Thermal-Hydraulic Phenomena - October 25, 2001
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: Thursday, October 25, 2001
Work Order No.: NRC-082 Pages 1-224
NEAL R. GROSS AND CO., INC.
Court Reporters and Transcribers
1323 Rhode Island Avenue, N.W.
Washington, D.C. 20005
(202) 234-4433 UNITED STATES OF AMERICA
NUCLEAR REGULATORY COMMISSION
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ADVISORY COMMITTEE ON REACTOR SAFEGUARDS
THERMAL-HYDRAULIC PHENOMENA SUBCOMMITTEE MEETING
(ACRS)
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THURSDAY
OCTOBER 25, 2001
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ROCKVILLE, MARYLAND
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The ACRS Thermal Phenomena Subcommittee
met at the Nuclear Regulatory Commission, Two White
Flint North, Room T2B3, 11545 Rockville Pike, at 1:00
p.m., Dr. Graham Wallis, Chairman,
presiding.
COMMITTEE MEMBERS PRESENT:
DR. GRAHAM WALLIS, Chairman
DR. F. PETER FORD, Member
DR. THOMAS S. KRESS, Member
DR. WILLIAM SHACK, Member
DR. VIRGIL SCHROCK, ACRS Consultant
DR. JOHN D. SIEBER, Member
ACRS STAFF PRESENT:
PAUL A. BOEHNERT, ACRS Staff Engineer
I-N-D-E-X
AGENDA ITEM PAGE
Introduction by Chairman Graham 4
Dresden/Quad Cities Power Uprates 6
Presentation
P-R-O-C-E-E-D-I-N-G-S
(1:00 p.m.)
CHAIRMAN WALLIS: The meeting will now
please come to order. This is a meeting of the ACRS
Subcommittee on Thermal-Hydraulic Phenomena. I am
Graham Wallis, Chairman of the Subcommittee.
Other ACRS Members in attendance are Peter
Ford, Thomas Kress, William Shack, and Jack Sieber.
The ACRS Consultant in attendance is Virgil Schrock.
The purpose of this meeting is for the
subcommittee to review the license amendment request
of the Exelon Generating Company for core power
uprates for the Dresden Nuclear Power Station, Units
2 and 3; and the Quad Cities Nuclear Power Station,
Units 1 and 2.
The subcommittee will gather information,
and analyze relevant issues and facts, and formulate
the proposed 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 October 15, 2001.
Portions of this meeting may be closed to
the public as necessary to discuss information
considered proprietary to General Electric 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 or
requests for time to make oral statements from members
of the public. I will say what I said before the last
meeting that we had on power uprates, that this
committee has received a large stack of papers, which
amounted to over two feet high.
Some of my colleagues said that was an
underestimate last time. I am really looking forward
to your help in pointing us to the elements of that
which are important for us to consider. So I will
now proceed with the meeting, and I will call upon Mr.
Bill Bohlke of the Exelon Generating Company after my
colleague, Peter Ford, makes a statement.
DR. FORD: Yes. I am a GE retiree, and
therefore I have a conflict of interest.
MR. BOHLKE: Thank you. Good afternoon,
Mr. Chairman, and Members of the ACRS. I am Bill
Bohlke, senior vice president of nuclear services for
the Exelon Corporation, and the executive sponsor for
the extended power uprate project for Dresden and Quad
Cities.
We have brought many members of our
project team who have been working on this project for
almost two years now, and that this team of engineers,
and analysts, and operators, I think is pretty well
positioned to answer the question that you may have
from reading the material and anything that comes up
from their presentation, which we hope will help
clarify and distill all of the information that you
have been asked to digest.
This is an important project for our
company. As you are already aware, Dresden and Quad
Cities are BWR-3s licensed for commercial operations
from 1969 through 1972 or '73.
Recently, we have seen significant
improvements in the reliability and safe operation of
those plants, and in addition to this extended power
uprate request, we are preparing a license renewal
application for Dresden and Quad which will be
submitted at the end of next year.
So we have got a substantial investment
going forward in these plants, and we are anxious to
tell you how we plan to integrate this uprate into our
operations, and why we believe that this uprate can be
safely and reliably achieved.
We are also aware that you just went
through similar material about a month ago on the
Duane Arnold project. There are many, many
similarities between what you heard a month ago, and
what you will hear today.
But there are also some differences,
because these are BWR3s, and a little bit older than
a Duane Arnold plant. Nevertheless, let me summarize
as I conclude what I think you are going to hear.
That we have followed the GE designed
approach for an extended power uprate described in
their EPU license topical report for a constant
pressure upgrade. That is to say, the steam dome
pressure doesn't change.
You will see that we have provided an
extensive sweep of analyses using methodology that has
been reviewed by the staff and you many times before
to analyze these plants, and in several cases these
methodologies.
We represent an upgrade from the previous
sweep of methodologies and analyses that existed for
the units, and we have benefited from that, and we
will also be able to demonstrate that the inputs to
the analyses are accurate and reasonably conservative
in addition.
The results of all of this work that we
have gone through, and the modifications which are
ensuing on Dresden 2 as we speak, because Dresden 2 is
in the outage during which the modifications required
for an extended power uprate must be implemented.
And you will see that at the end of the
day there are in fact no significant impacts on the
way that the plant responds to initiating events or
the way that the plant operates during transients.
And there are no challenges to system
integrity that are of any concern for us in an
engineering context. Near the end of the
presentation, you will hear a rather extensive review
of the risk assessment of this uprate.
And I think when you have seen what we
have done and have heard the results, you will
conclude as we have that there are minimal changes in
plant risk.
Thus, from all aspects, we believe that
the plant operation following the increase in power to
the extended level will be acceptable and safe. At
this time, pending any questions, I would like to turn
it over to our project manager for this project, Mr.
John Nosko. Thank you.
MR. NOSKO: Good afternoon. My name is
John Nosko, and I am the project manager for the
Dresden and Quad Cities extended power uprate
projects.
Our presentation this afternoon has been
constructed to generally follow the guidelines of the
agenda provided by the subcommittee. It incorporates
materials to address the questions received from the
ACRS before the meeting.
And we expect to take just over two hours,
Mr. Chairman, to cover all of the topics, which allows
time for questions from the subcommittee. We have
with us today members of our project team from Exelon,
and from General Electric, Stone & Webster, and Aaron
Engineering here, to support the presentation.
There is no proprietary information
contained in our presentation, but it may turn out
that responses to some of your questions would bring
out proprietary information. If that is the case, we
will ask to address the matters separately with you,
or in a closed session.
So looking at the agenda, we propose to
cover our compliance with regulatory issues in the
introduction and project overview. We will talk about
selected analyses and evaluations as requested by the
committee.
A separate presentation will focus on
probablistic risk analyses, and including a discussion
on open items identified in the draft safety
evaluation report.
And finally we will talk about
implementing the power uprates at the station from the
perspective of an operating license holder. Our
submittal is requesting a 17 percent increase in
license power level.
The goals of our project are to safely use
the excess capacity currently available at the
stations to increase power production levels to
leverage industry experience using a proven and
accepted methodology to minimize the impact of that
uprate on the plant by maintaining a constant reactor
dome pressure.
And to make our analyses and designs for
both stations as similar as possible to simplify
reviews and configuration management going forward.
Our submittal was prepared in accordance with the
license topical reports for extended power uprates.
They are ELTRs 1 and 2.
And it demonstrates compliance with
applicable regulations and safety limits. The
analyses that we have done consider a variety of
operating transients, postulated accidents, and
operating conditions.
We have evaluated the radiological
consequences and environmental impacts of the uprate,
as well as the effect of the uprate on station
programs.
Now, we have taken only one exception to
the license topical reports, and that is for
conducting major transient testing at uprated power
levels.
Our presentation will address why we are
taking that exception, and why we believe there is
compelling data to support that position. The
committee has also asked us to address the impact of
the extended uprate on plant margins, and our approach
this afternoon is to include that aspect in the
presentation on the specific topics.
DR. SIEBER: The large transient testing,
this is two tests, right?
MR. NOSKO: Yes, sir; MSIV closure, and
generator load --
DR. SIEBER: And maybe you could just say
a sentence or so as to why you don't want to do that,
because that is still an open item.
MR. NOSKO: Yes, sir. We have a -- if I
could ask that the question be held until a later
point in time. We do have a separate session that
deals with that directly.
DR. SIEBER: All right.
MR. NOSKO: Okay. Thank you.
DR. SCHROCK: I have a question. In
reading these documents, I find that to a very great
extent, and perhaps more than 95 percent, are verbatim
for the two plants.
And yet some numbers come out different
here and there. This is puzzling to me, and I don't
understand the reasons for these differences. I think
a better starting point for me would be to tell us
what are the plant specific differences that have to
be dealt with.
The scheme as I understand it is that you
have the generic evaluation done in the G.E. reports,
and that leaves plant specific considerations to be
dealt with on a case by case basis.
And what I don't find in these reports is
a clear delineation of what the plant specific
considerations are for each of these plants.
MR. HAEGER: I think that probably the
best way to answer that is --
MR. BOEHNERT: If you could introduce
yourself.
MR. HAEGER: Yes, I am Allan Haeger, and
I work for Exelon in the licensing area. We have in
our presentation pointed out differences where we
think that those are significant, and we are prepared
to discuss the reasons for the differences at that
time.
That might go to what you are asking. If
you would prefer to wait as we go through the
presentation, there are opportunities there.
DR. SCHROCK: I am simply pointing out
that I have difficulty digesting the material and
making sense of it for this reason and a few others,
but it would be helpful I think if you could tell us
what he plant specific considerations are. That does
not seem like an onerous request I don't believe.
MR. NOSKO: Well, they are sister
stations, and they are both BWR-3s. The Dresden
station uses an isolation condenser, for example;
whereas, Quad Cities is a little bit behind Dresden,
uses a RCIC system, reactor core isolation cooling
system.
There are differences in safe shutdown.
They have a safe shutdown pump at the Quad Cities
station, and a separate system to address that for
fire protection areas. We don't have that in the
Dresden station.
It is things like that. But I am sure
that we will be able to clarify this in the
presentation, and if we fail, please bring that to our
attention, and we will make sure that we get that
straight.
DR. SIEBER: In your list of things that
you are going to talk about, some of the questions
that I sent in had to do with the fuel design, and I
recognized that the lead safety analysis are separate
from the upgrade.
But I would be interested in knowing a
little bit more about the details of the fuel design
than currently appears in the SER. Can you address
that or do you plan to address that?
MR. NOSKO: Well, since the application
for G.E. 14 fuel was a separate licensing submittal,
we were not intending to address any of the specifics
about the G.E. 14 fuel.
But depending on the questions, and
depending on the proprietary nature, we might be able
to.
MR. HAEGER: We certainly have personnel
here who can speak and answer those questions.
DR. SIEBER: Well, it seems to me that
when you extend the rating of the plant by 17 percent,
other than a few balance of plant things and some new
analysis that you have to do, everything depends on
the fuel, and that is where you are getting the uprate
from.
MR. HAEGER: That's right.
DR. SIEBER: And so to me I think it is
part-and-parcel of it.
MR. HAEGER: Well, we will be covering the
fuel's response to at risk to LOCA, and we talk about
the general design to some degree. But I think there
is enough points in the presentation that touch on
that that is an appropriate place to answer questions.
DR. SIEBER: The ACRS doesn't get the
opportunity to review safety reload, safety
evaluations, and so we may miss out on the full
understanding of just exactly what the uprate is all
about, and how you achieve it, and everything that is
affected.
Because you actually affect a lot of
things when you change the fuel parameters. It
changes the results and the results virtually of all
the safety analyses as I see it.
Well, let's see what you do, and to the
extent that you miss the questions that I submitted,
then I will ask them at the appropriate time.
MR. NOSKO: Okay. This next slide is a
power-to-flow map, and you are very familiar with
this. We have a chart over there that is not as
visible as we had hoped that it would be and our
apologies.
From this chart, you can identify the
current hundred percent power level, and the power
level for uprated conditions, the 2957, and that is
the far upper right.
DR. FORD: Can I ask about this chart? I
mean, this chart -- well, what does it depend on? It
depends upon what?
MR. NOSKO: Core flow.
DR. FORD: It depends upon the fuel
design, and the way the flux is flattened, and so on?
Or is it something much more basic than that? Does
this middle upper boundary move around as you change
the way in which you fuel the reactor, or design your
flux distribution and so on?
MR. NOSKO: Jens or Jason, would you help
us with that.
MR. POST: Yes, this is Jason Post of G.E.
The MELLLA upper boundary is a licensed limit, and
that does not change. That is fixed in space, and
that does not change from reload to reload.
There can be small variations in the load
lines as a result of the core design, but the changes
are pretty small, and we have equations that we use
when we define those, and they basically don't change
significantly from cycle to cycle.
DR. FORD: Thank you.
DR. SCHROCK: I saw those equations and
they look like empirical relations. They don't seem
to relate to any physical aspect of the plant. I
think that I would like to ask the question that
Graham just asked again. What is the basis of the
line? How does it come to be where it is as a
licensing limit?
MR. PAPPONE: This is Dan Pappone of G.E.
The rod lines that are shown on the power flow map did
have their origination back in the plant design plant
response, but we have fixed those in licensing space.
So they approximate what the actual
response would be, but we are treating these as
licensing boundaries. So that helps.
MR. NOSKO: So you are right; they are
empirical.
MR. POST: It is an empirical bounding fit
to an original set of calculations, and having done
that original fit, we are now drawing that line and
saying this is our licensing boundary, and we will not
allow a plant operation outside of that boundary.
DR. SCHROCK: But if I am not mistaken,
that is one of the unexplained differences between
Quad Cities and the Dresden plants. These power flow
maps are not identical, and they differ significantly
I think. Is that right?
MR. PAPPONE: I believe that we kept the
power flow maps the same, or what we are counting as
a licensed power flow map, and I believe that is the
same.
MR. NOSKO: For the uprate, yes. That's
correct.
MR. PAPPONE: For the uprate, yes.
MR. NOSKO: Today they have differences in
their licensed power levels. Dresden is 27 (sic)
megawatts thermal for their license level; and Quad
Cities is 2511. So there are some differences there.
DR. SCHROCK: And that is an affirmed
power?
MR. NOSKO: Correct. And when we go to
the uprate power, we are bringing those two together
as part of maintaining a common configuration
management.
DR. SCHROCK: Well, I will have to look
again, but in searching for what are the differences
between these two reports, two sets of reports, I was
struck by the fact that here were different numbers,
different positioning of various lines -- this little
dashed line, which has something to do with natural
circulation, was in a different place.
But the numbers in the table that
characterize where the lines are seem to be different
also in Quad Cities and in the Dresden reports, SERs.
So we will have to look again to confirm if I am right
or am I wrong.
MR. HAEGER: What we will do is we will
look closely at those, and try to explain any minor
differences, and I think they are probably minor, but
any differences in those.
MR. NOSKO: Okay. And the purpose of this
slide frankly was to demonstrate that MELLLA allows us
to operate at higher power levels without changing
core flows.
The next slide summarizes differences in
key operating parameters between plants today and what
we expect after the uprate in Dresden.
CHAIRMAN WALLIS: And you talked about
flow rate just now. The flow rates on this diagram
are not the same as they are either for Quad Cities or
for Dresden on page 115 on the G.E. safety analysis
report.
And I don't know what the differences are
due to, and Quad Cities shows 105.8 for its full power
core flow range maximum; and Dresden shows 98. I
don't know why they are different, and yet Dresden
shows 105.8 for its extended power uprate, which is
not on yours either. And these are different numbers,
and I just don't understand why they are so different.
MR. HAEGER: I think I can handle that.
The full power expected core flow for both stations is
going to be as shown here, 98 million pounds mass per
hour.
Now, Quad Cities currently is licensed to
achieve what they call increased core flow, which is
to go beyond the right boundary of the power flow map
into that increased core flow region. Dresden is not.
For the power uprate, we did some of the
analysis, and it was stated that we did some of the
analysis for Dresden at that increased core flow range
to support future potential licensing actions. But
the full power, 100 percent core flow for both
stations will be the same at 98.
CHAIRMAN WALLIS: This is one of the
things that is confusing when you see different
numbers in different places for the same thing, and it
needs some explanation.
MR. HAEGER: Well, we do analysis -- and
you are going to see a few more differences.
CHAIRMAN WALLIS: So it is true then is it
that you are not extending the core flow rate with
this application, but that you would like to do so
sometime in the future, which is why you have some
higher numbers in some of these other places?
MR. HAEGER: That's correct.
CHAIRMAN WALLIS: Thank you.
MR. NOSKO: Quickly summarizing some of
these high points, the Dresden station, I mentioned
thermal power is increasing from 2527 to 2957
megawatts thermal, and Quad Cities is going from their
current 2511 to their same uprated level.
Steam flow is increasing from about 9.8
million pounds per hour to just over 11.7 million
pounds per hour. And as you saw in the power flow
map, the range of core flow at full power decreases
somewhat under uprated conditions, but maximum flow
through the core is not changing.
And you can also see here that we are not
changing dome pressure or --
CHAIRMAN WALLIS: The core flow rate has
to have a range because of condenser temperature
variations or something to get the same power; is that
why it varies?
MR. NOSKO: The range on the -- you are
talking about full power?
CHAIRMAN WALLIS: Why is there a range?
Why isn't it just 98? Why is it 85 to 98?
MR. NOSKO: It is a function of the MELLLA
line, where the MELLLA line intersects full power.
CHAIRMAN WALLIS: Oh, it is the flat part.
MR. NOSKO: Yes. Moving on, this uprate
will be accomplished in one phase. Mr. Bohlke
mentioned earlier in his presentation that plant
modifications will be installed during the next
refueling outage for each unit, and in the on-line
period immediately preceding that refueling outage.
I mentioned earlier that we will be taking
advantage of installed spare capacity at the stations.
These spares are maintenance spares for the plant, and
the most obvious example that we have is that we will
be operating all four of our condensate booster pumps,
and all three of our motor driven reactor feed pumps.
But I should say also that the use of all
installed feed and condensate pumps is common in the
industry, and it is just a difference for Exelon at
this time.
Following the uprate, our units will be
generator limited, which means that we will be varying
reactor power seasonally to account for temperature
differences so that we maintain maximum output from
the generators.
And this slide also shows our schedule for
implementing the uprates at the four units. Dresden-2
is in its outage now, and the remaining three units
will undergo their outages for the uprate next year.
Turning now to the modifications that we
will be making to the station. You will find that the
power uprate generally requires the same modifications
to be made at both stations. There are relatively few
safety related modifications, and the majority of the
changes are being made to the balance of plant
systems.
CHAIRMAN WALLIS: I am going to ask you a
question, because I don't see it in your presentation
here. The method for increasing the power without
raising the flow rates through core and the pressure
and so on is flux flattening essentially.
So what we have seen is that you have a
higher flux than you would have had before at the
outside of the assemblies of the core. And yet I
understand that the fluence, the vessel fluence, goes
down with a power uprate. How do you achieve that?
MR. NOSKO: Well, we are prepared to
discuss that.
CHAIRMAN WALLIS: Well, I didn't see it in
your presentation.
MR. NOSKO: It is there.
CHAIRMAN WALLIS: It is there? Okay.
MR. HAEGER: It is slightly touched.
CHAIRMAN WALLIS: So you are going to
answer that question later then?
MR. HAEGER: Yes, sir.
CHAIRMAN WALLIS: Thank you.
MR. NOSKO: I would like to talk about the
more significant plant changes that we will be making
for the uprate, using the chart behind Mr. Haeger as
a rough guide.
That chart over there is a very simplified
schematic of the steam and feed water cycles. I will
begin in the upper left-hand corner with the changes
to the reactor internals, and then follow that diagram
in a clockwise manner through the turbine, the
condenser, through the feed water system, and then
back to the reactor.
So starting with the reactor. New G.E. 14
fuel assemblies will replace existing G.E. and
Siemens's fuel. This will be done gradually over 3 to
4 operating cycles, and this new fuel type will allow
us to reach the higher EPU power levels, while
maintaining a 24 month operating cycle.
Mr. Bohlke mentioned that Dresden and Quad
Cities are BWR-3 units. As such the steam dryers are
smaller than those of the later designed BWR-4s, 5s,
and 6s, and they are not able to handle the increased
steam flow of an extended power uprate as well.
So to prevent the higher moisture
carryover levels predicted for the uprate, we elected
to modify the steam dryers to keep those levels to no
greater than what they are today.
We are adding clamps to 8 of the 20 jet
pump sensing lines to eliminate a concern for
potential vibration induced failure of those lines
caused by the vein passing frequency of the
recirculation pumps.
A reactor recirculation system runback and
the low SCRAM level set point change are being added
to improve station availability. Today, only two of
the three feed pumps and 3 of the 4 condensate pumps
operate at rated power.
If one pump trips, the standby pump
automatically starts. After the uprate, we won't have
a standby pump, and so we are adding a run back
feature and a SCRAM set point change to prevent low
water level SCRAM on either a loss of a single feed
pump or a single condensate pump.
Changes to the isolation condenser time
delay relay at Dresden and to the low pressure coolant
injection swing bus timer at both times are being made
to reflect new accident analyses for the extended
power uprate. And we are also making some changes to
set points on nuclear instrumentation.
DR. SIEBER: Before you leave that, what
is your guaranteed maximum moisture content at the
reactor outlet right now? Is it one percent?
MR. NOSKO: Currently today?
DR. SIEBER: Yes.
MR. HAEGER: The acceptance test for the
original steam dryers was less than .2 percent.
DR. SIEBER: So, .2?
MR. HAEGER: Yes.
DR. SIEBER: And what modifications are
you making to the dryers?
MR. HAEGER: We have a couple of slides on
that later in the presentation that show an insertion
of a perforated plate.
DR. SIEBER: Is that going to change the
pressure drop?
MR. HAEGER: That is going to change the
pressure drop.
DR. SIEBER: Do you know by how much?
CHAIRMAN WALLIS: Well, the higher flow
rate will change the pressure drop, too, right?
MR. NOSKO: Right.
CHAIRMAN WALLIS: So you actually have a
lower pressure at your turbine than you would like or
that you have now?
MR. NOSKO: Than we have now, yes. I
don't have that specific piece of data, but I am sure
that we will collect it.
DR. SIEBER: Right.
MR. NOSKO: Okay. So moving on to the
turbine generator system modifications, we are making
changes to our high pressure steam path by installing
new high pressure turbines, and we are also changing
the cross-around relief valve set points.
An additional steam line residence
compensator card is being installed in our electro
hydraulic control circuitry to handle the third level
harmonic for the steam piping system.
And at Dresden, we found that the existing
isolated phase bus up cooling system was not
adequately sized to handle the uprate, and so we are
making a change to improve the cooling capacity of
that system.
DR. SIEBER: You are putting in a new
return line?
MR. HAEGER: Yes, we are. We are putting
in a new return line, and we are having all the
cooling go down all three of the phases.
DR. SIEBER: And you aren't doing anything
to the generator to improve cooling I take it or are
you?
MR. HAEGER: We are increasing the flow of
standard water cooling to the generator, but it is a
small issue. I didn't include it int his
presentation.
DR. SIEBER: And how are you doing that?
You aren't changing anything. Does that take cooling
water away from other components in the plant and make
that system marginal? Is that just a turbine plant
closed cooling water system?
MR. HAEGER: Yes, and that has been
evaluated.
DR. SIEBER: And you have enough capacity?
MR. HAEGER: Actually, standard water
cooling is service water.
DR. SIEBER: Service water?
MR. HAEGER: Yes.
DR. SIEBER: Well, that is still a closed
cooling system, and you can't put service water there.
MR. NOSKO: You are correct. Standard
cooling is the closest one. And I didn't mention, but
Quad Cities doesn't have this problem. This is a
Dresden-unique situation.
Continuing now with changes to the
condensate and feed water systems. The increased flow
from the uprate causes additional stresses on the
condenser tubes, particularly in cold weather.
Several years ago, the Quad Cities station
installed intermediate bracing for their condenser
tubes to eliminate a concern that they had over tube
vibration. Dresden did not at that time. So now we
are making that change at the Dresden station as a
part of this uprate.
DR. SIEBER: Have you noticed damage at
the current levels to condenser tubes on expanded
vibration?
MR. NOSKO: No, sir, not at the Dresden
station, and Quad Cities, after they went through
this.
DR. SIEBER: And what kind of tubes are
they? Do you know?
MR. NOSKO: They are stainless.
DR. SIEBER: Stainless? Okay. But you
are expecting that the potential for vibration due to
the increased exhaust flow will cause damage?
MR. NOSKO: Well, we are expecting that if
it is staked at the present station, and the stakes
that we have at Quad have been evaluated for the
increased steam flow and they are adequate.
DR. SIEBER: Right. That is a time
consuming modification to put all of those things in
there, and there are tons of them.
MR. NOSKO: Yes. The increased condensate
and feed water flow also requires us to increase the
capacities of the condensate demineralizer systems at
both stations. Dresden and Quad Cities use four
stages of feed water heating.
