
there's what the -- the potential that credit
secondary systems such as fuel pool cooling or reactor
water cooling as decay heat removal systems by
themselves. Most of risk during shutdown is during
the early times of the outage when you can only use
RHR and fuel pool cooling wouldn't be effective.
MR. BANERJEE: And nothing is effected in
this RHR phase? There's no additional risk that
arises due to that?
MR. LEE: Not in terms of the additional
decay heat load, no.
MR. LEITCH: I guess if I understand that
last slide, it's incorrect. In other words, it's
somewhat dated. If I was making this presentation,
I'd get rid of that.
CHAIRMAN WALLIS: So it's a risk decrease.
MR. LEITCH: I'd say decrease instead of
increase; is that correct?
MR. POTERALSKI: The reason the slide is
shown the way it is, is the formal commitment to the
staff has not been made for the tech spec change and
this captures what was in the original submittal of a
MR. LEITCH: Okay, thank you.
CHAIRMAN WALLIS: Are we ready to move on.
Thank you very much for your presentation.
MR. WILLIAMS: Good morning, I'm Mike
Williams, the manager of operations at the Brunswick
plant. I want to talk about the operational impacts,
the training and the testing that we plan to do as
part of the extended power uprate. Some of the
operational impacts we have we've talked quite a bit
about stability III versus stability Option E1A that
we had previously. It's fully operational on Unit 1
right now. It is a good change for us.
It actually has an automatic detect and
suppress. The E1A option has a detect function and it
has an automatic trip function based on a flow versus
power relationship but you could have instability and
with only an alarm function and under E1A would allow
the operator then to have to insert the manual SCRAM
to suppress it.
Either one -- either option works well,
but Option III I think is a very, very good change for
us. The other part of -- thing that power uprate has
done is we are implementing that power range neutron
monitoring system. It's basically an upgrade for our
power range system and it's going to have a much
better operator interface than what we had previously.
That's on the good side.
On the other side there's -- we will be
doing more rod pattern adjustments. Currently we have
to change our rod pattern approximately once ever four
months. With extended power uprate. Once we get into
it, we'll be doing that much more often, on the order
of about every month. It's not a significant impact.
Moving control rods is what we do and it's very well
able to be controlled.
We also will have a slight reduction in
operator action times and they're very slight. We
have with the modeling we've done and with the
simulator exercises we developed, the change in the
operator response and the change in the plant response
is there but it's small enough to where it's not a
major impact at all and for the most part, from a
transient response situation the operators won't be
able to see the difference on the simulator.
MR. LEITCH: Has the preconditioning
operating requirements all been taken away now with
the fuel that exists? In other words, this control
rod pattern change need not be accomplished with a
power reduction and then gradually working your way
back up the way it used to be?
MR. WILLIAMS: My understanding is it will
still require preconditioning limits on GE14 as it has
in the past.
MR. LEITCH: Oh, really?
MR. WILLIAMS: Now, I'm not 100 percent
confident about that; is that correct?
MR. BOLGER: This is Fran Bolger from GE.
There is some best practices for fuel maneuvering
guidelines that are being followed. They're not
exactly -- they're not pre-conditioning, per se, but
there are other guidelines that are recommended.
MR. WILLIAMS: We're still following the
recommended guidelines and we will continue to do
MR. LEITCH: So on a monthly rod pattern,
one might expect power to be reduced and then work up
again over a period of a day or so, something like
MR. WILLIAMS: About a shift, yes, sir,
somewhere in that range.
MR. LEITCH: A shift. Okay, thank you.
MR. WILLIAMS: Operator training, we
started early last summer to do a conceptual, I guess,
overview of what was coming with power uprate talking
in very large terms as to what we were going to do.
We've gotten very much more detailed with that. So we
actually did training four times last year on what was
coming on power uprate. We started out very
conceptual and it moved into a lot more detail as we
got closer to the outage. Principally the large
changes that we have with the power range neutron
monitoring system, our management of thermal-hydraulic
instability and the balance of plant modifications.
So we trained on those four times last
year beginning with very conceptual based type stuff,
up to a lot of detail by December of last year.
MR. LEITCH: Do you have a plant specific
simulator at Brunswick?
MR. WILLIAMS: Yes, sir, uh-huh.
MR. LEITCH: And what is the status of
simulator with respect to these physical changes in
the plant? When is the simulator going to be changed?
MR. WILLIAMS: The simulator has been
upgraded to be physically compatible with Unit 1 as in
the new power range neutron monitoring system. All
those things have been installed on the simulator.
The new core model that is duplicating the 112 percent
power is what we have right now. And we have -- we
will be training on that starting in about a week.
The operators have not been trained with
the new core model. They have been trained with all
the new hardware power range neutron monitoring
Dr. Schrock: What kind of frequency do
you expect on this automatic trip feature? Is it
something that will be seen rarely or is it something
operators are going to have to get used to dealing
with or what?
MR. WILLIAMS: The automatic trip feature
would only -- it's the detect and suppress part of the
oscillating power range monitor. I would expect to
not see that in the plant at all.
Dr. Schrock: Never see it.
MR. WILLIAMS: I don't think so. We will
train on a simulator. Pretty much every time we go
over there, you will see something along that line but
I don't ever expect to see that in the plant.
Dr. Schrock: So how to you gain
confidence that it's going to work if it's really the
MR. WILLIAMS: Well, we test the system
when we put it in to verify that it's functionally,
you know, doing what it's designed to do, so I have
confidence that --
Dr. Schrock: Well, there are tests.
MR. WILLIAMS: We do test it in the plant,
yes, sir. I mean, you know, not make instabilities
and make it trip us but --
Dr. Schrock: Uh-huh.
MR. WILLIAMS: Now, in addition to that,
I mean, the way we train the operators is that system
doesn't even need to be there because if we detect
instability, we'll shut the reactor down. Whether
that system is there or not, it's pretty much
MR. POST: This is Jason Post from GE.
And also, the design of the instruction is such that
it has a low level of response even for normal noise
and so you have confidence that the instrument is
working during normal stable operation as well.
MR. WILLIAMS: Okay, just a list there of
the training things that we put into the cycle right
before this last outage so that we made sure that we
covered everything, the set point changes, tech specs,
all our procedure changes. The procedure changes here
were very minor. The set points, there were no
fundamental changes in how we operate with the
exception of the stability solution.
We -- before we go to uprate, we will go
in and do training on the simulator, demonstrate
transients, do transient response training, and talk
about the test plan, the start-up test plan with the
operators prior to going anywhere above our current
license power level. There will be classroom and
MR. LEITCH: Where do you stand in the
INPO accreditation cycle. Has the operator training
program been recently --
MR. WILLIAMS: We were accredited last
year, I think it was and so we are now, I think on an
18-month cycle. I mean, INPO changed that from two
years. We were put on 18 months so they could get the
plant evaluations lined up with the accreditation
evaluations. We're on an 18-month cycle.
CHAIRMAN WALLIS: This business about no
operating procedure changes, there really aren't many,
MR. WILLIAMS: Very few, and the ones that
were there dealt with set point changes more than
anything but also the instability change caused us to
change our AOP going from E1A to Option III.
CHAIRMAN WALLIS: But it's not a major
item, is it? I mean, you've got a bullet there. I
just wondered if there was something significant under
MR. WILLIAMS: There's nothing significant
about what we changed in the AOP.
CHAIRMAN WALLIS: And there's nothing
significant under EOP, the emergency operating --
MR. WILLIAMS: Fundamentally what we do
did not change with the exception of --
CHAIRMAN WALLIS: The plant transient
response is essentially the same.
MR. WILLIAMS: Right, yes.
CHAIRMAN WALLIS: So eliminate the slide,
MR. WILLIAMS: I can do that, watch this.
MR. WILLIAMS: I'm going to talk a few
minutes about implementation testing. We're going
through pretty much the LTR testing, chemistry
radiation monitoring. We'll monitor those parameters
on the way up to make sure we're staying within our
limits. We have to recalibrate our main steamline
flow transmitters because we'll be going to a higher
steam flow and we have an MSIV isolation of high steam
flow. We'll also be doing the APRM set point adjust
up to the 120 percent of original license power.
We'll be doing performance monitoring as
we always do on power increases. Our EHC, electro-
hydraulic control system, pressure control system and
our feedwater level control systems will be stopping
every five percent power and doing step changes,
regulator fail-over testing on those just as we did
coming out of the outage to make sure that they're
responding correctly at the above our current power
During that last outage we also installed
our main steam and feedwater piping vibration
instrumentation with monitoring data on the way up and
we'll be doing all our balance-of-plant monitoring on
the way up to look for anything in the plant that is
going to be a limitation for us on the way up. But
we'll be coming up very slowly in power, a little bit
at a time, doing a lot of monitoring and deciding it's
okay to keep going.
MR. LEITCH: I'm not so much concerned
after you have all the modifications done, but when
you bring the units up initially after only the Phase
1 modifications have been completed, what are the kind
of things you'll be looking for. Someone mentioned
earlier that the main transformer is one of the
limiting factors. Are there other factors that could
potentially be limiting?
MR. WILLIAMS: We have a large list of
parameters that we'll be monitoring on the way up. We
know our limiting point could be main transformers, it
could be our bus duct temperatures, it could be the
actual amperage on our condensate booster pumps as we
currently are. So we have a list, procedure already
made up that incrementally come up in power under
those parameters and that they're okay to continue up
to the next level.
MR. LEITCH: On that list would be things
like condensate booster pumps, suction pressure and
reactor feed pump suction pressure?
MR. WILLIAMS: Yes, all those things, lost
amperage, temperatures, flows.
MR. LEITCH: Okay.
