Thermal-Hydraulic Phenomena/Future Plant Designs - February 13, 2002
Official Transcript of Proceedings
NUCLEAR REGULATORY COMMISSION
Title: Advisory Committee on Reactor Safeguards
Combined Thermal-Hydraulic Phenomena/
Future Plant Designs: Subcommittee Meeting
Docket Number: (not applicable)
Location: Rockville, Maryland
Date: Wednesday, February 13, 2002
Work Order No.: NRC-232 Pages 1-327/361-375
NEAL R. GROSS AND CO., INC.
Court Reporters and Transcribers
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Washington, D.C. 20005
(202) 234-4433UNITED STATES OF AMERICA
NUCLEAR REGULATORY COMMISSION
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ADVISORY COMMITTEE ON REACTOR SAFEGUARDS
COMBINED THERMAL-HYDRAULIC PHENOMENA/
FUTURE PLANT DESIGN: SUBCOMMITTEE MEETING
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FEBRUARY 13, 2002
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The Subcommittee met at the Nuclear Regulatory
Commission, Two White Flint North, T2B3, 11565
Rockville Pike, at 8:3 a.m., Graham B. Wallis,
GRAHAM B. WALLIS, Chairman
THOMAS S. KRESS, Member
DANA A. POWERS, Member
VIRGIL SCHROCK, Consultant
WILLIAM J. SHACK, Member
JOHN D. SIEBER, Member
PAUL A. BOEHNERT
MAGGALEAN W. WESTON
ALSO PRESENT: (CONT.)
SHI LANG WU
Opening Remarks, G. Wallis, Chairman . . . . . . . 6
Arkansas Nuclear One, Unit 2 Power Uprate
Introduction, Rick Lane. . . . . . . . . . . 8
Plant Changes to Accomodate Power Uprate
Milton Huff. . . . . . . . . . . . . .19
Bryan Daiber . . . . . . . . . . . . .36
Compliance with Regulatory Requirements
Doyle Adams. . . . . . . . . . . . . .60
Rich Swanson . . . . . . . . . . . . .94
Dale James . . . . . . . . . . . . . .98
Jamie GoBell . . . . . . . . . . . . 116
Bryan Daiber . . . . . . . . . . . . 122
PRA Analyses . . . . . . . . . . . . . . . 156
Concluding Remarks, Rick Lane. . . . . . . 182
Introduction, T. Alexion . . . . . . . . . 189
Reactor Systems, C-Y. Liang. . . . . . . . 194
Plant Systems, D. Cullison . . . . . . . . 210
Mech. & Civil Engineering, K. Manoly . . . 230
Materials & Chemical Engineering,
B. Elliot. . . . . . . . . . . . . . . . . 239I-N-D-E-X
NRR Presentation (cont.)
Resolution of Open Issues, M. Hart . . . . 257
PRA Analyses, D. Harrison. . . . . . . . . 267
Concluding Remarks, T. Alexion . . . . . . 276
Clinton Power Station, Unit 1 Extended Power Uprate
Introduction, Joe Williams . . . . . . . . 288
Plant Changes, Dale Spencer. . . . . . . . 289
Technical Subjects, Bob Keresetes. . . . . 300
Core and Fuel, Fran Bolger . . . . . . . . 321
CLOSED SESSION . . . . . . . . . . . . . . 327
Core Flow, Kent Scott. . . . . . . . . . . 367
Concluding Remarks . . . . . . . . . . . . 369
Adjourn. . . . . . . . . . . . . . . . . . . . . 375
CHAIRMAN WALLIS: The meeting will now come
to order. This is a meeting of the ACRS Combined
Subcommittee on Thermal Hydraulic Phenomena and Future
Plant Designs. I'm Graham Wallis, the Chairman of the
Subcommittee on Thermal Hydraulic Phenomena, and Tom
Kress the Chairman of the Future Plant Design
Subcommittee will chair the meeting session beginning
at 1:00 on February 14, 2002.
Other ACRS members in attendance are Dana
Powers, Bill Shack and Jack Sieber. The ACRS
consultant in attendance is Virgil Shrock. The
combined subcommittee will first begin review of the
license amendment requests of Entergy Operations,
Incorporated for a core power uprate fo the Arkansas
Nuclear One, Unit 2 Plant, and secondly we will begin
review of the license amendment request of the Amer-
Gen Energy Company for a core power uprate for the
Clinton Nuclear Power Plant, Unit 1. And thirdly, we
will continue review of the Phase 2 pre-application
review of the Westinghouse Electric Company's AP1000
The subcommittees will gather information,
analyze relevant issues and facts and formulate
proposed positions and actions as appropriate for the
liberation 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 January 29, 2002. Portions of the meeting
may be closed to the public, as necessary, to discuss
information considered proprietary to General Electric
Nuclear Energy and the Westinghouse Electric Company.
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 the speakers first identify themselves
and speak with specific clarity and volume so that
they can be readily heard. We have received no
written comments, nor request for time to make oral
statements from members of the public.
Now this should be a very interesting
three days. We have two different power uprates for
different kinds of reactors, and then we have a review
of the AP1000, which some might claim is in some way
resembling a 70 percent uprate from the AP600. So we
have three different power uprates to discuss, and it
should be a very interesting time.
I'd like to begin this meeting, and I call
upon Rick Lane?
MR. LANE: Yes.
CHAIRMAN WALLIS: Of Entergy Operations to
MR. LANE: Good morning. My name is Rick
Lane. I'm the Director of Engineering Projects for
Entergy, and we appreciate the opportunity today to
come and visit with you about our plant power uprate
of Arkansas Nuclear One, Unit 2.
First of all, I'd like to introduce our
presenters. First we have Milton Huff. Milt
recognize yourself. He's with our designers group.
Brian Daiber, safety and analysis, Rich Swanson, with
operations, Dale James over here with the engineering
programs components, and Jamie GoBell, design
engineering also. We also have, as noted here, some
other support staff with us today from Entergy and
Next, I'd like to talk about our primary
goals in performing this uprate, and first and
foremost was safety. We wanted to make sure we safely
uprate the unit, doing the appropriate analysis, and
modifying the plant as required to achieve the 7.5
percent uprate. We want to make sure we maintain
adequate operating and design margins as we did that.
We want to use accepted and proven methologies to
And also, one other strategy we have, a
major goal was to have one cycle of operation on any
major modifications that were going to be necessary to
accommodate this, and we'll talk about that further.
We've already made some substantial modifications in
our previous outages to accommodate this and to allow
us to build with an uprate at the higher percentage.
As far as the project team, our Entergy
staff really was the AE on this effort. We performed
the necessary system evaluations and modifications to
accommodate the uprate. We did utilize some
contractor staff to augment our people, but we were
always in the lead and had the oversight of that
activity as the AE for the effort.
In addition to that, we had Westinghouse
involved with us, formerly Combustion Engineering, who
was the original SSS vendor for the ANO Unit 2 to
perform the associated SSS related analysis for our
safe analysis, structure analysis and so forth, to
support us in this effort. And, as indicated here,
it's a very substantial effort, a lot of man hours
over a few years here have been spent in planning and
to help us to be ready to execute this effort.
From the overview spent at standpoint
again, as I mentioned earlier, it's a 7.5 percent
uprate. We have also, and as is true in our 14
outages mentioned here, have made some substantial
changes, one of those of which was replacing the steam
generators, and that was key in our overall effort as
far as determining what kind of a size power uprate.
We factored that into the design and the
implementation of that replacement effort that was
achieved at the last refueling outage for ANO Unit 2.
We also, as part of that, re-rated the
containment for higher design pressure, and we'll talk
more about that today as far as exactly what was
involved there and what pressures and so forth we
uprated to. And in the overall implementation
CHAIRMAN WALLIS: Excuse me.
MR. LANE: I'm sorry.
CHAIRMAN WALLIS: When you replaced the
steam generators, you still have the same amount of
surface, or did you change?
MR. LANE: No.
CHAIRMAN WALLIS: You changed the surface?
MR. LANE: We changed the surface area and
CHAIRMAN WALLIS: Are you close to the
maximum surface you can get in there now?