The uprate increases extraction steam flow
from the low pressure turbines to the feed water
heaters, and this raises the internal pressure of the
heaters.
For our two lowest pressure feed water
heaters, that pressure increase is small enough so
that the heaters will continue to operate within their
existing design rating.
This is not the case for our two highest
pressure heaters, and so we are making modifications
to allow us to increase the pressure ratings of those
heaters.
We are increasing the capacity of the
bravo heater and normal drain valves at the Dresden
station to maintain heater normal water level control,
and avoid the need to bias open our emergency spills.
Because of similar changes already made at
the Quad Cities station that modification isn't needed
there. A change that is being made at the Quad Cities
station, but not at Dresden, is the staggered feed
pump low suction pressure trips.
Right now at Quad Cities all the reactor
feed pumps trip on a low suction pressure signal, and
after the uprate, they will be staggered somewhat,
depending on the duration of that low pressure signal.
And separately from the extended power
uprate project, a new digital feed water control
system is being installed at the Quad Cities station.
It of course will be tested and adjusted to support
planned uprated conditions.
And then there are plant changes that
don't neatly fit into any of the previous categories.
The results of the piping analyses require us to make
some changes to our main steam and torus-attached
piping supports, as well as to some drywell support
steel.
We are upgrading the interrupting
capability of the non-safety related 4kV switchgear to
handle the additional running loads. A feature to
trip the delta condensate pump in the event of a loss
of coolant accident is being added to retain the
ability to make up with feed water.
And the Dresden station uses a cooling
lake and supplemental cooling towers to cool the
circulating water. We have plans to install new
cooling towers at the Dresden station to install, or
excuse me, to handle the additional heat load from the
uprate.
But this is an economic decision driven
primarily to avoid derating the plants in the summer
months. Depending on the results of more recent
economic evaluations, we may elect to defer
installation of those additional cooling towers to a
later date.
While we are prepared to go on to selected
analyses and evaluations, I thought I would ask the
committee if there are no further questions on the
modifications?
DR. SIEBER: I have a couple of questions.
Because you are now operating your installed spares as
to provide sufficient pumping capacity, that creates
a problem with your unit auxiliary transformer and its
spare; where when you get a bus transfer, you end up
with more load on the spare transformer than it is
rated for.
And you have addressed that in a number of
ways, one of which was to test the circuit breaker for
interrupting capability. I presume that test is
complete and satisfactory?
MR. NOSKO: Yes.
DR. SIEBER: And another thing that you
did was to cut out the instantaneous over current
protection so that you would end up with a six cycle
delay or something like that?
MR. NOSKO: Yes.
DR. SIEBER: What was the basis of doing
that? Was it because the peak was too high?
MR. HAEGER: I believe that is the case,
yes.
MR. NOSKO: Right now I am not sure
whether it is the interrupting or the instantaneous.
DR. SIEBER: It is the instantaneous that
was cut out, and the long term one is designed to
allow you to start motors where the current one would
go above the operating current, and as the motor
starts to the normal operating current.
The instantaneous one is for short-circuit
protection, which now if you have a bolt short in your
system, you have no protection. So when you close on
it --
MR. HAEGER: As I understand it, the
equivalent protection is obtained by the other relay
scheme in there that is maintained, but I am not an
electrical expert. Is there anybody back there that
can help with this?
MR. KLUGE: Yes, I am Mark Kluge from
Exelon. The test that was performed actually used the
short-circuit current and then with some modifications
to the switch gear bracing, and the switch gear then
proved capable of interrupting that, even with the six
cycle delay.
DR. SIEBER: The question is not whether
the circuit-breaker can interrupt it, but whether the
transformer can take that fault, because the
protection is gone.
MR. HAEGER: Yes, and I am pretty sure
that the answer lies in the equivalent protections in
the other features of the release scheme. Let us
confirm that for you.
DR. SIEBER: Okay. Now, the other part of
that is that you end up with a required manual
operator action to eliminate or disable some of the
loads on that transformer to bring it back to its
current rating.
And I take it that the effect of the
operator not doing some stripping on those buses would
lead to damage to the core or to the windings of the
transformer and cause overheating.
And you say if he does it within an hour
everything is just perfect, and where did the one hour
come from?
MR. NOSKO: We had a separate evaluation
conducted.
DR. SIEBER: Yes, I have read that, and
they said one hour, and the question is how did they
come up with that? What was the basis?
MR. NOSKO: The basis? I need to --
DR. SIEBER: Or is that engineering
judgment?
MR. NOSKO: No, sir, it was based on the
test results.
DR. SIEBER: Well, it takes the life out
of the transformer when you do that.
MR. HAEGER: That's correct. We
understand that to be the case, but as far as the
specific basis, I think we are going to have to get
back to you on that.
CHAIRMAN WALLIS: One hour sounds like a
rounded-off number in some way.
DR. SIEBER: It certainly does. It should
have been 58 minutes, and then we would believe it and
not ask the question.
MR. HANLEY: This is Tim Hanley from
Exelon. I believe the one hour actually came from me.
I am the operations representative and I had them
evaluate it at one hour because I thought that was an
acceptable time period for which the operators to take
those actions.
So it was a backward calculation on would
it be okay from an hour. So I believe that is why it
is such a round number.
DR. SIEBER: Let me ask since you are the
operating person, you probably know this. Does Exelon
or its predecessor have a practice of looking at
transformer gas composition?
MR. HANLEY: Absolutely.
DR. SIEBER: How often do you do it on
that transformer; do you know?
MR. HANLEY: We take oil samples to
measure the gas content I believe on a monthly basis
on all of our large power transformers. So, in an
event like this, if we knew that we had over duty on
the transformer for some period of time, we would
immediately go out and take another sample and check
for gasing.
But we do have an analysis program that we
do on a regular basis for all the large power
transformers at the plant.
DR. SIEBER: And if somebody from your
laboratory came back and said you have got high
acetylene in this transformer, what would you do as an
operator?
MR. HANLEY: It depends on the level at
which it comes back at. We trend that. In fact,
Dresden this past summer had a transformer that was
gasing and they trended it over time, and did a
control plant shutdown, and shut down, and went in and
repaired the transformer and brought the unit back on-
line.
DR. SIEBER: Why would it be a shutdown?
MR. HANLEY: You would have to with the
unidox transformer, because it is tied directly to the
generator. There is no way to separate it without
taking the unit off-line.
DR. SIEBER: Thank you.
MR. NOSKO: Moving then to the selected
analyses and evaluations. A full scope of the
evaluations was performed in accordance with the
ELTRs. These analyses were used to prove methods
within previously accepted ranges and in all cases the
results were within the acceptance criteria for the
planned EPU configuration.
This next slide identifies the analyses
and evaluations that we will be covering; the
containment, the emergency core cooling system; and
thermal-hydraulic stability. We will talk about the
anticipated transient without SCRAM analogies, piping,
and also we will look at the effects of the power
uprate on reactor internals, and the flow accelerated
corrosion programs at the stations.
These were selected for discussion based
on a request from the committee and in the case of the
reactor internals, because of recent industry
operating experience. And with that, I will turn the
discussion over to Mark Kluge, who will begin with the
review of the containment analyses.
DR. SCHROCK: Excuse me, but before you
leave, could you say what the current licensing basis
for these plants is?
MR. NOSKO: In terms of what, sir?
MR. HAEGER: Yes, can you be more
specific?
CHAIRMAN WALLIS: That's a pretty broad
question.
DR. SCHROCK: Right. Well, in terms of
the LOCA evaluation is what I am thinking of.
MR. NOSKO: Those are covered in this
presentation. They are summarized along with the pre-
EPU and the post.
MR. HAEGER: Are you asking for the
methodology or the --
DR. SCHROCK: Well, I will ask the
question subsequently.
MR. NOSKO: Okay. Very good. Thank you.
MR. KLUGE: Good afternoon. I am Mark
Kluge from Exelon's EPU project engineering team, and
I will be discussing the containment analysis that we
performed for the Dresden and Quad Cities power
uprates.
I will cover the methodology that we used
to perform these analyses, and we will look at the
results for the design basis accident, and we will
also look at the Mark I hydrodynamic loads, and I will
summarize the conclusions of the containment
analysis.
CHAIRMAN WALLIS: When you say design,
there are several design basis accidents.
MR. KLUGE: The design basis accident that
I am referring to is the maximum recirculation and
suction line break.
CHAIRMAN WALLIS: The most critical one or
something like that?
MR. KLUGE: It provides the limiting case
for containment and--
CHAIRMAN WALLIS: Okay.
MR. KLUGE: A containment analysis is
performed in two phases; a short-term phase, and a
long-term phase. For the short-term analysis, we use
the M3CPT and LAMB codes. LAMB models flow down and
then M3CPT calculates the peak dry well pressure and
temperature.
In the long term, we use the SHEX code,
which then looks at the conditions in the suppression
pool. And for the Mark I hydrodynamic loads, we use
the methodologies that were defined during the Mark I
long-term program.
In all cases our EPU license power is
within the range for which these codes are applicable,
and we analyzed a full spectrum of break sizes and
locations, and we used conservative input parameters
so that we would have conservative results.
Moving to the next slide, the results for
the design basis accident. Peak drywell pressure, you
can see that when we perform the calculation with the
same methodology for current conditions and uprate
conditions, here is approximately a one pound rise in
peak containment pressure, which is still well below
the acceptance limit for these containments.
For drywell air temperature, again when we
perform the pre-EPU and the EPU case, we have a very
nominal two degree rise in peak drywell air
temperature.
CHAIRMAN WALLIS: Now, the drywell metal
temperatures.
MR. KLUGE: The drywell metal is designed
for a temperature of 281 degrees.
CHAIRMAN WALLIS: And you have to do some
transient heat transfer analyses or something?
MR. KLUGE: That's correct, and in this
case the design basis loss of coolant accident is not
even limiting for the drywell metal temperature. The
peak temperature that is given here, and the air
temperature lasts less than 10 seconds and simply is
not there long enough to eat up the drywell shell to
its limit.
CHAIRMAN WALLIS: I read that, and I would
be a little reassured if you had actually given a
number to how hot it gets. How hot does it get in
this 10 seconds?
MR. KLUGE: I believe the peak drywell
temperature is in the 277 degree range.
CHAIRMAN WALLIS: So it is a few degrees
off the limit.
MR. PAPPONE: This is Dan Pappone. That
is a typical result that we have seen for
recirculation line break analysis, and 5 to 10 degrees
below the shell temperature has been 5 to 10 degrees
below the design temperature.
MR. KLUGE: Going on to the next slide,
here are the results for the suppression coolant --
CHAIRMAN WALLIS: Typically is it always
below?
MR. KLUGE: Well, the reason that I said
typically is that last month we did have the shell
temperature slightly above, but when they went and
looked at the structural evaluation for that higher
temperature in the case where it did come up higher on
the shell temperature, the structural analysis was
still acceptable.
And so occasionally we have seen the
drywell shell come above the 281 limit by a handful of
degrees, and if we go to the next step in the
structural analysis. The structural analysis results
were okay.
DR. SIEBER: So when you say last month,
Dan, you were talking about?
MR. PAPPONE: The Duane Arnold analysis.
CHAIRMAN WALLIS: The calculation and not
an event. So what is the regulation? The regulation
says that if it is above 281, then you have to do a
detailed structural analysis or something? What does
the regulation say about this structural limit?
MR. HAEGER: I don't believe there is any
direct regulation on this. I believe that the
licensing process is to set the structural limit, and
then ensure that you don't achieve it; or if you do,
justify a new structural limit.
MR. PAPPONE: This is Dan Pappone. The
containment for the drywell torus shells are ASME
pressure vessels, and so at that point we are working
within the ASME structural codes.
CHAIRMAN WALLIS: So there is nothing
written in some CFR document which says that 281 is a
limit?
MR. PAPPONE: No.
CHAIRMAN WALLIS: I guess we can ask the
staff the same question and what they think about
these when we get to them tomorrow.
MR. KLUGE: Moving on to the suppression
pool analysis. When we did a limiting analysis using
the most conservative inputs from the two sites, we
saw that EPU resulted in approximately a 9 degree rise
in suppression pool peak temperature.
We used that bounding analysis, 202
degrees, in the containment analysis and piping
analysis. We also calculated plant specific heat
suppression pool temperatures, and that was used in
the ECCS and NPSH analysis, and as you can see those
numbers are lower than the limiting analysis.
For the EPU wetwell pressure analysis,
again we had a very nominal rise in peak wetwell
pressure when we applied the same methodology to the
pre-EPU and post-EPU case.
The Mark-I hydrodynamic loads, we looked
at pool swell, and vent thrust, condensation
oscillation, chugging, and SRV discharge loads. We
ran all the limiting cases for EPU as John Nosko
mentioned, and reactor pressure does not change for
this uprate.
That is a primary driver in these
hydrodynamic loads. So we found in all cases the
current Mark-I load definitions remained bounding for
these plants.
DR. SIEBER: That is for pressure and
flow, as opposed to duration of the transient, right?
Because there is additional energy in the extended --
MR. KLUGE: There is additional energy,
but it was all within the original load definitions.
DR. SIEBER: Okay. Do you use some kind
of a starter or something like that on your safety and
relief help discharge lines?
MR. KLUGE: We have T-quenchers. In
conclusion, the containment analyses we performed for
EPU used accepted methods within the range for which
those codes are applicable.
We chose conservative input parameters and
all of our results were within acceptance criteria.
Therefore, we conclude that containment performance is
acceptable under EPU conditions.
If there are no questions, I would like to
introduce John Freeman, of our nuclear fuels
department, to talk about the ECCS-LOCA analysis.
CHAIRMAN WALLIS: Well, can we conclude
that not only containment performance acceptable, but
containment performance is not a feature which limits
the amount of power uprate that you can have within
the range you are considering.
And that you are not getting close to a
limit in containment performance which is preventing
you from going to, say, 3,000 megawatts?
MR. KLUGE: That is correct. As you
observed, there is substantial margins in all of the
containment acceptance criteria.
CHAIRMAN WALLIS: Thank you.
MR. FREEMAN: Good afternoon. My name is
John Freeman, with Exelon Nuclear Fuel Management. I
am going to discuss emergency core cooling analysis,
along with Dan Pappone of General Electric.
Dan is going to go over the methodology
and some of the acceptance criteria, and part of the
approach that was used for the extended power uprate.
I will go over the results and some of the
conclusions that we had reached, and with that, I will
turn it over to Dan Pappone.
MR. PAPPONE: For the for the ECCS
analysis methodology, we used the SAFER/GESTR-LOCA
methodology for performing LOCA analysis. We applied
it as it was outlined in the ELTR, and we did
basically a full scope analysis, and I will get into
a little more of the particulars, because we are
moving from the previous version of the code for the
way we had applied it for Quad Cities, and we are
essentially changing the fuel vendor of the analysis
for the Dresden plant.
DR. SCHROCK: My question earlier about
the licensing basis. I had this specific thing in
mind. The current basis is also -- rests on
SAFER/GESTR calculations, using the provisions of SECY
83-472; is that right?
MR. PAPPONE: Right. Well, the current
analysis for the G.E. fuel in Quad Cities.
MR. HAEGER: Right now Dresden uses
Siemens fuel, and they have a Siemens analysis
methodology.
DR. SCHROCK: Which is different.
MR. HAEGER: Yes.
MR. PAPPONE: And because we are bringing
the Quad Cities analysis up to date, and we are
bringing Dresden into the SAFER/GESTR methodology, we
did do a full-scope analysis for the plants, and when
we do that analysis, we analyze the break spectrum
using a nominal set of assumptions to determine the
limiting break location, and limiting break size, and
the limiting single failure.
And once we establish that, we calculate
a licensing basis peak clad temperature using the
required models from Appendix K. This is the process
that is outlined in SECY 83-482.
And in order to demonstrate that licensing
basis PCT has sufficient conservatism, we also
calculate an upper-bound peak clad temperature for
limiting nominal case.
DR. SCHROCK: In all of these descriptions
of many analyses that have been performed, the results
seem to be given in sort of a simple narrative
description that things are well within the existing
range or increase only by insignificant amounts, as
opposed to showing us quantitatively what the results
are, and what the range of investigations span, and
how many there were, and things of this nature.
I would think that we need to hear some of
those details to have a better understanding of do we
buy in or don't we. Do you follow me?
MR. PAPPONE: Yes, I understand.
MR. HAEGER: We actually have some of
those comparisons in our upcoming slides, but as far
as --
DR. SCHROCK: Well, my reading of the
thing is that it is a pretty broad brush description
of how you comply with an existing set of regulatory
limits that are imposed on you, as opposed to a
technical evaluation of how the thing performs under
these new conditions.
MR. PAPPONE: We did perform that
technical evaluation.
MR. FREEMAN: This is John Freeman. I
think I can address that. What was great about this
analysis was that it gave us a chance to do a complete
new analysis to cover all four of those units, and we
very carefully chose all the emergency core cooling
performance inputs, and we ran it before the power
uprate and after the power uprate.
And that's where the difference is very
small. With the same fuel type, all the same inputs,
and the only difference being the power level for the
dba, and we are going to go over this here in a minute
to talk about for the dba, the temperature doesn't
change that much.
Most of the impact due to power uprate is
in the small break analysis, and we will go over that
in a little bit. But we will also talk a little bit
about the fuel aspect, which is something that you
wanted to be discussed.
When we are finished, maybe you could see
if you have any more questions on this.
DR. SCHROCK: Sure.
MR. PAPPONE: The prime purpose of doing
the analysis is to demonstrate that the plant is in
compliance with 10 CFR 50.46, and acceptance criteria,
and peak clad temperature, local oxidation for wide
water reaction, coolable geometry, and long term
cooling.
We do the plant specific analysis for the
peak clad temperature, and local oxidation of the core
wide metal-water reaction; and coolable geometry and
long term cooling we have addressed generically in the
SAFER/GESTR methodology.
The primary parameter of interest is the
peak clad temperature, and we have to keep the peak
clad temperature below 2200, which is the 50-46
acceptance criterion.
And out of the SECY methodology, and the
SECY approach, we also have to demonstrate the
licensing PCT is greater than the upper bound PCT, so
that we have demonstrated that licensing PCT we
calculated is sufficiently conservative.
And then as part of the SER conditions
that were imposed on the SAFER methodology, as part of
that approval, we have a limit on the upper bound peak
clad temperature of 1600 degrees.
And that was based on the test data that
was supplied for the code qualification and the
application methodology calculations that we had in
the generic LTR for the SAFER methodology.
CHAIRMAN WALLIS: You show here two
different things for Appendix K and licensing basis.
Aren't they the same thing?
MR. PAPPONE: The licensing basis PCT is
essentially a statistical summation of the nominal
Appendix K, plus some additional plant variable
uncertainty terms.
So in the practical sense, it is the
Appendix K temperature, plus a small ADS. That ADS
picks up a few terms that aren't in the Appendix K
calculations. So it ends up being slightly higher.
Now, back to the actual scope of analysis
that we did. We did a full scope SAFER analysis for
bringing the G.E. 9 fuel, the G.E. fuel that is in
Quad Cities, and we are bringing that up to the
current analysis process procedures and code.
We are also applying the SAFER methodology
to the Siemens fuel that is in both Dresden and Quad
Cities. So at the end of all of this, we have got one
common analysis basis for both units, and for all the
fuels in the units.
We did all of the analyses, the full break
spectrum analyses, assuming G.E. 14 fuel, because that
was the hottest fuel that we were looking at. That
was fuel that was giving us the highest temperatures.
DR. SIEBER: That is 10 by 10 fuel?
MR. PAPPONE: That is a 10 by 10 fuel.
DR. SCHROCK: And that is an equilibrium
cycle?
MR. PAPPONE: When we do the analysis, we
are assuming an equilibrium loading.
CHAIRMAN WALLIS:
DR. SCHROCK: And you have a basis for
concluding that that is the worst situation?
MR. PAPPONE: Yes. During the -- the two
places that we look at a transition, versus
equilibrium core, and during the initial blow down and
core flow coast down that would affect the boiling
transition time, that is once place that could be
affected.
And then the other places during the
reflooding. The fuel bundle design is such that it is
hydraulically compatible. There isn't much of a
difference in one fuel bundle to the next, because
they have got to be able to co-exist and intermixed
core
So there is very little hydraulic
difference between the two, and you put a bundle in
that has a lot higher resistance, or otherwise it will
be starved and be too limiting locally, where we can't
put in a bundle that has got a low resistance that
will steal flow from the existing bundles.
So we tend to even things out that way,
and then the operating limit CPR will take care of any
small differences from one bundle to the next one, and
fuel type to the next.
DR. SCHROCK: For your peak clad
temperature, your decay power is certainly a
consideration, and so the different points in the life
of the core and the refueling changes, and all of
those considerations, I guess my questions would have
been more appropriate a year ago when we were talking
about the generic aspect of the thing.
I tried to ask it then, and I didn't get
a very satisfactory answer, but my knowledge of it
doesn't come really from discussions in these current
meetings. It comes from more than 10 year old memory
of discussions that we had when that methodology was
bring developed.
MR. PAPPONE: Right.
DR. SCHROCK: I really think that you owe
an explanation of how these changes in the fuel
characteristics impact what you have done to come to
the methodology that is employed in applying the ANS
standard to get the decay power curves that you are
using in these analyses.
And they must be different now than they
were when they were developed for the original cores
that existed 15 years ago.
MR. PAPPONE: The key assumption for the
decay heat is that we are using a nominal -- say mid-
cycle exposure, and when we are doing the upper bound
calculation, we do have the two sigma uncertainty on
there.
DR. SCHROCK: But how do you get to that,
that's what I am talking about, and my recollection of
it is that you took a lot of different core
compositions typical of what would occur in the life
of the core, and you calculate the K-power using the
ANS standard, and you evaluate the uncertainty using
the uncertainty values given there for those
conditions that you did a Monte Carlo evaluation.
And it came to some kind of generic curve,
which was then applied essentially in all of the many
evaluations that you have described here, for example.
But it would be a different one now than it was then.
MR. PAPPONE: No, we have not gone back
and revisited that Monte Carlo analysis. I am not
aware that that Monte Carlo analysis being directly
applied in the SAFER world.
DR. SCHROCK: You are not aware of that?
MR. POST: I don't think that ever was
directly used in the SAFER world.
MR. HAEGER: You are talking about the AMS
standard decay heat curve.
MR. PAPPONE: No, G.E. did an analysis on
decay heat sensitivity, where we did go and look
through --
DR. SCHROCK: You see, what I understand
that I am talking about gets at the difficulty that
arises when something has been approved, and the
industry can utilize that approval to move ahead and
use that methodology and satisfy regulations in that
way.
And I accept the fact that that exists,
and it is a fact of life, and it is probably
necessary. But we are looking at the technical site
of the thing here, and we want to understand are the
conclusions that are being reached reasonable
conclusions.
Now, I find it difficult to come to grips
with answering the question when confronted with a
situation where many of the details that I think are
necessary just don't appear in the discussions.
MR. PAPPONE: We have just recently looked
at the decay heat curve that we are using in the SAFER
analysis, and come up with a new one for the -- we
took a little bit different approach this time. We
had been going through and looking at the core average
exposure of the fuel types, and the operating cycle
link.
And coming up with a bounding decay heat
value based on those parameters that would go into
this the 79 model. We have been using that in the
containment analysis, because that analysis is one
where we look at each individual part and make sure
that each individual component is conservative.
So out of that family of curves that we
have developed for the power uprate containment
analyses, gone back and compared that with the decay
heat curve that we are using in the SAFER analyses.
And on a nominal basis, considering that
we are going from mid-cycle to end-of-cycle exposure,
given those differences, the decay heat that we are
coming up with now, that bounding envelope, is maybe
a half-a-percent higher than what we had in the
original SAFER curve.
DR. SIEBER: Could I make an attempt to
ask about the Appendix K --
MR. PAPPONE: I haven't even gotten to the
Appendix K yet. The other pieces in the SAFER
methodology, the licensing basis PCT, is based on an
Appendix K PCT calculation, and that includes the 71
decay heat, plus 20 percent.
So we have a large chunk of conservatism
that we are introducing in the licensing PCT
calculation.
DR. SCHROCK: And that is done at the end
for what you have established as the worst situation?
MR. PAPPONE: Right. But what we have
done in looking at these containment decay heat
curves, and comparing to what we are using today in
SAFER, we are very close. So I hope that answers your
question.
DR. SCHROCK: I hear what you are saying,
and I am not saying that I don't believe it, but what
I am saying is that I haven't seen the backup details
that make it totally convincing to me.
DR. SCHROCK: I understand.
DR. SIEBER: Maybe we could back up for a
second to the second bullet. When you read that off,
you made a statement that I think I misunderstood,
which was you chose to use G.E. 14 fuel because it is
the hottest fuel?
MR. PAPPONE: Right.
DR. SIEBER: I would think you mean in
comparison to 9-by-9 fuel?
MR. PAPPONE: Yes.
DR. SIEBER: I would think that it would
be the other way around, because you have more surface
with 10-by-10 than you do with 9-by-9.