MR. KITCHEN: This is Bob Kitchen. We
have a special procedure that's going to be issued
with the license -- part of the license testing that
coordinates the plateaus and the data to take during
the power ascension in very small increments up to the
test plateaus, which includes, as you mentioned the
balance-of-plant, core performance, pressures,
temperatures at various points in the plants. Steam
line tunnel temperature for example, is an area of
concern that we'll monitor, temperature on the main
generator, isophase cooling, as well as the routine
core performance parameters. We'll be doing that
throughout the start-up.
We also have three management hold points
built in, one prior to starting, power ascension above
current license power level, one at the intermediate
plateau and one prior to resuming normal operation.
MR. LEITCH: Now, what concerns me is that
a license is granted for 120 percent power, yet,
admittedly, you don't know of all the physical changes
made to go to 120 percent power, so we're okay here
and eventually we'll be okay there, but I guess what
I'm concerned about is moving through this zone where
you've got permission so to speak to go to 120
percent, yet not the physical hardware to move to 120
percent yet, so all those things have to be very
carefully monitored and it sounds like you have a
program to do that.
CHAIRMAN WALLIS: Can you run at this 120
percent power all year round or do you have
environmental limiting conditions some of the time?
MR. KITCHEN: We'll be able to operate at
the 120 percent power level year round. In terms of
environmental, condenser or temperature limitations,
we do have an environmental MPDS change in progress
which was -- coincidentally it was due for renewal
anyway and there is a slight change in our circ. water
discharge temperature so that the mixing zone is
increased. And we'll have to have that -- we'll want
that in concert with the full uprate. We do not
anticipate any limitations for environmental.
MR. WILLIAMS: To summarize the greater
impacts of EPU augmentation, we have done extensive
training and we still have training to do before we go
above our current license power level and we have a
very comprehensive test plan laid out to monitor the
plant carefully as we're coming up above our original
license power level.
The operational changes that we see have
to do with extended power upgrade. As we have a new
approach to instability, we will be doing more rod
manipulations to maintain power and there is some
small reduction on operator response time with respect
to transients but it's very small and in most cases
the operators won't notice the difference.
MR. LEITCH: Mike, one concern I have with
this -- with these power uprates is, I have the
perception and maybe it's incorrect, but I have the
perception that it's going to be a great deal more
challenging for the operators to maneuver rods without
making a mistake. It seems to me we're encroaching on
margins and I guess I'm concerned about thermal limits
being exceeded as we operate these what I call
designer fuels. And I guess, have you done anything
to increase the operator training in that area or
perhaps, even more importantly, the guy that really
has the control in that situation and the way most
plants operate is the reactor engineer.
MR. WILLIAMS: That's correct.
MR. LEITCH: And I'm concerned about the
training of reactor engineers. Have you done anything
different in that area?
MR. WILLIAMS: I don't know that -- I
really can't speak for the reactor engineers. Blane
may want to do that. I can tell you from the
operator's side, we have a very strong reactivity
management program that we use and we also have a very
good relationship at Brunswick with the reactor
engineers and the operators and you'll almost never
see, unless it's something that we have to do, an ALP
type situation, a power change in the control room
that doesn't involve the reactor engineer being in the
control room to help us monitor the thermal limits
while the operators are performing that action.
As far as any additional training for
reactor engineers based on having to do more control
rod manipulations, I don't know of any plan.
MR. KITCHEN: Well, right now the training
to say it's changed, I'm not sure I could say that but
the training that is given for operators as well as
the engineers includes the reload plan and fuel cycle
plan and impacts and it's also reviewed with the
operators mid-cycle. So they get the core performance
expectations twice during cycle on each unit as part
of the routine training.
I don't think there's really a change in
-- you know, in that. It's just the content of it
would be different, certainly because of new fuel and
different parameters are limiting.
MR. LEITCH: Some plants have a
qualification program, if you will, for reactor
engineers where a reactor engineer, in order to be a
reactor engineer, one must pass through certain
hurdles, including witnessing some draw rod pattern
exchanges in the control room and so forth. I was
just wondering if you have such a program.
MR. WILLIAMS: Yes, sir, we do.
MR. KITCHEN: And Blane, can you add
MR. WILTON: Yeah. The way we control
that is really going to be the same way we've always
controlled it, which is we have a predictor code that
we have in the control room and before -- when we
start getting tight on limits, before we do any
manipulation which changes reactivity, we run the
predictor codes, see where it's going to put us and
then we march through those steps.
Our design margins really aren't going
down with respect to the core. And at least for this
cycle, we're still going to be in a control cell core
configuration. So we really haven't planned any
special training other than we do initial training.
Our fuels group, after they've designed to core for
the upcoming cycle, they do an extensive training
session with the reactor engineering staff to let us
know what the cycle is going to look like, what our
limits are going to be, those type things and then do
also emit cycle training session also.
So I don't see our conduct of operation
really changing in the control room, which we're still
going to be running our predictor codes as we planned.
Our margins to our thermal limits from a design
perspective really haven't changed. So I don't see
really a change in operating strategy for us up there.
MR. LEITCH: Okay, I'm just concerned that
if VWRs are becoming more complex to operate as we
move to these higher power levels from a fuel
management standpoint and I just want to be sure folks
are putting the right emphasis on the operators and
the reactor engineers and it sounds like you've got a
program to do that.
MR. WILTON: Well, like Mike eluded to
earlier, any plan change in reactivity is controlled
with a reactor engineer in the control room, so those
are covered. Any time there is an unplanned change,
they have immediate reduction, power reduction sheets
available to tell them --
MR. LEITCH: To stay calm.
MR. WILTON: Yeah, on what to do in those
cases and then the reactor engineer is there to help
with the recovery and those are going to remain.
MR. LEITCH: Thank you, that's good.
MR. GANNON: I'm Neil Gannon. I'm the
director of site operations at the Brunswick plant.
You look at our discussion on the various topics
today, you can follow through this program of our
analysis on the fuels. ECCS performance, PSA, we'll
call your attention to the operational impacts.
In light of the change to the station and
the potential challenges to the BOP system and the
fact that we're changing the station, one thing that
was incorporated into our evaluation of the extended
power uprate program was a standing PNSC, plant
nuclear safety committee, standing committee on power
uprate itself to identify power uprate related issues
as they impact operations.
Some of the things that came out of that
was the concern on the impact to our chemistry
performance index and things of that nature so that
while not necessarily an obstacle to power uprate,
operational impacts that we wanted to carry forward
and resolve them as we implemented the program, an
example being the condensate cooling modification
which our subsequent activities indicate to us it may
not be necessary but we'll follow those through to
Obviously, there's a business case to be
made for extended power uprate. It increases the
plant capacity, so that's one of the business plan
aspects of this. We are also using the extended power
uprate program at Brunswick to look at some of the
operation strategies and our plans for the future of
Some of the features of that are we are
using our plant staff as the extended power uprate
program. This is not something that's out-sourced.
Bob and a lot of the crew are people that came out of
the line organizations so that we have that sense of
plant ownership and we have that knowledge that's
going to be institutionalized and come back to the
plant when we're done.
We'll use this opportunity to increase our
knowledge base at the station, the BOP systems and
we're going to address some long term issues that,
while not necessarily strictly power uprate related
are challenges to us, equipment obsolescence, the
power range neutron monitoring is something that we'll
address. An equipment obsolescence issue and provide
a benefit as well as just facilitating extended power
We have some components that we've
identified here such as feedwater heaters that while
not necessarily obstacles, are components identified
as not going to serve to the existing license life of
the plant and we're using this opportunity to go ahead
and upgrade those and give ourselves a better plant
when we're done.
We also feel that our plant staff
capabilities will be increased, as I said before. The
individuals that we're using to manage power uprate
are people that came out of our line organizations;
engineering, operations and other areas, and will
return to the station when we're done. So this is
something that's internalized and we'll have that
available to us as we go forward and operate the
So we're proud of the work that's gone
into this and pleased to present this material to you.
If there are no other questions for me or anyone else
MR. KRESS: The upgrades and the
improvements you've listed are all very good. Is the
power uprate approval contingent on those being made
or are they -- is that a separate issue? I don't know
if that's -- that may be another question to the
MR. HARRISON: Could you rephrase that
MR. KRESS: The question is, they're
talking in order to make this power uprate or as part
of the power uprate are improving the power range
instrument, particularly increasing the SLC and
upgrading the grid stability. My question is, if
you're going to say we will approve this power uprate,
is there something in that approval that says these
things have to be done and it has to be demonstrated
that these improvements and upgrades have been made
before the power uprate takes place or not?
MR. HARRISON: Well, some of them, the one
in particular, the safety -- the standby liquid
control system modification won't be done until later
on. They're going to make a license amendment later
on this summer to revise the operation of the standby
liquid control system and we're going to put a license
condition in the license that says that they have to
MR. LEITCH: Okay.
MR. HARRISON: But the rest of the
modifications are being described in the documentation
that has been submitted to the staff.
MR. KRESS: So that's part of the
MR. HARRISON: Part of the application and
that will be done in order to --
MR. KRESS: But the SLC is the only one
that's not part of that.
MR. HARRISON: I believe that's the only
one that -- well, there are some secondary site
changes, I believe, that -- what was it, the
transformers and some other changes that won't be done
MR. KRESS: Okay.
MR. HARRISON: But they can't physically
get to that power level without making those changes.
MR. KRESS: Yeah, those don't bother me
because they'll have to make those if they're needed,
MR. LEITCH: But did I understand -- well,
maybe this is this afternoon's discussion. Let me
just quickly ask a question. Did I understand you to
say that power uprate will be conditional on SLC
modification being installed?
MR. HARRISON: There's a condition that's
going to go on the license that says that by -- what's
MS. ABDULLAHI: I'm Zena Abdullahi, the
reviewer. The license condition that is attached to
the power uprate on the SLC is for the shutdown
requirement that the change from 660 to 620 -- I'm
sorry, 660 to 720 or whatever ppm, that is what that
is based on and in any case, we're giving them an
uprate of 20 percent and we don't know when they put
in the second batch of G14 fuel what the reactivity
requirement would be then. And this will insure that
the staff will review it six months before the
The SLC margin, though, is the licensee
plans to make the change but the condition is not
really there and we will be discussing it in our
MR. KRESS: So the change from one to two
MR. HARRISON: Two to one.