MR. LANE: That was one of the limitations.
We'll talk about that. We have increased the diameter
of the generator, increased the surface area, and
we'll talk more about that. So we pretty well maxed
out as far as what we felt we could reasonable
accommodate for the configuration within the
And again, our overall implementation
schedule is for our 2R15 outage which is coming up
this spring, is to come up out of that outage and go
through a rigorous test effort and go into an uprating
condition. That's our current schedule.
As far as the reactor design rating, the
original core design rating is 2815 Mwt. The Post
2R15 uprate again is 7.5 percent is at 3026. This is
our first request for a design re-rate for this unit.
MEMBER POWERS: Does that imply that we can
expect more requests in the future?
MR. LANE: One of the things that we have
not, that we are going to be looking at is Appendix K
type of uprate potentially to take advantage of the
margins there and we will look at that and post the
rerate here to see if the appropriate margins that are
there possibly for an Appendix K uprate.
MEMBER POWERS: Are you speaking of an
MR. LANE: Instrumentation. As far as
uncertainty, the two percent
MEMBER POWERS: Relatively.
MR. LANE: We're talking about maybe a
percent and a half, something like that would be a
potential uprate that might, we might look at that.
MEMBER POWERS: You are not discussing
going to a more realistic analysis for Appendix K
MR. LANE: No. We're talking about just
taking the instrument of uncertainty that's available
there is all we'd be talking about.
Next slide please. Our submittal that we
provided here we feel was in accordance with the
guidelines out there available, the Westinghouse WCAP
topical, the guidance in the GE topical, also the SECY
document 97-042, and also we utilized the Farley
uprate submittal, as again guidance for us to make
sure we were being consistent with what the
expectations were, as far as our submittal.
CHAIRMAN WALLIS: That Westinghouse topical
is quite old, isn't it?
MR. DAIBER: 1983.
MR. LANE: Yes, 1983. We tried to use the
companion data out there to help us make sure we were
providing the required information to address the
MEMBER POWERS: I guess I'm a little
perplexed on how a Westinghouse topical is helpful for
a combustion engineering plant.
MR. LANE: One aspect of that is to
recognize that Westinghouse was the provider of the
replacement steam generators, and that was part of our
effort. But as far as the topical applicability
MR. BOYD: This is Dennis Boyd. I work in
the licensing department. Back when we were
formulating our plans for uprating in power, we tried
to find, assimilate all the guidance that was out
there, in order to make sure we got the right kind of
information to the staff for review.
What we found was there wasn't a lot out
there for PWRs, so we use this 1983 document, which
like you say, it's a Westinghouse document, but it is
for PWR. We also gathered as much as we could out of
the GE topical, and then we looked at the 1997 SECY
document and those three things, other than the
uprates that were already out there, was all that we
could put our hands on at the time.
MEMBER POWERS: So what you're going to
tell me is that you're going to take this plant up to,
what is it, 3065 MWt, and there is absolutely no date,
not one data point in the world on this type of plant
operating at that level, right?
MR. BOYD: Bryan, do you want to.
MR. DAIBER: This is Bryan Daiber from
Entergy. The ANO 2 plant is a CPC plant. It's a CE
designed plant and it's similar, although a smaller
version of the System 80 plants, the Songs (phonetic)
Plant, the Waterford Plant, and the Paliverde Plants,
all of which have higher rating than what we're
planning to go to with the ANO 2 unit.
So there are comparable or similar CE
designed plants out there already at higher power
ratings and they are higher rated than where the ANO
2 is going.
MEMBER POWERS: Your statement is similar
to hear. It is a general one. I mean, it's not
specific to the things that I would use, like
Wendell's numbers and whatnot are exactly the same in
MR. DAIBER: With respect to the rapid
protection system design considerations, the fuel
design considerations, the geometry, the layout,
they're all CE designs using a comparable rapid
protection system and design considerations.
CHAIRMAN WALLIS: Now you said this is all
you could lay your hands on. You didn't get anything
from the staff by way of guidance?
MR. BOYD: The staff requested that we use
the Farley submittal.
CHAIRMAN WALLIS: That's for the use of the
because they don't have any review plan.
MR. BOYD: Not to my knowledge, no.
CHAIRMAN WALLIS: So they requested that
you use Farley?
MR. BOYD: Yes, sir.
CHAIRMAN WALLIS: Okay.
MEMBER SIEBER: Farley was based on what we
MR. BOYD: That's correct.
MR. LANE: Okay. As a final point I'd like
to make as far as we feel we have demonstrated
compliance with the applicable regulations and safety
limits. In doing the analysis for this effort, we
looked at reactor operating conditions, accident
conditions, transients, radiological consequences,
probabilistic risk, and the programmatic evaluations.
We'll talk more about that in the presentation today,
to address that in more detail for you.
So that pretty much concluded my
introduction, and what I'd like to do now, unless
there's other questions, is to really turn it over to
our next presenter.
MEMBER SCHROCK: I had
MR. LANE: Yes, sir.
MEMBER SCHROCK: a point that I'd like
to raise and that is the kind of agreement that you
had with the staff about proceeding as you have with
substantial capital investment up front, to be
followed by a review of the methology to justify the
uprate. It seems to me that that is an awkward
position to be in , an awkward position on both sides.
Was that discussed with the staff prior to installing
these steam generators?
MR. LANE: The major capital investment,
like the steam generators, were driven more from steam
generator tube integrity and a new to do that
particular change irrespective of whether we were
going to uprate or not. It's just that when we did
uprate, when we did replace the steam generators, we
make sure we accommodate, as we have in other changes.
MEMBER SCHROCK: In the documentation, you
determined the level of 7.5 based on an economic
consideration, that you would be able to recover the
capital cost if you could get to 7.5, 6.5 was
problematic. Did I have that right?
MR. LANE: The increase of 6.5 to 7.5 was
when we really got into sizing the steam generators
and looked at what was available as far as the
again, we talked about earlier about surface area and
size and then we went from the 6.5 to the 7.5. But
it's a combination on any of these uprates, a
combination to look at the technical aspect and the
economics aspect of what's the various pinch points
and plateaus that make good sense as far as going to
MEMBER SCHROCK: Thank you.
CHAIRMAN WALLIS: Yes, sir. Aren't you
going to introduce yourself?
MR. WILSON: Yes. I'm Roger Wilson. I'm
with Entergy. We made some attempts to talk to the
staff as early as possible about the potential for the
uprate, but really we proceeded at risk with the
increase in sizes. There was no dialog with the staff
of agreeing that they would approve the 6.5 or 7.5
uprate. We proceeded at risk. When we were changing
the steam generator to put the surface area in there,
which is about 24 percent more surface area in there,
but we did that at risk.
MR. LANE: What I'd like to do now is turn
it over to
CHAIRMAN WALLIS: While we're on the
MR. LANE: Yes, sir.
CHAIRMAN WALLIS: About what's changed, I
noticed an increase in the containment building design
MR. LANE: Yes.
CHAIRMAN WALLIS: It's the same building
though, isn't it?
MR. LANE: Yes, it was.
CHAIRMAN WALLIS: So what's happened?
MR. LANE: What we did, as far as, and
Bryan will talk more about that, when we get into
looking with the larger steam generator and then look
at the boil down and so forth you get, we got an
increase in building pressure, and so it's just a re-
rate to the existing structure, and we went through
the appropriate structural integrity testing and so
forth to basically, you know, demonstrate that along
with the analysis effort. And it's really about five
pounds, from 54 to 59 pound increase that was involved
as far as the re-rate of the existing structure.
CHAIRMAN WALLIS: So we'll hear about that
MR. LANE: You will hear about that later,
MEMBER POWERS: As we go through these
presentations, will you be discussing how you know
that you maintained adequate operating and design
MR. LANE: Yes, we will.
MEMBER POWERS: I'd be intrigued to see
this with the relative absence of guidance on how you
know that they're adequate.
MR. LANE: Okay, we'll try to be sensitive
to that and address those points as we get to those
sections where we talk about the margins and so forth.