MR. PAPPONE: If we look at 9-by-9
bundles, or why don't I take the G.E. 9 8-by-8 bundle
if it is in there.
DR. SIEBER: Okay.
MR. PAPPONE: We have got the maximum
linear heat generation rate that we are allowed is
14.4 kilowatts per foot.
DR. SIEBER: Right.
MR. PAPPONE: But we have only got 62 fuel
rods, and they are depending on -- well, we have got
60 fuel rods in there. If we look at the G.E. 14
bundle, its maximum LHGR is 13.4 kilowatts per foot,
a kilowatt per foot lower.
But we have gone to 92 fuel rods in there,
and so if we look at the power remaining slice, we
have got a lot more power.
DR. SIEBER: The density is --
MR. PAPPONE: Right. The total power is
higher.
DR. SIEBER: But the PCT should be lower,
right?
MR. PAPPONE: Well, the PCT is --
DR. SIEBER: Or what is the point of going
to the 10-by-10 fuel?
MR. PAPPONE: It can pack more energy into
that bundle.
DR. SIEBER: For a given set?
MR. PAPPONE: For the nuclear site, yes.
DR. SIEBER: For thermal conditions?
MR. PAPPONE: Right. And PCT is primarily
driven by the LHGR, but the average planer power is
also secondary, but still significant, input.
So, yes, we would expect if we went and
looked at an 8-by-8 bundle, and dropped the LHGR, we
are going to see a large drop in the PCT, a
significant drop. But because we have gone to almost
half again as many fuel rods in that plane, the power
is up about 12 or 13 percent, 12 or 15 percent higher.
DR. SIEBER: Well, it should be up 17
percent if that is what your core average power
increase is. But your surface probably only goes up
10 percent, right?
MR. PAPPONE: When we do the analysis, we
put that hot node -- the hot rod and the hot node
right on its LHGR limit.
DR. SIEBER: Okay.
MR. PAPPONE: So that doesn't move around.
The hot bundle power that we use in the analysis
doesn't change. The average bundle power will change
with the power uprate.
But when we put that hot node on full
power, that is when I am saying the power level is
about 12 to 13 percent higher for that node. So we
end up with a little higher PCT because of that.
DR. SIEBER: Thank you. That clarifies
that for me.
MR. HAEGER: We didn't finish this slide
I don't think.
MR. PAPPONE: Okay. So we did all of the
analyses for G.E. 14 fuel type, and the full break
spectrum, non-recirculation line break, like steam
water, and feed water, and single failure evaluation.
And once we establish limiting cases, we
went back and evaluated those limiting cases using
legacy fuel types, Siemens fuel, and the older G.E. 9
fuel.
And we also did a sensitivity study for
the power uprate. We did all of these analyses at
power uprate conditions. We went back and analyzed a
case of current power condition, where the only
changes in the analysis were the reactor operating
conditions. So we had a true what is the impact of
power analysis on that.
CHAIRMAN WALLIS: Which PCT are you
showing us that you did this analysis for different
fuels? Which PCT are you actually showing us?
MR. PAPPONE: The PCTs are the G.E. 14
PCTS.
CHAIRMAN WALLIS: And the others are
lower?
MR. PAPPONE: Right, except for the upper
bound, we had a little larger sensitivity in the upper
bound for the Siemens fuel. So the upper bound PCT
that we are showing is a little bit higher than the
G.E.
It is based on the Siemens 9-by-9 fuel,
and that was a little higher than the G.E. 14 fuel.
But the other temperatures are the G.E. 14.
DR. SIEBER: Right. Now, let me ask
another question. As you march through the next 2 or
3 fuel cycles, you are going to have a mixture of
legacy fuel and G.E. 14 fuel, which sort of tells me
that when you do your reload safety analysis, unless
you do some pretty fancy things in the fuel design
space, that you won't achieve the extended power
uprate for a couple of cycles. Now, is that true or
not true?
MR. FREEMAN: This is John Freeman. I
think the question as I understand it was because we
don't have a full core G.E. 14, we are not going to be
able to achieve --
DR. SIEBER: Yes, and is that true or not.
MR. FREEMAN: No, that is not true. They
are essentially operating strategies for the first
reload cycle by the enrichment and the guideline
choices that will allow us to hit the expected
targets.
Now, something that you have to realize is
that we are not going to be operating that unit at
2957 right on the money for the whole cycle. We will
be just like John mentioned. We will be cycling the
reactor power up and down to meet maximum generator
output.
So that is all factored into the reload
analysis for any particular cycle. But it is done
-- obviously the safety analysis is always done at the
license conditions, although the energy design will be
for what we expect to operate at.
DR. SIEBER: Now, for a two year cycle,
and changing the fuel -- the number of fuel rods per
assembly, I wold presume that the enrichment has to go
up and to control it you have to add more guidelines?
MR. FREEMAN: That's right.
DR. SIEBER: Doesn't that place more
pressure on your core shutdown margin?
MR. FREEMAN: The core is designed to meet
all of its core shutdown margin criteria.
DR. SIEBER: Well, I understand that, but
the pressure -- the more that you go in that
direction, the harder it is to guarantee to meet core
shutdown requirements; is that true or not true?
MR. FREEMAN: No, actually every core is
designed to meet that criteria. So if the design
doesn't meet the criteria, it is not used.
DR. SIEBER: Well, yes, I understand that.
MR. FREEMAN: So it is a design process.
You either hit the target every time or you don't
operate that particular design.
DR. SIEBER: Well, there is trade-offs
there.
MR. FREEMAN: Yes.
DR. SIEBER: All of your fuel parameters
fit in some kind of a regulatory design box, and
somehow or other you have got to get it in there, and
the way you do it is to spend money, right?
MR. FREEMAN: That's right. You have to
put --
DR. SIEBER: That is usually one of the
trade-offs. And I also would imagine that the fuel
would be most reactive sometime other than the
beginning of life, and obviously not at the end of
life; is that true also, because it is a balance
between remaining enrichment, versus remaining
venerable poisons?
MR. FREEMAN: Where you get into the
transient analysis Chapter 15 type world, which is
apart from this LOCA stuff, yes, the particular core
can be more reactive from a standpoint of a void
coefficient, a doppler coefficient, and all of that is
taken into account.
DR. SIEBER: So about 30 percent of the
cycle lifetime is usually when it is most reactive?
MR. FREEMAN: It depends on the specific
design and the goals that are being met for that
design, and whether it is a spectral shift core, or
whether it is some other goal.
It can change, but it is all within the
approved methodology, and the operating limits and to
include all of that, as well as the LHGR and upper
hydro limits are all protected for any particular
design. And that covers the entire exposure for that
cycle.
CHAIRMAN WALLIS: I suspect that we are
getting behind on time; is that not the case?
MR. FREEMAN: Yes, a little bit.
DR. SIEBER: I should not ask any more
questions I guess.
CHAIRMAN WALLIS: Well, if you are getting
the right answers --
DR. SIEBER: Well, I understand the
answers.
MR. FREEMAN: All right. Let's go on with
this slide then. The approach as Dan mentioned
calculated full spectrum as required by Appendix K.
I would point out that the DBA, which is a break of
the recirculation section line, was a limiting case
for this analysis.
Of course, small breaks and other selected
breaks were evaluated, and per Appendix K, the
limiting single failure was determined and it is the
diesel generator failure.
And on page 30, I will just go over some
of the results that I --
CHAIRMAN WALLIS: I guess I thought when
I read the SER that the steam line break brought the
drywell air and shell temperatures very close to the
limits, and yet you said --
MR. HAEGER: This would not be for the
LOCA analysis, but for peak clad temperature.
CHAIRMAN WALLIS: It is peak clad
temperature that is the limiting analysis, but for the
containment, it may be something else.
MR. HAEGER: That's correct.
CHAIRMAN WALLIS: Now, is this true that
this upper bound PCT is exactly 1600 Fahrenheit?
There must be some kind of a do-loop in this program.
MR. PAPPONE: Well, no. Well, actually
there is a do-loop in the process, and that's where
were if we do calculate a value above 1600 degrees,
and we run out of fancy tricks to bring it back down
to 1600 degrees, we have imposed a map of outer limit
on the plant to keep the PCT below 1600 degrees.
In this case the calculated answer came
out to be just below the 1600 degrees. What we do
when we report these temperatures, we run the
calculated number up to the next 10 degrees, because
I don't want to say that I calculate that number to
four significant factors.
CHAIRMAN WALLIS: Is this what determines
the 2957 megawatt thermal?
MR. PAPPONE: No.
CHAIRMAN WALLIS: It's not?
MR. PAPPONE: Even if we had to impose a
map of outer limit, and keep the fuel from going up to
the 13, there is still margin in the core design world
to absorb that without affecting the overall plant
power uprate.
CHAIRMAN WALLIS: What is the upper bound
PCT with the existing power level?
MR. FREEMAN: The upper bound PCT with the
existing power level? I think I have it here.
MR. PAPPONE: Do you mean current
licensing basis?
CHAIRMAN WALLIS: Yes, current licensing
basis.
MR. FREEMAN: I believe for Quad Cities it
is below 1600.
CHAIRMAN WALLIS: Well, it better be, yes,
but what is it? It just seems high to me. When we
were looking at Duane Arnold, I don't think that we
had anything like such a high PCT. Why does it come
so high in this case?
MR. PAPPONE: I believe there is a big
difference between the Dresden and Quad plants and
Duane Arnold. Duane Arnold is a very small vessel,
and a very small core, and as a result, when they did
the plant design, they used a smaller recirculation
pipe.
Their recirculation pipe diameter is a 22
inch pipe, and Dresden and Quad Cities, and the rest
of the BWR-3s and 4s, it is 28 inch pipe. So we are
looking at for Duane Arnold, their break size is about
60 percent of the Dresden and Quad.
And if we looked at the Appendix K PCTs
for the two plants, if we looked at Dresden's and
Quad's 60 percent and Duane Arnold's hundred percent
break size, they are fairly close.
CHAIRMAN WALLIS: Could you get that
number that I was asking about, the current licensing
basis upper bound PCT? I think it ought to be on one
of your transparencies, but I am not sure it is.
MR. FREEMAN: We will get back to you on
that. Okay. I think we are on page 30. What we are
looking at here --
DR. SCHROCK: Excuse me, but you mentioned
the question of accuracy on the PCT. There is also
the question of accuracy on the power level of the
plant. When you talk about 1957 or whatever the
number is, plus or minus what on that?
MR. PAPPONE: The Appendix K calculations
include the 2 percent core power, and also on the
linear heat generation rate, peak linear heat
generation rate, and that is also factored into the
initial CPR that is used in the analysis.
DR. SCHROCK: No, what I am asking is how
accurately do you know what the true thermal power is
in the plant?
MR. PAPPONE: Well, it is within that two
percent and --
MR. HAEGER: That is what 90 percent is
for, is the uncertainty.
MR. PAPPONE: Right.
DR. SCHROCK: Well, that is a nominal
value that was written into law a long time ago, but
that isn't the true uncertainty in what you know to be
the case. So what I am asking is what is your known
accuracy of thermal power of the plant at any given
instance?
DR. SIEBER: It is generally one percent,
right? It comes out of a calimetric calculation,
which used to be 2 percent, and that's why they put
the 2 percent adder on to the core thermal power when
it improved their ability to calculate that with
improved flow instruments and temperatures.
MR. HAEGER: Right, and in fact many
plants of course are taking small uprates because they
are demonstrating their uncertainty --
DR. SCHROCK: They have reduced that
uncertainty.
MR. HAEGER: Right.
DR. SIEBER: So the increment of margin
that is in these calculations fully encloses the
uncertainty of the calimetric calculation, at least in
my opinion?
MR. HAEGER: Yes.
MR. FREEMAN: Okay. Page 30, these are
the results for the LOCA analysis; a peak clad
temperature of 2110 degrees, which is less than the
5046 limit at 2200.
As Dan mentioned before, we talked a lot
about the upper bound and I won't go into that
anymore. The local oxidation was 6 percent, which is
below the 17 percent limits for 5046.
Similarly, the core wide metal-water
reaction was .1 percent, and it is well below the one
percent limit, and of course the other 5046 criteria
are met.
What this analysis showed that was done
for the PSAR was that the effect of the power uprate
on peak clad temperature was less than 10 degrees, and
that is consistent with what GE has seen with other
plants.
CHAIRMAN WALLIS: And so going back to my
question before then, that means that on the current
licensing basis, it is something like 50.90 something?
MR. FREEMAN: The current licensing basis
does not have G.E. 14 fuel.
CHAIRMAN WALLIS: Like I was saying the
EPU effect on PCT less than 10 degree fahrenheit, that
presumably means upper bound PCTs is 1590.
MR. FREEMAN: Well, remember that we
stated earlier that this comparison was done strictly
with G.E. 14, and the only change being the power
uprate. That was for purposes of determining what the
effect on PCT was of the increase in power.
So with the different methods and fuel
types that the other plants currently have, that 10
degrees wouldn't apply that difference.
CHAIRMAN WALLIS: So the effect of fuel
type is some other number of degrees fahrenheit, which
we don't know here?
MR. FREEMAN: That is right.
CHAIRMAN WALLIS: But you are saying it is
a small effect, and the message that you are trying to
convey would seem to me is that EPU has small effect
on PCT, and it may well be that the change in fuel
type has a bigger effect than the EPU.
MR. HAEGER: That is precisely right.
MR. FREEMAN: That's right.
CHAIRMAN WALLIS: So we maybe ought to be
discussing changes of fuel type, and that is another
meeting altogether isn't it?
DR. SIEBER: Yes.
MR. FREEMAN: Yes.
MR. HAEGER: Yes, it is a separate license
amendment request that we have before the Commission.
MR. FREEMAN: Okay. Moving on to page 31,
I just want to apologize for this first bullet here.
It says that the EPU effect on large break LOCA, and
in the subbullet, really as you mentioned, sir, it is
the G.E. 14 effect on the large break LOCA that
motivated us to make a set point change in the swing
bus delay timer.
And it really wasn't the power uprate.
This was something that came from the use of G.E. 14
fuel, and I think that John mentioned that swing bus
set point change already.
Whereas, the really big effect of the
power uprate was on the small break LOCA and that was
expected because of the higher decay heat values.
To summarize, before power uprate, we
could afford to have one ADS value out of service, and
we could get adequate depressurization for small
breaks with four ADS valves.
However, at extended power uprate
conditions, the analysis showed that we needed all
five of the five ADS valves to operate in order to
keep our upper bound PCTs below the 1600 degrees.
CHAIRMAN WALLIS: Does this only affect
the risk?
MR. FREEMAN: I believe the impact upon
the risk will be discussed.
MR. HAEGER: We will be discussing that
later.
MR. FREEMAN: Moving on to page 32. In
conclusion, the emergency core cooling analysis
methodology that is being used is conservative, as
well as accepted by NRC.
The licensing basis PCT is a conservative
way of calculating the result based on Appendix K
models. In conclusion, after meeting all 5046
criteria, the emergency core cooling system
performance is acceptable at the power uprate
conditions.
And unless there are any other questions,
I will introduce Tim Hanley, and he is going to go
over the thermal-hydraulic stability.
CHAIRMAN WALLIS: Thank you very much.
MR. FREEMAN: You're welcome.
MR. HANLEY: I am Tim Hanley, and I am a
senior reactor operator at the Quad City station.
Jason Post of General Electric will be talking about
the background methodology and analysis results, and
then I will be covering operational aspects and
conclusions.
CHAIRMAN WALLIS: I would like to ask
where we are on the presentation, and when I discussed
with Exelon earlier, and we thought that we could have
a break before the risk evaluation, but I noticed that
we don't even seem to be about half-the-way there yet.
MR. HAEGER: What we thought that we would
try to do is to get through the slide and all the
analysis on that slide that stated the selected
analyses.
CHAIRMAN WALLIS: Well, that will get us
up to slide 70 something, and we are only to 34 now.
MR. HAEGER: Yes.
CHAIRMAN WALLIS: Can we do that in half-
an-hour or 40 minutes, or something? We may have to
break before we intended to break.
MR. HAEGER: And we can certainly work
around whatever break time you want.
CHAIRMAN WALLIS: We are behind where we
thought we would be.
MR. HAEGER: Yes.
MR. HANLEY: With that, I will turn it
over to Jason Post of General Electric.
MR. POST: This is Jason Post. Dresden
and Quad Cities are still operating with a BWR owners
group interim corrective actions in place. They have
-- the ICAs provide manual prevention and suppression,
and they have been in operation for something over 10
years now with those in place.
They have not yet implemented the
stability solution, and the stability solution that
they have selected is Option 3, and Option 3 is a
robust detect and suppress solution.
It requires some new hardware, the
oscillation power range monitor, the OPRM. The OPRM
has been installed, but it has not been operational
yet, partly as a result of the Part 21 notification
that G.E. issued earlier, this summary of the DVOM
curve.
It is a robust detection algorithm that
looks at LPRM signals, and determines when an
oscillation occurs, and if the oscillations go up to
a set number of oscillations in a row, called the OPRM
count, and the amplitude reaches a certain set point,
and that occurs within what is called the trip enabled
region, then the OPRM will give an immediate SCRAM.
The next slide shows the ICA power flow
map, with the ICA regions on them, and the key thing
to note here is that the absolute power and absolute
flow on the region boundaries has not changed.
They have been effectively rescaled so
that you maintain the same absolute power and absolute
flow on those boundaries. And just the way that the
ICAs work, ICA in Region 1 is an immediate SCRAM
region.
So if they were to get a flow run back
into that region, there is an immediate manual SCRAM
by the operator based upon simply being in that
condition.
It is not -- it doesn't require
determining that an isolation has occurred or
anything. You get an immediate manual SCRAM. Region
2 is an immediate active region, and so if there is a
run back into Region 2, the operator immediately
inserts control rods or reduces core -- I'm sorry,
increases core flow to exit that region.
Region 3 is called a controlled entry
region, and under the Owners Group ICAs, you are
allowed to enter that region if you have a stability
control. For example, high core boiling boundary,
which makes the core more stable.
And actually for Dresden and Quad Cities,
they have just assumed or have included Region 3 as
part of Region 2. So it makes the immediate exit
region include both of those two regions.
CHAIRMAN WALLIS: And where does this
Option 3 OPRM -- well, where does that fit in that map
in terms of where it would SCRAM the reactor?
MR. HANLEY: That is shown on the next
slide.
MR. POST: Let me just say that before we
go to the next slide, to remember that the purpose of
the ICAs is to prevent a reactor instability, and if
one does occur, to have a manual SCRAM.
So it is drawn to be a limiting condition
for where you would expect instability to occur.
CHAIRMAN WALLIS: I would expect the
limits of his OPRM to be sort of inside the other
boundaries.
MR. POST: It actually needs to be larger.
CHAIRMAN WALLIS: Larger?
MR. POST: Yes, it needs to be actually
larger, and the reason is that because you want to
make sure that it encompasses the area in which an
instability could possibly occur.
CHAIRMAN WALLIS: Well, it encompasses it,
but where you actually predict that it is likely to
SCRAM the reactor is going to be a smaller region than
where the operator would do it.
MR. POST: Yes.
CHAIRMAN WALLIS: Otherwise, it would
always be done automatically.
MR. POST: That's correct.
CHAIRMAN WALLIS: So the actual -- what
you expected to really happen is a fairly small region
up in the corner there somewhere?
MR. POST: Yes. If you were to draw a
line of constant decay ration, and if you could go to
the next slide, please. The line of constant decay
ratio would be somewhere in here.
CHAIRMAN WALLIS: It is way up in there.
Right. Right.
MR. POST: And so that is the reason that
you would expect oscillation would actually occur, and
the OPRM and trip enabled region is defined to be well
outside that region.
Again, for the trip enabled region, what
we do is rescale the region boundary so that the
absolute power and flow condition is maintained the
same as the pre-uprate condition.
MR. BOEHNERT: When is the Option 3 going
to be implemented?
MR. HANLEY: For Quad Cities and Dresden,
they will implement that when the Part 21 notification
has been resolved. Even plants that have already
enabled that have gone back to the ICAs as a backup
because it is non-conservative in some points. So as
soon as the Part 21 issue is resolved, we will be trip
enabling that system.
MR. POST: We are working with the BWR
owners group on that, and it will probably be a year
from now before it is actually -- the new subpoints
are defined and it is ready to go.
Just moving on to the next page then, on
the analysis results, we did a demonstration analysis
for the demonstration EPU core on the OPRM setpoint
simply to demonstrate that that calculation can be
performed.
It is a cycle specific calculation and is
done for each reload. The three elements of it are
the hot bundle oscillation magnitude, and that depends
upon the OPRM hardware. It is unaffected by EPU,
MELLLA or G.E. 14.
It is strictly related to the LPRM
configuration. The second part is the CPR change
versus oscillation magnitude, and that is known as the
DIVOM curve, and that is currently being revised by
the owners group and G.E.
And the third part is the fuel specific
CPR performance and limits which are addressed in the
cycle-specific analysis. So we use all those elements
to calculate what the OPRM set point is that provides
safety limit protection for our reactor instability.
CHAIRMAN WALLIS: Well, that doesn't mean
anything ot me at all. That is so full of acronyms
and --
MR. POST: I'm sorry?
CHAIRMAN WALLIS: It didn't mean anything
to me at all.
MR. POST: Well, I'm sorry.
CHAIRMAN WALLIS: I am not sure that you
can make it clearer, but --
MR. POST: The OPRM is the oscillation
power range monitor, and that is the new piece of
hardware that you install specifically for Option 3.
CHAIRMAN WALLIS: Yes, I understand that.
MR. POST: And it has an amplitude sub-
point, and so as the oscillation grows, it is a
normalized value --
CHAIRMAN WALLIS: So that is on the
reactor when the oscillation is big enough, and I
understand that.
MR. POST: Yes.
CHAIRMAN WALLIS: But this business about
the DIVOM curve.
MR. POST: DIVOM stands for delta CPR over
initial CPR, versus oscillation magnitude. Hence the
acronym, DIVOM. And that that is, is just how much
does CPR change as a function of the fuel type.
What we found for the Part 21 when we did
the Part 21 notification is that we had a generic
curve, and we found out that we were a little bit
overestimated in the generic applicability of that
curve, and some specific factors were not fully
addressed.
And so that resulted in the Part 21
notification, and we are developing what a new DIVOM
curve should be. It is likely to be more plant and
cycle specific, and factor in the specific parameters
that affect that curve.
CHAIRMAN WALLIS: Well, if you are
developing something, what has that got to do with
application for a license now?
MR. HAEGER: We should probably go back
and put this in perspective. We are going to start up
using interim corrective actions, which is what we
have been operating on for quite some time. And what
we are trying to show in this slide, number 36, is
that those interim corrective actions are applicable
to the EPU power level.
And so really until this Part 21 issue is
resolved, all this discussion about the OPRM system
and these DIVOM curves is somewhat moot right now.
CHAIRMAN WALLIS: So does that mean that
we have to move on? Now, this is the drunken man's
walk; is that what that is?
MR. HANLEY: This is Tim Hanley again from
Exelon. I am going to go over some operational
considerations in discussing stability. What you see
on the screen now is a picture of the power flow curve
with the actual data from our last Unit 2 start up.
Two real operational concerns when talking
about thermal hydraulic stability is, first, we want
to avoid entering the regions of potential
instability.
The real concern there is do you have
enough room between your cavitation interlock line
down here, which is the point at which you can
increase your recirculation pump speed, and the bottom
of the instability region. It is quite a bit of
margin and not difficult to avoid that region during
the start-up.
So that is the initial thing that we do,
and the other consideration is what do you do if you
enter one of the regions of instability, or potential
instability inadvertently. The recirculation pump
trip is evaporating at a high flow control line at low
power.
There is a potential if you are operating
at low power, low flow, loss of heat core heating can
raise your power levels in those regions. So what do
you do if you get there?
Jason mentioned that you have two options;
inserting rods or increasing flow. Neither Dresden
nor Quad Cities do we have increasing flow as an
option. We always insert rods to decrease your flow
control line.
So if the operator gets in the instability
regions, they will monitor for instabilities, and what
they are looking for is about a two times change in
the noise level on the nuclear instrumentation --
SRMs, LPRMs, or ATRMs.
CHAIRMAN WALLIS: Well, there is nothing
new about extended power about this.
MR. HANLEY: No, the only thing different
-- and maybe since we are running behind we ought to
keep it at that, but the only thing is that the
potential instability region has expanded, because we
are going to higher power.
And that area that comes off of the top
there that kind of jets out is a new region of
instability, and anything above our current 108
percent MELLLA region is new.
But the operator action flow won't change,
nor will the OPRM change, when we install that. The
region will just be expanded. So in conclusion,
really we intend to start up with the ICAs in place
that we have been operating under to implement the
OPRM, and trip enable that when the Part 21
notification is completely settled and we can do that
at the right opportunity.