MR. KRESS: -- two to one, I'm sorry, will
not be a condition on the uprate.
MR. HARRISON: No, the way the condition
is currently worded, it says that the licensee shall
submit a license amendment request to insure that the
system remains capable of shutting down the reactor,
demonstrating appropriate shutdown margin and
continues to meet the requirements of 10 CFR 50.62
which is the ATWS requirement, by August -- I believe
August 29th or August 30th. So there's a requirement
in the license condition that they must submit a
license amendment request to show that they meet the
shutdown margin requirements and the ATWS requirements
by August this year.
MR. KRESS: Yeah, but they could do that
without making that particular change probably.
MR. HARRISON: Well, we don't believe that
they can meet the shutdown requirements.
MR. KRESS: Okay.
MR. HARRISON: So that will allow us to
review the other aspects of the system at that point.
MR. BOLGER: This is Fran Bolger from GE.
As far as Unit 1 cycle 14, which is the first plant
that's uprating, the shutdown requirements were met
with the 6-60 as Tom Dresser has shown earlier.
MR. HARRISON: That's for the first cycle,
but that's not to go to -- for the next cycle of
operation, they need this in order to meet that next
cycle of operation, to load a full batch of GE14 fuel.
Is that correct, Fran?
MR. BOLGER: Yes, I believe it will be
required for the next cycle.
MR. HARRISON: And that's why we allowed
them to operate right now with this cycle with the
current standby liquid control system as designed.
That's why we insisted that we get a license amendment
in August to support the next cycle.
CHAIRMAN WALLIS: Can I ask you how much
of the cost of this uprate is what I call regulatory
costs, preparing for presentations to ACRS, filling
MR. KRESS: A very small amount.
CHAIRMAN WALLIS: And how much of it is
cost in the Super Boron, balance-of-plant and new
MR. GANNON: Well, the project overall is
run at about $150 million over four outages for two
years, two outages per unit. The breakdown in cost,
I think for analysis and things like that it's about
CHAIRMAN WALLIS: It's $10 million of this
regulatory overhead or whatever you call it?
MR. KITCHEN: Are you talking about just
the licensing effort itself?
CHAIRMAN WALLIS: Yes, how much of that --
MR. KITCHEN: That would be in the
neighborhood of about 10 to $12 million.
CHAIRMAN WALLIS: So it doesn't sound
unreasonable, does it?
MR. KITCHEN: No.
CHAIRMAN WALLIS: Well, what's the return
MR. KITCHEN: It's been awhile since I've
looked at that number to be honest with you. The
payback period, which I can remember, is about 2009
with the implementation on the time line we've
CHAIRMAN WALLIS: It's 2000 --
MR. KITCHEN: 2009, the year 2009.
CHAIRMAN WALLIS: 2009, okay.
MR. GANNON: A relative merit when we had
our treasury group price this out or do the cost
justification, this -- and the cost benefit came out,
number 1 for progress energy capital investment.
CHAIRMAN WALLIS: Are there any other
questions for the --
MS. MOZAFARI: I just wanted to make a
comment. I'm Brenda Mozafari, the project manager for
Brunswick. I was not Duane Arnold, you may recognize
me. I want to make sure that it's very clear that
these are not all going to be license conditions. In
fact, the power range instrumentation I believe, has
already been approved. So some of these are done as
separate actions and they've already been approved or
will be approved.
Anything that is not approved or upgraded
will be in the license condition and as I understand
there's only one license condition at this point and
that was the one --
CHAIRMAN WALLIS: You'll tell us more this
MS. MOZAFARI: Hopefully, all you need to
know. Thank you.
MR. LEITCH: Just one quick question, Neil
and it's really not part of this discussion but could
you give us any insight as to what your thinking is
with respect to license renewal for Brunswick?
MR. GANNON: We have an active license
renewal program at this point started and the
individuals are on site doing the evaluation right
now. In progress energy, you know, we have a program
that's going to go through all sites to first plant,
to go through the license life extension was the
Robinson Plant. The Brunswick units will be following
MR. LEITCH: Okay, thank you.
CHAIRMAN WALLIS: Do you another question?
You owe us a couple of things after the break, I
think, that you're going to come back to us.
MR. KRESS: Timing of the net positive
suction head pressure.
CHAIRMAN WALLIS: Show us some curves of
pressure versus time and things like that.
MR. KITCHEN: So I understand, you wanted
the feedwater line forces and the net positive suction
head break time line.
CHAIRMAN WALLIS: Right. Is there
anything else that we need? I'm just about to break
for lunch. We have mysteriously gained some time
having lost some earlier. Maybe we should have spent
some more time when we were asking questions earlier.
I propose that we meet again at 1:30
instead of 2:00. The staff has indicated they prefer
to do that and it's going quickly in the afternoon and
get us out of here, perhaps, a bit earlier, otherwise
I'm going to break for lunch and thank you very much
for all your hard work and presentations this morning.
(Whereupon, at 12:23 p.m., a luncheon
recess was taken.)
CHAIRMAN WALLIS: We'll come back into
session, please. Does Brunswick have a couple of
answers from this morning before we get started with
MR. GRANTHAM: Yeah, this is Mark
Grantham. I've got a couple of slides for the MPSH.
CHAIRMAN WALLIS: Oh, that's --
MR. GRANTHAM: Can you see this?
CHAIRMAN WALLIS: You wanted a picture,
MR. KRESS: It says the pressure gets up
pretty fast and stays there a long time. You know I
didn't want to see a repeat. It comes up there and
just hangs there a long time.
MR. GRANTHAM: Right, what this shows is
right around 1.8 hours is where we actually lose our
margin and our acquired credit for containment over-
pressure. The actual peak occurs at about 7.3 hours.
This is --
MR. KRESS: Yeah, but it's not much of a
peak. It's pretty flat all the way up through there.
MR. GRANTHAM: Right, 3.1 psi is what was
needed and we require a containment of under pressure
out to about the roughly 18, 19 hour mark when it goes
back positive and credit for containment over-pressure
is not required.
MR. KRESS: Now, in this analysis for the
containment pressure, you said you did have sprays
MR. GRANTHAM: What we did was for
containment pressure, we assumed that the spray is
operated, okay. That gave you the lowest wet well
pressure. Okay. For suppression pool temperature, we
assumed direct cooling which gave you the highest pool
temperature. So you got a worst case combination for
MPSH of lowest wet well pressure and highest
MR. KRESS: I'm just surprised that with
the sprays operating that you kept that pressure up
there for 24 hours almost at a high level. That
surprises me for some reason. Where are the -- are
these -- this is Mark I containment. The sprays are
in the dry well?
MR. GRANTHAM: Dry well and suppression
MR. KRESS: And suppression pool.
MR. FLADOS: The reason that the
containment pressure stays so high is the fact that
the sprays are taking the suppression pool water and
spraying it down. The quenching effect isn't there
because you don't have cold water.
MR. KRESS: It's already hot water.
MR. FLADOS: The pressure is really the
overall contribution of water vapor pressure plus the
pre-existing nitrogen at that temperature almost
equilibrium conditions. So that's why it goes up and
stays up until you start bringing suppression pool
water temperature down. That drives pressure down.
MR. KRESS: Yeah, just by condensation.
Okay. So that answers my question. I was worried
that there would be a peak pressure and the timing
might be such that if you didn't have that just right,
you would miss it, but -- okay, thank you.
MR. GANNON: The other question, as far as
the feedwater loading, GE is actually researching some
information on that. We'll have a response back by
the end of the day.
CHAIRMAN WALLIS: Okay. Before the end of
MR. GANNON: Hopefully.
CHAIRMAN WALLIS: Brenda, are you ready to
make your presentation?
MR. BERKOW: Good afternoon, my name is
Herb Berkow and I am the project director for Region
2 plants in the Division of Licensing Project
Management, and, of course Brunswick is a Region 2
plant. The staff is here today to present the results
of our review of the extended power uprate application
for the Brunswick plant. Several members of the NRR
management team are here to support the staff and the
staff's safety evaluation and others will be joining
us as we proceed through the agenda.
The Brunswick power uprate is similar to
Duane Arnold, Dresden, Quad Cities and Clinton
extended power uprates which were recently reviewed by
the ACRS. The Brunswick application deviates from the
approved ELTR 1 and 2 methodologies for BWR extended
power uprates in five areas as discussed in the
staff's safety evaluation.
This is consistent with the four areas of
deviation identified by the licensee this morning. We
just broke them out a little differently. In this
respect the Brunswick power uprate most closely
resembles the Clinton power uprate, even more so than
the others. This review was consistent with existing
staff practice and includes the Maine Yankee lessons
learned. The results were transmitted to you in our
draft safety evaluation last month.
Our project manager for the Brunswick
plant is Brenda Mozafari and Brenda will guide us
through the individual staff presentations this
afternoon. As we proceed, the staff is available to
answer any questions that might arise and at this
point, I'll turn it over to Brenda.
MS. MOZAFARI: Good afternoon. I'm Brenda
Mozafari. I've recently been assigned the project
management responsibilities for the licensing portion
for NRR of the Brunswick power uprate.
MR. LEITCH: Brenda, right on the first
slide, I have a question that I was sort of wondering
about this morning.
MS. MOZAFARI: Okay.
MR. LEITCH: And that's we refer to this
as an extended power uprate.
MS. MOZAFARI: Right.
MR. LEITCH: And last week General
Electric was here talking to us about constant
pressure power uprate and this is a constant pressure
power uprate but I guess my confusion is, is this just
semantics or is there really something different about
EPU versus constant pressure power uprate?