The next topic on the agenda is talking about the
plant changes to accommodate the power uprate, and I'm
going to turn it over to Milton Huff to have that
discussion with you.
MR. HUFF: My name is Milton Huff. I'm
with Entergy. I was the engineering supervisor on the
power uprate project. The power uprate project has
been a plan in process for about the last six years or
so. And before we even started this formal process,
our site management, any modification coming into the
site would have power uprate considerations.
All modification to accommodate the 7.5
percent uprate condition, that was part of that
strategy, modifications implement over the last four
cycles. The point there I want to stress is that
we've have opportunity to make the operations staff
familiar with the large components that we have
installed, evaluate the synergistic effects. So we've
kind of with this planning effort and the way this
project's been laid out has given us opportunity to
feel comfortable with the changes in the power plant.
The majority of the major modifications
are installed. Go to the next slide and we'll go
through these. As Rick mentioned earlier, at the
heart of this uprate is the steam generator
replacement and that surface area increased from
86,000 square feet to approximately 109 square feet.
The issue that drove us to the generators,
as Rick mentioned, was the tube degradation and we
took the opportunity to improve our power plant
performance with these generators.
MEMBER SHACK: Now how did you get that
increase in area. You changed the pitch of the tubes?
MR. HUFF: The actual, yes the vessel size
is approximately four inches bigger diameter. It's a
smaller tube. It's Alloy 690. Dale James will go into
tube integrity issues, but that's basically the
MEMBER SHACK: There's a smaller tube?
MR. HUFF: Yes, smaller diameter.
MEMBER SCHROCK: What about the other plant
components, such as heat exchangers and smaller pumps?
MR. HUFF: I've got these on these next
MEMBER SCHROCK: Oh, okay.
CHAIRMAN WALLIS: What were your units?
You said 109?
MR. HUFF: Yes, sir. The original was
86,000 square feet. We went to approximately 109,000
CHAIRMAN WALLIS: I wasn't sure I heard the
thousand. I was puzzled.
MEMBER SIEBER: Could you give us a little
bit of an idea how the primary system DP across a
steam generator changed in area?
MR. HUFF: I think Bryan
MR. DAIBER: This is Bryan Daiber from
Entergy again. From the pressure drop across the
steam generators, we went with quite a few more tubes,
and the smaller diameter. However, the tubes, the
drawing process has improved so that the slickness,
the roughness has gone down, and what we effectively
designed for in the overall steam generator design
through the tube sheet, was a comparable delta P as
the original steam generators before 220.
MEMBER SIEBER: So RCS was the same as it
used to be?
MR. DAIBER: We restored RCS flow back to
essentially where it was, prior to a significant
MR. HUFF: These next two modifications,
the condenser and the separator, even if we weren't
doing uprate would have required replacement, because
of the copper alloys present in the original
component. The condenser, we uprated the size of it
also to accommodate the higher steam flows, went with
the Titanium because we are on the Arkansas River,
which is border to brackish, so that was the reason
for the Titanium tube support plate. Spacing is such
that we won't get excessive vibrations, so we designed
these new modular condensers for this uprate steam
MR. SEIBER: So the spacing of the tube
support plates is closer?
MR. HUFF: Yes, that's correct.
MEMBER SIEBER: What is the distance from
the tube sheet to the first support plate?
MR. HUFF: It's approximately two feet.
Well, it's in the two feet range. It reduced about a
third. I don't have the exact number, but we can get
MEMBER SIEBER: And you've operated with
MR. HUFF: Yes, two cycles.
MEMBER SIEBER: Is its performance equal to
the original? Can you maintain the same vacuum with
the same cooling decline?
MR. HUFF: Yes, sir. Actually it's more
MEMBER SIEBER: More efficient.
MR. HUFF: More surface area, and obviously
because of the change, we had copper nickel, there was
an offset in surface area just to go to the same
thermal performance, and then for the anticipated
power uprate, we expanded that surface area even
MEMBER SIEBER: How do you know that? I
mean, it hasn't been operated at a higher level.
MR. HUFF: It's standard heat exchanger, we
use the HEI standards in the sizing of that head
MR. WILSON: This is Roger Wilson again
from Entergy. The condenser, we went up about 13
percent more in surface area, but with the slight
decrease in conductivity through the Titanium tubes,
effective surface area is around a 9 percent increase,
adjusted for the Titanium tubes. We also put in an
AmerTap system cleaning system, and during Cycle 14,
when we were at degraded conditions, our secondary
flow rates were up.
In order to correct for the lower steam
pressures, we raised our flow rates. So our flow rates
were up at Cycle 14, the last cycle at the steam
generators, comparable to where we're going to be with
power uprate. So we have operating experience with
that, plus we made improvements on our condenser
vacuum system, air removal system. So we've had very
good experience with these new condensers.
MEMBER SIEBER: Generally when you go to
Titanium tubes, one of the issues is tube vibration.
I presume, have you measured that in any way, and did
the decrease in spacing of the support plates correct
MR. HUFF: Well, the tube support spacing,
there are several things we did to it to address that.
The steam lanes where we had the highest, you know the
introduction into the bundle, we went with a higher
gauge wall on top of the spacing, and there were also
along the top, the top row is solid bar for
impingement, because that was one of the big design
concerns for Titanium was moisture impingement. So we
put a lot of extra design features in there to protect
MEMBER SIEBER: You didn't have to do
anything like staking or?
MR. HUFF: No, that's correct. Had we had
a stainless condenser, we would have had if you
can't change your support plate spacing, then you have
to put the stakes in or something like that to stiffen
MEMBER SIEBER: That's sort of the fallback
position if you start to get tube leaks caused by
MR. BOEHNERT: Closer to the mike, Jack.
She's having trouble hearing.
MEMBER SIEBER: Okay, so that's the
fallback position that you would have to take.
MR. HUFF: Right.
MEMBER SIEBER: Should you begin to get
MR. HUFF: That's the big advantage I guess
we have over this period of time and the age of the
plant and the opportunity to design these components
to accommodate these increased mass flow conditions.
The condenser is designed for the higher flow rates.
I think we have ample design features in there to
protect that and give us satisfactory performance.
The moisture separator reheaters fit in on
the side are also. Primarily what drove it for the
protection of the generators, was to remove the
copper. We took the opportunity, we've improved the
moisture separators in 2R12, and then changed the
bundles out to 439 stainless, increased the surface
area of this heat exchanger by approximately 50
MEMBER SIEBER: What about copper and
feedwater heaters and steam condenser ejectors and
things like that. Is all the copper gone there?
MR. HUFF: All the copper is gone. The
high pressure turbine, the first three stages with
uprated condition represented a choke flow, so we were
having to go into our HP turbine. So we took the
opportunity, again, to pick the GE advanced design to
get additional efficiency megawatts out of that
modification. The low pressure turbines, we changed
those out, put high efficiency turbine blading in, and
just from the efficiency gain for these two
modifications, separate from uprate, we're gaining
about 42 megawatts for those two.
Other major modifications, we rewound the
generator this past cycle, past outage. That took it
was 1046 Mega Bars to 1133. That would be the rating
after we've put the auxiliary components in here to
support that re-rating. Hydrogen coolers, analysis
showed we needed to replace those to support the
Standard piping, we made a configuration
change. The Stator cooler and series with the main
cooler, so it picked up, that flow path picked up heat
so we separated them and put them in parallel paths to
insure a cooler source of water for the Stator
I think Bryan will discuss this when he
gets into the containment analysis. One thing we had
to do, because the containment analysis results in a
higher peak pressure, it has more load on the
containment building fans and motors. To accommodate
that requirement in increased load, we changed the
pitch approximately three degrees, retarded the air
flow to accommodate the change in pressure.
To counter that, from a standpoint of
normal cooling, the containment chill water coils are
the normal coolers. We increased the surface area
there, and the result of this mod, we've already seen
a 10 degree drop in normal containment building
temperature. So we took the opportunity to improve,
accommodate those conditions in what we currently
CHAIRMAN WALLIS: How cool is the chilled
MR. HUFF: Chilled water coming in,
approximately 45 degrees, is that correct?