We have rescaled the instability region,
and so we have maintained our absolute levels for when
we say we are entering the regions of potential
instabilities, and that power uprate doesn't
significantly affect how we would handle instabilities
and our analysis is acceptable for power uprate with
thermal-hydraulic stability. Any questions?
DR. SCHROCK: Maybe it is not important,
but there is a curious effect here on this particular
curve. It looks like you went up initially, and then
you kind of dwelled for a while with rods in and out
jingling a little bit. Is that the way they really do
it?
MR. HANLEY: What you have got here -- you
are talking about the 25 percent power level?
DR. SCHROCK: Forty percent, 40 percent
flow. Well, 30.
MR. HANLEY: And then it is about 25 or 30
percent power. WE do a lot of testing at that point,
turbine testing, to verify all the turbine trip SCRAMs
are all operational. So we do end up staying at that
power level for a while during a start up.
It is also kind of jagged. I did get
this, I believe, off of 15 minute increments of data.
So that is why it tends to jump around. It is not a
smooth curve because I didn't go to minute data.
But there are certain points where we
spend more time due to required testing, and that in
particular is the turbine testing.
DR. SCHROCK: Well, can the thermal power
change by as much as this spread and data point shows
without rod movement?
MR. HANLEY: Certainly.
CHAIRMAN WALLIS: And another question
becomes how about --
MR. HANLEY: You are looking at flow
though, right?
DR. SCHROCK: Well, flow is constant
there, that group of points that I am looking at.
MR. HAEGER: I don't know that we can
resolve them that clearly. The resolution isn't --
MR. HANLEY: You are looking just at that
little glob of points in there?
DR. SCHROCK: Right. Yes. I am curious
about why they would stop there, and it looks like
there almost was in and out rod jiggling.
MR. HANLEY: What you really see is the --
you are getting -- depending on how long you stay
there, you will begin to see some zenon build in, and
so you may be pulling some rods. You may be adjusting
recircs to compensate for that.
And like I said, during this start up, you
may sit there for as much as eight hours doing your
testing. So you will in fact be adjusting power at
that point.
CHAIRMAN WALLIS: And then there is the
jingling around at the hundred percent core flow, and
one has to wonder how much jingling around you would
do if you got to Point D in your uprate.
MR. HANLEY: Essentially, the way you can
operate is that right now we have this band to operate
in from our permanent 100 percent power out to the
current 108 percent flow control line.
You operate on that line and adjust your
recirc flow so that as your Zenon builds in, you will
pull up to above the hundred percent flow control
line. Zenon builds in your adjust recirc pumps to
stay at that same power level.
The operating band we will have is
actually between charlie and delta up here. So we
will in fact be adjusting recirc flow at the higher
power level or doing some power rod moves.
But we do have an operating region that we
will be able to operate in so that the operators won't
constantly be pulling control rods. They will be able
to make slight adjustments in recirc flow and maintain
full power.
CHAIRMAN WALLIS: But they still won't go
over 2957 megawatts while they are doing that?
MR. HANLEY: No, we won't go over 2957
megawatts, and until we do modifications to the
generator, it is unlikely that we will even get there.
We will actually be operating at a lower
thermal power level because we will be limited by the
capability of the generator.
MR. HAEGER: But I think the point is that
you do calimetrics frequently to determine that you
are not over the --
MR. HANLEY: Oh, certainly. We have a
computer program that warns us if we get within five
megawatts thermal of our rated thermal power. So the
operators -- it runs on a -- every two minutes. So
they will --
CHAIRMAN WALLIS: So it is definitely an
upper bound. I mean, it is almost the impression that
is being given that with the line through that orange
jiggling around that you can jiggle around some set
point or something. But actually the 2957, that is an
upper bound isn't it?
MR. HANLEY: Well, if you draw crosses,
and the top of the crosses are all very much the same
place. So the actual data goes --
CHAIRMAN WALLIS: But the top of the
crosses would be the 2957 if you ever get there.
MR. HANLEY: The middle of the cross.
MR. HAEGER: The middle of the cross.
CHAIRMAN WALLIS: The middle of the cross?
MR. POST: This is just a plot in XL.
MR. HANLEY: XL uses the point to put a
cross at --
CHAIRMAN WALLIS: Okay. So it is not the
line that is jiggling around. All right. Okay.
MR. HANLEY: Are there any other
questions? With that, I will turn it back over to
John Freeman and Jason to discuss ATWS.
MR. FREEMAN: Thanks, Tim. We are going
to talk about anticipated transient without SCRAM, and
Jason is going to go over some of the methodology and
assumptions.
CHAIRMAN WALLIS: I guess if you are using
established methodology and assumptions we can skip to
the results.
MR. FREEMAN: Surely.
MR. POST: That would be great. We did
have one slide in here on ATWS instability, or
actually two slides that I am prepared to cover. As
we discussed previously when I was here for Duane
Arnold, the two reports were NEDO-32047, which was the
instability with no mitigation; and the 32164, had the
instability with mitigation.
And our previous argument was that these
generic studies were applicable to EPU and MELLLA, and
there was some question about that. We since our last
meeting, we have done a sensitivity study at a more
limiting condition.
It is on a rod line actually above the
MELLLA line. It is for an EPU condition, and it is
for G.E. 14, and we have finished the no mitigation
study, and it showed a less severe fuel response than
we showed previously in the topical report with no
mitigation.
In other words, it had less susceptibility
to the extended dryout. It still could experience the
extended dryout, but it took a little bit longer time
to get the oscillation that put it into that
condition.
So this confirms our expectation that the
generic studies are valid for EPU and MELLLA, and
confirms our expectation that the mitigation actions
will be effective.
MR. FREEMAN: Okay. I would like to skip
forward to page 47. These are the results for the
five criteria and the limiting event. You can see
over here the peak pressure of 1492 was below the
acceptance criteria of 1500.
For the peak pool temperature, 201 was
below this 202 degrees, which I think Mark may have
mentioned was the TORUS attached piping limit that was
analyzed for the LOCA.
It turns out -- and you probably remember
that 281 was a structural limit for the suppression
pool. But these results show that they are quite
acceptable.
CHAIRMAN WALLIS: So you are again pushing
the limit on pressure and temperature, the 1499 versus
the 1500?
MR. FREEMAN: This 1499 is for transition
core, and that included -- all these analyses were
done with exactly the same inputs, and they have
conservatisms built in.
So we would actually expect not to see a
pressure like this. That is a conservative number.
CHAIRMAN WALLIS: But in terms of the
criteria, you are just meeting the criteria.
MR. FREEMAN: Yes, sir. Of course, with
the peak suppression pool temperature, it is very low,
and the peak clad temperature is also very low, which
has a negligible maximum local oxidation.
So in every case for ATWS, which is a
beyond design basis event, this demonstrates that the
50.62 criteria can be met.
CHAIRMAN WALLIS: Doesn't this depend on
valves opening and that sort of thing, and numbers of
valves?
MR. FREEMAN: Yes.
CHAIRMAN WALLIS: And do you have to have
more valves open in this case than before, or is that
a different --
DR. SIEBER: It depends on the success
criteria.
MR. FREEMAN: The ATWS analysis takes
credit for all the relief and safety valves as is
typical for ATWS analysis.
MR. HAEGER: However, in the PRA study, we
will be discussing --
CHAIRMAN WALLIS: Yes, you need one more
valve to show the open.
MR. HAEGER: That's correct, and we will
be talking about that.
MR. FREEMAN: Okay. With that, I would
like to introduce Norm Hanley, and he is going to talk
about the piping analysis.
CHAIRMAN WALLIS: With the ATWS, there is
no requirement about operator reaction time in any of
the ATWS regulations? It only appears in the PRA?
There is nothing in the --
MR. POST: That's right. There is nothing
in the regulation that specifies what the minimum or
maximum operator action time is.
MR. N. HANLEY: Good afternoon. I am Norm
Hanley, and I am the test manager for the piping
evaluations that were performed for the power uprate
for Quads and Dresden City.
I am going to present the methodology that
was used to do the piping evaluation, and the actual
impacts as a result of the EPU, and what the
disposition and conclusion, and results of those
evaluations that were performed.
The impact of the power uprate would be a
change in the operating conditions, flow pressure and
temperature in some of the fluid systems. In order to
evaluate those systems, we reviewed the plant specific
criteria to identify those parameter bases for the
existing analysis.
We also as part of that review identified
what the original code that was used, the analytical
techniques that are used consistent with the license
spaces, and also the code allowables.
The one exception to this was that we
developed some criteria for the main steam piping
consideration for dynamic loads due to a turbine stop
valve, and I will address that in my presentation.
The conclusion in the initial review was
that the majority of the piping systems were not
impacted by the power uprate. The methodology that
was employed to evaluate those systems that were
impacted was a simple evaluation to identify what we
call a change factor.
This looked at those parameters such as,
for instance, in temperature, and if the temperature
changed or the operating temperature would be higher
for a power uprate, we simply looked at that delta
change and compared it to the original analysis basis.
And if the comparison was the post-uprate
versus pre-uprate was greater than 1.0 the ratio, then
we would evaluate it further. Any ratio less than
1.0, the pre-uprate conditions were bounding, and no
further analysis was required. For minor changes in
the parameter --
CHAIRMAN WALLIS: There didn't go for
pressure or anything like that. This didn't go for
vessel pressure? This is just piping?
MR. N. HANLEY: This is piping, correct.
Now, for minor changes, where the parameter change was
between 1.0 and 1.05, again we considered the change
acceptable.
And this is based on a conservatism in the
original analysis, and some of these conservatisms
where the initial inputs were conservative, the
combination of loads, and incorporating loads that had
been changed for the power uprates for seismic and
dead weight, and also due to the inherent analytical
techniques where there were gaps between piping and
pipe supports were not included.
DR. SIEBER: Could I interpret this to say
that if it was less than 5 percent, you didn't bother
to find out where the conservatisms were, or whether
it was conservative or not? You just said it was
okay?
MR. N. HANLEY: Right. And that was based
on experience with the piping systems and evaluations
that we performed. We have done a number of power
uprates where we have used this application.
MR. HAEGER: Realize that we are taking
one parameter and if it changed five percent, there
are all the other factors in the equation that we are
seeing, there is conservatisms in there. So that is
the basis of that.
MR. N. HANLEY: I think when I present the
systems that were impacted and where we did further
evaluations, we will see what -- I think we can
support some of that argument there.
Where the change factors were greater than
1.05, we did take the next step, which was to look at
that ratio. Let's say, for instance, the ratio is
1.1, and we would take that parameter and scale the
existing peak load up, and see if it was within the
acceptance criteria of the code allowables.
And gain if it was less than the code
allowable acceptance criteria, the analysis was
acceptable. Now, for cases where we couldn't do that,
we did go back and reevaluate or reanalyze the piping
system, and if needed we would do modifications.
The most notable change area was the
temperature change due to the TORUS border temperature
increase. The increase was approximately about a 20
degree temperature change for the pre-uprate and the
post-uprate.
We did have to do reanalysis and
modification for this system. However, the
modifications were isolated primarily to piping
supports, and in existing supports, we didn't have to
add new supports.
Those changes resulted in like the
replacing of U-bolts, the modification of the base
plates, structural members, et cetera. The most
noticeable change was that we did have to replace the
rigid support with a snubber to reduce the piping
loads on the flange connection.
So I think that type of analysis, rigorous
analysis that we did there, a significant change
resulted in that.
CHAIRMAN WALLIS: Were there any changes
that ACRS needs to worry about? I mean, changing
bolts and snubbers --
MR. N. HANLEY: These were minor
components to the existing supports, and just to show
that their load capacity could be handled. The other
significant change that we had was the main steam
piping, where we incorporated the dynamic loads due to
a turbine stop valve closure event.
The original design for Quads and Dresden
is based on static load conditions outside
containment, and a dynamic load condition inside
containment for a safety relief valve-load. It did
not include the turbine stop valve loads.
We evaluated the impact of the uprate on
a turbine stop valve closure event, and since we do
increase flow approximately 20 percent, we felt that
it would be prudent for us to include the impact of
that turbine stop valve closure event.
The evaluation identified that there was
significant impact on the loading on the piping system
outside containment, as well as the piping supports
and drywell steel on the inside of the containment.
The resulting evaluations required modifications.
CHAIRMAN WALLIS: That's because the
closure is rapid; is that it?
MR. N. HANLEY: Yes, you have a very rapid
hundred milliseconds or what it is, and so you have a
significant on the change. So the approach that we
took to the evaluation of that was that we wanted to
make sure that for a turbine stop valve closure event
itself that we didn't have a defamation of the piping
system.
And also we looked at it coupled with a
seismic, and we wanted to maintain structural
integrity with a seismic event resulting from a
turbine stop valve closure.
So the approach that we used was there
would be no loss of structural integrity coupled with
a seismic event.
DR. SIEBER: Well, you probably had a
number of stop valve closure events in the history of
these two units.
MR. N. HANLEY: Correct.
DR. SIEBER: Did you get damage?
MR. HAEGER: We have never seen damage.
CHAIRMAN WALLIS: Well, damage in terms of
broken snubbers is a pretty minor thing compared with
a safety --
MR. D. HANLEY: Right. There was no
identified or reported when we did the evaluations.
And again the piping system itself is -- that when we
evaluated it and used conservative assumptions, then
you would see the overload on the existing snubbers
and supports.
So the result was that for the piping
inside containment, the changes to the existing
snubbers, we replaced some with higher capacity. We
had to replace some members with higher members.
We also had to evaluate the drywell steel
which was supporting -- taking a load from the
supports. There we had to stiffen up the connections
to take the increased load capacity.
The more significant changes were outside
the containment, where the piping as I mentioned
earlier was a static load design. We did have to add
supports to take the lateral loads.
The main supports were -- well, we put in
specially designed clamps with a box frame support at
the main steam header to take the load, and we also
had some lateral guides through the G-line wall at
Dresden.
Quad Cities is similar, and we added some
supports on the main steam lines, and these were more
towards the main steam isolation valve in the tunnel.
Again, we used the specially designed clamps with
vertical and horizontal struts.
DR. SIEBER: You would have had to do that
whether you were doing an uprate or not, right?
MR. HAEGER: As he said, they were not
designed, originally designed for these dynamic loads.
DR. SIEBER: But they should have been,
right? I guess in '68, which is the code of record,
it was not in the code of record?
MR. HAEGER: That's correct.
CHAIRMAN WALLIS: Okay. Go to your
conclusion.
MR. N. HANLEY: Yes. The conclusion is
that the piping analysis demonstrated that the piping
will meet acceptable requirements based on the --
consistent with the current licensing design basis.
CHAIRMAN WALLIS: But you have made them
acceptable.
MR. N. HANLEY: We made them acceptable by
doing modifications in the TORUS attached piping area,
and also we incorporated the TSV loads, and made those
analyses acceptable as well.
So the conclusion is that with the
modifications and the reanalysis the piping systems
will be adequate for an extended power uprate.
CHAIRMAN WALLIS: I am inclined to think
that we should go to this next one, reactor and
internals, and perhaps take a break after that.
MR. N. HANLEY: Actually, the next two fit
real nicely together, and the second one can be short,
but either way.
CHAIRMAN WALLIS: Well, let's see how we
do. We are getting pretty close to the time where we
are going to need a break. So, let's go ahead with
reactor and internals.
MR. N. HANLEY: I would like to introduce
Keith Moser now to discuss reactor and internals.
Thank you.
MR. MOSER: Hello. My name is Keith
Moser, and I am the reactor and internals program
manager for Exelon, and I want I want to cover today
is the scope and methods that we used to evaluate
reactor and internals for power uprate conditions.
And the effect that EPU had on those
components, and the modifications that John Nosko
talked about earlier. And then finally conclusions.
Before we even started the power uprate
project, Exelon and G.E. had developed an asset
management strategy that took into account the
industry information both from the domestic fleet and
G.E.'s worldwide experience, and compared that against
what we had done in our inspection program and
operating history at Dresden and Quad.
And we came up with susceptibility
rankings for each one of our components, and at that
point what we did is that we came up with inspection
strategies, mitigation strategies, and finally repair
strategies if we needed them.
Now, for EPU, we again went component by
component and one of the first ones that I wanted to
go over was the fluence issue that was just talked
about earlier.
Now, back in 1992 -- and, John, if you
don't mind holding that up. Back in 1992, we wanted
to take advantage of two co-case. The first one was
co-case 640, and the next one was co-case 580.
And especially for Quad Cities and
Dresden, it lowered our temperature at which we did
hydro tests from about the 212 range by 50 degrees to
55 degrees.
And in doing this, we went back and looked
at what fluence calculation was done in the past. The
fluence calculation of record was for the Southwest
Research, and what they had done is that hey had
actually taken capsule pools from all four units and
the capsule pools ranged after they scaled them up
from 3.5 times 10 to the 17th neutrons per centimeter
squared, all the way up to 5.1 times 10 to the 17th
neutrons per centimeter squared.
In our evaluations, we took the most
bounding and said this is where we are going to do our
fluence calculations for the 1999 and 2000 PT curves.
What we have come to find out after we
have done the neutron transport calculation for power
uprate is the following. Yes, we are lower than what
was previously put into the PT curves that was done by
Southwest Research, but we have an explanation of why.
And I just got that from my expert, Gida
Boo, and Sam Ranganath, and Brian Frue, and Betty
Bramlin at G.E., and what we think has happened is
when they modeled their capsule with their fluence
methodology, they had it right up against the reactor
wall.
They did not take into account about a
little over one inch gap and that difference is where
we think a lot of this can be explained. We also
understand that the methodology at that point in time
didn't require you to model the jet pump in the -- I'm
sorry, the fast flux calculation.
Those type of things make it not an apples
to apples comparison. Now, there are improvements in
the methodology, and we are following the new NRC
requirements, but we honestly think it is the spacing
that they did not take into account for the capsule
itself.
CHAIRMAN WALLIS: Now, tell me more about
this. The capsule, it is an experiment? They put
something in there?
MR. MOSER: That is a sample capsule that
he put right in the belt line region.
CHAIRMAN WALLIS: So it is an experiment.
You put something in.
MR. MOSER: It is on a bracket that is
held away from the vessel walk and the distance like
I was saying is a little bit over an inch. And if you
don't model that, even though it is not that far, just
the attenuation through that one inch gap, or 1.75
inch gap, is enough to make a significant difference.
MR. HAEGER: Let me make sure that we have
the right perspective on this. When we applied for
the EPU application, we used the G.E. improved fluence
methodology that Keith is describing now. That
calculation showed that our fluence is actually lower
than what we had projected.
DR. SIEBER: So the bottom line is that
you made out, right?
MR. HAEGER: Right, although -- well, let
me finish though. At the time that we had our
application in, that methodology was being reviewed by
the NRC staff and had not yet been accepted.
CHAIRMAN WALLIS: But it has now been
accepted?
MR. HAEGER: It has now been accepted, but
there are some data that G.E. needs to collect over
the next couple of years to do some verifications.
CHAIRMAN WALLIS: So is it true then that
the actual fluence has probably gone up, but the
calculated fluence has gone down?
MR. HAEGER: That's correct.
MR. MOSER: As you would expect.
MR. HAEGER: That's correct. But to put
the final note on this, currently we are only asking
the staff to approve our application for one cycle of
operation with the current PT curves until this issue
is further wrung out.
CHAIRMAN WALLIS: Will there be some
future better measurements of fluence that we can rely
on, rather than just calculation?
MR. MOSER: Actually, when G.E. did their
methodology, they actually had samples from KKM that
they had pulled, along with the overall sample program
for the industry.
The sample population for BWRs isn't quite
as big as it is for a PWR. As we go in time and we
have more capsules that are being pulled, additional
fluence calculations will be done, and we will make
sure that the methodology is correct.
MR. BOEHNERT: Do you have samples at the
Dresden and Quad Cities?
MR. MOSER: We have samples at Dresden and
Quad Cities, but they are part of the integrated
surveillance program that the BWRVIP is in the process
of pursuing.
DR. SIEBER: And if you had an extended
life license you would not have enough samples to take
you to the end, right?
MR. MOSER: Say that again, sir?
DR. SIEBER: If you went for a 60 year
license term, you wouldn't have enough samples.
MR. MOSER: Well, as an industry, we will
have enough samples, but if we --
DR. SIEBER: You have to use the new
dosimetry methods and you will be okay.
MR. MOSER: Yes.
DR. FORD: How much will the flux
increase?
MR. MOSER: You know, I had Harmeta look
into that for me a whole back, and the nice thing
about Dresden and Quad, because they have got such a
big vessel -- it is a 251 inch vessel, and my power
out of the core is so much lower than a BWR-4 or a
BWR-5, and a BWR-6 of the same size.
At this point in life, I am still below 5
times 10 to the 20th neutrons per centimeters squared
at the eight-four. Now, we have the shroud repairs
already in place, but it is nice when I inspect my
vertical welds on the shroud.
DR. FORD: How much will be the flux be?
DR. SIEBER: Seventeen percent.
MR. MOSER: It is about 17 percent, but
that is based on actually being somewhat lower than
what we had projected with the Southwest Research
methodology.
DR. FORD: Is it more than 17 percent
because you are flattening the --
MR. MOSER: It will be somewhat less than
that.
DR. SIEBER: Well, you don't run it at a
hundred percent all the time either.
MR. HAEGER: Well, I guess the point is
that we didn't do an apples to apples comparison pre-
to-post EPU. We used the new fluence methodology that
showed the decrease in the overall fluence, and not
having done that apples to apples comparison, I don't
think we can tell you.
The point is that it appears to have gone
down from our previous count.
CHAIRMAN WALLIS: And what is the core
shroud --
MR. MOSER: Actually, we have done Noble
Chem, and so that projects the inside and the outside
surface, and we have also done the shroud repair tie
rods at all four units.
And again that takes care of all of the
horizontal welds. So the inspection plan would be the
vertical welds, which we are doing on a good basis.
CHAIRMAN WALLIS: I would guess that at
the time of license renewal application that all of
this is going to be revisited?
MR. MOSER: I am sure it will be.
MR. HAEGER: Yes.
MR. MOSER: You know, going on, the other
areas that I wanted to discuss were related to flow
induced vibration, and there is two issues; the
increase in steam flow, and the increase in the dry
flow. If you would switch to the next slide. The
Dresden-2 --
DR. FORD: Hold on. How much will the
delta-P increase -- well, the --
MR. MOSER: I just read that, and I don't
have that on the tip of my tongue, but we can look
that up and give it back to you. It is not a very
large increase from what I remember.
DR. FORD: So in the risk assessment, and
not the PRA type assessment, but the numerical
assessment, was there taken into account any potential
cracking of the excess hole covers?
MR. MOSER: You know, for three out of our
four units, we have actually replaced the access hoe
cover, and so that risk somewhat goes away. And then
we with the Noble Chem application, and the hydrogen
injection that we are doing, we feel like we have an
adequate basis for mitigating the shroud excess hole
covers.
And for the one unit that we haven't
replaced, we do inspections on a periodic basis per
the SIL (phonetic) and the VIP, and while we are down
there looking at the shroud support, we also look at
the access hole cover. Did that answer your question?
CHAIRMAN WALLIS: Noble Chem is good.
MR. MOSER: Say that again?
CHAIRMAN WALLIS: Noble Chem is good.
MR. MOSER: Yes, I really like that
benefit. Again, for the dry flow, we had the benefit
at Dresden of actually being the first BWR-3 plant,
and so it was well instrumented across all the reactor
or many of the reactor internals component.
And that included the jet pump and the
steam separator. When they did the power uprate, they
varied the levels of power, and they did single loop
and double-loop operations, and then they were able to
extrapolate that information as we went to power
uprate conditions.
The analytical result of that work was
that accept for the eight jet pump sensing lines, I
really have no material endurance conditions that I am
worried about for the components that I have analyzed.
Now, for the eight jet pump sensing lines,
we are slightly increasing our RPM pumps leak speed by
about 25 to 27 RPM. And we are so close. One thing
that is somewhat unique about Dresden and Quad is we
have six vain and pillar rather than a five vain and
pillar at Peach Bottom and Limerick.
And when you do that, and just have a
slight increase, you have eight jet pump sensing lines
that are close to the natural frequency of the vain
passing frequency.
We had two options. We could go down
there and do a ring test on these eight welds, or
eight jet pump sensing lines. But the time that it
took and the benefit of only being able to exclude
maybe one or two of these, we decided to preemptively
strike and install the clamp on all HF pump sensing
lines, and in fact we will be doing that tomorrow at
Dresden.
The dryer posed a different problem, and
that is a steam flow problem, and just last year at
Quad Cities when we were in our fall outage, we found
higher than anticipated radiological issues on our
secondary side.
And as a result of that, we immediately
went into a route cause analysis, and my job was to
investigate the dryer and the separators and see if
there was enough degradation that would cause that
moisture carryover to occur.
We put a camera on every square inch that
we could get to with either a robot or a sub, and
after we looked at this, we really had no degradation
that would explain the moisture carryover.
In fact, they were in fairly pristine
condition. So in a sense what happened is that we
focused our route cause -- and if you will move on to
the next slide, we focused our route cause on the core
loading and how we operated the core.