MR. SIEBER: One's approved and one isn't.
MS. MOZAFARI: Right.
MS. ABDULLAHI: This is reactor systems.
MR. HOANG: This is Hoa Hoang with General
Electric. I'd like to address that question. The
Brunswick submittal is actually based on the extended
licensing topical report. So it's the ELTR
methodology and guideline. ELTR methodology does
provide a provision for dome pressure increase. And
CPPU or constant pressure power uprate, that you were
-- discussed with GE recently is the next evolution of
As part of CPPU, we have taken the scope
and the methodology and the generic evaluation from
ELTR and further simplified them to be commensurate
with a pressure uprate -- I mean, with a power uprate
with no pressure increase, and, therefore, this
submittal technically is still under ELTR with those
specific exceptions that were discussed, presented to
MR. LEITCH: So it does not have those
simplifications, if you will, that would be associated
MR. HOANG: That's absolutely correct.
MR. LEITCH: Okay, thank you.
MR. HOANG: With exceptions for those four
areas that were mentioned in the presentation.
MR. LEITCH: Right, okay, thanks.
MS. MOZAFARI: Okay, just by way of
reviewing a little setting the stage over what's been
presented this morning, Brunswick is a BWR 4 Mark 1.
They have requested a 20 percent power uprate from the
original reactor thermal power, licensed power. They
do include a constant reactor dome operating pressure.
The five percent stretch uprate was approved in
November 1996, so they've gotten the five percent.
This would be 15 percent on top of that, bringing them
to 20 percent.
There is two parts in their
implementation. It would be done in two phases, a
seven percent and an eight percent. It does include
balance-of-plant modifications and it does incorporate
the GE14 fuel further in their plant. The application
for the most part follows ILTR 1 and 2. There are
some exceptions as Mr. Berkow mentioned, to the ELTR
1 and 2 in predominantly four areas that the reviewer
will be going over.
It is a non-risk informed submittal.
However, Brunswick did submit some risk information to
assist us in doing our evaluation of their submittal
and the application incorporated experience from
Hatch, Montecello, Duane Arnold, Dresden/Quad Cities
and Clinton. They did go through, they looked at
RAI's from the various plants, questions that may have
been raised previously by ACRS, and tried to address
them in making their application.
MR. KRESS: Your third bullet there, every
plant so far has submitted this risk information.
MS. MOZAFARI: Right, right, but there is
MR. KRESS: There's no requirement for it?
MS. MOZAFARI: There is no requirement.
MR. KRESS: Do you expect some plant will
come in without it some time and what would you do if
MS. MOZAFARI: I wouldn't know. I'm not
in that position right now to make a decision but my
management would tell me what to do.
MR. HARRISON: This is Donnie Harrison
from the PRA Branch. Right now, it's in the GE
methodologies that the topical reports ask for the
risk information to be provided.
MR. KRESS: Oh, one of the topical reports
MR. HARRISON: The ELTR actually asks for
it and even on the constant power pressure uprate, it
has a section in it --
MR. KRESS: So they could take exception
MR. HARRISON: Sure, sure and then we'd
evaluate the exception.
MS. MOZAFARI: They could.
CHAIRMAN WALLIS: Well, looking at how
little really you have to worry about it in the PRA
results, I would think they might -- it might be
advantageous to have a risk informed submittal. It
might reduce the work.
MS. MOZAFARI: According to Donnie, that
does seem to be the case at times.
MR. HARRISON: I would argue for like
Brunswick if they actually did the SLC modification
where they could actually change from a two-pump to a
one-pump success criteria, it would be worthwhile to
submit it. That would be a open and closed book as
far as I'm concerned on the power uprate.
MS. MOZAFARI: Okay, Zena Abdullahi, the
lead reviewer in the reactor systems branch area for
the Brunswick power uprate and she's going to do the
next portion of the presentation.
MR. BOEHNERT: Excuse me, Zena, you or
Brenda told me that you'll need to have a closed
session for part of this?
MS. ABDULLAHI: I would think my notes
would have something that would require me to have a
closed session, otherwise I would have to edit myself
throughout and that would be difficult.
MR. BOEHNERT: So you're suggesting we
close this session?
MS. ABDULLAHI: I think so, then I could
speak freely without worrying about it.
MR. BOEHNERT: All right. GE, would you
make sure that on one's here that shouldn't be here?
Transcriber, let's go into closed session.
(Whereupon, the subcommittee went into
closed session at 1:44 p.m.)
(On the record at 2:37 p.m.)
MS. MOZAFARI: We were going to present
the PRA, the PSA portion with Donnie Harrison but he's
not here right now. He'd asked to have it done before
3:00 o'clock, so the next person would be Richard
Lobel, who is going to give the plant systems portion
of the staff's evaluation.
MR. LOBEL: He's here now.
CHAIRMAN WALLIS: So we're going back to
MS. MOZAFARI: We had a staff meeting in
order to accommodate someone's schedule, so --
MR. HARRISON: I'll do better next time
with my bathroom break.
MR. KRESS: You're here right on time.
You can't beat that.
MR. HARRISON: Now, if this was a PRA --
MR. KRESS: You have negative margins,
MR. HARRISON: That's right. Hopefully,
we'll go through this fairly quickly, at least the
first few slides because you all -- some of this is
almost motherhood now. What we look at is the same
thing we look at, at all the other power uprates that
have come through and how we do that. So we can
probably move to like the third slide.
MR. KRESS: No, no, don't do that.
MR. HARRISON: Okay. I put these together
last night so if they're off center, that's probably
why. But what we do is we look at the internal
events, external events, shutdown operations and we
take a look at PRA quality, asking questions on those
things and we also took a look at the SEs on both the
OPE and the IPEEE and to get back to, I think, Graham
Leitch's comment earlier about hurricanes and winds,
that is in the IPEEE and it's four times 2-6. You'll
see it on the next slide.
MR. KRESS: Let me ask you a question.
MR. HARRISON: Okay.
MR. KRESS: Similar to the one asked
before but a little different.
MR. HARRISON: Okay.
MR. KRESS: I know these are not risk
informed submissions but suppose one of the plants
came in and you found that your LERF or delta LERF or
CDF or delta CDF puts you in the Region 1 on 1.174.
MR. HARRISON: Puts me into the black
MR. KRESS: Yeah what would you do?
MR. HARRISON: At that point, what we're
put into is there's a RIS (phonetic) on the street, I
think it's 2001.02 which says are we -- and in the
area where we're questioning adequate protection and
at that point, then I'm instructed to inform my
management and inform the licensee that we've got some
serious questions that need to be answered.
MR. KRESS: You're questioning adequate
protection at that point?
MR. HARRISON: And at that point, you're
questioning adequate protection because it's not risk
MR. KRESS: Uh-huh.
MR. HARRISON: If it were a risk informed
application, you would be in a -- you know, you could
pursue it directly.
MR. KRESS: But they meet all the
MR. HARRISON: Right. The --
MR. KRESS: So how can you question
MR. HARRISON: Well, what -- the
conditions of adequate protection -- actually, I've
got a slide on this.
MR. KRESS: Oh, okay.
MR. HARRISON: Slide 5 in the risk as we
bounce through my conclusions here, oh, never mind.
The backup, yeah. Sometimes technology is not the
MR. KRESS: At this point, my computer
would hang up and quit.
MR. HARRISON: Slide number 5. There is
it, that's it. This is the top part of that RIS. In
the back of the RIS is a nice page-long logic diagram.
This is the top block. It's a decision block that
says, you know, you get a non-risk informed submittal.
You ask a question, does it raise issues that could
rebut the presumption of adequate protection, just in
case you wonder where I get those words in my SE. And
if you do, then it's because you believe there's a
special circumstance that exists and it gives a
definition for special circumstance and that's on my
next slide, slide 6.
And these are the two conditions for
special circumstance. The first one says, you've found
a problem that the regulations never thought of and I
think the classical example here is the electrode
sleeves for steam generators. And it was a condition
they found. The regulations didn't cover the area and
so it was missed and so now you can get in the process
through that. The other condition says, I, as a
reviewer knows something about this plant that would
say if this was risk informed, we would deny it.
Essentially that's what it comes down to.
MR. KRESS: That's what I was looking for.
MR. HARRISON: The reason to believe that
the risk increase would warrant denial. So at that
point, if we get to that high a level -- and again, if
I'm up in Region 1 in the dark region of the reg guide
117.4 chart, I'm going to invoke that and I'm going to
start asking more questions.
MR. KRESS: Now it may not -- it just
leads you to a further investigation.
MR. HARRISON: It leads me to a -- and it
may result -- I think in Arkansas, we actually were up
and just barely got up there but we saw that the fire
analysis was so conservative that we convinced
ourselves that it wasn't that bad and that if they'd
done a realistic analysis, they wouldn't have been up
there. If we're up in that region and we think we're
up in that region, then we're going to --
MR. KRESS: Now, in the case of Brunswick,
they didn't have any numbers for the shutdown
contribution and seismic or --
MR. HARRISON: Right. You could -- well,
actually there is a fire number and a wind number.
MR. KRESS: But they're -- it's internal
MR. HARRISON: Right, again, this is a --
MR. KRESS: If you added those in --
MR. HARRISON: Right.
MR. KRESS: Do you? Do you add them in?
MR. HARRISON: I take a look at them and
as a matter of fact, one of the concerns I had on
Arkansas was you were approaching the limit if you
added everything together and then the fires just kind
of blew the world apart. On this one, if you add them
all together, you're still not there. If you --
MR. KRESS: Unless you double the LERF.
MR. HARRISON: Unless you double the LERF
but -- and I've been thinking about your question on
doubling the LERF. The reg guide's not --
MR. KRESS: The reg guide --
MR. HARRISON: It doesn't speak to it and
MR. KRESS: It's silent.