MEMBER SIEBER: Another question on the
change to the turbine. Is the exit moisture content
higher or lower or about the same as it was before?
MR. HUFF: Bryan, do you have the heat
MR. DAIBER: Yes, it's higher. It's more
efficient, so on the high pressure turbines, of
course, it increased our loads on our heater drain
pumps. It's a more efficient turbine.
MEMBER SIEBER: So you would expect more
blade erosion because of that?
MR. DAIBER: I'm not the expert on that.
I'm sorry. I believe it's been designed for that. I
know we were able to increase the number of years
between inspections, so I believe there's some
advanced features in that too.
MR. HUFF: Well that design, that blading,
GE provided the heat balance, and designed the blading
MR. WILSON: Again, this is Roger Wilson.
We replaced the whole high pressure steam path. It's
not just three stages, but it's a whole new high-
pressure turbine stators and rotors. The only thing
that remains is the casing.
MEMBER SIEBER: Ok, thank you.
MEMBER SCHROCK: You mentioned GE in this
MR. HUFF: Yes, sir.
MEMBER SCHROCK: Stepping back a moment, I
was a little puzzled as I read the documentation to
find that your basis in part if GE proprietary
documentation for uprates. I'm unclear as to what the
GE involvement is in this particular uprate. Can you
give a very brief explanation of that?
MR. BOYD: Let me take a shot.
MR. HUFF: Okay, this is Dennis Boyd again.
MR. BOYD: What I was trying to convey
earlier was, we used the GE document just as a basis
for knowing the types of information to include in a
power uprate submittal on the PWR side. So we only
used that, as I stated earlier, for lack of having a
specific topical form like a CE PWR plan. So we just
used it for content.
MEMBER SCHROCK: Well, my question pertains
to the proprietary nature of the document that's cited
in the references here. How do you have access to a
proprietary GE document is really what puzzles me.
MR. WILSON: I don't think there was any.
Again, correct me, Dennis Roger Wilson. I think it
was all just a CE. See I don't remember any GE
proprietary, did we?
MEMBER SCHROCK: Well, the one that you
reference is proprietary. It's in the title of the
MR. WILSON: Oh, I don't know how we got a
hold of that.
MR. HUFF: I'd have to go back and pull the
string on that.
MR. WILSON: Yes. I guess we got it from
a brother plant that's GE PWR.
CHAIRMAN WALLIS: That's the first time
I've heard brother plant. Sister, they're usually
MR. HUFF: This slide represents the major
modifications, hardware modifications left to go at
this point for the Cycle 16 upcoming spring outage.
We plan to put in the Stator water heat exchangers,
replace those. We're also upgrading the Isophase bus
cooling fans. The coolers were replaced last cycle,
last outage, and the fans and housings are being
changed out to this outage to improve that capability.
Heater drain pumps, on the feedwater side,
the heater drain pumps are really the only major
component to be changed out there, and that's with the
more efficient heat cycle that we had, as Roger
explained. We're going to have more drain flow, so
the capacity of these pumps had to be increased and we
also improved and redesigned three stages of the pump,
and larger motors and recirc lines. There will be a
The rest of the feedwater heater system
isn't far from the original design. Each loop
approximately capable of 80 percent power operations.
So this is the last of the components that we saw we
needed to change, and with the uprate a footnote
here. With the uprate conditions, feedwater system
grids will be capable of approximately 65 percent
single loop operations.
CHAIRMAN WALLIS: The transformers are
MR. HUFF: The transformers, yes they were
okay. There was an increased load, but from a life
cycle, the load on the transformer will increase where
degradation or the life cycle will be shortened. But
there's no need to replace those to support uprate at
CHAIRMAN WALLIS: There was a remark that
I didn't quite understand about the load on the
transformers being highest in the winter, highest in
MR. WILSON: Yes. I don't remember that.
This is Roger Wilson. I don't remember that. The
highest loads are in the summer. Our peak loads are
in the summer.
CHAIRMAN WALLIS: That's what it says in
MR. WILSON: Well, I think what it says is
you could load it higher in the winter.
CHAIRMAN WALLIS: You could load it higher
in the winter, but it's going to be stressed more in
MR. WILSON: It's stressed more in the
summer. Our peak time is definitely in the summer in
CHAIRMAN WALLIS: I didn't understand why
that was relevant to deciding things were okay.
MR. HUFF: Ambient obviously has a lot to
do with transformer performance and cooling. But I
think the point they were trying to make there, during
the summer period because of the limitation on the
cooling power, the climate affect on cooling tower
performance, you will get some lower megawatt
predictions, a droop there in summer operations.
CHAIRMAN WALLIS: So it says here that the
proposed 105 to 109 percent loading, which will occur
during only the wintertime is acceptable. So what's
going to happen in the summer? Are you going to
operate at a lower loading?
MEMBER SHACK: Right, 101 to 103 is what it
CHAIRMAN WALLIS: So you're going to be
stuck with a lower loading in the summer.
MEMBER SHACK: Right.
MR. WILSON: This is Roger Wilson again.
As Milton said, because of our back pressure on our
condenser, we do have a sag off of approximately 12
megawatts in summer because our back pressure in our
condenser goes up as a result of those in the cooling
tower. Those loads are taken off prior to the main
transformer, so the load onto the transform is lower.
CHAIRMAN WALLIS: So the two things go
MR. WILSON: Yes.
CHAIRMAN WALLIS: You produce less power
because of the efficiency of they cycle.
MR. WILSON: That's right.
CHAIRMAN WALLIS: And the transformers can
handle so much anyway, so it all works out all right.
MR. WILSON: Yes.
CHAIRMAN WALLIS: So the uprate we're
approving really is for the winter?
MR. WILSON: No, it's a year round
operation. That's incorrect.
MR. HUFF: Setpoint changes, we've kind of
got this broken up into two parts of our discussion.
Bryan, the Director of Safety Systems will discuss
those setpoints, the ones that in my area here that we
modified on the secondary side, such things as
feedwater water control setpoints, seamed up bypass
control setpoints, NRS release valve setpoints, things
of that nature were changed.
All these setpoint requirements and the
modifications, this process we've gone through is a
system-by-system evaluation. We have an engineering
request that we put out on each system, and that's
what drove the modifications, is what drove the
MEMBER SCHROCK: Your feedwater heaters,
you say they were so robust in the original design
that you didn't need to make any changes there, but
there must be some reduction in performance.
MR. HUFF: And I have two per training I'm
having to re-rate, the 3s and 4s, simply on
temperature, not pressure. We've had Yuber do a
detailed evaluation from thermal performance, design
from a tube vibration issue, so from the standpoint we
had the OEM on the heat exchangers validate the
performance of those feedwater heaters, and they would
be on site, along with the code inspectors, to re-rate
the 3s and 4s on both loops.
The equipment and structure re-rates, Rick
touched on it earlier, the containment uprate in the
feedwater heaters are the two things that are having
to be re-rated, and the containment went from 54
pounds to 59 pounds. Bryan will discuss in his
presentation what drove that, and the details on that
In conclusion, is the balance of plant
structures. Systems and components are acceptable for
power uprate by either modification or evaluation. At
this point, the modification section I'll turn over to
MR. DAIBER: Let's see if I can do this
without knocking the mike off. I'm Bryan Daiber. I
work for Entergy. I've been involved with the RSG and
power uprate programs for the last five years or so,
and I was the safety analysis lead for the power
The first thing I'm going to go over is
one other plant modification for consideration at ANO
that we took into account for the uprate condition was
related to the fuel design. For Cycle 16, which is
our next cycle, the first uprated core design, we're
still using the standard 16 x 16 fuel assemblies that
we're currently using. We're still maintaining the
same number of total assemblies of 177 in the core.
We are adding 80 fresh assemblies to the core for the
first cycle of operation.
We are changing burnable poisons, however.
WE're going from Gadolinia to Erbia.
MEMBER POWERS: I guess I don't understand
the significance of 80 fresh assemblies being added to
the first cycle.
MR. DAIBER: My next slide will get into
that a little bit more, if you can just wait.
MEMBER SIEBER: From Baddinia to?