And we found that there is some
differentials in pressure as you get hot areas. And
the steaming effect -- and this isn't the best
picture, but essentially it would overcome the dryer
in a certain location, and the dryer, because it
didn't have a perforated plate, wasn't able to
essentially have the flow dissipate across the dryer
bank to make full utilization of the dryer.
So what we did is we used our Moss Landing
test data that we had when we were originally
designing these dryers, and we used computational
fluid dynamics, and came up with a perforated plate,
and pulled or looked at each one all the way across
this.
And what that does is essentially flattens
out the steam flow across the dryer bank and decrease
the velocity going through the dryer so that it is
able to perform its function.
CHAIRMAN WALLIS: And all of this has
already been installed?
MR. MOSER: It is being installed as we
speak. In fact, I need to go back and see how the
progress is doing.
CHAIRMAN WALLIS: So we don't know yet if
it works?
MR. MOSER: We will know in a couple --
about a week or two.
CHAIRMAN WALLIS: Now, we had the Duane
Arnold presentation a couple of weeks ago, and they
talked about the increase in frequency of loading
vibration in the steam dryer, and that being
transferred to the brackets on the steam dryer. How
are we set for this one?
MR. MOSER: Actually, again, since we are
installing the dryer modification, we do stiffen up
the whole dryer assembly, but the Dresden and Quad
dryers, because they were somewhat smaller and thicker
than the models that preceded it, we have a much
stiffer unit than say a Peach Bottom unit would be.
Now, we also -- if you will flip to the
next slide, we wanted to cover that. You know, based
on what we have done with our asset management, we do
know that flow induced vibration is a concern.
And even though we modeled everything with
a ANSI finite element program, 3-dimensional, and we
made sure that both the dryer and the modification
were well below their endurance limits, and there were
no problems from that aspect, we know that modeling
isn't always a perfect science.
And so what we have done is we have gone
to the place to say what can we do from an asset
management strategy, and what are the safety concerns.
Can we address this by just going in and doing an
inspection plan.
And one of the things that I want John to
hold up -- and this isn't quite a BWR-3 unfortunately,
but if you look at this dryer up here, we anticipate
that you will get a fairly good sized chunk out of
that if it actually cracked off.
And the places for it to go are really
down, and so you get on top of the shroud head, and
you may get down on the annulus, but it is almost
impossible -- well, it is impossible in our estimation
to get it into the fuel where you are really going to
cause some damage.
The other thing that G.E. did for us is
that in the unlikely case that we actually got part of
the dryer to go out and get out to an MSIV line, they
looked at what the MSIV closure would be, and came to
the conclusion that it would not be an issue and that
we would be able to close our MSIVs.
DR. FORD: The steam dryer support
bracket, have you had experience with those cracking
at Dresden or Quad Cities?
MR. MOSER: I have not had any experience
with that at Dresden or Quad, but we do understand the
Susquehanna event and we do understand that there is
an Asian plant that just had an experience with that.
DR. FORD: Because it could potentially
crack and you would have he whole dryer assemblies.
MR. MOSER: Well, one of the things that
we do is we inspect those are a very periodic basis,
and so far we have not had that problem, but we do
understand that it is a potential issue, and when we
set this, we will make sure that we don't have the
rocking concerning that Susquehanna had. Any other
questions?
DR. SCHROCK: You mentioned the Moss
Landing data. That is an experiment that was done on
a partial mock-up?
MR. MOSER: If I remember right, it was a
full-scale mockup.
DR. SCHROCK: A full-scale?
MR. MOSER: Yes. This was back in time
where Moss Landing --
MR. HAEGER: George is shaking his head
no.
DR. SCHROCK: I didn't think it was.
MR. MOSER: Partial? Forgive me, partial.
Any other questions?
MR. HAEGER: Do you want to move on?
CHAIRMAN WALLIS: Well, I guess we should
probably take a break. I am just thinking that it
would be more reassuring to me if you had some sort of
quantitative measure of success here, and you could
show that on that scale the present system and the EPU
were fitted somewhere so that we knew where we were,
in terms of getting to some --
MR. MOSER: On the carry over?
CHAIRMAN WALLIS: Well, you had a
discussion here about --
MR. HAEGER: I should point out that each
of the reactor internal components was formally
evaluated for stresses, and that those were all within
acceptance.
CHAIRMAN WALLIS: And again it would be
useful if you could show that you have made -- that it
appears in the previous case there was criteria for
acceptance, and here is the new case, and here is some
criteria for acceptance, and see some numbers or
matrix of comparisons.
It would be a little bit more reassuring
to me than a discursive presentation.
MR. MOSER: Actually, we have a backup
slide. We did testing at the Peerless facility in
Dallas to make sure that our perforated plate was
going to work, and if you don't mind putting that up.
It is a two-pronged approach. We have to
manage the core correctly, and we can't have a very
hot spot.
MR. HAEGER: Are you talking about this
one, Keith?
MR. MOSER: Yes.
MR. HAEGER: I think he is thinking though
about -- you are thinking about the stresses?
CHAIRMAN WALLIS: Yes.
MR. HAEGER: And that is all in the
material that we submitted to the NRC. I guess -- I
apologize --
CHAIRMAN WALLIS: So we have to ask the
staff about how they found this material acceptable,
rather than see the material itself?
MR. MOSER: The actual stress loads on the
dryer are very, very low from the analytical
standpoint. They are well belong 10,000.
CHAIRMAN WALLIS: As long as it doesn't
vibrate?
MR. MOSER: Yes, as long as it doesn't
vibrate.
MR. HAEGER: And just to summarize what
Keith said, we did the finite element modeling on the
dryer, and that showed that within limits, and then we
are following that up with the inspection program.
CHAIRMAN WALLIS: And you are doing that
because the actual prediction of these vibrations is
a little bit iffy, and so you have to keep monitoring
and inspecting.
MR. MOSER: You know, going back to our
asset management strategy, if there is industry
experience, we want to keep on top of it, and that is
why we have the inspection program.
CHAIRMAN WALLIS: I think this might be a
good time to take a break. Can we be back by 3:30?
We will take a break until 3:30.
(Whereupon, at 3:19 p.m., the meeting was
recessed and resumed at 3:31 p.m.)
CHAIRMAN WALLIS: Back on the record.
MR. CROCKETT: Good afternoon. I am
Harold Crockett, and I am the fact program manager
with Exelon and Canterra. I would like to talk about
our flow accelerated corrosion program this afternoon,
and from time to time I will change that name to the
acronym FAC.
What have we done to address uprates. I
am going to talk a little bit about susceptibility.
It is interesting to note that there are no new
systems susceptible to FAC as a result of the uprate.
And I am going to talk about the
predictive methodology and the CHECWORKS analysis, and
then we will go into the impact in a following slide,
and show some of the details of that.
I will discuss our programmatic controls,
and how our program works, and how do we do these
things. And then I will summarize on a conclusion
slide.
It is useful to start with susceptibility.
This is a chemical degradation, and fact effects,
carbon steel components in a steam cycle, where the
temperature exceeds 200 degrees fahrenheit
DR. KRESS: Do you add oxygen into your
system?
MR. CROCKETT: Yes, sir. Dissolved oxygen
is typically I think 30 ppb or greater typically.
Dresden and Quad Cities use the standardized Exelon
programs to predict, detect, and monitor for full
accelerated corrosion.
And we use the EPRI guidelines that is
really the basis for all domestic power plants, the
ANSAC-202L document, and that is really a living
document that is revised from time to time, and it has
caused us to realize other activities at the plant
that tie into our FAC program, notably our performance
monitoring leaking valves, and those kinds of things
that we turn into our program.
We go in and examine now some of the
components, and the feed water heater shells have been
a big issue in the past several years. So staying in
touch as far as the industry has helped us a lot.
The code that we use for our predictive
analysis is the EPRI CHECWORKS code, and that is how
we evaluated our changes, and that's how we initially
modeled the plant.
And then in the next slide, I will
describe the EPU conditions and how they are bounded
by the CHECWORKS parameter ranges. This slide
addresses the changed input for the analysis.
Obviously, there are other inputs -- the
typing diameter, and piping material, and geometry
factors, that did not change. But here are some of
them that were, and while I was preparing this slide,
I called up some of my counterparts at the other
utilities just to get a feel for what kind of values
they were using in their plants.
Are we are hitting new ranges that we have
not previously seen in the industry, and that was kind
of my question, and I wanted to find out where they
were.
So I am going to talk about four of these
values right now; the steam rate, or really for the
sake of this discussion the feed rate, and these
numbers will vary because obviously you have seen some
other charts that may talk about valves wide open,
versus hundred percent power, and 115 percent power,
and those kinds of issues.
But the numbers will be consistent in our
analysis. The CHECWORKS program is really geared up
to have a hundred-million pounds per hour, and
obviously nobody is at that level.
The pre-uprate, we were at about 9-1/2
million pounds per hour, and we will be going to a
little over 11-1/2 million pounds per hour. Now,
BWRS, the ones that I talked to were as high at 14
million pounds per hour, and PWRs almost approaching
16 million pounds per hour.
Now, the velocity, obviously since your
diameters change throughout the line in going through
valves and such, and it is calculated in the program,
and feedwater is pretty significant to people
obviously.
Our old analysis, I think actually this
philosophy was before the feed pumps, where we found
22 feet per second. With the new analysis, and with
all the pumps going, we actually -- the highest value
that I found was just over 23 feet per second.
And when I was talking to some of the
other utilities, the numbers that I got feedback on
were 24 feet per second and higher, and after I made
up this slide, I talked to one that mentioned 27 feet
per second, and these are not uprated conditions.
And so we are still within those values as
well. Steam quality. We have talked a little bit
about how we are maintaining the dryness of the steam,
and the operating temperature, and some slight
differences there.
We are going in the final feed water from
340 degrees to 356. Boiling water reactors we have
seen 420 degrees, and PWRs, 446 degrees. And actually
check codes have been used on fossil plants to
slightly higher temperatures.
So the conclusion is that all of our
values are really within where the industry is using
the predictive analysis.
DR. SIEBER: A quick question on steam
quality, do you have a way to measure it in your
plant?
MR. HAEGER: Yes, we will do a carry over
test with the steam dryers. At Braidwood, for
instance, we did it with saviors.
DR. SIEBER: Well, you can't do that with
BWR. It gets swamped out.
MR. DIETZ: My name is Jerry Dietz, and I
put together the start up tests. We will be measuring
the carryover with sodium from the reactor. It is
trans-sodium that is naturally occurring, and it will
take a sample in the hotwell and in the bottom of the
condenser, and we will compare the two, and that ratio
will give us the carry over.
DR. SIEBER: Do you do that on a regular
basis or just as a part of the start up?
MR. DIETZ: Well, we have been doing it
for almost a year now at the plants in regards to our
modification, and then we will be doing it as we come
up at each pipe toe in the test, verifying that it is
correct.
There has been some new industry data,
too, that there is some assumed values for carryover
and some plants have much lower, and we are also
factoring that into our test program.
DR. SIEBER: It seems to me that unless
you measure them on a periodic basis, degradation of
the dryer elements would cause additional moisture,
which accelerates flow, which accelerates corrosion.
MR. DIETZ: It will change with each set
of rod patterns, and configuration of rods, and Tim
may be able to tell us more about what Quad does.
MR. HANLEY: Several years ago -- this is
Tim Hanley again. Several years ago, we found that we
had a carryover issue at Quads City, Unit 1, and to
monitor that and address this, we do on a periodic
basis take samples in the hotwell and determine our
carryover fraction.
I can't say for sure that they do that at
Dresden, but I do know that we do that at Quad Cities
as part of a routine chemistry sample.
DR. SIEBER: And routine is what, monthly
or something like that?
MR. HANLEY: Yes, I believe it is done on
a monthly basis.
DR. SIEBER: Thank you.
CHAIRMAN WALLIS: So your concern is
corrosion in the steam line; is that what you are
worried about?
DR. SIEBER: Yes.
DR. SIEBER: It screws up the carbon, too.
CHAIRMAN WALLIS: Yes, but this is a fact
that they are talking about. Does CHECWORKS take
account of flow patterns and two-face flow in the
steam line?
MR. CROCKETT: In the steam line, the
industry has regarded that as being so close to dry
that it is essentially non-susceptible, and we do some
analysis and testing. But at large the plants
consider that to be dry, and not susceptible, the main
steam line.
CHAIRMAN WALLIS: When do you worry about
what steam for fact?
MR. CROCKETT: We have seen no indications
in the industry of wall loss in the main steam lines.
CHAIRMAN WALLIS: So this is a non-issue?
MR. CROCKETT: Yes, that's correct, and as
long as the steam does not get any worse, we do not
see this as an issue.
MR. HAEGER: I guess the point is that he
is asking why the --
CHAIRMAN WALLIS: Well, the 99.8 percent.
MR. HAEGER: I guess it was just to show
a representative input to the fact.
CHAIRMAN WALLIS: Maybe we should move on.
MR. HAEGER: Yes, let's go on.
DR. FORD: Could I just check? All you
are expecting is a one foot per second increase in the
feed water line?
MR. CROCKETT: Well, the earlier higher
velocity was before the feed pumps, and now we have
three feed pumps going, and this higher velocity
downstream of that in the final feed water, and so it
is not that 5 or 6 percent throughout. It is just the
way that it unfolded in here.
What is the impact on the wear rates, and
another thing that I would like to bring up at this
time is that we have been fairly proactive in material
upgrades, and putting in chrome moly and materials
that are not susceptible to flow accelerated
corrosion, and that has given us a stronger position
at all our plants.
And that is consistent with where the
industry is, and we are trying to be proactive so that
even the lines that we are doing now and that we are
looking at, the scope as time goes on, we continue to
reduce susceptible lines.
DR. FORD: So is that first one a chrome
moly?
MR. CROCKETT: No, I am not talking about
chrome moly in any of this. This is still facts
suspectible lines. Once I make it chrome moly, it is
not longer susceptible.
In the wear rates, we saw that we had some
mild increases and some decreases, and when I first
reviewed the data, the uprate data, I wanted to know
what systems are doing what.
And so feed water obviously is a
significant consequence, and the worst wear rate, or
the highest absolute value was this 21 mils per year.
There were some lines that had a higher percentage
increase. Like the reactor water cleanup was at one
mil per year, and that had a 33 percent increase, and
so that was 1.3 mils per year.
CHAIRMAN WALLIS: These feed water line
wear rates are actually measured as well as
calculated?
MR. CROCKETT: Yes, sir. We go out with
ultrasonic inspection --
CHAIRMAN WALLIS: When you measurement
something like 19 mil per a year on your --
MR. CROCKETT: That is correct. That is
correct.
DR. FORD: Now, you predict that it is
going to go to 21 mils per year, and so presumably you
have got some faith that the CHECWORKS is correct, and
presumably in your fact management, you compare --
MR. CROCKETT: We always compare measured
wear with predicted wear, and that allows you to
refine your predictive analysis.
DR. FORD: And what would you sigma value
be on that?
MR. CROCKETT: Well, what the EPRI
guidelines are for the predictive analysis is to come
up with a line correction factor that ranges from .5
to 2.5, and you get a confidence once your comparison
is predictive to measure comes closely together.
If it does not come closely together, then
you have to do more work, more inspections
essentially.
DR. FORD: Is that a kind of fudge factor?
MR. CROCKETT: Well, it is a continual
refinement of comparing it, yes. The line correction
factor shows you how close you are.
DR. FORD: What I am trying to get at is
that you have only got -- you are only predicting a
two mils per year change.
MR. HAEGER: I think the next slide will
answer what you are asking.
DR. FORD: I mean, does this mean
anything?
MR. CROCKETT: That's why we don't believe
it is a significant impact is what you are going to
see in the conclusions.
MR. HAEGER: I think the next slide is
really what he is talking about.
MR. CROCKETT: Okay. How do we deal with
these changes? That's exactly right. On the lines
that have increased wear rates, we have brought out
next scheduled inspection closer. So if we are
looking at R-17 right now, we are at our 17, and the
next scheduled inspection was perhaps R-20, and we may
have pulled that back to R-19.
MR. HAEGER: Meaning the refueling outage.
MR. CROCKETT: The refueling outage, yes,
I'm sorry. And what we have the dash there for, the
1.1 factor of save, we increase our wear rates by 10
percent to account for uncertainties, variations, and
to give us a little more conservatism.
And then as I mentioned earlier, we
reinspect at least one cycle before we anticipate
hitting the minimum wall thickness.
DR. FORD: Are you ever go to advance at
a rate -- well, are you ever going to hit the minimum
wall thickness?
MR. CROCKETT: Typically, we do not. Our
inspection program has been pretty successful. We
don't walk on water. Sometimes things wear slightly
faster, and that's why we incorporate the factor of
safety.
DR. SIEBER: Well, CHECWORKS is really
intended to tell you where to inspect.
MR. CROCKETT: That's correct.
DR. SIEBER: And the official number that
you get is the number that comes off of the thickness
gauge, the UT thickness gauge.
MR. CROCKETT: That's correct, yes, sir.
And I would like to emphasize that in this next
bullet that we are going to continue to perform
inspections on susceptible lines, and compare them to
the predictions, and we are going to continue to
upgrade material.
When we see a line that is wearing, we are
not going to get their management wear. It is not
cost effective to me to keep going out and seeing
something that is wearing, and uninsulating scrapple
and then UT it.
After we do that several rounds, we are
going to upgrade it with fact resistant material. And
this was your comment earlier, the last bullet, that
whenever appreciable wall loss occurs, we expand the
sample, which means that we look upstream and
downstream.
And we look in sister trains and that type
of thing to make sure that we bounded the conditions
of the wear. What we found is that we are bounded by
industry experience, as well as our predictive codes.
The predictive analysis has been revised
to determine potential impacts, and the inspections
for the affected components have been accelerated
where it is appropriate. Inspection data is
incorporated into the program and it will continue to
be incorporated.
In conclusion, the uprated conditions do
not significantly affect flow accelerated corrosion at
Dresden and Quad Cities.
DR. FORD: I have another question. If
you don't have any platinum eroding --
MR. CROCKETT: Platinum in the feed water
lines?
DR. FORD: Platinum from Noble Chem.
MR. HAEGER: Can anybody help us with
that? Tim, did you hear the question?
MR. T. HANLEY: This is Tim Hanley again.
The only part of the feed water lines would be up to
the check valve to the vessel, the last check valve
that was injected into the reactor water cleanup
system. So it would only be that portion up to the
last check valve.
MR. CROCKETT: Bill Burchill will be next.
MR. BURCHILL: Good afternoon. My name is
Bill Burchill.
CHAIRMAN WALLIS: Welcome, Bill. I have
to say that you are twice as old as the last time that
I saw you.
MR. BURCHILL: Well, Grant, you have not
changed at all. Graham and I did some great things
about 25 years ago together, right? Or was it 30.
Gosh, it has been a long time.
My name is Bill Burchill, and I am the
Director of Risk Management for Exelon, and on my left
is Larry Lee from Aaron Engineering. Larry did most
of the risk evaluations that we are going to be
talking about today. So hopefully he will get a
chance to participate here.
On the next slide, I have outlined the
topics that we are going to cover. Principally, there
are two types of risk evaluations that we did; those
that were quantitative, and both of a full
quantification of the PRA mode; and also some limited
individual special effects quantifications, and then
the qualitative evaluations. And we will talk about
both of those.
CHAIRMAN WALLIS: ACRS will tell you that
there is no such thing as qualitative risk
evaluations.
MR. BURCHILL: Yes, I have talked to
George about that, and I am fully aware of his
position. Thank you though for reminding me. The
purpose of this risk evaluation -- and I want to start
out by saying that we use generally accepted figures
of merit for risk, which is CDF and LERF.
So those were applied and those are the
figures of merit that as you know are called out in
Regulatory Guide 1.174. We estimated the change in
both CDF and in LERF using the full power internal
events model, and that was the only model that we
actually did a full quantification evaluation.
For other risk sources, external events,
and the shut down state, we did qualitative
evaluations, although with some numerical evaluation
included.
The other important aspect of this was
that it helped us to identify parts of the PRA that
would be impacted EPU plant changes, and that will
guide us then in updates to the PRA that will be used
to properly represent the as built as operated plant
when EPU conditions are implemented.
A brief outline and the methods. Of
course, we had to identify the plant configuration
changes that were due to EPU, and most of those had
been outlined already today.
We looked at the hardware changes, and the
procedure changes, operating condition changes, and
set point changes. And in each case, we looked at
what those changes would impact within the PRA
evaluation models.
We used recently upgraded PRA models for
both plants. These are not the models that were used
for the IPE studies. They are significantly upgraded
models, and both upgrades were completed in 1999.
And in both plants the upgraded PRAs have
been reviewed by the BWR owners group certification
peer review process. In each case, we identified the
elements of the PRA that are affected, and I will go
over those in somewhat more detail in the next slide.
The next two bullets will be the
foundation for why you will see a number of
differences between the numbers that I will show you,
and those that you have seen earlier in the afternoon.
PRA by its very nature uses realistic
evaluation techniques. It compares with realistic
success criteria, and limits, and therefore some of
the numbers that I am going to speak to will be
different from ones that you heard earlier, and if you
wish, I will go back and explain some of those
differences.
When we looked at the impact, we used
sensitivity studies, and we did not do a full update
of the PRA. We looked at individual parts of the PRA,
and we changed those parts as we felt that they were
appropriate to represent the impact of the EPU
conditions.
And then finally as a benchmark, we
compared the results to the guidance for risk
significance given in Reg. Guide 1.174. As you know,
this is not a risk informed submitted, but we felt
that that guidance was a useful comparison for a
benchmark.
Now, we reviewed each of the PRA technical
elements, and in particular we looked at initiating a
bench, and we looked at whether there were any new
initiating events, or whether there were any changes
to existing initiating events in the PRA.
We looked at success criteria. For
example, changes due to EPU and boil down times, and
reactor pressure vessel inventory makeup, rates, pool
heat load, RPV, over pressure protection and
depressurization.
Every one of those as you can readily
imagine mechanistically can impact what the success
criteria are. So in each case, we did look at that,
and either evaluate that it was insignificantly, or if
we saw that there was a significant impact, actually
put it in the PRA and see what influence it had.
We looked at all of the system changes
that were made, both hardware and set point, and we
looked for whether or not those system changes
produced any new scenarios, and also whether it
impacted the failure rates that were assumed within
the PRA.
Similarly then we looked at data to see
whether or not the increased duty on some of the
equipment would impact some of the PRA reliability
data.
Probably the biggest area that was
identified, and I think you can readily imagine is in
the operator response area. There are a large number
of operator responses in a PRA. Failures by the
operator generally contribute to on the order of 30 to
50 percent of the core damage frequency in a PRA.
So it is a very significant contributor.
So we evaluated in each case the most significant
operator actions in the PRAs. In both cases, that was
on the order of two dozen actions which had a FSAR
vastly greater than .005 or a raw greater than one.
Those are the typical values used to
determine risk significance, or I'm sorry, a raw
greater than two. And we also looked at time critical
operator actions.
But we looked at structural responses,
which are particularly important of course in
containment response. We looked at quantification,
and in that regard, you look at whether or not the
risk profile changes, which gives you an indication of
whether or not there has been anything new introduced.
We looked at individual cut sets, and we
also looked at whether or not our truncation was
adequate at the uprate conditions. And then the
embodiment of all of that shows up in looking at the
event tree sequences.
We did do a number of additional thermal
hydraulic calculations, many of them with a map code,
to evaluate the impact of the changes due to time to
boil down, and times to core damage.
The next two slides outline in general the
qualitative impact on the PRA, and I will follow that
with then an explicit evaluation summary of the
quantitative impacts.
I would like to preface this by saying
that we didn't find any new accident types, which is
of course no real surprise, and we found no
significant changes to the existing accident scenarios
in the PRA.
We found no changes in system
dependencies, and of course that is a very important
aspect of plant modeling. And we found no
vulnerabilities that were produced by the PRA, or by
the EPU rather.
We did find limited logic structure
changes relative to operator actions, and then of
course changes in the human error probability of some
of the actions.
Now, the things that we did find under the
operating condition area was the decreased decay heat
load reduces times to boil down pool temperature
limits and times to core damage itself.
This obviously puts more limit on --
CHAIRMAN WALLIS: Hold, please. I am
trying to figure out the grammar here. Reduces. I
thought that this read that it reduces pool
temperature limits and reduces core damage, and
reduces qualifying evidently came after.
MR. BURCHILL: It reduces the time to,
yes.
CHAIRMAN WALLIS: It doesn't reduce time
to pull temperatures limits, or I guess it does.
MR. BURCHILL: Times to is qualifying
everything after it, and the impact there is primarily
as you can imagine on the operator action times, the
response times.
Now, recognizing that, and the fact also
is that most of the operator response times of
interest are in a fairly long time frame, and so you
are talking mostly response times that are greater
than 20 or 30 minutes.
So the ultimate quantitative impact is
generally fairly small. Increased ATWS power levels
and peak pressures; again, more limiting success
criteria, and reduced time for operator action.