MR. HARRISON: Right, and I think partly
because the concept was, it was done -- most of these
analyses are done on a per plant and so that just
MR. KRESS: But the LERF is a site
characteristic. It's a surrogate for the proper
MR. HARRISON: Right, the problem you have
is your LERF may double at a site, but your dose
release from an accident is going to be from one
MR. KRESS: Yeah, but that release is
frequency times the dose.
MR. HARRISON: Right, and that's the
problem we've got. We've doubled -- the LERF doesn't
directly tie at a dual unit site to a dose.
MR. KRESS: But it's a surrogate.
MR. HARRISON: It's being used as a
surrogate but that's the problem we're in.
MR. KRESS: Yeah. You really should think
of that because there ought to be a site
characteristic. And this comes up, for example, with
the modular reactors, you've got 10 modules. You're
going to add up every one of those.
MR. HARRISON: Right.
MR. KRESS: Well, it's the same thing.
It's just --
MR. HARRISON: On the LERF criteria, you
could go there. The question becomes if I postulate
an accident, I do my dose consequence part of it, I'm
only going to postulate a single unit release.
MR. KRESS: Well, sure, but you're going
to multiply the frequency to it.
MR. HARRISON: Right, right.
MR. KRESS: I mean, you're going to
multiply the frequency.
MR. HARRISON: Right, it's just I didn't
want to give the concept that we were actually
doubling the dose somehow.
MR. KRESS: No, no, I realize that.
MR. HARRISON: Okay, right, in that case
CHAIRMAN WALLIS: You're doubling the
MR. KRESS: That's right, you're doubling
the probable dose, that's right.
MR. HARRISON: I just wanted to make sure
we were on the same page there. And I agree with you,
it's the -- that would be an issue there. For doing
it again, the reg guide -- I wasn't here when it was
written but it was written with the idea it seems
like, that it's on a per plant or a per unit basis.
All the wording seems to go that way.
MR. KRESS: Now, suppose a plant came in
with a power uprate request, clearly that would put
them in the wrong range, but at the same time, they
said, "Okay, we're going to do this and this and this,
make these other changes to the plant", and that
actually pulled them back out.
MR. HARRISON: Right. That would be
MR. KRESS: Is that all right with you?
MR. HARRISON: Yeah, yeah. Like I said
earlier, if Brunswick would make a solid commitment to
make the mod to the SLC system that changes its
success criteria to, you know, one pump success, that
-- the uprate effects the K heat, it's primarily
effecting the upper air actions in a ATWS. If you fix
the SLC system, ATWS falls of the table.
MR. KRESS: Sure.
MR. HARRISON: At that point, you're
making the plant safer by doing that. I'm not going
to -- I'll cut back on my RAIs, I promise.
MR. KRESS: But then should you make it a
condition for the uprate?
MR. HARRISON: If you were in a situation
where you're trading off and you need the trade-off,
yes, if you need it. What I did in this review
because I wasn't sure where CP&L was going to be at
the end of the process, my review for the most part
does not reflect any mods to the SLC system. It still
assumes that it's a two out of two pump success.
MR. KRESS: Where do uncertainties enter
into this analysis on your -- say there are
uncertainties on the LERF?
MR. HARRISON: Well, again, I would say
that when you get close to the boundaries --
MR. KRESS: You didn't think about
MR. HARRISON: For this one, I don't go
down that route unless I feel like I'm getting close
to a boundary. Again, the example I would use would
be Arkansas, where we were not only at the boundary
but we kind of went a little bit on the other side of
it and at that point, it's like how much confidence do
we really have in what they're doing and how much
confidence do we have in their conservatisms to back
-- to have confidence that we really aren't going to
be over that line.
MR. KRESS: Do you have a simple way or
rule of thumb to go back to the actual site now and
look at the wind rows and the population and density
and distribution and say, "Oh, well, I could guess the
LERF is going to change so much"?
MR. HARRISON: No, no, I --
MR. KRESS: You'd have to do the Level 3.
MR. HARRISON: You'd have to the Level 3.
MR. KRESS: You don't have any rules of
MR. HARRISON: Right, at least I'm not --
it's been a long time since I've done a dose
calculation and for me, you're in the Level 3 space
and we've only got a few plants out there doing Level
MR. KRESS: I think the combination of the
wind direction and where the population is distributed
within that region where you calculate the LERF could
make a difference.
MR. HARRISON: Right.
MR. KRESS: And it's probably an easy
calculation to --
MR. HARRISON: And you could use some --
MR. KRESS: You could ratio the --
MR. HARRISON: And you could use some
common sense. I would say, you know, a plant down
around Brunswick is probably a better plant than one
near a large population.
MR. KRESS: That would be nice if the
wind's blowing out to the ocean.
MR. HARRISON: Unless it's hurricane
MR. KRESS: Well, we don't get those.
CHAIRMAN WALLIS: Then disbursal is pretty
MR. KRESS: Yeah, hurricanes are good for
CHAIRMAN WALLIS: Are you going to finish
by 3:00 o'clock?
MR. LEITCH: I'm sorry, I'll quit. You
were asking me the questions. I just wanted to get my
MR. HARRISON: Yeah.
MR. KRESS: There are some things that
need to be thought about.
MR. HARRISON: Right. And I've heard you.
I hope -- Michael, you've heard him, right? Okay.
I've just thrown up on this slide, this is just the
bottom line result. Internal events, I've put
everything up here for their worst case sensitivity
results. They did some sensitivity studies. That's
another way of addressing some of the uncertainty, by
And really the driver for the worst case
is they increased their turbine trip frequency by
about 10 percent and ran that through and that
resulted in about a seven percent increase in CDF and
I forget what the percent increase was for LERF, but
this gives the numbers. For external events, there's
a fire number. There's a high wind number 4 times
10-6, and that's not changed by the EPU. It's just
what it was.
MR. KRESS: I know we're pressed for time
but let me ask you one more question before you leave
this slide. The conditional containment failure
probability for late failures for these Mark Is
generally run around .8?
MR. HARRISON: Uh-huh, it wouldn't
surprise me, yeah, okay.
MR. KRESS: It makes me worry about land
contamination and latent effects and --
MR. HARRISON: That's something I didn't
even look at.
MR. KRESS: I just wondered if you'd even
thing about it in terms of, you know, we look at LERF
and CDF, that's it, but here I'd have a problem. I'd
be worried about late containment failures and does
the uprate effect the late containment, the
probability and the conditional late containment
MR. HARRISON: Yeah, I -- most of the Mark
I values even at early containment failure is like a
.5 or you know, you get those high numbers, .1, .5, is
done very conservatively. I don't know if that's
really the real value of the --
MR. KRESS: Anyway, .8 something is
already close to 1.
MR. HARRISON: You might as well -- right.
MR. KRESS: It's the CD that saves you
MR. HARRISON: Right, right.
MR. KRESS: But anyway, it seems to me
like that ought to be something, well, anyway, when we
redo 1.174, we might ought to think more about late
containment failure as well --
MR. SIEBER: That's sort of a safety goal
policy issue, is it not, because it's certainly not a
LERF or addresses itself to protecting the public.
MR. KRESS: Well, in my mind it could be
a long term latent condition. It could also be land
MR. SIEBER: But I think you need another
term to describe that --
MR. KRESS: Oh, yeah.
MR. SIEBER: -- and another safety goal to
say what's acceptable and what isn't.
MR. KRESS: Yeah, yeah, I don't think we
have a safety goal that deals with it.
MR. SIEBER: I don't think you have the
tools, nor do you have the goal.
MR. HARRISON: Again, yeah, the only way
to get there is to do the Level 2 -- Level 3 analysis.
MR. KRESS: Yeah, it comes right out of
MAX but you could use a surrogate for it just as well
as you do a LERF. You'd have a LERF of even a late
containment surrogate, but if you have the tools, you
can do it with MAX.
MR. SIEBER: You don't have the policy.
MR. KRESS: You don't have the policy,
MR. HARRISON: Okay, and just my bottom
line, nothing -- we didn't identify anything that
would make us question adequate protection and again,
so we don't have anything that throws us into that
If we go to the next slide, I just want to
make these observations. At the Arkansas full
committee, we were questioning about HRA methodologies
and one of the suggestions that I think in a
conversation between Dr. Kress and the full committee
chairman, Dr. Apostolakis, one of the ideas was why
don't you just bound the HRA analysis and spit out an
answer? Well, that's pretty close to what Brunswick
And the problem you get is you can't
calculate a delta then or one that you truly know is
the right margin. So Brunswick recalculated the --
basically it's really one operator action. It just
has four conditions on it, it's power level control
and there are a whole bunch of operator actions that
we expected to see impacted that weren't and it's
because they were all covered by the way they did a
conservative timing for the operator action.
Therefore, when they did the MAAP runs to
find out what the time was for those operator actions,
they were already bounded. And the net result is you
get a very small delta of one and a half percent delta
risk increase when you know it's not. You know it's
more than that.
MR. KRESS: You know it's something more
MR. HARRISON: Right. Now, the reason
that's not an adequate protecture question is because
it's changing the delta but you know the base is
bounded. So what this would really do, to do it
correctly, you'd have to do the current plant
condition, that would lower that number. The power
uprate plant may actually come down just a little bit
but that would give you the real delta, but I just
wanted to put that up there just to make a point of
what can happen.
The other thing I wanted to make a point
of is, the NESC, we're included a statement to make it
clearer. There was a question of we could be
misleading the public and thinking that we're
approving methodologies, HRS methodologies and we've
added a statement to the SE to make it clear that
these methodologies have not been formally reviewed
and approved. That they're common used, widely used
by the petitions and it's the current state of the
art, but it's not something that we've actually
officially recognize as the method to use?
But it can be used. It can give you a
relative feel for the importance of actions and
importance of changes and those actions.