MR. DAIBER: Erbia.
CHAIRMAN WALLIS: You mean you take out 80
old and put in 80 new?
MR. DAIBER: That's correct.
CHAIRMAN WALLIS: So it's an exchange.
MEMBER SIEBER: Basically that's what's
MR. DAIBER: Right, we're exchanging 80
assemblies with 80 fresh assemblies.
MEMBER SIEBER: Are all 80 the same
enrichment, and if so, what is it?
MR. DAIBER: There's a range of enrichments
for the assemblies. It varies. It's around four and
a half weight percent, plus or minus about a half
percent, is that correct, Mehran, the enrichments for
Cycle 16, four and a half plus or minus about a half
MEMBER SIEBER: And per given assembly, is
it zoned fuel or is it all the same enrichment in a
MR. DAIBER: In a single assembly, I
believe it varies slightly within assembly, is that
correct? There may be one or two zones in an
MR. BOEHNERT: You need to get to a
microphone. There's a microphone there.
MR. GOLBABAI: I'm Mehran Golbabai. I'm
from Westinghouse. I believe most assemblies, the
enrichment within the assemblies are the same.
MR. BOEHNERT: Thank you.
MR. DAIBER: We're also changing Tcold.
We're increasing Tcold 2o from where we're at in Cycle
15, from 529 to 551, and also to accommodate power
uprate, we're reducing the radial peaking factor. In
the next slide, I'll get to some of the numbers in the
From the change in burnable poisons, we're
currently using Gaddolinia, and we're moving to Erbia.
Now the reasons for that has to do with the poison
itself. Erbia is a much more dilute poison. It
allows us to have better power peaking control, better
moderating temperature control. It gives us more
smooth power considerations, and this transfers, not
just only during normal operations but also during an
anticipated transient, such as CA withdrawals, the
peaking considerations are controlled better with
Ernia burnable poisons.
MEMBER POWERS: How does the Erbia change
the oxygen potential of the fuel relative to what
MR. DAIBER: The oxygen potential?
MEMBER POWERS: Right.
MR. DAIBER: I'm sorry. I don't know the
answer to that. We'll have to get back to you on
MEMBER POWERS: If it makes it worse and
you have a stronger clad interaction, then it's not
MR. DAIBER: Are you talking about the
MEMBER POWERS: Inside attack on the clad.
MR. DAIBER: On the clad.
MEMBER POWERS: By the fuel. It may not be
a less adverse response to transients.
MR. DAIBER: I don't know about the exact
oxide thickness, relative to the other core designs.
We did look at that from the overall magnitude or the
result of the oxide thickness, and I believe 100
microns is what we used as an acceptance criteria for
that, under power grid conditions.
MEMBER POWERS: How much is the power plate
dependent on the changes in the fuel?
MR. DAIBER: With respect to the change
from Gadolinia to Erbia, we gained quite a bit of
margin in the peaking considerations, and we gained
about five, six percent operating margin with respect
MEMBER POWERS: This is because of the way
things develop over the cycle?
MR. DAIBER: With respect to the
challenges, with regard to peak considerations during
normal operation and also during transient conditions.
MEMBER POWERS: Are you going to change the
fuel again for the next cycle?
MR. DAIBER: With respect to the burnable
poison, no. The intent is not to do that.
MEMBER POWERS: You're going to keep
reloading with Erbia?
MR. DAIBER: Yes.
MEMBER POWERS: So you're going to have all
Erbia after a while?
MR. DAIBER: That's correct.
MEMBER POWERS: How about the 80 fresh
MR. DAIBER: The 80 fresh assemblies are
all Erbia assemblies.
MEMBER POWERS: No, I mean you're starting
the cycle with 80 fresh assemblies.
MR. DAIBER: That's correct.
MEMBER POWERS: Okay, now we're going to
come to the next cycle. Are you going to put another
MR. DAIBER: That will vary depending upon
cycle length and the energy requirements for each
MEMBER POWERS: I'm still trying to
understand what the significance of putting 80 -
MR. DAIBER: Go to the next slide.
MEMBER POWERS: And then the next cycle,
there's going to be some different number.
MR. DAIBER: Yes, it will. It varies from
cycle to cycle. With respect to the number of
amenities with Cycle 14. In Cycle 14, we added 80
fresh assemblies. The current cycle we're in, we
added only 68 assemblies. The next cycle we are
looking at adding essentially 80 assemblies.
Now that value, that number of assemblies
is dependent upon the energy content, and what this
slide compares here or shows effectively is for Cycle
16, the energy and content in Cycle 16 is actually
less than the energy content required for Cycle 14,
due to the decrease in cycle length, and secondly due
to the decrease in cycle length, even though we are
operating at 7.5 percent for Cycle 16.
MR SCHROCK: What has been the past
practice on exchanging fuel? How many cycles will
they bundle experience in the core?
MR. DAIBER: Usually up to three cycles.
MEMBER SCHROCK: Up to three, meaning that
some fractions go up to three, but some only do two.
MR. DAIBER: That's correct.
MEMBER SCHROCK: So what is the ratio of
MR. DAIBER: From cycle to cycle?
MEMBER SCHROCK: Do most of them do three?
Do a few do three?
MR. DAIBER: A very small fraction of them
do three, 10, 20 percent would be in there for three.
CHAIRMAN WALLIS: So you have to
continually check that the fuel is satisfying all the
margin requirements and all those things?
MR. DAIBER: Yes. That's done on a cycle
CHAIRMAN WALLIS: It is. Well, I guess the
staff has to be satisfied that you are continually
doing that. This is not going to limit the power that
you can get out.
MR. DAIBER: That's correct. On a cycle
specific basis, we continue to look at the core
CHAIRMAN WALLIS: So is this a step forward
that's made possible with new fuel, this upgrade of
7.5 percent? If you didn't have Erbia, you wouldn't
be able to do it?
MR. DAIBER: It would have been a lot more
challenging with Gadolinia. There are several other
modifications not modifications per se, but changes
in the fuel design that also have helped accommodate
power uprate; in particular, the original core designs
did not credit or did not use the integral burnable
poisons, such as Gandolinia and Erbia. They used
So we removed those shims over the past
several cycles, and now effectively, there's usually
maybe one of the few assemblies that may still have
the shims in it. But for the most part, we removed
all those. That alone has increased the fuel pin
percent by about five percent alone there.
CHAIRMAN WALLIS: Is experience with Erbia
poison fuel over three cycles in other plants?
MR. DAIBER: Yes. Most the Westinghouse CE
Plants using the integral burnable poisons are using
CHAIRMAN WALLIS: So there has been
experience over the full life of the fuel?
MR. DAIBER: Yes.
MEMBER SIEBER: What is the assembly
average discharge burn up poison burning fuel?
MR. DAIBER: I believe the number is around
58,000 plus or minus about 500. That's the peak rods.
You're talking about the average assembly?
MEMBER SIEBER: The average assembly, yes.
MR. DAIBER: Mehron, do you known the
average assembly numbers?
MR. GOLBABAI: (Off mike.)
MEMBER SIEBER: And I presume the Thot is
the same for every cycle and if so, what is it?
MR. DAIBER: For power uprated cycles, as
I mentioned, we're increasing Tcold by 2o from 549 to
551 and with the increase in power uprate, the Thot is
expected to go to 609 for Thot.
MEMBER SIEBER: And that's right around the
activation temperature for Alloy 600. What components
in the plant, for example, control rod drive mechanism
and so forth that are IC600.
MR. DAIBER: Dale James will be talking
about that in a later presentation. So if we could
defer that, I'd appreciate it.
MEMBER SIEBER: Thanks.
MR. DAIBER: So with respect to the fuel
design, we're changing the burnable poison. Another
key factor here is part of the Cycle 16 core designs
are we are reducing the radio peaking factor
considerations and that reduction in radial peaking
factor relative to prior cycles, is greater than the
7.5 percent uprate.
MEMBER SHACK: Is the core protection
calculator qualified for these fuel change designs?
MR. DAIBER: Yes. Yes, it doesn't
necessarily look at the fuel itself, obviously. It's
looking at the thermal hydraulics into the assemblies.