And then again the increased required
number of feedwater and condensate pumps. This has
the potential for increasing the turbine trip
initiating event frequency, because of the fact that
with all of the pumps operating, any individual pump
tripping off may have the potential for producing a
turbine trip.
CHAIRMAN WALLIS: Increased ATWS power
levels and peak pressures; isn't that controlled by
valves opening, and it actually increases the peak
pressure?
MR. HAEGER: And that is what that second
bullet is saying; more limiting success criteria for
ATWS, in terms of the number of valves.
CHAIRMAN WALLIS: Pressure controlled by
the valves opening?
MR. HAEGER: Yes. And one of the success
criteria is how many valves open.
CHAIRMAN WALLIS: I thought the peak
pressure stayed the same, but more valves had to open
in order to keep it the same. And how you are
actually saying the peak pressure itself does go up?
MR. BURCHILL: In a realistic calculation,
the peak pressure will go up and you will need more
valves to stay below the limit. So both occur.
CHAIRMAN WALLIS: Because of the set
points.
MR. BURCHILL: Right. Now, on the last
point that I made here, because this is a fairly
significant one, this is the only place where we saw
a potential increase in an initiating event frequency,
the evaluations that were done were done early before
a completion of the recirc runback feature that was
discussed earlier, and so they do not take any credit
for that recirc runback.
We believe that with the recirc runback
that there would be no increase in initiating event
frequency, except in the case of a recirc runback
failure, simply because of the fact that you would not
have the single pump tripping leading to a turbine
trip.
And in the next slide, we talk about the
system effects, and specifically to the point that we
were just talking about, an over pressure protection.
We find that an increased number of
reactor safety and relief valves is required for over
pressure protection. As you know on these plants,
there are 13 valves available. The current success
criteria is 11 valves to hold the pressure.
And in the case of the EPU, we found that
would increase to 12 valves. The increased number of
reactor relief valves required for emergency
depressurization on any of these plants, there are
five valves, and currently only one valve is required
for emergency depressurization.
Under the EPU conditions, we judge that
that would go up to two valves. So this modifies the
success criteria for transient small and medium LOCAs,
and again for ATWS.
And we looked a numerous BOP and set point
changes, as well as logic changes, which produced
negligible risk, and most all of these changes were
described by John Nosko at the beginning of this
discussion.
I want to note in particular that the electrical
load fast transfer that I think was mentioned earlier,
and talked about by Mr. Sieber, that feature, and the
addition of the condensate pump trip on LOCA, were
both found to have a negligible impact.
Their impact is conceptually on an
increased loop frequency, loss of off-site power and
initiating event frequency. But when we went through
the quantification, we found that in fact the increase
was extremely small compared to the existing loop
frequency assumed in the model.
DR. SIEBER: I don't know whether you are
going to get to this later or not, but in the success
criteria for valves and the way you modeled it, it
seems that the overriding failure mechanism was common
cause?
MR. BURCHILL: True.
DR. SIEBER: And could you explain how you
treated common cause failures in your analysis?
MR. BURCHILL: Certainly. You want to go
through some of the specifics in each case?
DR. SIEBER: Yes. It doesn't have to be
real detailed, but I would like to understand it.
MR. LEE: Okay. This is Larry Lee from
Aaron. So initially the success criteria was one of
five valves for depressurization. So it would be a
common cause of all five valves failing to open.
So now that the success criteria is 2 of
5, you would need common cause failure of any four of
the valves. So the common cause failure rate
increased by approximately a factor of two from around
1-E minus 4, up to about 2-E minus 4.
DR. SIEBER: And so you came to your
detailed analysis using beta factors?
MR. LEE: Yes.
MR. BURCHILL: Okay. The next slide is
Slide 77, and if we can have that up. This is the
slide that we will probably spend most of our time on,
or at least proportionately on slides, and I will even
try to time this one.
Mention was made earlier that the Dresden
and Quad plants are similar, but not identical. And
this of course is true in the PRA representation.
Some of the key features, the Dresden plant has an
isolation condenser, and it has a dedicated shut down,
decayed heat removal system.
In the Quad plant, we have a dedicated
high pressure safe shutdown make up pump. We have no
isolation condenser. There are a number of
differences in the electrical area, and each of those
are represented in the PRA, and then lead to a
difference being found in the quantitative importance
of either those systems or their failure.
We looked at about 15 different model
changes that were quantified with the full PRA
sensitivity studies, and we looked at a number of
other model changes, where we looked specifically, for
example, at just the change in the human error
probability.
And we found that it was negligible, and
then did not include that in the full model
quantification. This table then in some detail gives
you the most important ones that we found, in terms of
carrying through to actually having some significance
in the eventual impact on CDF.
And by significance, we looked at anything
that was on the order of one percent or more as being
significant. And what you will see is that there are
three groups.
One is the impact on the turbine trip
initiating event frequency, which is on the first
line, and as I mentioned that is the only initiating
event frequency that we found impacted.
The next five are in the human error or
the human operation or action category. And then the
last is in the success criteria category, the one that
we have already talked about with respect to
depressurization.
I will briefly speak to each of these, and
if I am going into too much detail, please don't
hesitate to stop me. I am sure that everyone would
like to get on to something else.
In the turbine trip initiating event
frequency, you will see that there is a range
represented there for the PRA model change, and the
size of that range is not indicative of any
significant difference between the plants.
It is indicative of a difference in the
modeling technique that was used to derive the
numbers. In the Quad Cities case, we used a
simplified fault tree of a fairly conservative nature,
and that led to the higher number that you see there,
the 18 percent change.
I'm sorry, that was the 2-1/2 percent
change. In the Dresden case, we looked at actual
turbine trip data from a seven year period, and then
we made an evaluation of whether each one of those
trips would have actually been aggravated by the EPU,
or in fact would have occurred under EPU conditions.
And so what that led to was the 18 percent
change that you see. In quantitative terms, Quad
Cities initiating event frequency changed from 2 to
2.05 per year, and Dresden's changed from 1.14 to 1.35
per year.
Now, those changes, when put into the PRA
model, then lead to the CDF contribution increase of
the one or less than one to 2-1/2 percent.
Again, I would remind you that if we had
accounted for the recirc pump run back feature that
that would essentially be zero. It would be
negligible.
Each of the five operator actions has to
do with times being reduced somewhat for the operator
to take action. In most cases, we simply scaled these
times relative to heat load because most of them are
driven by heat load.
The times that we are talking about in
general are in the 20 to 25 minute range being reduced
to on the order of 16 to 20 minutes. So we are
talking about relatively long action times. We are
talking about more or less a 20 percent decrease in
each case.
DR. KRESS: But what is the time on Item
4 on that one?
MR. LEE: Line 4?
DR. KRESS: SPC during ATWS.
MR. LEE: Right. There are two time
frames there. There is an early time frame, and I
think we talked earlier -- I don't remember if we
talked the time frame earlier. On the licensing
analysis, it is shorter.
But in the PRA analysis, which is a
realistic analysis, the short time to act is 6
minutes. And we looked at the thermal hydraulic basis
of that and found that that did not change under EPU
conditions. For the longer time to act, that went
from 20 down to 16 minutes.
MR. HAEGER: That was line 3, I think, and
so --
MR. BURCHILL: He said line 4, but then he
said SLCS. So, I think he was talking about SLCS.
DR. KRESS: It was SLCS that I was talking
about.
DR. SIEBER: Do you have another one that
was down as long as 10 minutes, I guess.
MR. BURCHILL: Yes, it went from 10 to 8-
1/2 minutes. I think it had to do with ADS.
DR. SIEBER: ADS during --
MR. BURCHILL: And what happened was that
when we evaluated that, that changed and that was well
less than one percent impact. That's why you don't
see it on this chart.
DR. SIEBER: All right.
MR. BURCHILL: Now, one other thing to
point out, that on the second line there is a range of
zero to 1.4, and on the fourth through fifth line, it
is zero to one. Those zeros are somewhat artificial
because of the fact that what we found that the actual
HEP that was in the PRA model in each case was a
fairly conservative value.
So that conservatism in and of itself
masked any impact. However, looking at the other PRA
for a very similar plant, we found more realistic
values, and we were able to then vary them to give the
range of influence that you see there.
On the last line, the one point that I
would like to make there, because it is a unique one,
is that the inadvertent opening of the relief valve,
or a stuck open relief valve sequences, and the
increased common cause failure probability that we
just talked about, is the only place where we actually
found a modified sequence to occur.
If you think about this pre-EPU, we only
had one valve required for the depressurization, and
therefore if we had that one valve open through an
IORV or an SOFV, we would depressurize.
With two valves being required for
depressurization, even though you have one valve
inadvertently opening or stuck, you still have to
depressurize. So there is a new branch that gets
added to that event tree to accommodate the fact that
the second valve has to be opened.
And Larry has already described the change
in common cause. I would also note that you don't see
on this chart an impact due to the success criteria
change on the overpressurization. That was found to
be very small, well less than one percent.
We also looked then at the level two risk.
In other words, the containment risk influence. We
used a methodology that is described in NEUREG/CR-
6595.
This is a fairly conservative methodology,
and it has been reviewed and endorsed by NRC for risk-
informed submittals. But it does lead to fairly
conservative results as we will see in a moment.
There are two groupings of impact that we
want to consider here. The first three bullets
discuss the disposition of the end states from the
level one analysis. And that is actually the
methodology that is described in the NEUREG/CR-6595.
It involves a binning technique where a
binning of the source terms, or fraction of
radionuclide inventory is used. That is unaffected by
the EPU. The actual release frequency in each bin is
proportional to the level one result.
But the impact of EPU will be specific to
each bin, depending upon the distribution. The second
three bullets are the risk impact on the containment
response itself. So there are in fact been
containment responsive ventries that could attach then
to the actually end states of each of the level one
bins if you will.
There were very minor changes in the Level
2 HEPs, and very minor changes in accident progression
timing, and decay heat load, and a negligible change
in the timing that we found to containment failure, on
the order of several minutes over a several hour
period.
So what we found then was that the EPU has
a very minor impact on the Level 2 portion of this
analysis, but the overall impact on LERF is
essentially proportional to or similar to Level 1.
The quantification results then are given
in the next slide. The base PRA results are given in
the first group there under the first bullet. Again,
these plants are similar, but not identical, and for
the reasons that I cited before, as well as others, we
do not have identical CDF or LERF based values,
although I would point out that these are pretty darn
close.
CHAIRMAN WALLIS: Why is LERF so close to
CDF?
MR. BURCHILL: Because of the conservatism
in the 6595. This is about --
CHAIRMAN WALLIS: You might not have the
containment.
MR. BURCHILL: You usually expect it to be
on the order of 10 to 20 percent. So this is very
conservative. To be frank with you, it becomes an
economic decision. If we can use it and still meet
regulatory requirements, we will.
And at the time that we find that that
won't work, we will go to something more extensive.
That will probably be during license renewal. Now,
the impact of EPU is quite small on both CDF and LERF,
and in fact if you look at the impact on CDF, for both
plants, adding up all the little pieces, even though
there are somewhat differences in the mix, they both
come out to be an impacted 2.4 times 10 to the minus
7 per year, which I think you have seen in the
submittals or in the RAI responses.
The difference in percent then is entirely
due to difference in base value. It is not a
difference in the absolute impact. In the terms of
LERF, there is a little bit of a difference. Quad
Cities has a face value of 1.3 times 10 to the 7th,
and Dresden is 1.4 times 10 to the 7th.
I would note that these results,
percentage wise, are very similar to what has been
seen in other evaluations for other plants. The last
point is that we did compare these results to the
guidelines for risk significance in Reg Guide 1.174.
Just to refresh, Reg Guide 1.174 for the
magnitude of CDF and LERF for these plants,
differentiates between small risk and very small risk
at 10 to the minus 6th for CDF changes, and 10 to the
minus 7th for LERF changes.
So if you compare what we found on --
well, I think I said that wrong. Yes, 10 to the minus
6 on CDF, and 10 to the minus 7th on LERF. So the
change that we found in CDF in both cases is a about
a quarter of the way up to the threshold between very
small risk and small.
And so we conclude that we are well below
any concern here, and that the CDF is well within the
very small risk region. Relative to LERF, we are just
barely over the line to small risk, and considering
the conservatism that we just talked about if we were
to do that realistically, it seems pretty obvious that
we would be in the very small risk change arena.
An area of considerable concern, and if
Dr. Apostolakis were here, we would have some
considerable discussion on are the uncertainties. We
looked at the uncertainty and the base full power
internal events PRAs using standard techniques.
We looked at risk importance measures, and
we found that the distribution of them and their
general magnitudes were normal. We looked at
sensitivity studies and we looked at the pertinence of
the various equipment.
We looked at failure rates, and we looked
at operator actions using ranges of 5 to 10 times the
human error probabilities, and we compared the results
to what is reported in NUREG-1150.
But we found no uncertainty sources beyond
those that are identified in NUREG-1150, but we did
not do an explicit quantitative uncertainty analysis
of this EPU risk evaluation.
However, if we were to take the
uncertainty range cited by 1150, which it appears we
would agree with, the range there is cited to be on
the order of 5 to 6 times the calculated point value.
So if we were to apply that to the delta-
CDF that we have calculated, we would be just at the
borderline or slightly above the range, the threshold
between very small and small risk.
And if we were to apply it to the delta-
LERF, we would still be within the small risk range,
even considering the conservatism. So we think that
adequately covers the question of uncertainty.
Now, we looked at four different areas,
and qualitatively the present PRA does not explicitly
include internal flooding in the quantification.
However, in the IPE studies, we did look
at flooding, and it was found to be a very small risk
contributor, estimated to be on the order of one
percent of the base CDF of the plants.
Therefore, although the dominant full
power internal event model changes would apply,
because they would be applied to such a small fraction
of the CDF, they are essentially negligible.
We found no new initiating events
increased during initiating event frequencies, and so
the bottom line conclusion is that the internal flood
is not impacted by the EPU.
Relative to external events, the IPEEE for
both plants concluded that external events other than
fire or seismic do not pose any significant risk of
severe accidents.
So what we focused on in this study then
was the fire and the seismic area. The fire
evaluation or both plants used recently revised fire
PRAs in the 1999 to 2000 time frame, and we completely
redid the fire PRAs for both plants, and resubmitted
the associated parts of their IPEEEs.
We did not do a full requantification.
Instead, we looked at the dominant scenarios in each
of these fire PRAs, and qualitatively evaluated
whether or not they would be impacted by EPU
conditions.
In both cases, we examined the top 10
scenarios. In Dresden, the dominance scenario is a
control room exposure fire, and it contributes about
40 percent of the fire CDF. In Quad Cities, the
control room fire is about 10 percent.
Basically, in both cases the control room
scenarios were evaluated with a very conservative
conditional core damage probability of about .5, and
so any impact of EPU would really be subsumed in that,
and that is not very satisfying.
So what we did then was that we looked at
what were the actual operator actions that that .5
represents, and we said how much time does he have to
take those actions.
And then again looking at what would be
the actual impact. And, for example, if you take
Dresden, and the time to go out and initiate the
isolation condenser for a fire scenario, and the
dominant fire scenario that we are talking about, is
about 35 minutes.
We estimated that would shrink to about
33, and then the time beyond that to restore makeup to
the isolation condenser would also change by the type
of figure that I mentioned previously, the 20 to 16
minutes.
So again a very small impact. The other
major type of scenario is decay heat removal scenario,
and the dominant scenario at Quad is a fire in the
reactor feed pump area, and that contributes about 25
percent and leads to a loss of decay heat removal.
And that Dresden has about 20 percent of
its various scenarios tied up in to decay heat removal
sequences. Again, the impact on those sequences
through the human error probabilities is very small,
because the operator has very long times to respond in
each one of these cases, on the order of 30 minutes.
CHAIRMAN WALLIS: Are these fire risks
-- the CDF contribution is bigger than the full power
CDF that you were talking about?
MR. BURCHILL: Right. It is about an
order of magnitude higher mainly driven --
CHAIRMAN WALLIS: So we were worrying
about some increases of five percent in something
which is considerably smaller than this fire risk?
MR. BURCHILL: Right. The impact of the
way that we model fire ignition frequencies, most
people who do fire PRAs believes is what drives
results of this type. This is not an unusual
comparison between fully quantified fire risk and
other internal events.
So I think it is fair to say that it is
now a significant debate within the PRA community as
to how to even compare these two. In most cases, we
don't. We simply address them one at a time, because
we know that the fire risk evaluation techniques are
so conservative.
Other changes in the success criteria --
for example, the number of relief valves, has a
negligible impact, and the ATWS related changes that
we have talked about would be negligible due to the
low probability of a fire induced ATWS.
We didn't find any new fire initiating
events or increased fire initiating event frequencies,
meaning new fire ignition frequencies. So again we
felt that the EPU had a negligible impact on fire
risk.
The seismic area was the third area of
qualitative evaluation, and we do not have seismic
PRAs for either one of these plants. In both cases
the IPEEE requirements were satisfied using the EPRI
seismic margin analysis method.
So we looked at those seismic margin
analyses to determine whether or not there was
anything in there that would be significantly impacted
by the increase in power.
We found no impact on the seismic
qualifications of the structure systems and
components, and I think that is no surprise. We did
look at the potential impact of increased stored
energy on blow down loads, and we found that that was
also a very small -- and which as you heard earlier --
the same conclusion as the deterministic analysis of
the containment that Mark Kluge described very early
in the afternoon.
We also looked at the impact on ultimate
heat sink issues, which I think we are going to defer
and discuss with you in the open issues area. I will
just forecast that the result there was determined to
be minor, but we will describe to you under that
discussion, which requires really understanding the
scenarios.
But we will describe to you how we
quantitatively evaluated that using a scenario
specific event tree.
CHAIRMAN WALLIS: So you are going to come
back to that?
MR. BURCHILL: We are going to come back
to that.
CHAIRMAN WALLIS: And the staff has some
issues with that.
MR. BURCHILL: Right, the staff has some
issues, and we are going to try to address those under
our open issues discussion.
DR. SIEBER: I do have one question which
you can probably answer in one sentence. I think it
is Dresden ultimate heat sink operation. And it talks
about using the canal to run through the parking lot
there.
MR. BURCHILL: Yes.
DR. SIEBER: And then having time to
refill it by pumping into it?
MR. BURCHILL: Yes.
DR. SIEBER: And then the safety
evaluation talks about portal pumps. Are those pumps
at your site at Dresden, and they can be wheeled out
and operated?
MR. KLUGE: This is Mark Kluge. Those
pumps are not on-site, but given the large amount of
time available to stage those pumps, we have standing
contracts with pump vendors, and our belief and our
procedural basis is that we can obtain those pumps in
ample time to refuel the UHS.
MR. BURCHILL: Not to preempt Mark's later
presentation, but we are talking about days.
DR. SIEBER: I'll check that.
MR. BURCHILL: Yes, he will talk about
that, but we are talking about days, just so we don't
leave that on the table. So our conclusion again is
that EPU has a very minor impact on seismic risk, but
the particular place where it may have impact is going
to be described later.
Lastly, in the qualitative area, we did
look at shutdown risk. Again, we do not have shutdown
PRAs for these two plants. However, it is easy to
recognize that the dominant full power internal events
PRA model changes in most cases do not apply, either
because the times are different or because the
equipment requirements are different.
We did not see any new initiating events
or increased initiating event frequencies. It is
obvious, of course, that the higher decay heat load
will increase boil down times. And then we will have
some minor impact on human error probabilities.
Now, recognize that most of the operator
actions during a shutdown are of a recovery nature.
They are recovering, for example, a lost decay heat
removal system, or something of that type. And they
mostly occur in the many minutes to hours time frames.
So it is not surprising that there would
not be much of an impact. There is one place where
there is an impact, and that is that there is a number
of backup systems that are available for decay heat
removal.
Some of these are low capacity systems,
and they are not able to be used until the decay heat
load drops sufficiently so that their heat removal
capability is sufficient to match decay heat.
And so there is a somewhat shortened time
for that to occur, but again we are talking about
something out in days, and a shortening of a few days
on that. So, a very minor impact there.
And the last thing is that we do manage
our risk during shutdown using configuration risk
management techniques. We use a commercial tool
available that was developed by EPRI called ORAM, and
I am sure that you have heard of that.
It is a defense in depth monitor, and
there is no impact whatsoever of EPU on the use of
that tool, and how it would be applied during an
outage. So again we conclude that EPU has a
negligible impact on shutdown risks.
So, I will summarize, and I note, Dr.
Wallace, that you are getting tired of me saying over
and over again negligible, small, minor, but that is
what we found.
The risk impact was evaluated using
standard PRA methods, and with deference to George,
both quantitative and qualitative. The quantified
impact was a small percentage of the current plant
risk, and it is well within the criteria that the Reg
Guide 1.174 specifies for either a very small or small
risk impact.
DR. KRESS: Let me ask you a question
about that.
MR. BURCHILL: Yes.
DR. KRESS: I seem to recall in Reg Guide
1.174 that they had an absolute limit on LERF of 1
times 10 to the minus 5?
MR. BURCHILL: What you are thinking of is
in Reg Guide 1.177. There is an absolute limit of 5
times 10 to the minus 7th on delta risk, which is
essentially a CDP, or what is now being called an
ICCDP, which is a change in risk, multiplied by the
time over which that risk exists. I think that is the
only place that there is an absolute.
DR. KRESS: I thought that the 1.174 was
divided up into regions.
MR. BURCHILL: Yes, there is.
DR. KRESS: And if you were in a region
above --
MR. BURCHILL: Oh, that's true. If your
base is too high, you're right.
DR. KRESS: Too high, and that value for
-- well --
MR. HAEGER: If I could reply to that.
MR. BURCHILL: Which one are you putting
up?
MR. HAEGER: The Quad CDF impact.
MR. BURCHILL: Yes, that's fine. If you
want to turn it on.
MR. HAEGER: Do you want to do LERF or
CDF?
DR. KRESS: LERF.
MR. HAEGER: You can do it either way.
DR. KRESS: Yes, they are almost the same,
but we will do the LERF. Now, the dark region is the
region where no changes are allowed.
MR. HAEGER: Unacceptable, right.
DR. KRESS: And on that LERF line that is
like something times 10 to the minus 5 --
MR. BURCHILL: Actually, it is about 10 to
the minus 4. This is 10 to the minus 5, and this is
10 to the minus 6. And what we found is that we were
right about here.
MR. HAEGER: Here is where the box is.
MR. BURCHILL: Yes, where the box is, and
we are about here. This is where we are, and the 1.37
times 10 to the minus 7. And at a base of 4 times 10
to the minus 6.
DR. KRESS: And if you were to add in the
low power shutdown, and add in the seismic, and add in
the fire, would that move you very far in that
direction?
MR. BURCHILL: I can give you a judgment
on that, because we don't have it quantified, but I
would judge that it would be very small movement in
this direction.
DR. KRESS: The other question that I have
is the LERF value where that line is drawn was derived
on the basis of the quantitative prompt fatality
health objective.
Now, if you increase the power, it seems
to me that that line ought to move back the other
direction, because you are increasing the fission
product inventory, and if you were to back out the
same fraction or release value from the prompt
fatality value that you calculate, then the allowable
value of that line ought to move back in the other
direction by at least -- well, it is not linear
because it has to do with a lot of the iodine.
MR. BURCHILL: The way that these explicit
boundaries were derived is a mix of philosophy in
numerics, but there is a relationship that is known,
and that there is about a 3800 megawatt thermal
assumption that went into the calculation of trying to
relate these figures of merit to the public health
figure.
DR. KRESS: They use sort of an average
plant.
MR. BURCHILL: But they use a very big
plant.
DR. KRESS: And your plant is much smaller
than that big one, and so that --
MR. BURCHILL: A 3800 megawatt thermal.
DR. KRESS: So that would move the line in
the other direction, and it also uses an average site
source. So your site is probably much less populated
than the average, considering a large LOCA.
MR. BURCHILL: I know that we are at a
lower power level, but I don't know if we are much
less populated than what was used there. But I know
that in the deliberations that have been going on
about revisions to Reg Guide 1.174, that has been on
the key points, is whether or not the 3800 that was
actually assumed to set these boundaries needs to be
looked at, in terms of actually making these lines as
you suggest variable.
But if we were to actually take the power
level that we are talking about, in theory the line
would actually move to the right. I wouldn't
subscribe to that by the way. I don't think that is
a proper interpretation of how these were done.
DR. KRESS: I was just trying to figure
out how close you were actually to that line.
MR. BURCHILL: Well, we know this line
should not be moving this direction, and I believe
that if we were able to do an explicit calculation of
the other risk sources, it obviously wouldn't move
very far this way.
And if I were to actually be doing that,
I would do an explicit level-2, and this thing would
drive down here anyway.
DR. KRESS: Okay.
MR. BURCHILL: That is the real key,
because I have got a factor of -- a minimum of two,
and probably a 4 or 5 in conservatism in it.
CHAIRMAN WALLIS: Well, your box there is
for this FPIE risk evaluation?