MR. KRESS: Do you know if they had a risk
informed submittal. Or the major changes were due to
human errors, would you feel like you'd have to go and
MR. HARRISON: Sadly, that's what Arkansas
did and it's -- if it was risk informed, I would have
sent them to look at what Arkansas had which is go
back and recalculate your human error probabilities
based on your current condition using your MAAP code.
Make those runs, figure out what those should have
been, then calculate what they will be and give me the
But this is really not a slide necessarily
for Brunswick as much as it is just to address the
questions from before. And really, that's all I have.
MR. KRESS: Appreciate it, thank you.
MS. MOZAFARI: And now Richard Lobel from
the plant systems branch to discuss the containment
MR. LOBEL: Good afternoon. My name is
Richard Lobel. I'm with the plant systems branch and
I would like to talk about the review we did of the
Brunswick containment and other balance plant systems
for power uprate. The -- we didn't find anything
extraordinary in this review. There were no special
issues raised and no tech spec changes for the plant
and the trends were as we expected.
These are -- the next two slides are the
systems that we looked at. You've seen these slides
before, for plant systems. Main steam isolation
valves are evaluated by a generic evaluation in the GE
methods. The RHR suppression pool cooling and
containment spray cooling I'll talk about a little
later as well as the fuel pool cooling.
Containment system performance and NPSH
I'll talk about a little later. Combustible gas
control, the existing nitrogen suppose was found to
still be adequate and the CAD system for uprated
power. There was no significant change in the
conditions for the main control room atmospheric
control system. The standby gas treatment system, the
draw-down time hasn't changed and the loading actually
goes down with the alternate source term.
Spent fuel pool cooling, as we've
discussed before, there wasn't a big effect from the
power uprate. Service water, component cooling water
MR. LEITCH: Richard, could we just touch
a minute on the standby gas treatment system.
MR. LOBEL: Sure.
MR. LEITCH: You said the loading goes
down. I mean, I would picture that the loading on the
standby gas treatment system would be -- the iodine
level would be proportional to power and that the
higher power level you would have more iodine
production and would therefore, increase the loading
in the standby gas treatment system.
MR. LOBEL: Maybe somebody else can
address it in terms of the loading. We don't look at
it in terms of how -- of the amount that's there. We
look at it in terms of heating of the filters and the
draw-down, the more mechanical parts of the system.
I don't know if there's anybody -- is there anybody
else here to address that?
MR. GRANTHAM: This is Mark Grantham,
CP&L. I think the loading went down as a result of
implementation of alternate source term which was a
separate submittal from this. So we went from the --
to the new methodology and that's what drove the
loading down. So it's actually a result of
methodology change and not due to an increase in
MR. LEITCH: Okay, that would make sense,
yeah, okay, thanks.
MR. LOBEL: And there were no significant
changes to the power dependent HVAC systems, liquid
and gaseous waste or the high energy line breaks since
the pressure didn't change. Next slide, please.
Okay, the containment system performance
was analyzed for the power uprate using General
Electric Codes M3CPT for the short term response.
LAMB code was used for the blow-down analysis rather
than the M3CPT code and Super Hex was used for the
long term response. M2CPT and Super Hex were already
in the Brunswick licensing basis. LAMB was added in
order to give the licensee more flexibility in
analyzing a wider range of conditions.
We did not perform an audit calculation
for Brunswick since we had previously performed one
for Mark I and had gotten good agreement with the GE
methods. This table is just to provide some
information about some of the changes that were made
in conditions for the power uprate analysis. The
service water temperature used was raised to the
technical specification limit at 92 degrees.
The licensee assumed spent -- assumed RHR
pool cooling rather than containment spray cooling for
the suppression pool and that's conservative. It adds
a little bit to the temperature. The decay heat value
was upgraded from the nominal value to the nominal
plus the two sigma for the same correlation and also
some changes were made in terms of the longer burn-up
was used in the calculation of the decay heat and some
additional isotopes were considered.
DR. SCHROCK; Can I ask about this LAMB
code. It was mentioned earlier that it was based on
MR. BOEHNERT: Virgil, do you want to get
the microphone there. They can't hear you.
DR. SCHROCK: Are you familiar with --
MR. LOBEL: The LAMB code is in Appendix
K, ACCS code but it's also used by GE for performing
the blow-down in some cases for the mass and energy
release in the containment. It provides them with a
little more flexibility in the conditions that they
can analyze since the M3CPT model for blow-down is
fairly simple. And it does -- yeah, they said they
used the Moody correlation because that's the Appendix
DR. SCHROCK: Which is generally
considered to be conservative from the standpoint of
analysis of the primary system which means what, it
blows down more slowly. From the standpoint of
containment, that's puts him to be non-conservative.
MR. LOBEL: No, I think it's the other
DR. SCHROCK: The other way?
MR. LOBEL: Yeah, the Moody correlation,
in terms of ACCS, it gives you a faster depletion of
the inventory vessel because it is a rapid discharge
and that's conservative also for containment.
DR. SCHROCK: Okay, thank you.
MR. LOBEL: Okay. The next table I
thought would just be interesting. Some of this was
shown this morning by the licensee and the only point
that I wanted to make by showing the table was the
licensee did calculations using the same methods for
the current rate of thermal power and for the extended
power uprate. So it gives you a chance to look at a
change due purely to the increase in power for the
drywell peak pressure, drywell peak temperature, the
bulk pool temperature and the wetwell pressure.
And also you can see the limits but
there's still considerable margin to the design
limits. The next slide. For the NPSH of the ECCS
pumps, the licensee hadn't previously taken credit for
containment over-pressure but with the power uprate,
it became necessary to take some credit. This was
discussed by the licensee this morning, too and maybe
the only point to make now is I tried to show in this
table a little bit of sensitivity studies that went
into the calculation.
When the -- the two important parameters
in terms of the containment are the wetwell
temperature and the wetwell pressure for determining
NPSH of the ECCS pumps and when the calculation was
done with containment spray providing the cooling, the
pressure was fairly high and the temperature was --
I'm sorry, let me start over.
Without containment spray, with just bulk
cooling of the suppression pool water the pressure was
fairly high and the bulk temperature was high.
Assuming containment spray, which was done for the
actual calculations for Brunswick, the pressure,
calculated pressure is much lower, 11.3 psig, but
there wasn't much of a change in the calculated
temperature and, in fact, like the licensee said this
morning, they actually increased the temperature up to
the same value that they calculated without the spray.
So the point is just that the licensee
selected a conservative set of conditions and for the
case of NPSH conservatively low pressure and high
temperature. For the spent fuel pool cooling, the
spent fuel system consists of two independent spent
fuel pooling trains, one pump and one heat exchanger
each. The heat is transferred to the reactor building
closed cooling water system. The RHS system can serve
as a backup which may be needed for situations like --
abnormal situations like the full core off-load and
Brunswick also has a supplement spent fuel pool
cooling system as a backup to the RHR spent fuel
The analysis was done with a surface water
temperature of 95 degrees and in all cases the
temperature was less than the limit of 150 degrees
although it was fairly close. And in conclusion, the
licensee in the area of the balance of plant and
containment systems complied with the NRC regulations
and the guidance on EPU conditions.
MR. BANERJEE: I'd just ask you a
question. Are you going to talk at all about the fire
MR. BOEHNERT: Sanjay, get close to the
MR. BANERJEE: -- because whoever is the
right person, I want to ask the question.
MR. LOBEL: It definitely isn't me. I
don't know if we have anybody here.
MR. BANERJEE: Because there is an aspect
which I'd like to find something out about. It's part
of your --
MR. SIEBER: It's SER and if you look on
page 73, Section 6.
MR. LOBEL: We can try to get somebody
over here to answer your questions but I had nothing
to do with the fire protection side.
MR. BANERJEE: Well, it's part of the
systems and facilities or whatever.
MR. LOBEL: Yeah.
A VOICE: A big increase in PCT then.
MR. BANERJEE: Yeah, what happens there is
the PCT goes very close to the limit.
MR. CARUSO: Mr. Chairman, why don't we
try to get the right fire protection engineer over for
you. John Hanon is the branch chief and he's just
going to give him a call and see if we can do this
either in this session or whatever you'd like to do.
MR. BANERJEE: Well, the issue really is
related to what happens to peak clad temperature.
MR. CARUSO: Okay, fire protection, peak
MR. SIEBER: The Appendix R, peak clad
temperature maximum is 1500 compared to the LOCA
maximum which is 2200. That's the issue. I think the
numbers come out for safe shutdown the same as the
LOCA response. As far as containment performance,
peak clad temperature --
MR. LOBEL: I can speak to that a little.
MR. SIEBER: Okay.
MR. LOBEL: The 1500 degrees is usually a
temperature that's used for the cladding when you
don't want any damage or excessive oxidation to the
cladding. It's typically thought of as the
temperature at which the cladding reaction starts to
increase significantly expedentially. The 2200 degree
temperature in the ECCS, the basis of that is
maintaining a coolable geometry, so you can have
failure of the cladding and in fact, the dose
calculations that are done for a LOCA assume that the
fuel has all failed.
But I think that's the basic difference
between the numbers.
MR. BANERJEE: Yes, but I mean, the
current RTP has a peal clad temperature of less than
1200 and with the EPU it was close to 1500. So
there's a big difference there. And --
MR. LOBEL: Yeah, I can't explain why the
MR. BANERJEE: Yeah, first why and then
the SCR or whatever it is --
MR. CARUSO: Okay.
MR. BANERJEE: It's below the design limit
but it's very close and you know, I'd like to --
MR. CARUSO: Okay, the gentleman's name
who is the fire protection reviewer is Ed Connell and
he is not here today but we will get the question to
him and get an answer to you. It will be whatever
you'd like it, in writing or phone call, whatever
MR. BANERJEE: Okay, it's on page 73 of
your SER and it's on page 617 of the NEDC 33039P.