MR. BOEHNERT: Well, has that changed? Do
these new assemblies have any modifications relative
to the thermal hydraulic parameters?
MR. DAIBER: The CPC is the only one
monitoring the Coles, the plant monitoring systems.
They look at the RCS inlet temperatures, the flows,
the in-core considerations with regard to flux
mapping,a nd all of that is effectively staying the
same, even with the new fuel. It's not any real
different within the current Gadolinia core design.
MR. BOEHNERT: No, I'm asking if the
assemblies themselves, have they been modified or
never been changed at all?
MR. DAIBER: No, there are no physical
modifications to the general geometry of the assembly
and the pins and the grids.
MR. BOEHNERT: Compared to what you were
MR. DAIBER: Compared to what we're
currently using, that's correct.
CHAIRMAN WALLIS: Are you going to reach
the conclusion that everything's okay, and that means
that you still got a margin to all the various limits
classified for fuel.
MR. DAIBER: Yes.
CHAIRMAN WALLIS: You haven't shown us any
of these margins, so we don't have any direct evidence
that you are below the margins, or how far you are
below the margins. Do you care to explain that?
MR. DAIBER: With respect to the core
designs and the considerations, we've looked at all
those, with respect to current core designs and
previous core designs, and with these modifications
that we're making here, the challenge with respect to
fuel considerations are really bounded by what we've
seen in the past for Cycle 14 type core design
Now there are a few areas where we did go
beyond past core designs. MTC is one of those. We
went with these core designs do result in a slightly
more decative modulary core coefficient, and all the
safety analysis have been updated to accommodate that
with adequate margin. Pin pressure have gone up
slightly, as a result of the core designs. But again,
to insure that the pin pressures stay within
acceptance criteria, we have limited our linear heat
rate considerations after about 200 EFDP, we insure
that the linear heat rate is limited to insure that
pin pressures aren't exceeded.
Other than that, for the most part, the
parameters and other considerations with the core
designs that we're seeing for this cycle and several
other cycles, when we looked at this power uprate
effort, we didn't just look at Cycle 16, we did
various core designs beyond Cycle 16 and looked at the
general range of parameters that we look at on the
cycle specific basis, and all those core designs
effectively fell in with the ranges that we had
essentially used when we established the Gadolinia
core designs back in Cycle 13.
So a lot of the parameters and
considerations that we are still using now in all
their downstream analysis and considerations were
established when we first went to integral burnable
CHAIRMAN WALLIS: And the staff has audited
these methods that you're using.
MR. DAIBER: The methods that we use with
respect to pin pressures, oxide buildup and those
considerations, the fate methodology essentially, we
use methodologies for considering fuel performance
MEMBER POWERS: You tell us that all of
them are the same, but I can think of at least one
that surely must not be the same. I mean, if you were
letting fuel up to 58,000 megawatts per ton, surely
you can't have the fuel survive a rod ejection
accident and put 240 calories per gram into it.
MR. DAIBER: I'm not thinking the high
burn-up assemblies are typically limiting with respect
to ejection analysis. Typically, it's the higher
burn-up assemblies, correct me if I'm wrong, Mehran am
I wrong, but typically the lower burn-up assemblies
are more limiting with respect to route ejection and
energy addition considerations.
MR. GOLBABAI: The peak burn-up limit has
not changed, so with respect to burn-up, even with
operated power, the 60,000 megawatt per day per ton
remains the same. So we did not extend that in
response to your question.
MR. DAIBER: So in conclusion, we looked at
the core design and we feel that the core design
itself has met the design criteria and is acceptable
for power uprated conditions.
The next area I'm going to go into will
deal with the boric acid makeup tank volume and weight
percent design criteria. The ANO operates with a high
concentrated boric acid tank, the BAM tanks that we
refer to, and the design of these tanks is essentially
developed based on what we refer to as a cool down
without let down situation. We go from Mode 1, which
is power operations down to effectively Mode 4, and
during this transient consideration, we looked at the
cool down during that let down available.
We start the cool down at about 26 hours
with essentially Xenon at its started 2K at that
point. Similar offsite power, end of cycle conditions
with respect to initial Boron concentration and MTC
considerations, and during that cool down, we insure
that the tank concentrations and inventory there are
enough to insure that we have five percent shut down
margin during that cool down.
In a similar fashion, we do a Mode 5 and
6 cool down scenario, again making sure that the boric
acid concentration and inventory is sufficient to cool
the plant down and maintain a five percent shutdown
margin in the tank.
As a result of the more negative MPCs that
we are seeing, we did have to impose a slight increase
in restrictions on the tank concentrations. The
current tank concentrations can vary between 2.5
weight percent and 3.5 weight percent. We've narrowed
that band to the 3.0 to 3.5 weight percent, and
inventory in the tank has increased slightly, also as
a result of the demands.
But, all of these requirements with
respect to the tank themselves, are within acceptable
limits and design considerations for the tank and
CHAIRMAN WALLIS: Is somebody going to talk
about mixing in the core. It seemed to be an issue in
MR. DAIBER: That's dealing with the long-
term core, boric acid considerations on ECCS. So if
we could wait until we get the ECCS analysis, we'll
discuss that. So with respect to the BAM tank
considerations, we reviewed design requirements on it
and found it to be acceptable.
The next item I'd like to move on to would
be the pressure temperature limits, the PT limits for
active vessel limits of 4 ANL 2. The current PT
limits were set in the tech spec to expire at 21 EFPY;
however in response to generic letter 9201, the
limiting material was changed and the effective EFPY
was reduced to 17. Associated with that, more
At the end of Cycle 14 operation, which
was our last refueling outage, we had effectively
reached about 15.5 EFPY. So to make sure we could meet
the 17 EFPY considerations, we pulled a reactive
vessel specimen at that point in time. We had that
specimen analyzed and we have developed new PT curves
as a result of that. The results have been submitted
to the staff for review in October of last year.
In the development of that PT curves for
that effort, we did account for the increased power
uprated core designs in those PT calculations. The
fluence to the specimen was based on the proved
methodology, FTI's methodology BAW-2241P-A. We used
that methodology to estimate the fluent and accounted
for also the power uprate effects in the PT curves.
Fluids outed 32 EFPY.
CHAIRMAN WALLIS: Is this something you
submitted since the draft I see that we have?
MR. DAIBER: This was submitted to the
staff in October.
CHAIRMAN WALLIS: I was puzzled by the SE
we have because it talked about neutron fluence and
everything seemed to be okay up to Cycle 16. I mean
it's now or tomorrow.
MR. DAIBER: That's right.
CHAIRMAN WALLIS: I couldn't see why it was
okay after that. You were going to submit something.
MR. DAIBER: Yes, and this is the submittal
CHAIRMAN WALLIS: Something which is since
MR. DAIBER: That's correct.
CHAIRMAN WALLIS: Which I haven't picked up
yet. I need to find it or read it or something, or
the staff will explain it perhaps.
MR. DAIBER: Yes.
CHAIRMAN WALLIS: It's very puzzling that
you were sort of okay until the next cycle. That's not
a very comfortable feeling. You want to be okay for
quite a few.
MR. DAIBER: That's right. The
justification only went into about three weeks of
Cycle 16, which is the uprated core design.
CHAIRMAN WALLIS: You uprate and then you
shut down a few weeks later.
MR. DAIBER: Hopefully not. So we have
submitted these new PT results, and the results of the
PT limits actually have opened the operating space a
little bit. And the reason for that is two reasons.
One is the fluence that we've seen that the original
PT curves were based on, were based on a specimen poll
that occurred at 1.69 EFPY. Those early core designs
which were effectively the first two core designs that
that first specimen saw, were highly rich core
In Cycle 6, we essentially started to go
to low leakage core designs and we continued to
implement core leakage designs even under the
operating conditions. So the fluence values on your
uprated conditions are essentially expected to be less
than what the vessel was seeing in the first five
cycles of operation.
And also, in the PT curve development
itself, we referenced ASME coke case, N-641 in
development of curves, which wasn't available when the
original PT codes were developed.