MR. BURCHILL: Yes, it is. This is a
legend box and I don't know why there is two of them.
And then this one is the result.
MR. LEE: That is what we say in region-2
and region-3.
CHAIRMAN WALLIS: You didn't give us
numbers for fire related CDF, but the staff has some
numbers which seem to be pretty high. I mean, 6 or 7
times 8 to the minus 5.
MR. BURCHILL: Correct.
CHAIRMAN WALLIS: And they are much bigger
numbers than any of these.
MR. BURCHILL: Yes, but that is typical.
CHAIRMAN WALLIS: But if we put down the
same picture, it would take you over into the greater
region.
MR. BURCHILL: If I were to blindly add
those numbers, it would do that. But before I would
do that, I would go in and I would do a whole lot of
work on my fire ignition frequencies, and I would do
comp calculations, and --
CHAIRMAN WALLIS: You would bring that
down?
MR. BURCHILL: I would certainly be able
to bring them down by on the order of --
CHAIRMAN WALLIS: There seems to be a bit
of uncertainty about the right number to use for these
fire related CDFs then.
MR. BURCHILL: I'm sorry?
CHAIRMAN WALLIS: There seems to be a lot
of uncertainty about what to use for these fire
related CDFs.
MR. BURCHILL: Well, the fire risk
analyses were a part of the IPEEE, which as to
identify vulnerabilities. I think there is a lot of
question about using them as numerically comparable to
internal events.
CHAIRMAN WALLIS: Maybe we will ask the
staff what they think about that. Do you know what
that hurricane like region is over to the left there
on your picture, the dark blob there?
DR. KRESS: That is the crest mark.
MR. HAEGER: That is actually on the
screen.
MR. BURCHILL: So our conclusion is that
we are well within the acceptable ranges on the 1.174,
which we have just looked at in anguishing detail, and
that the impact from external events and shutdown is
either negligible or minor.
So overall, if we had the last slide up,
but it doesn't matter, we believe that the EPU risk
impact is acceptable. I would like to make one
further comment. I believe that the staff did an
extremely thorough evaluation in this case.
And particularly recognizing that this is
not, quote, a risk informed submittal, but the fact
that we did get asked a large number of questions, and
they spent some times with us in July as you have
read, I was actually very impressed with their
inquiry.
So I just wanted to put that on the
record. I know that is something a licensee normally
says, but I thought that they did a very good job.
CHAIRMAN WALLIS: They were equally
impressed with your answers to their inquiries.
MR. BURCHILL: Well, I am pleased to hear
that. Okay. I would now like to introduce Mark Kluge
now, who will continue with the discussion of open
items.
CHAIRMAN WALLIS: Thank you very much,
Bill.
MR. BURCHILL: You're welcome. A pleasure
to meet with you again.
MR. KLUGE: This is Mark Kluge, and we are
going to cover four of the open items from the staff's
safety evaluation. I will be discussing ECCS net
positive suction head requirements, and the ultimate
heat sink that we touched on just a moment ago.
Then I will bring John Freeman back up to
talk about the standby liquid control system, and an
issue involved with that. And then finally Tim Hanley
will discuss the large transient testing that came up
earlier in the presentation.
The pre-EPU basis for both Dresden and
Quad Cities was that credit for a containment
overpressure is required for adequate ECCS MPSH.
Because that is the case, our procedures, our
training, are all focused on operator awareness of
that need, and the proper actions to maintain MPSH.
The EPU impacts on this condition are that
using a limiting analysis with the proper conservative
assumptions to minimize containment pressure, we have
an overall need to increase the containment over
pressure credit for the EPU condition.
Dresden and Quad Cities installed larger
suction strainers as to the rest of the BWR fleet, and
the staff had some open issues with our methodology in
calculating the head loss for those suction strainers.
DR. SIEBER: That was independent of --
MR. KLUGE: That was independent of EPU.
However, EPU provided us the opportunity to address
those issues.
DR. SIEBER: If that issue is not
resolved, I take it that EPU is. What is the caboose
behind that train?
MR. HAEGER: Well, we have submitted
material to the staff now that we believe resolves
that issue.
DR. SIEBER: Well, it takes two to resolve
it; you and them.
MR. KLUGE: But we believe that the
calculation that we have performed now addresses all
of the staff issues with the head loss methodology.
It does result in an increase in head loss at a given
ECCS flow.
The overall effect from EPU on the Dresden
and Quad Cities plants, we have a reduced period of
pump cavitation int he short term over the existing
analysis. That small period of cavitation has been
previously evaluated and shown to be acceptable based
on some testing that we did of the ECCS pumps some
years ago.
CHAIRMAN WALLIS: Do you actually know the
flow characteristics of the pump when it is
cavitating?
MR. KLUGE: Well, there are a couple of
points to remember here. First of all, the ECCS
analysis has to assume a limiting single failure,
which means inherently that analysis does not use as
much flow as does our limiting MPSH analysis.
Our worse case here is when all of the
ECCS pumps are operating, and in fact not only are
they all operating, but we assume a loop select
failure such that the LPCI pumps are all pumping out
the break.
CHAIRMAN WALLIS: But when the pump
cavitates, what do you do? Do you put in some reduced
pumping capacity as a function of lower suction head
or something, or what?
MR. KLUGE: For the assumptions in the
ECCS analysis, this cavitation wouldn't occur because
of the reduced number of pumps available.
CHAIRMAN WALLIS: I am just saying that
there is a period of pump cavitation?
MR. KLUGE: There is a period of pump
cavitation if I assume that all the ECCS pumps are
operating. That period is limited by operator action
at 10 minutes into the event, and you --
CHAIRMAN WALLIS: Well, what is the
consequence of having that cavitation? You reduce the
flow or what do you do?
DR. SIEBER: You trip a pump.
CHAIRMAN WALLIS: Do you assume that there
is no flow or what?
MR. KLUGE: Well, the actual pump
operating characteristics would be slightly reduced
flow.
CHAIRMAN WALLIS: Slightly reduced flow?
MR. HAEGER: From all ECCS pumps running,
and what Mark is trying to say is that the ECCS
analysis assumes a single failure, and so the flow
rates are much less there.
The cavitation won't get you anywhere near
that low of a flow rate. So we are bounded by the
ECCS LOCA analysis.
MR. KLUGE: And not to berate the point,
but the ECCF analysis also uses lower flows from the
available pumps; whereas, we assume full flow capacity
to do the MPSH analysis. So there are different
inherent assumptions in these two analyses
MR. PAPPONE: This is Dan Pappone. The
flow that they are talking about, there will be a
degradation in the flow, but that degradation will not
go from the actual value down to our analysis value.
The value that we assumed in the analysis
was below the grated flow value. So effectively we
have accounted for it in the analysis. Another factor
is that --
CHAIRMAN WALLIS: Well, maybe I should ask
a simpler question. Even if you have this pump
cavitation, you are able to calculate that you have
enough flow?
MR. PAPPONE: That's right.
CHAIRMAN WALLIS: And this is based on
some model or some understanding of effective
cavitation on the pump flow characteristic?
MR. PAPPONE: Right.
MR. KLUGE: Another factor is the time
when it occurs, and the time when we would expect this
cavitation to occur after we have reflooded the vessel
and terminated the core heat up.
So that part happens in the first few
minutes, and the cavitation is out at -- well, let's
say when we get past the reflooding in 3 or 4 minutes,
and the cavitation is out in the 5 minute range, the
5 or 6 minute range.
DR. SIEBER: Plus, there is an implicit
assumption that there is no vortexing associated with
the cavitation; is that correct?
MR. KLUGE: Flow characteristics were
based on testing that we did some years ago.
DR. SIEBER: Where you actually induced
cavitation?
MR. KLUGE: Where we induced cavitation in
an ECCS pump identical to those installed in Dresden
and Quad Cities. That cavitation was allowed to
continue for a period of an hour, which is far in
excess of what we are talking here.
DR. SIEBER: Right.
MR. KLUGE: And when the pumps were
inspected, the results of that cavitation were that
the pump operability had not been affected.
DR. SIEBER: Well, the vortexing using
affects the flow in a major way, and I presume that
during the test that you also did flow measurements to
see what the degradation was?
MR. KLUGE: That's correct.
DR. SIEBER: And maybe you could tell us
the percentage. Was it 90 percent, or 80 percent, or
what?
MR. KLUGE: Well, I don't have that
information in front of me, but just to echo what Dan
said, in every case, even the degraded flow would give
us much lower than what was required for the accident
analysis.
DR. SIEBER: All right. Okay.
MR. KLUGE: Moving on to the long term
reduced pump flow and the long term compared to the
previous licensing basis analysis, that is partly a
factor of the increase during our head loss, and
partly a factor of the increased suppression pool
temperatures.
But again all flow requirements, both for
core cooling and containment cooling, continue to be
met. The next two slides show graphically the
available over-pressure above that which is credited
in the analysis.
If you compare Dresden and Quad Cities,
there are some minor differences due to plant
specifics, such as different heat exchanger capacity
and piping configuration.
CHAIRMAN WALLIS: Now, what does credited
in the analysis mean? Is it what the NRC allows you
to us?
MR. HAEGER: Yes.
MR. KLUGE: Yes, what we have requested.
CHAIRMAN WALLIS: Oh, so you have
requested something less than what you think is
available?
MR. KLUGE: That's correct. And all this
information has been submitted to the staff.
CHAIRMAN WALLIS: When you say credited,
you mean that is what you need really isn't it?
MR. KLUGE: That is what will appear in
our operating license.
CHAIRMAN WALLIS: That is what you need
and so you are claiming you have got more available
than what you need?
MR. KLUGE: Yes.
MR. HAEGER: That's correct.
DR. SIEBER: It's always a good idea.
CHAIRMAN WALLIS: And this available is
calculated with some sort of conservatism which goes
the other way from when you are trying to calculate
the loads on the containment when you are conservative
in the other direction?
MR. HAEGER: That's correct. There is a
number of different assumptions made that limit the
containment pressure that is available.
MR. KLUGE: For instance, the containment
sprays are assumed to operate since they bring the
pressure down. However, the assumed containment heat
removal capability is the minimum, which of course
drives the suppression cool temperature up.
Moving on to the summary slide, we used
acceptable methods to determine the suction strainer
head loss and the NPSH requirements. Although we do
experience short term pump cavitation, we devaluated
that condition and it has no detrimental effect on
pump operability or meeting the required flow.
And the long term flow rates are
acceptable, and the operators are aware of the need to
maintain MPSH per their emergency operating
procedures. Therefore, we conclude that the ECCS pump
and NPSH remains acceptable under EPU conditions.
CHAIRMAN WALLIS: Does the staff agree
with that?
MR. KLUGE: They haven't indicated to the
contrary. We do think we have addressed all of the
issues with the methodology that we considered.
CHAIRMAN WALLIS: So they have not come
back to you and said yea or nay yet?
MR. KLUGE: That's correct.
MR. HAEGER: They have not formally
replied to us.
MR. KLUGE: Next, I would like to discuss
the Dresden ultimate heat sink and I will ask Larry
Lee to come back up here to handle the risk portion.
As was previously mentioned, the Dresden
ultimate heat sink consists of the intake and
discharge canals to the plant. And there is a picture
being put up so we can see what we are talking about.
Dresden 2 and 3 intake valve spans from
this point to this point, and the discharge runs from
this point to this point. To give you some idea of
the scale from the plant to the south end of the lake
is approximately 3 miles.
So we are talking 2,000 foot canals and a
total inventory that we are looking at in those canals
once we postulate that the river level has dropped to
a point, the separation is about 6 million gallons.
The ultimate heat sink inventory is used
both as makeup to the isolation condensers to maintain
safe shutdown, and for diesel generator cooling water.
As indicated before, the canals are then replenished
by means of portable pumps to ensure long term safe
shutdown, and those actions are all in the current
procedures.
CHAIRMAN WALLIS: So whatever it was that
caused the dam to fail didn't also inhibit the arrival
of portable pumps?
MR. KLUGE: That is the assumption in the
current licensing basis.
CHAIRMAN WALLIS: Well, why should that
be? I mean, something big enough to fail the dam
might --
MR. KLUGE: Well, it certainly could have
been a localized effect, such as a river barge,
causing enough damage.
CHAIRMAN WALLIS: Or it could be a seismic
event or something?
MR. KLUGE: It could be a seismic event.
DR. SIEBER: Well, a lot of plants use
fire trucks to do that, and they run around to all the
local fire companies and say if we have this problem
will you support us.
And I know of a number of plants that have
made that arrangement. So it is not impossible to get
pumping capacity.
MR. KLUGE: That is correct, and as I
indicated previously, we do have standing contracts
with pump vendors to ensure their availability.
CHAIRMAN WALLIS: So portable pumps, or
something like a fire truck driving up and hitching up
as a source of water?
MR. KLUGE: Well, the source of water in
this case is the lowered river bed.
DR. SIEBER: Right. Is it about a half-a-
mile from the river to the plant?
MR. KLUGE: Yes, but the required distance
to pump this water is simply over the contour in the
canal that has caused the separation.
MR. T. HANLEY: This is Tim Hanley again.
We actually had our ice melt line fail at Quad Cities,
and not this winter, but a winter ago when we had a
fire truck actually perform this same type of thing to
keep our intake structure from freezing over.
And we had that well within a shift, and
then portable irrigation pumps also to back that up.
So especially in rural Illinois, there are plenty of
irrigation pumps available if you should need that.
MR. KLUGE: And to evaluate the impact of
EPU on the ultimate heat sink, we did a bounding
analysis, which actually credited the inventory only
in the intake canal.
And we determined that the available time
for replenishing the canal would decrease from 5-1/2
days to 4 days, which we would still consider an ample
time frame to restore make up means from the lowered
river bed.
DR. SIEBER: Would you use water from the
discharge canal? It seems to me that it was pretty
hot, and there is always vapor coming off of there.
MR. KLUGE: The assumption in this
particular analysis was not that we use water from the
discharge canal. However, that heat would only make
a significant difference if we were using the water as
a cooling source via heat exchangers. We are just
pumping it into the isolation condenser and boiling it
off.
DR. SIEBER: Okay.
CHAIRMAN WALLIS: Did you worried about
net positive suction heads for the fire truck pumps
and pumping hot water?
DR. SIEBER: They are pumping out of the
river. So the river probably never gets about 90
degrees.
MR. KLUGE: That's correct. I would like
to describe the operational scenario here in a little
more detail. The initial makeup to the isolation
condenser is from on-site tanks and the capacity in
those tanks is considerably beyond what we require in
the scenario.
An operator action is required to reflood
a bay in the crib house, which due to the lower level
has lost suction. And that action is taken by
installing stop logs and using permanently installed
pumps to reflood the bay.
Then that reflooded bay becomes the
suction source to the diesel driven fire pump, which
provides long term makeup to the isolation condenser.
I mentioned that the USH also supplies the
diesel generator cooling water pumps. Those pumps
happen to be at a higher suction level than those that
reflood the intake bay.
Therefore, if diesel operation is
required, they become limiting as far as the useable
inventory in the bay, and they were accounted for in
the limiting analysis that I described previously.
The diesel generator water cooling water
flow path is from the intake canal, and through heat
exchangers, and back to the discharge canal.
The procedures then direct the operator to
establish recirculation of that water back to the
intake, which maximizes the use of the available
water, although again we did not credit the inventory
in the discharge canal in the limiting analysis. We
do credit the recirculation path.
The lack of a seismically qualified make
up path to the isolation condensers was identified
during our seismic margins analysis. The original
FSAR analysis that was the basis for licensing Dresden
relied on non-seismic equipment, but recognized that
there was a diversity of make up sources available.
However, as a result of the seismic
margins analysis, we identified the need for a
modification to provide that seismic makeup path, and
that is scheduled to go into the plant in 2003.
The staff requested that we evaluate the
risk of operating with the current configuration and
in doing that we concluded that EPU had an
insignificant impact on the plant risk for the
scenario, and Larry will talk about that a little
later.
The seismic margin success path must also
be able to mitigate a case where a seismically induced
equivalent one-inch LOCA comes about. We analyzed the
situation, and determined that the isolation condenser
and the available ECCS would mitigate the scenario for
at least 24 hours.
In order to provide a long term
capability, we identified another modification that
was necessary, and this would use different portable
pumps to make up directly to the containment cooling
heat exchangers, and therefore allow us to maintain
safe shutdown for a longer time period.
All the necessary actions to accomplish
this will be put into the plant procedures, similar to
the current required actions. Again, the staff
requested that we analyze the risk for the small LOCA
scenario, and we concluded again that EPU had a very
negligible impact on this risk.
And now Larry will describe those focused
risk assessments in some detail.
MR. LEE: Hi. This is Larry Lee. So,
consistent with NEUREG or the guidelines provided in
NEUREG-CR 2300, we used standard seismic risk
techniques to estimate the risk for specific scenarios
involving seismic dam failure with failure to the IC
makeup path.
And I will speak to a few of the sub-
bullets. First of all, the Dresden site-specific
seismic hazard curve was used from NEUREG-1488, and
the information here is based on the studies performed
by Livermore National Labs, and the curves are judged
to be conservative.
In terms of the -- we evaluated the entire
seismic hazard curve by dividing the curve into
discreet .1g intervals so that we could evaluate the
frequency and the seismic impact for each of the
intervals, and then add the risk for each individual
to come up with a total risk for the specific
scenarios.
And then the second to the last sub-bullet
is talking about we calculated the human error
probabilities for the pre-and-the-post EPU associated
with the scenarios consistent with how the human error
probabilities were calculated, and the base Dresden
PRA model.
And we only credited proceduralized makeup
paths. So we didn't credit any non-proceduralized
actions associated with any proposed modifications.
In terms of the results, we analyzed two
cases. The first one is safe shutdown with the IC for
a non-LOCA case, and we found that the delta-CDF
associated with EPU was on the order of 1E-minus 8,
and for a seismic dam failure with a coincidence small
LOCA, the delta-CDF was negligible.
DR. KRESS: Did you do an actual CDF?
MR. LEE: In terms of the actual CDF for
the pre-EPU, and for the first bullet, for the safe
shutdown with the IC, the CDF was approximately 9.3E-
minus 6. So with the delta of 1E-minus 8, the post-
EPU CDF was approximately negligible.
CHAIRMAN WALLIS: Within the --
MR. LEE: Yes. For the coincidence small
LOCA case, the pre-EPU CDF was approximately 1.9E-
minus 6 per year, and the probabilities for a seismic
induced small LOCA were based on the Zion analysis
from NEUREG-4550.
MR. KLUGE: This is Mark Kluge again. In
summary, we have concluded that EPU has minimal impact
on the ultimate heat sink capability for Dresden.
We will be completing the required
modifications on the previously committed schedule for
the seismic margins, IPEEE outlines, and the risk
impact and increase in risk is very small for these
scenarios.
Therefore, the ultimate heat sink is
acceptable for EPU operation. If there are no further
questions, I will ask John Freeman to come back up to
discuss the standby liquid control system.
CHAIRMAN WALLIS: Thank you.
MR. FREEMAN: This is John Freeman. We
are going to be talking from page 101. The issue
involved here was the information notice that was sent
out a few months ago concerning the standby liquid
control relief valve margin response under an ATWS
scenario.
Exelon has looked at the standby liquid
control system for Dresden Unit 2, and concluded that
there would be no interruption of the standby liquid
control flow rate delivered to the reactor under the
analyzed scenario.
However, Unit 3 of Dresden and Quad Cities
1 and 2 are still being evaluated, and there is a high
potential that we are going to need to make
modifications to the SLCS relief valves set point in
order to ensure that that valve will not lift and that
it will get our ATWS rule required flow rate to the
reactor.
Therefore, the conclusion is that the
standby liquid control is acceptable at EPU conditions
for Dresden Unit 2, and it will be acceptable for Unit
3 of Dresden, and Quad Cities 1 and 2, with the
completion of the modifications we have planned.
DR. SIEBER: It would seem to me though
that whether you add EPU or not, that would still be
an issue.
MR. FREEMAN: That is correct.
MR. HAEGER: Yes, this is not specifically
an EPU issue. This same phenomenon would occur prior
to EPU.
MR. HAEGER: Right.
DR. SIEBER: Okay.
MR. FREEMAN: Okay. If there aren't any
other questions, I will introduce Tim Hanley
MR. T. HANLEY: This is Tim Hanley again
from Exelon. The topic that I am going to discuss is
the large transient tests. As you are all aware,
ELTR-1 specifies two large plant transient tests to be
conducted.
One is an MSIV closure if the power uprate
goes to 110 percent; and the other one is a generator
load reject if the power uprate is greater than 115
percent.
Earlier, a question was asked, well, what
was the basis, a simple one or two sentence, for not
doing these tests. And to begin with, we believe that
it is unnecessary to assure the plant's response, and
I will go over some of the reasons why we believe that
is unnecessary to put the plant through the transient.
In both of these scenarios, both the MSIV
closure and the generator load reject, the SCRAM is
initiated off an anticipatory signal. In the case of
the MSIV closure, when the valves are less than 90
percent full open, the SCRAM signal is initiated
inserting the rods, and essentially terminating the
power excursion.
And the generator load reject, as the EHC
pressure drops and the turbine control valve bodies to
a certain point, indicating the fact acting solenoids
have actuated that SCRAMs the reactor and terminates
the power excursion.
In both tests, feedwater is still
available for level control and in the case of the
generator load reject, the bypass valves are still
available for pressure control.
Most of the major parameters of interest
in the input into determining how the plant is going
to respond are unchanged for EPU. The SCRAM times are
not being changed, and the valve closure times are
being changed.
The only thing that has really changed is
the peak dome pressure, which is really essential in
both of these. The beginning dome pressure is not
being changed. The only two parameters that are
changing are the reactor power level and the steam
line flow.
DR. SIEBER: And the stored energy.
MR. T. HANLEY: Right. You do have
additional stored energy. However, that decays very
rapidly as soon as the SCRAM goes in. In both cases,
you are well within your relief valve capacity are in
one case within the bypass valve capacity.
So the real test and the real parameters
of concern in these tests is what is your peak
pressure that you reach, and what is the peak power
that you reach prior to it turning around prior to the
SCRAM being effective, and terminating the excursion.
When G.E. originally put these in the
ELTR, they had no experience really with uprating
plants, and they had no basis for assuming that the
ODYN code that they used to determine the plant
response would be effective for uprated conditions.
And since that time, G.E. has concluded
that these tests should no longer be required for
power uprates at a constant pressure up to a certain
level, and I believe it is 120 percent, which we are
not exceeding.
CHAIRMAN WALLIS: Where would this large
transient test -- you mean that you actually take the
system to 115 power?
MR. T. HANLEY: No, no, no. If your power
uprate goes to 115 percent of your current power
level.
DR. SIEBER: These sub-bullets are
misleading.
CHAIRMAN WALLIS: They are misleading,
yes.
MR. HAEGER: Yes, that is misleading.
CHAIRMAN WALLIS: Then you have to test
the ability of the generator to reject load or
something, but you don't -- okay.
MR. PAPPONE: This is Dan Pappone. The
tests that we are talking about would be performed at
the uprated power level.
MR. CROCKETT: That's correct, but not 115
percent of the uprated power level. If your power
uprate exceeds 115 percent of your original license
power level, then it calls for that.
MR. FREEMAN: The original intent was to
perform those tests at the full uprated power level.
The safety analysis that has been done at both Dresden
and Quad Cities has been done using the ODYN code. It
has been benchmarked against BWR test data, and has
incorporated industry experience.
MR. BOEHNERT: What BWR test data?
MR. FREEMAN: Particularly it has been
benchmarked at --
MR. HAEGER: It is Peach Bottom, right?
MR. ANDERSEN: This is Jens Andersen. The
ODYN code has been benchmarked against full-scale
plant testing, particularly the Peach Bottom turbine
test.
MR. BOEHNERT: Were those at uprated
conditions?
MR. ANDERSEN: No.
MR. BOEHNERT: So what do you have a
benchmark at uprated conditions?
MR. ANDERSON: There are start up tests
for other plants that have been performed.
MR. T. HANLEY: In fact, we do have a back
up of a comparison, I believe, KKM.
MR. HAEGER: Well, what some foreign
plants have done is do this testing at higher power
levels than Dresden and Quad.
MR. BOEHNERT: At 120 percent? At 115?
At 110?
MR. HAEGER: Well, it is the thermal power
that they are at, which is higher than Dresden or
Quad.
MR. BOEHNERT: So they had a test where
they had done it 120 percent of uprated conditions?
MR. HAEGER: I think the one set of data
that we have was 110 percent of their original license
power. But I guess the point that we are making is
that the power levels at Dresden and Quad are at are
lower than the power levels of these units.
MR. T. HANLEY: And the beginning dome
pressures are lower than the pressures of these other
units, and so we are within the bounds of where ODYN
has been proven to be effective in determining how the
plant's response will be.
We are not extrapolating it out to some place where it
hasn't been proven.
MR. BOEHNERT: Do we know how applicable
that plant is to Dresden and Quad Cities?