MR. CARUSO: Well, all right, that's fine.
Is there any GE persons who can address the question
directly? We can also have the staff confirm the
CHAIRMAN WALLIS: I'd like to know the
result of this --
MR. BOEHNERT: Will do, the staff, will
CHAIRMAN WALLIS: -- response as well.
MR. PAPPOANE: This is Dan Pappoane. With
regards to the change in PCT for the Appendix R, the
Appendix R is similar to a small break LOCA. So we do
see -- we do see an increase in the PCT because we are
dealing with more decay heat and more steam that we
have to vent to depressurize the vessel.
The thing that I don't know right off the
top of my head, when we do an Appendix R analysis,
there is a certain number of relief valves that we can
take credit for in that analysis. Usually we're not
using the full -- okay, we use three relief valves
instead of the full ADS complement or six or seven.
And with the smaller number of relief valves, that
accentuates the effect of the power because we're
using a smaller area to depressurize the vessel.
So we'll see a bigger change in the PCT
bit of the power change.
MR. SIEBER: Why do you use a smaller
number of valves? Is that --
MR. PAPPOANE: That's the number of valves
that they'll protect for the remote shutdown.
MR. SIEBER: So an Appendix R issue.
MR. PAPPOANE: Right.
MR. SIEBER: Okay.
MR. PAPPOANE: Right, it's an Appendix R
issue but we are seeing that power and the effect of
that power increase.
MR. BANERJEE: Right, it's just that the
number changes very lot, almost 300 degrees.
MR. PAPPOANE: Yeah, and that's in line
with what we've seen in some of the previous uprates.
When we have less relief valve capacity, one way or
another, either smaller valves or smaller number of
valves, the effect of the uprate goes up. The PCT
delta goes up.
MR. FLADOS: Paul Flados again. Another
big impact on the Appendix R is this event that had
the peak clad temperature is the one where we delay
any operator actions until they can get staged out
into the power block. There's a big impact on this
calculation in that with the extra decay heat in the
same amount of time, by the time he gets there ready
to do it, vessel level is a lot lower than it used to
be. As a matter of fact, top of core is already
uncovered by the time he starts depressurization.
The EPU effect on Appendix R is very
significant and it's one of the things that could
cross over a threshold if a utility does have a delay
that corresponds to boiling too far down on the vessel
level before he can get out there his remote shut down
MR. SIEBER: But the solution to that
would be to protect another valve as far as Appendix
R is concerned.
MR. FLADOS: If you uncover too much fuel
before he gets out there, the number of valves isn't
going to help you as much as doing something to
otherwise get out there faster or protect the vessel
level before he gets there.
MR. SIEBER: So it would be better to buy
him roller skates.
MR. CARUSO: Yeah, these valves are
normally divisionalized too, and you may have a train
that's protected, a whole train that may be protected
and to decide to protect another train is a major
issue. You may have to put barriers and other
sprinkler systems, et cetera, just to gain one or two
more valves. So -- and the whole alternate shutdown
technique is because of how many trains you can
But let me get the staff's answer to the
question, too, just to make sure we're on the same
wave length as GE. Okay.
MR. SIEBER: I'd like to have a copy of
MR. BOEHNERT: Yeah, why don't you have
him send it to --
CHAIRMAN WALLIS: Okay, I'll send it to
MR. BOEHNERT: Send it to me, yeah.
CHAIRMAN WALLIS: And it better be quick
because we're going to receive -- I think this is
going to the full committee next week.
MR. BOEHNERT: That's correct.
MR. CARUSO: Okay, John, can you support
MR. ULSES: Yeah. Yes, the reviewer is
actually working at home today, so we should be able
to get it by close of business today.
MR. CARUSO: Great, thank you. Super,
CHAIRMAN WALLIS: I had a question earlier
about this SRV discharge being ingested into the ECCS
suction and I was told I'd get my answer this
afternoon. Are you the one who's going to give me the
MR. LOBEL: Well, I can -- we did ask the
question and we have an answer. It was a response to
a question 1-4 on an October 17th, 2001 letter.
CHAIRMAN WALLIS: Yeah, I remember that.
MR. SIEBER: It basically --
CHAIRMAN WALLIS: I read that in the SEC.
MR. LOBEL: Okay, it was pretty much
repeated in the SEC and we did not do any further
review of that.
CHAIRMAN WALLIS: You asked a question and
the licensee indicated that they had performed an
MR. LOBEL: Yes.
CHAIRMAN WALLIS: And they said something
about bubbles and so on and so on and so on. And then
you concluded it was all right. Well, how do we know
that that evaluation was any good?
MR. LOBEL: We did not review the --
CHAIRMAN WALLIS: So we're just taking the
word for the licensee that they did a proper technical
evaluation and --
MR. LOBEL: In this case, yes. I don't
have any more to add.
MR. CARUSO: Okay, Brenda, do you want to
summarize for us, please?
MS. MOZAFARI: So just our last slide
summarizes that the analyses are based on NRC approved
analytical methods and codes. Onsite audits confirmed
the compliance to staff approved methodology. The EPU
SAR is consistent with NRC accepted guidelines and
generic evaluations. Thermal limits and applicable
safety analyses would be re-analyzed or re-confirmed
using NRC approved core reload analyses methodology.
Now, you did have on your agenda that you
had some issues in some other areas. Are there any
other areas that you want the staff to elaborate on?
We have the staff members available if there are any
other particular issues.
MR. LEITCH: I just harken back to the
Maine Yankee situation where there was evidently a
controversy about the peak cladding temperature and
the code that was used to determine that and the first
bullet on your slide there, I guess, what you're
saying is you're confirming that for the whole
spectrum of LOCAs, the peak cladding temperature has
been calculated using NRS approved codes and found to
be less than 2200 degrees.
MS. MOZAFARI: That's correct.
MR. LEITCH: Okay.
MS. MOZAFARI: Were there any other
CHAIRMAN WALLIS: Any other issues?
MR. CARUSO: We do have the take-away on
fire protection. We're going to get an answer on
MS. MOZAFARI: Right, we're going to get
MR. CARUSO: And we heard some
discussions, too, about the number of RAIs in general,
and what I'd like to do for the subcommittee, the full
committee, whatever you'd like is fill you in, in
terms of the plan for the standard review plan and the
plan for improving the efficiency, including looking
at the RAIs, whether there's duplicate RAIs, how we
can improve our efficiency in terms of that. So
that's a take-away that I'll bring back to you.
We're due to go back to the Commission for
the Commission paper the end of June, June 26th, okay,
so we'll probably be talking back with you before that
CHAIRMAN WALLIS: So it looks as though we
are through with the staff presentation.
MS. MOZAFARI: Right, and Herb Berkow
would like to give some closing remarks for our staff.
MR. BERKOW: I want to thank you for your
time and for the opportunity for us to present the
results of our Brunswick extended power uprate review.
The results of the staff's review, as Brenda pointed
out, show that the proposed power increase meets the
regulatory requirements and therefore, it's acceptable
and we recommend approval of this power uprate.
This concludes our presentation and I
guess there are no other questions and if there are,
we'd be happy to answer them.
CHAIRMAN WALLIS: Well, the question we
have to address is whether or not this is a mature
enough situation for it to go to the full committee
next week. I think that's what's on the schedule.
MR. SIEBER: That's right.
CHAIRMAN WALLIS: Is that your
MR. BOEHNERT: The morning of May 2nd.
CHAIRMAN WALLIS: Yes, May 2nd. And does
the committee disagree with me that this is ready for
next week's presentation?
MR. KRESS: I think it's ready.
MR. SIEBER: I think it is.
MR. LEITCH: I agree.
CHAIRMAN WALLIS: So it is okay to go
ahead next week. Then maybe we should talk a bit
about what's to be said next week. The licensee has
less time next week?
MR. BOEHNERT: We have a total time of two
hours for everything.
CHAIRMAN WALLIS: A lot less time next
week to put across your case.
MR. KITCHEN: Certainly, we can arrange
CHAIRMAN WALLIS: Again, just speaking for
myself, I think we need your overview. That's
important. The core considerations are important.
There are some important issues covered there and my
impression is the reactor vessel cracking and
embrittlement could be covered fairly rapidly and also
the containment response. We probably don't need to
spend a lot of time on electrical system and piping
There isn't much about operation --
operator actions and training. It just sounded as if
there's nothing much new there, not much of a testing
program. So you should be able to do it in the time
available, I think if you hit the main points. It's
very much like what we've heard from other plants, so
the full committee should be familiar with that, this
sort of a power uprate.
MR. KITCHEN: Yes, sir, the areas that you
don't want as much discussion do we eliminate those or
do we need to cover all the areas that we covered
CHAIRMAN WALLIS: Well, you might put them
on -- have a least a bullet saying, this has been
covered. I don't think you need to go into the
details unless asked. You never know what the full
committee is going to ask you.
MR. BOEHNERT: Do you want them to talk
about PRA at all?
MR. KRESS: I think you'd better talk
about the PRA but it went pretty fast. You can make
it pretty fast, you know, just almost bottom line
CHAIRMAN WALLIS: I think the bottom line
is important and the fact that the only thing that
really seemed to matter were changes in time operators
had to make decisions.
MR. KRESS: I think it's very important
that you cover the SLC changes.
CHAIRMAN WALLIS: Yes.
MR. LEITCH: I think it might also be
appropriate to discuss the justification for not doing
the large scale tests.
MR. KRESS: The large transient testing
because that will come up.
CHAIRMAN WALLIS: It will be the same
argument that we had before.
MR. KRESS: It will be the same, but it
will come up, so you ought to be prepared.
CHAIRMAN WALLIS: Anything else from the
MR. BOEHNERT: What about the staff?