So as a result of that, we've developed a
new PT curves under power uprated conditions and the
new PT curves have been determined to be acceptable
under power uprated conditions.
MR. WILSON: This is Roger Wilson again.
We made our original submittal back in December of
2000, and we provided the additional information on
the PT curves on July 24, 2001. I have a copy of the
MR. DAIBER: Yes, I believe the vessel
specimen results, the PT codes were in October.
MR. WILSON: October, that's right.
MR. DAIBER: I'd like to move on to the
third agenda item, compliance with regulatory
requirements at this time.
CHAIRMAN WALLIS: We're just about on
schedule. I'm making a rough calculation. It looked
to me as if you were on schedule. Is that the way you
MR. DAIBER: I think we are.
CHAIRMAN WALLIS: Because we've got other
things going on later in the day. Is that about
MR. DAIBER: It's about right. Compliance
with regulatory requirements, from an analysis
perspective, we started power uprate considerations
back when we were doing the RSG design and
implementation and all the analyses done at that time,
in addition to the new analyses, specifically for
power uprates, with respect to the containment
analyses, the LOCA analysis, the 50-46 analysis, the
non-LOCA transient analysis, all these events and
considerations were performed with approved methods.
So all those analyses were performed with
a few slight exceptions here, where we applied new
applications of approved methods. In these cases, for
large break LOCA and boric acid precipitation, we use
approved methods, but this is the first time
application for ANO 2 on these methods. And we'll get
to both of those a little bit later on.
Also with respect to offsite releases and
control room doses, again what we utilized here is we
utilized methods consistent with what we had used in
the RSG effort. The doses specific to power uprate
were performed with the same methodology that we had
used for RSG considerations, with respect to the
control and dispersion factors in offsite releases.
MEMBER POWERS: When you calculated your
control room doses, what leakage?
MR. DAIBER: When we did our original
control and dose calculations, the limiting event is
the MHA LOCA, and we did that with 10 CFM in leakage.
And subsequent to that, we have done a test which has
greater in leakage, and I'm going to go into that
issue a little bit later on.
There was one area where we felt there was
a new method that was applied and that was for feed
level line break. Here the new method really deals
with a credit for low level actuation in the affected
generator. In prior analysis we had conservatively
waited until low generator level occurred in the
unaffected generator. With respect to the power
uprate application, we've credited low level actuation
in the affected generator for the first time.
Also when we performed the analysis, we
looked at the acceptance criteria required for those
particular evaluations and made sure that we met all
the acceptance criteria and we also made sure that we
applied all the appropriate regulatory guidance on
When we were using NRC approved methods,
we also verified that all the limitations and
constraints confined for those methodologies were
appropriately accounted for in the application of
those approved methods.
In conclusion, all the safety analysis
that we performed for the RSG power uprate combined
effort, we use verified, approved methods. We
verified compliance with all the applicable regulatory
guidance. We verified the acceptance criteria was
met. We also verified that the limitations and
constraints in the SERs were also met.
MEMBER POWERS: You're going to give us
some more details later, are you?
MR. DAIBER: With respect to the LOCA
analysis, we'll be going into more detail in that,
LOCA containment analysis.
MEMBER POWERS: And the control room,
you're going to go into more detail?
MR. DAIBER: That's right, yes. With
respect to plant margins now, I'm going to kind of go
over an overview in these areas. In the first part
here, Milton Huff had presented mostly the balance of
plant component considerations, and when we looked at
the balance of plant design, we verified that those
components would be able to operate within those
design requirements for those systems.
For any of those components or systems
that were not meeting the design requirements,
appropriate modifications have been installed or will
be installed to insure that we can meet those design
requirements and margins.
MEMBER SIEBER: When you talk about the
electric power portion of the plant, did you consider
and have to make any changes to circuit breakers,
since you're interrupting capability margin is
probably reduced to some extent, current carrying
MR. WILSON: This is Roger Wilson. I don't
remember any modifications to any of those, but all of
those were reevaluated. We did detailed reevaluations
in all of those areas. We have very detailed
calculations on all that.
MEMBER SIEBER: All right.
MR. DAIBER: In a similar fashion, we also
looked at the NSSS, and the NSSS, which includes
reactor coolant system, the volume control system, the
safety injection systems, and your shutdown cooling
systems. We looked at the design requirements for
those systems and components, and made sure that we
could maintain the same design requirements, which we
were originally licensed to.
And after reviewing those systems and
components, we were able to verify that no
modifications were necessary to insure that the NSSS
was able to meet its design requirements.
We also looked at the control systems.
The control systems including the pressurizer pressure
and level control systems, the feedwater control
system, steam dump and bypass control systems. We
also looked at the plant protection systems, and the
plant monitoring systems to insure that the setpoints
associated with those systems and those control
systems also would operate and function properly under
power operated conditions with the appropriate design
In those situations where adjustments to
setpoints were necessary, we've implemented and will
be implementing as necessary, setpoint changes.
From the containment perspective, when we
did the RSG analyses, we did indicate an increase in
peak building pressure design requirements. So, we
have, as part of the RSG effort, we underwent a re-
rate of the containment design from 54 pounds to 59
psig. During that effort, we looked at all the
equipment inside containment and verified that the
equipment inside containment could operate under the
uprated pressure of 59 pounds.
CHAIRMAN WALLIS: How does it explain
what's going on here. You have the same building, and
somebody naive would assume that it's designed for 54
psig. That's what it's designed for. How do you
manage to change its design pressure?
MR. ADAMS: My name is Doyle Adams with
Entergy. I was working with the RSG when they did all
that, and also was the RPE for the repairs,
modifications to the containment, and also the testing
as it came out of the outage 2R14.
To answer your question, we had some
slides. Due to the modern ability of everything, we
managed to lose those things. So I'll try to go
through what I had prepared and then try to answer all
your questions you have there.
What we have ANO is a Bechtel containment,
designed in `68 to the early `70s when it was actually
designed. It's a three butress plant. It's a sphere
dome cylinder walls with a nine-foot thick concrete
normally reinforced base mat. We have a quarter inch
thick steel liner on the inside of it.
It was regularly designed for 54 psi at
300 degrees Fahrenheit. We uprated the containment to
59 psi and still used 300 degree Fahrenheit number for
that. It was originally designed and still is to ACI
318, `63 version of that code. And what we did, when
we came out of the outage, we actually tested it
again. I guess we're probably the only containment
that's been uprated that way and actually did another
structural integrity test on it.
And we came out using, read at 1.18 to do
that test, with minor modifications to some changes in
it that we dropped as far as amount of instrumentation
we did and things like that, mainly due to the fact
that we already had, the second time we had unit 1,
which is basically the same plant, and Unit 2 we'd
already done a SIT on it. So we knew how the building
was reacting, and we wanted to confirm that as we went
We also subjected our containment to ILRT,
which you would have to anyway. But to keep from
recycling and more cycles on the containment, we
actually performed the SIT and the ILRT at SIT
pressures. So we did it normally, you would have it
in about three to four hours at SIT pressure. It's
dated for 11 hours. We also had
CHAIRMAN WALLIS: I'm sorry, what is SIT?
MR. ADAMS: It's structural integrity test.
CHAIRMAN WALLIS: Okay.
MR. ADAMS: As opposed to SIT tanks. But
due to some construction issues, we also had two
tenants that we want stressed up. We had one vertical
and one horizontal.
CHAIRMAN WALLIS: What is the pressure of
MR. ADAMS: 68 PSI, 1.15.
CHAIRMAN WALLIS: Well, I don't know how
long it's going to take, but is the basis for
operating it that you did tests at higher pressures?
You changed your basis of analysis?
MR. LANE: He's looking for the basis I
think. You did a combination of analysis and tests,
MR. ADAMS: Oh, yes.
MR. LANE: Answer the question, you know,
as far as the basis of how we re-rated the
MR. ADAMS: The basis, okay. Well that was
the next slide.
MR. LANE: How did you do this then?
MR. ADAMS: Okay. How we did this was we
went through and we did all new analysis. We used
Bechtel BCEP analysis, which is a fine idea on
analysis developed and used for concrete containments.