MR. T. HANLEY: Well, I guess the next
bullet on the slide is that ODYN uses plant specific
inputs, models of steam lines and geometries of the
length.
DR. KRESS: Are the valves the same at
these plants, the same kinds of valves that you have
to open and close?
MR. T. HANLEY: That I can't say for sure.
However, once you isolate the vessel, you essentially
have relief valves left as your pressure protection.
We do know in fact the opening times of our relief
valves, and those are included in there, which would
be included at the other plants in their data.
And whether they are exactly the same or
not, that is a specific input that is used in the
modeling.
DR. KRESS: Oh, that's part of the
modeling? That's not in ODYN.
MR. HAEGER: Valve closure times are
modeled.
DR. KRESS: Valve closure times are
modeled.
MR. HAEGER: Yes.
DR. KRESS: But whether the valves can
actually close during time is another issue.
MR. HAEGER: Yes. We will get to that in
the next slide.
DR. KRESS: Okay.
DR. SIEBER: But if you run the test, you
are going to get all those relief valves and safety
valve actuations at least for relief valves, right?
MR. T. HANLEY: We will get relief valve
actuations on the MSIV closure for sure. You should
not get any safety valve actuations, but we will get
relief valve.
The power uprate, since the ELTRs were
initially -- was initially approved, they do have
additional operating experience to compare the
predicted plant response to actual plant response.
And what it has shown is that the code
adequately predicts the way the plants would respond
under those real conditions. So of those have been
under plant test conditions, and some have been under
unplanned transients, where they have gone back and
collected the data, and compared them.
And it does show that the code to
acceptably predict and also bounding predictions,
particularly on peak power and peak pressure. And
Dresden and Quad Cities both have adequate collection
capability.
And should we have one of these unplanned
transients, we would of course go back and verify that
the code predictions were as we expected. We have
done extensive code analysis and the --
CHAIRMAN WALLIS: You might have an
unintentional test anyway.
MR. T. HANLEY: And we have. In fact, at
Quad Cities in the last two years, we have had a
generator load reject and an MSIV closure at full
power.
CHAIRMAN WALLIS: And you have already
done the tests?
MR. T. HANLEY: Not at our uprated
conditions. Both Exelon and G.E. have analyzed the
major components that affect the large transients, and
those are MSIVs, steam piping, SCRAM signal, safety
release valves, and turbine valves, and the
interaction of those.
We have years of operational experience --
unfortunately, some of them awfully recently -- to
show that those components do operate as they are
designed, and we are well aware of their operational
history. And the transient testing does not mean that
these components will respond as designed.
MR. HAEGER: Now, that was to your point,
Mr. Kress, that to look at each of these components,
and really there is nothing in the EPU that would
change their response to the timing or whatever the
particular feature is.
MR. T. HANLEY: And in each of them we do
specific component testing on. We do stroke our
relief valves during start up, although some plants
have gotten away doing that due to the relief valves
leaking.
But in the MSIVs, we do time their closure
and set their closure time based on to be within our
tech spec limits.
DR. SIEBER: And do issues like Stone and
Webster speak to main steam line piping analysis and
supports, and those are factors here that may be
different than they were at your previous rating?
MR. T. HANLEY: Those could potentially be
impacted, because you are interrupting a higher flow.
DR. SIEBER: You have a big hammer, and it
breaks snubbers and pull things out of the wall, and
all kinds of stuff.
MR. T. HANLEY: The other thing to keep in
mind though is that we would be running these tests on
the plants at that power level. So whether you do it
planned or it happens sometimes unplanned, the results
are going to be the same.
So from an operational perspective, why
would I induce this transient on the plant unless I
had some real concern about the ability of the
analysis to accurately predict how the plant would
respond.
If I break a snubber under a planned -- we
would call it a test, but it is a transient that I am
inducing, or if I break a snubber when the turbine
trips from full power at some other time, the effects
to the operations in the plant are exactly the same.
You still have to deal with a broken
snubber, and so that is really kind of my conclusion
in all of this, is that we have limited changes to the
inputs to the plant because we are doing a power
uprated constant steam dome pressure.
Most of the other parameters of interest,
with the exception of reactor power and main steam
line flow, are remaining the same. So these are in
fact -- although they are labeled as tests, they are
transients being induced on the plant.
And are challenging the equipment of the
plant, and without a compelling reason, it doesn't
seem to me operationally to be prudent to go and shut
all the MSIVs at full power unless there was some
concern that we didn't have high confidence in the
modeling.
MR. BOEHNERT: Well, G.E. must have been
concerned. I mean, they initially said you should do
this testing. What changed their mind?
MR. HAEGER: Well, like I said, they have
had experience now with some uprates, and it showed
them that everything works out as predicted.
MR. T. HANLEY: Well, I should ask G.E. to
respond, but my discussions with them are that in fact
they have submitted a constant power uprate submitted
to the NRC that would no longer require these tests.
And we can't use that as a basis
obviously, because it is not approved, but they have
themselves come to that conclusion, and it is based on
their experience that their modeling has accurately
and adequately predicted the plant's response under
uprated conditions.
CHAIRMAN WALLIS: So their argument is
that they have already got experience, and there is no
extrapolation beyond experience involved.
MR. T. HANLEY: That's correct, and in
fact, Quad Cities and Dresden will be at a lower power
and lower steam line flow rate than a lot of plants
were originally licensed to have.
Van Gulf, which I have some experience
with from people that I work with, is over 3,000
megawatts thermal, with a corresponding steam flow
rate. So we are within the bounds where this code has
been proven to be effective in predicting the plant's
response.
CHAIRMAN WALLIS: This is again where some
kind of matrix or something would help, and if you
could show that here is the experience base, and here
is where you are going to be with the uprate, and just
as a comparison.
MR. HAEGER: For instance, in the material
that we have supplied to the staff, we do show some
specific data from KLL, and I have it here. KKL is at
3130 megawatts thermal, and they were -- and that was
113 percent of their original license thermal power.
MR. BOEHNERT: Has the staff accepted your
arguments?
MR. HAEGER: That is another open issue.
MR. BOEHNERT: That is an open issue?
MR. T. HANLEY: That's correct.
CHAIRMAN WALLIS: So may be they will
provide this matrix, or whatever it is, and that we
can actually look at and see the comparison between
experience and uprated power in these particular
plants, and see if it is covered.
DR. SIEBER: Well, I am not sure that you
can leap right away to the fact that everything is
okay just by saying that some bigger plant did it
before me. I think that it takes more thought than
that.
MR. T. HANLEY: But I think that is part
of the consideration. I certainly would be more
concerned had we been uprating to a new higher power
level that no plant had ever been licensed to. So
that is one of the considerations to look at.
DR. SIEBER: Well, I think more in terms
of power density, and cubic feet of plant per
megawatts, and --
MR. HAEGER: Well, once again this power
density for our plants is lower than other plants that
are licensed currently.
DR. SIEBER: I understand. Okay.
MR. T. HANLEY: So my final conclusion is
that we shouldn't intentionally put the plant through
what is a significant transient unless there is really
a compelling reason, which we haven't found there to
be one. Any other questions?
CHAIRMAN WALLIS: And this gets us to the
end of your presentation?
MR. T. HANLEY: Yes, it does. It gets me
actually to the beginning of my next presentation,
which is the implementation, training, and testing.
I am going to go quickly what training we
have done for the operators, both classroom and
simulator training, and what testing we will be doing
during the start up.
When I talk about the testing, it has been
completed at Dresden, which is going through their
uprate outage right now. With the exception that they
are going to have two hours of delta training that
they will do just prior to uprate just to get the
operators reacquainted with the changes, and what they
will be doing differently when they go about their
current hundred percent thermal power.
At Quad Cities, we have only begun this,
and we will complete all of the training before our
February outage on Unit 2, which is our uprate outage.
DR. SIEBER: Will all of the MODS be
modeled into your simulator?
MR. T. HANLEY: Yes. In fact, they were
modeled in the Dresden simulator prior to their last
session of simulator training, which was all focused
on EPU, and the same would be true for Quad Cities.
Classroom training covered really
everything that we would normally cover going into an
outage; any tech specs or other changes; design
changes, whether they were for EPU or not.
We are going to or are covering operating
procedure revisions that are going in, and mostly
those are due to modifications. There are some in
general that are just due to EPU.
Some other things that we did is look at
the plant limits and operating condition changes, and
those things include running all the four condensate
pumps, and all three feed pumps, changes in the
operation of the pressure control system for the
turbine throttle.
The vessel looked at MELLLA, and the new
power to flow map, and the differences that you may
see during certain transients, such as recirc runback,
and recirc pump trip. And we did cover some operating
experience from other plants that have done uprates.
Monticello had some feed flow inaccuracies
that they had not considered when they did uprates,
and Peach Bottom found that they had excessive
vibrations and had to put in another coronary EHC
system, residence compensator.
And in fact that got factored in as a
modification that we did at Quad Cities and Dresden.
Fitzpatrick had excessive vibrations that affected the
feedwater heating system, and the air line supplying
those control valves. So we went over a number of
things that had happened at other plants.
DR. SIEBER: How is that incorporated in
these to look for these things?
MR. T. HANLEY: Well, I will go over --
DR. SIEBER: Are do you just depend on the
operators?
MR. T. HANLEY: No, this was a heads up to
them, but it is incorporated into our start up testing
programs. So we will have a controlled look at all of
those things as we are going up.
DR. SIEBER: Now, your external nuclear
instruments will all be --
MR. T. HANLEY: We don't have ex-core. We
have all in-core.
DR. SIEBER: All in-core?
MR. T. HANLEY: That's correct.
DR. SIEBER: Okay. Do they all work?
MR. T. HANLEY: Most of the time. We had
some issues with copper migration in some of the SRMs
and IRMs in this last refueling outage that we have
replaced those that were susceptible. So we have had
good response with the nuclear instrumentation.
The simulator training began with a static
walk through the similar was set up as full power EPU,
and what they should see when they go in to take the
unit for the first time, and at its new uprated
condition, and just walk around and see where the
different parameters are from where they are used to
seeing it.
And just basically to get acquainted with
the plant as you will be seeing it. And we went
through some normal operation scenarios; power
changes, inserting rods, and doing some small recirc
changes.
And then did some dynamic scenarios that
we selected to highlight both the differences that
they will see at EPU and the similarities in their
response under these conditions.
And we ran through a loss of feed water
heating, and feed water controller failure, high
recirc controller failure, condensate pump trip. And
obviously before a condensate pump trip, the first
thing an operator does is verify the standby pump auto
starts.
Well, there is no standby pumps, and so
now the new action is verify the recirc pumps are
running back.
DR. SIEBER: Right.
MR. T. HANLEY: So we ran through a group
one isolation and a loss of off-site power with a
LOCA, and also a turbine trip without bypass with a
ATWS. Really from the operators experience the --
DR. SIEBER: This is a turbine bypass.
MR. T. HANLEY: That's correct. So
essentially it is almost the design basis ATWS,
because you give no bypass applicability. Really from
the operator's feedback, they didn't see a lot of
changes in their response to transients or accidents
other than those specifically associated with hardware
changes, like the condensate pump trip.
And that really is a credit to the generic
EPGs now that we work with symptom-based emergency
procedures. You are going everything off a parameter.
So you are looking at TORUS temperature,
and you are looking at drywell pressure, and you are
taking actions at specific levels of those parameters
before you reach them. So it doesn't really affect
how the operators respond.
DR. SIEBER: Have you had to change your
emergency response guidelines for the uprate?
MR. T. HANLEY: Yes, there will be some
minor changes to those.
DR. SIEBER: Like control points, and sub-
points, and things like that?
MR. T. HANLEY: Right. We are in fact
-- I believe that it is part of this submittal, and it
may be a separate one. We are changing our low level
SCRAMs at that point from 8 inches to zero inches.
So that obviously is an entry point into
the EOP. So that will be a change that goes in. But
the overall strategy of the Ops has not changed, and
really the operators, their feedback was that they
didn't see a significant difference in the way that
they attack it as transient.
DR. SIEBER: Has the power uprate created
any walk arounds for the operator that otherwise would
not exist?
MR. T. HANLEY: We will only be able to
tell that for sure once we get to those conditions.
As designed, operators are always skeptical, which is
good.
But as a design, we should not have
controllers left in manual that are supposed to be in
automatic. We should not have additional monitoring
required once we get through our testing program.
DR. SIEBER: That's right.
MR. T. HANLEY: And those are the things
that we are on the lookout for, as designed, and none
of those are built into this uprate.
But those will be the things that we will
have to look for when we get to the new license power
condition to make sure that they are identified, and
get put in our program, and get fixed in a timely
basis. So we don't intend to incur any operator work
arounds to reach our new power, licensed power.
CHAIRMAN WALLIS: Well, then all the
modifications will be -- except for records update,
will be complete, tested, and --
MR. T. HANLEY: Well, digital feedwater,
which is not being installed as part of EPU, but we
are taking advantage of that for particular input into
the recirc runback, obviously we will be doing start
up testing as we start up from that. So there will be
testing that goes on with this.
DR. SIEBER: So the run back won't occur
until you put that in?
MR. T. HANLEY: No, it will. It will all
be in during the outage, but all the testing on that
now won't be complete you are at power, and that is
the only way to test it.
But our intention is not to have feed
water heat level control valves left in manual, or
have the emergency dumps on those bias partially open.
So those are the things that the operators are
concerned about.
And we have done a lot of analysis, and
the increased shell pressure should increase the flow
through the same sized valves. So we shouldn't have
an issue with the drains on the feedwater heaters.
DR. SIEBER: And you will find that out
probably.
MR. T. HANLEY: Probably, and that's --
well, as operations, we are keeping our eyes out for
anything that didn't come out the way that we were
told it was going to.
That really covers the training portion of
it, and so I was going to go on to the testing. The
way that we are going to perform our testing is do one
power increase a day, and approximately 3 percent, and
stop there, and collect all of our data, and compare
it to the predicted value acceptance criteria.
And look for anything that would keep us
from increasing power the next day, and if we have to
make minor system adjustments, and if we have to go
back and reevaluate, and if we have to go back and
hold power there, that's the point where we will do
it.
We will be increasing along a constant
flow control line to limit the variables that we are
changing at one time. So, really essentially we will
be increasing recirc pump speed over the days to
increase power.
We are going to start collecting our
steady state day at 90 percent of our current licensed
thermal power for the systems that we are monitoring
for vibration data for the main steam and feed lines.
And we will actually be getting that data
at 50 percent of our current license thermal power.
But for the systems, we have got good operating
history, and we just want to get a base line at 90
percent of our current license power level.
DR. SIEBER: Are you going to do anything
special with the turbine since you are getting a new
high pressure turbine?
MR. T. HANLEY: And we are changing the
diaphragms on the control valves, and what we will be
doing is we always monitor turbine vibrations, and we
always do --
DR. SIEBER: And that is standard on the
start up?
MR. T. HANLEY: Right, and we will be
doing our normal control valve stroking to ensure that
the other control valves can compensate adequately for
one control valve closing.
But the high pressure turbine itself will
have a unique MOD test associated with it, and not
related to EPU. In fact, Dresden right now is
installing a new high pressure turbine.
And so when they start up, even though
they won't be licensed EPU, they will be doing their
generic MOD test for that.
DR. SIEBER: Now, you have a boreless
spindle?
MR. HAEGER: Boreless rotor?
DR. SIEBER: Yes. Well, a spindle. We
always run a line through the bore, and if you don't
have a bore, then I am not sure how you align.
MR. HAEGER: The question, George, is if
you don't have a bore, how do you do the alignment?
MR. NELSON: This is George Nelson. They
are using laser alignment techniques, which are
primarily off of the opening of the shaft.
DR. SIEBER: And we shoot through the
shaft with a laser.
MR. T. HANLEY: And these tests will be
conducted with a dedicated testing team lead by an
SRO. There is one assigned to Quad Cities and one
assigned to Dresden. We are also sending our people
to Dresden for our start up testing when they begin
their power ascension testing.
And then those people from Dresden will
becoming to Quad to make sure that we capture any
lessons learned about that. We are doing specific
signal and system response testing for the two
systems, control systems, that are being significantly
altered for EPU.
The pressure control system for the main
turbine, the control valves will actually control
turbine throttle pressure at a lower pressure than it
does right now to maintain reactor pressure at a
thousand-five, because it is controlling at a new set
point, and we will be doing specific pressure
incremental changes on it to make sure that it has a
stable response.
And that it does not oscillate
divergently, and we are also going to do a pressure
regulator fail over test to make sure that the back up
pressure regulator takes control when it is supposed
to, approximately three pounds higher than the normal
pressure regulator.
The feed water level control system, we
operate normally in three element control, and so the
input is from feedwater and steam flow have been
changed.
We are going to do some specific testing
of that unrelated to our digital feedwater at Quad
Cities and Dresden, which went digital a number of
years ago.
And doing incremental level changes and
verify the system response as stable. We will put one
feed rate valve in manual and make adjustments to it,
and verify that the other valve can control
adequately.
And then we will do that at varying power
levels to ensure that it is stable over the range of
normal operation for them. We will be doing specific
system equipment performance monitoring.
These are mainly geared towards the
balanced plant systems, which are the ones being
modified for EU. Each parameter we have gotten from
the system engineers are predetermined acceptance
criteria.
And the performance parameters, as we go
up through our 3 percent increases each day, that is
where we will be collecting the data, and comparing
that, and seeing if any changes need to be made to the
plan, and to the system operation before we continue
our increase.
In addition, there are the 10 balance of
plant systems that we have selected, and we will also
be monitoring the recirc pumps since we will be
operating those at a higher RPM than we are currently
and also the reactor, and just verifying that we don't
see anything odd happening there.
Specifically, we are increasing the flow
in the feed water and steam -- main steam line piping,
and want to verify that we don't have excessive
vibration and it is difficult to try to determine
ahead of time where that may occur.
And so we are putting vibration monitoring
equipment, both inside and outside containment. We
will be getting lower power vibration data, which I
talked about earlier, and we are getting about 50
percent power.
And then the acceptance criteria are
established from the ASME stress analysis limits on
what is acceptable and what is not. And we won't
exceed any of those limits.
In conclusion, we have completed at
Dresden extensive training, and we will complete at
Quad Cities extensive training for the operators,
which has used both the design features and are
operating and experience from other plants, the
testing plans, incremental and comprehensive, and
gives us good guidance before we increase power to the
next level.
And the project implementation will ensure
that EPU is implemented as designed. Do you have any
questions? If not, with that, I will turn it over to
Jeff Benjamin, Vice President of Licensing and
Regulatory Affairs.
MR. BENJAMIN: Since I am on the verge of
having to say good evening, I will make my remarks
brief. First of all, we are pleased to have the
opportunity this afternoon to present our submittal.
As I think we articulated at the beginning
of this presentation, our objective at the outset of
this project was to increase the power output for the
Dresden and Quad Cities stations, while maintaining
the appropriate operating margins, and continuing to
operate the units safely and reliably.
I think the project team that has worked
for the past two years in partnership with our
vendors, have met those objectives as we talked about
today, and as supported by the bullets up on the
slide, I think our package before the Commission for
their review and approval also reflects those points.
I want to particularly emphasize what Tim
touched on last, and that is that we have had the
opportunity to go through three power uprates in our
fleet over the past couple of years, and have learned
through each one of those the importance of our change
management program, including the operator training,
testing program, and the monitoring program.
And I am confident that the infusion of
those lessons learned, as you just heard Tim
articulate a piece of. We will also add confidence
that the assumptions that went into the power uprate
package will be borne out and tested out appropriately
as we bring the unit up on line, and as we test it out
at the higher power levels.
So, in summary, we believe that the
submittal that we have before the staff demonstrates
the acceptability of our proposed power uprate, and
that completes our presentation, subject to any
questions.
CHAIRMAN WALLIS: Thank you very much. Do
we have any questions from the committee or
consultant?
Now, you are going to make a presentation
to the full committee, and you are going to compress
this presentation by a factor of eight or something
like that?
MR. HAEGER: Yes, and we would expect some
guidance from you on that.
MR. BENJAMIN: I think we would anticipate
working with you on the areas of emphasis that you
would like to see, and obviously we would compress
that material accordingly to facilitate the discussion
within your schedule constraints.
CHAIRMAN WALLIS: I think things that you
can show in a diagram would be helpful; like with
numbers with the containment analysis and the
conclusions from the ECCS and so on, and show that you
met some criteria specifically.
CHAIRMAN WALLIS: Okay.
MR. BENJAMIN: I also assume that you
would look for a condensed version of our risk
discussion?
CHAIRMAN WALLIS: I would think we would
need that, yes. We need a very brief overview to
remind the committee of what is involved with this
EPU, in terms of changes in flow rates and so on.
MR. BENJAMIN: We will clearly articulate
differences between Dresden and Quad Cities as well in
the presentations. So we won't have to go over that
again.
DR. SCHROCK: I would think it would save
time.
MR. BENJAMIN: I think it will, yes.
DR. KRESS: I think you want to talk about
your reasons for doing the transient test, because
that will be a question of contention perhaps.
MR. BENJAMIN: Very good.
CHAIRMAN WALLIS: Do we need anything on
stability?
MR. BENJAMIN: I had a chance to observe
the Duane Arnold presentation, and we may have an
opportunity with the full committee to go back over
the power to flow chart one more time, and have a
chance to articulate exactly how we operate in the
higher power regions.
And in a very practical way I think show
how we do that, and --
CHAIRMAN WALLIS: This is part of the
overview?
MR. BENJAMIN: This would be part of an
overview, and I would suggest that Tim could go back
through that again with the full committee and do that
rather efficiently. And I think that would be
worthwhile as well.
DR. FORD: As part of the materials
degradation is concerned, I guess one bullet.
MR. BENJAMIN: No problem.
DR. FORD: I don't know if I am allowed to
say anything. Am I?
DR. KRESS: Yes, you can say or talk about
things like that.
CHAIRMAN WALLIS: Yes, you can.
DR. FORD: Well, I don't see any problems
at all with that.
DR. KRESS: Well, it seems like they might
want to discuss the FAC, because that is what will
come up at the full committee.
DR. FORD: There is a whole range of
things, such as the FAC, the flow induced vibration,
and potential cracking of the core shroud. It seems
to me that all of those issues were in fact being
adequately managed. We all recognize that they are
being adequately managed.
DR. KRESS: And I think that the committee
would probably have a preconceived notion that
extended power uprates only affects FAC.
MR. BENJAMIN: So could I suggest that we
would have one slide that would cover that topic, and
that would have the bounds around how we are managing
our materials and draw those conclusions?
DR. FORD: Well, depending on what we hear
from the staff, and they don't have any problems with
that.
CHAIRMAN WALLIS: And for accuracy, you
could have a summary slide for ATWS.
DR. SCHROCK: One thing that never came up
in this meeting that I wondered about and that is the
statement in the SERs that the task code has not had
prior NRC approval, but it is under review.
MR. HAEGER: Dan, can you speak to that?
DR. SCHROCK: That ought to get clarified
I would think.
MR. PAPPONE: This is Dan Pappone. The
task code has been accepted for transient evaluations,
and delta-CPR evaluations, and it is currently under
review for the LOCA considerations, where we are using
it and taking it one step further.
As far as transients, we are looking at
whether or not when or if transition occurs, and in
LOCA we are looking at when and where. But that is
under review.
DR. SCHROCK: When I look at this table of
computer codes used for EPU, for transient analysis,
and ATWS, you have a number of codes, and it appears
in both places.
MR. PAPPONE: Right.
DR. SCHROCK: It is a little hard to tell
-- and also I think it is G.E. terminology. You have
SAFER/GESTR, which is a cover name for amalgamations
of these various codes; is that right?
MR. PAPPONE: That's right.
DR. SCHROCK: And I may be alone in not
understanding how they go together to do what you are
doing it with it, but maybe that is something that
needs to be clarified.
DR. KRESS: It certainly would be nice to
see that database that you referred to on the ODYN
code that shows that you are still within the
parameters that it has been validated at.
MR. BENJAMIN: Would you like us to submit
that prior to the full committee, or would you like us
to submit that at the committee?
DR. KRESS: At the full committee would be
fine.
MR. BENJAMIN: Okay. That's fine.
CHAIRMAN WALLIS: On the piping and
reactor internals, I don't think you need to spend
very much time. I think you do have to address the
fluence issue, because they expect it to go up and it
went down, or it appeared to go down.
DR. FORD: I think that comes under
materials degradation.
CHAIRMAN WALLIS: Well, we don't need to
go into a lot of the --
MR. BENJAMIN: That would be an
approximately one slide treatment as you suggested,
yes, and we would pick that up in there.
CHAIRMAN WALLIS: If there is nothing
else, we will recess until tomorrow at 8:30 a.m., and
we will then hear from the staff.
(Whereupon, the meeting was adjourned at
5:38 p.m, to convene at 8:30 a.m. on Friday, October
26, 2001.)
Page Last Reviewed/Updated Tuesday, August 16, 2016
Page Last Reviewed/Updated Tuesday, August 16, 2016