CHAIRMAN WALLIS: We're going to get to
MR. LEITCH: I'm still a little -- not a
little confused but I think it bears some discussion
about the operation what I guess we're calling Phase
1, that is what is going to be the status during the
first cycle when only certain physical changes have
been made, yet the license is approved up to 120
percent but the plant is not physically capable of
MR. KITCHEN: So you would want an
expanded description of the plant controls and
mechanisms in place to operate the plant with a
reactor limit above our balance plant capability.
MR. LEITCH: Yeah, I don't think we need
anything expanded from what we heard today but I think
that is an area that initially was somewhat confusing
and I think we could just sharpen that area up a
MR. KITCHEN: Okay.
MR. SIEBER: Well, the thing that's
limiting there I think is the turbine. If you're wide
open, that's all you're going to get, right?
MR. LEITCH: Well, I don't think so.
You've put in the new turbine, right. The new turbine
is part of Phase 1.
MR. KITCHEN: Yes, that's correct. That's
been installed but we could --
MR. SIEBER: You need pumping, feedwater.
MR. LEITCH: I think you're more limited
by the transformer capability and by the ability of
the condensate feedwater system to pump enough water.
MR. KITCHEN: We can make that portion of
the presentation clearer as far as how we're
controlling the plant and what actions were put in
place to do that.
MR. LEITCH: I think that would be
helpful, yes, thank you.
MR. KRESS: One of your slides had
referred to a 70 megawatt base per metric ton burn-up.
That's going to raise the eyebrows of at least one of
the members and I'd be prepared to discuss it in
further detail in case a question comes up and the
detail would be how much of the core is actually at
MR. BANERJEE: There was very little
discussion, I don't know if this is the forum for it,
of fuel performance and fuel behavior because of this
high burnout and also you know --
MR. KRESS: Yeah, that would be the nature
MR. BANERJEE: So that would be something
that is missing here and I don't know if there's
enough of a experience base here to talk about it.
MR. SIEBER: Well, the average discharge
burn-up is 50 --
MR. BANERJEE: This is like 40 or 50 or
MR. SIEBER: 40 to 50.
MR. KRESS: So, you know, if they could --
that didn't come out until we asked the question.
MR. SIEBER: Yeah, well, that's where they
should start, starting at 70 and saying --
MR. KRESS: Yeah, they should clarify what
does 70 -- they should clarify what does 70 mean.
MR. SIEBER: Yeah.
CHAIRMAN WALLIS: Are we ready to move
onto the staff presentation? My impression was that
the written report gives the impression that a great
deal was done and that the bases were all covered,
although in some cases we have to take something on
trust that, yes, indeed, the licensee did do good
I think in your oral presentation, it has
to come across better than it did today that you folks
really are on top of things and you don't have to turn
to the licensee to get answers to questions and
there's more certainty somehow in your presentation.
Any colleagues want to wade in on this matter?
MR. BOEHNERT: Do you want to give them
direction on what topics?
CHAIRMAN WALLIS: Well, we had asked in
the past and you responded a bit this time to which
parts of the review gave you some trouble or did you
really have to think about and that didn't really go
very far it seemed to me. Maybe there weren't any.
I got the impression there really weren't any. Maybe
that's the way it is. Maybe that's all you need to
say, unless there was something really interesting
that you had to pursue and resolve. That would be a
good story to tell there. The SLC you need to be a
bit more clear about.
MR. SIEBER: Well, I was wondering about
that. Is the licensee committed to the changes and if
they aren't, you know, even though it's been discussed
in the SER, they aren't committed to, you know, super
Boron and all of that, then I'm not sure we ought to
give credit for it because they may not do it.
MR. POST: This is Jason Post with GE. I
talked to Dr. Kress in the restroom a little while ago
about this. When we did that ATWS analysis -- that
doesn't have to be on the record, I guess. When we
did the ATWS analysis, we used 86 gpm equivalent,
okay. And so when the reload requires them to make a
change to increase the boron so they have more
shutdown margin. It will be made such that they
maintain a minimum of the 86 gpm equivalent.
So the ATWS analysis remains applicable as
long as whatever change meets the ATWS rule
requirements, which, of course, it will.
MR. CARUSO: We'll talk about SLC and ATWS
and challenges that we had in those reviews. Are
there any other areas that were challenging that you
want to bring up? Okay, we'll present those two.
We'll highlight the challenges that we had and how we
CHAIRMAN WALLIS: And maybe we'll be able
to write a short letter.
MR. CARUSO: Great, short and sweet.
CHAIRMAN WALLIS: So is there anything
else we need to do today? Am I ready to adjourn is
the right word?
MR. KITCHEN: This is Bob Kitchen. I have
two things. The targeted time for the presentations
next week should be about an hour?
MR. BOEHNERT: Yeah, I'll get with you,
Bob, but yeah, basically there's a total of two hours.
I think with introductions and that, you guys will
have close to -- well, yeah, close to an hour and give
the staff the remaining time, maybe 45 minutes or
something like that. That's just off the top of my
head, but I'll sit down and think about it. I'll get
back to both of you guys and let you know, but on that
And you should plan on -- we try to keep
it 50 percent presentation time and 50 percent time
for questions but that's going to be tough, given what
we're handing you. But anyway, I'll get back with you
on this, give you the details.
MR. KITCHEN: Okay.
MR. BANERJEE: There's one thing. They
will provide some information about the feedwater
CHAIRMAN WALLIS: That's right, you'd
asked for that. Yeah.
MR. KITCHEN: We can discuss that a little
bit right now if you'd like.
CHAIRMAN WALLIS: You're ready for that
MR. KITCHEN: Yeah.
CHAIRMAN WALLIS: Okay.
MR. PAPPOANE: This is Dan Pappoane again.
I just went through a crash course in annulus
pressurization and the like that I guess what you're
after, the bad news is we don't have a direct one-to-
one comparison for feedwater line break. The original
analysis or the current power analysis was done with
a fairly high feedwater pressure that was assumed of
1475 and what we did for the extended uprate was that
creativity that Ralph was talking about, we're using
the actual feedwater system pressure at the uprate
conditions, as the extended uprate conditions.
And that's 1210, so for the piping outside
of the containment, that's primarily driven by that
pumping pressure and that's what gives us the relief
to get fit under the current design loads for the
MR. BANERJEE: And what was done
originally? Did you look at the --
MR. BOEHNERT: Talk into the mike.
CHAIRMAN WALLIS: Speak into the mike.
MR. BOEHNERT: They can't hear you.
MR. BANERJEE: What did you do originally
when you did the calculations at higher pressure?
MR. PAPPOANE: Well, when they're doing
those calculations outside the containment, they're
looking at the room pressurization and flooding and
they're also looking at pipe width and jet impingement
and make sure the forces don't take out any safety
systems. So those were all based on the -- on that
We've got an enveloping analysis and did
pencil sharpening with this extended uprate to fit in
that envelope by using the actual system pressure
instead of very high bounding pressure and then --
MR. BANERJEE: Did you look at the force
imbalances on the reactor internals?
MR. PAPPOANE: Yeah, that's the next part.
We can go inside the containment. Inside the
containment we look at what happens to the reactor
vessel, what happens to the internals, also look at
what happens to the reactor shield wall, because when
we're looking at the pipe break inside the
containment, we're assuming the break is at the safe
end which is usually just inside the wall or actually
within the wall itself, in the shield wall itself.
So we're looking at pressurized in that
space and again, we're looking at the pipe width and
the jet impingement loads. The reactor side of that
is driven by the vessel pressure and for this uprate
this hasn't changed. So that side of the forcing
function is staying the same.
Now, for the pumping side, the feedwater
pumping side, again, we're looking at the high
pressure for the current -- or for the original
analysis and using the actual pressure for the lower
-- for the extended uprate analysis and also did a
little bit of fine tuning on calculating what the two
phase flow out of the pump side of the pipe would be
because we're doing to be seeing some depressurization
in there and some flashing of pipe, so that's going to
restrict the flow. And so that contribution -- the
vessel site, what's coming into that annulus, the
vessel side is staying the same. What's coming in
with the fine tune calculation, is just fitting under
the original design value.
So the overall design envelope for the
loads has stayed the same. And then look at the
energy content in there, we are getting a little bit
higher flow initially. We have lower feedwater
temperature but a higher flow rate so the initial
energy that's being deposited in that annulus goes up
but about three percent. And we looked at that as far
as the -- as far as the forces on the shield wall and
there's a lot of margin on the shield wall. I didn't
fine it off-hand here but ones that I've looked at in
the past, the forces have been -- the pressure forces
have been down in the 25 to 50 percent range of what
the shield wall design forces were.
So there was a lot of margin to the
MR. BANERJEE: Did you take the pressure
wave going into account bouncing off the breaks? Is
it a sudden guillotine break you're looking at?
MR. PAPPOANE: Yes, it's a sudden
guillotine break. I don't have the analysis for the
annulus pressure calculation but there they are
looking at that pressure wave going out around the
MR. BANERJEE: Do you have this available,
could be available?
MR. PAPPOANE: We have to see what they
have, what they can bring next week for that when we
get into that kind of detail.
MR. BANERJEE: Well, I'd just be
interested to know more about this problem so that I
understand what implication it may have. Were it be
ready for the ACRS meeting, I don't know because I
have encountered this problem with another BWR in some
other country, that problem.
MR. PAPPOANE: Yeah, we do look at that
acoustic loading for the circulation line break, which
is a bigger break.
CHAIRMAN WALLIS: Okay. I'll ask the
consultants to get --
DR. SCHROCK: Send a report.
CHAIRMAN WALLIS: -- a report to me right
away because I have to write a letter.
DR. SCHROCK: Very promptly as usual.
CHAIRMAN WALLIS: And I'm ready to adjourn
the meeting and will do so.
(Whereupon, at 3:38 p.m. the meeting of
the subcommittee was concluded.)