It was developed and is being used for, the San Onofre
Plant used that particular code. It consists of a
finite element, which gives you your moments and
forces. Then it has a post operative system which you
go through that compares it, does the load
combinations and compares it to, in this particular
program, actually compares ASME Section 3 Div 2, 75
addition of code.
CHAIRMAN WALLIS: So you did a different
MR. ADAMS: Yes.
CHAIRMAN WALLIS: To get the power
MR. ADAMS: We did a complete reanalysis of
CHAIRMAN WALLIS: Using a different code?
MR. ADAMS: Yes.
CHAIRMAN WALLIS: Okay.
MR. ADAMS: Okay, as we went through, and
I'm sure you're wondering where we got all the extra.
When you design a plant you get to have the capability
of adding in extra capacity as you go, and what they
did originally, they had three additional tendons in
there for surveillance, calling for surveillance for
each grouping, both dome, vertical, and hook tendons.
They actually had a few more that were
added in toward the last, probably for construction
reasons. We lost some in Unit 1. We lost two hook
tendons as we went through the construction issue. We
used all tendons as we came through the re-analysis.
All of them are credited in this particular analysis.
CHAIRMAN WALLIS: So there's something
physically different. You're now using more tendons?
MR. ADAMS: No we did not change any
tendons in there, but in the analysis, we used all the
CHAIRMAN WALLIS: In the analysis
assumption, are you using more tendons than you used
MR. ADAMS: That's correct, sir.
CHAIRMAN WALLIS: So there is something
different about the physical basis?
MR. ADAMS: There's nothing we did to
modify the containment to get to where we were. The
other thing that we had some additional capacity in
was through the creep values. We used a very
conservative creep value when they went through the
first time around to do the analysis, and they used it
because in Unit 1, they didn't allow time to go all
the way through the creep testing.
So they went through part of it and they
just used that value. We gathered data off of Unit 1,
based on all of the tests that we did over the period
of time that we had, because we had to do liftoffs and
everything in Unit 1, where Unit 2 being a cinder type
plant, we didn't have to do that over the years. But
it's basically identical, the same concrete, basic
mix, and tendons were the same, just a different
number of them in Unit 2 based on the pressures that
MEMBER SCHROCK: Your reference to creep is
in the tendons?
MR. ADAMS: NO, this is creep in the
MEMBER SCHROCK: All right.
MR. ADAMS: But the rest of everything we
used the same. We did not change the seismic values.
In fact, we made real sure that we made sure that we
did not do anything different in the seismic that
would change how that actually got into the analysis.
MR. WILSON: Excuse me. This is Roger
Wilson. One thing I don't think we have told him is
that a Unit 1 design pressure is 59 pounds. So when
he's comparing against Unit 1, he's comparing against
a containment that is designed for 59 pounds. But the
original analysis for Containment 1 was 59 pounds
versus 54 pounds for Unit 2.
CHAIRMAN WALLIS: These were essentially
the came containment?
MR. WILSON: They essentially are the same
containment, very close.
MR. ADAMS: Except for the fact that we
have a different number of tendons in it.
MR. WILSON: Right.
MR. ADAMS: And they did reduce the tendons
in some areas, based on how much pressure was actual
MR. WILSON: But we had spare tendons.
MR. ADAMS: We had additional spare tendons
that were in there. That's where those numbers came
CHAIRMAN WALLIS: The tendons are what
holds the concrete together.
MR. ADAMS: That's correct. Your design is
such that you don't allow it to go into tension under
certain conditions in your design basis.
CHAIRMAN WALLIS: Are you pre-stressing?
MR. ADAMS: We pre-stressed, yes.
CHAIRMAN WALLIS: That's where the creep
comes in then?
MR. ADAMS: These are large tendons, and as
I said three butress is what we have. They are
basically tensioned up to about 1.4 million pounds.
They're 186 wire tendons, massive things.
CHAIRMAN WALLIS: Yes, that's probably
enough. Maybe we'll ask the staff to send questions.
MR. ADAMS: Is that enough?
MR. DAIBER: Thank you, Doyle.
MR. ADAMS: Okay.
MR. WALLACE: Thank you very much.
MR. DAIBER: Along with containment design,
some of the things we did incorporate in the RSG
program to try to minimize the impact of containment
pressure challenges with the new steam generators, the
new steam generators did incorporate an integral flow
restrictive nozzle which was not available in the
OSGs, the original steam generators.
Also we installed a containment spray
actuation signal to isolate feedwater and steam.
Prior to the steam generator replacement, isolation
was only based on those steam generator level. We
incorporated an additional isolation signal on high
containment pressure of the main feed and main steam.
Fuel design considerations. As I discussed before, we
switched over to the Erbia burnable poisons to assure
fuel design considerations.
So in conclusion, with respect to plant
margins, we removed the plant
MEMBER SCHROCK: I'm still not completely
clear on how you get to a change in the radial peaking
by changing the burnable poison. You burn out more
rapidly than you did with the Gadolinia, is that
right? And so, you'd have more reactive old element
in the periphery of the core?
MR. DAIBER: The peaking factors are
actually more of a design other than in relation to
the burnable poisons. The radial peaking factors I'm
referring to here are designed into the actual
assembly designs with respect to whether it's Erbia or
Gadolinia. So, with Erbia core designs, there is the
potential that future poisons
MEMBER SCHROCK: Is there someplace in the
documentation I haven't found that I could understand
what this all means about the change in the radial
peaking factor? What you do to come up with those
numbers and why the physical changes in the fuel
result in that change?
MR. DAIBER: With respect to the peaking
factors, there's some information in the power uprate,
though I don't think it's very extensive on that.
Most of that work is done on the reloads.
MEMBER SCHROCK: See this is a problem I
have. I mean we try to evaluate the technical details
of what you're arguing. But it's difficult to do that
when what you hear over and over again is that we've
complied with all existing regulations. It doesn't
tell us how you do the analysis in any technical
sense. It tells us in a compliance sense that it's
being done using methodologies that are approved, et
cetera, et cetera. What I need is a little more
technical explanation of how you come to a change in
such numbers at the radial peaking.
MR. DAIBER: The radial peaking factor, the
decision on the lowering the radial peaking factor, is
based on some recent data that's been gathered at
Calvert Cliffs and Palo Verde Plants. There are
concerns with the higher, more aggressive core designs
resulting in actual offset anomalies, sub nuclear
Westinghouse has reviewed that data as a
result of those other core design considerations, and
they've developed a thermal hydraulics code. I forget
the name of it, but they've developed a methodology to
try to predict when that sub nuclear boiling would be
onset and the conditions that would onset that. Then
we went back and we looked at the Cycle 16 core
MEMBER SCHROCK: See, this is precisely the
point that I'm making. This is Thermal Hydraulics
Phenomena Subcommittee. You're talking about now a
thermal hydraulics consideration which somehow depends
on a new analytical method developed in Westinghouse.
I don't know what it is.
MR. DAIBER: That information has been
provided to the staff in response to an RAI question
in respect to the thermal hydraulics considerations
there. There was an RAI on that. The staff had
requested additional information with respect to how
we were accommodating the data that was recently
collected at Calvert Cliffs and provided some
information in that area.
CHAIRMAN WALLIS: Maybe you can tell us
where to find it.
MR. BOEHNERT: Can you reference that RAI,
because we should have that?
MR. DAIBER: I was trying to find it.
MR. WILSON: October time frame, I think
it's in the letters there.
CHAIRMAN WALLIS: Maybe at the break, you
can call our consultant.
MR. BOEHNERT: Yes. We have these RAIs.
MR. SHROCK: I've looked at a lot of RAIs
and none of them have presented anything like the kind
of explanation that I'm talking about. But what I
find absent in all the discussions is any technical
explanation of the phenomena that are involved here.
But what we have instead is reference to a code we
don't know, or may not know, something which meets the
requirements in your view of the staff, and then we'll
hear from the staff whether or not it has met these
But nowhere are we hearing a real
technical explanation of how one gets a reduction in
the radial peaking factor as a result of the
modification in fuel.
CHAIRMAN WALLIS: Maybe we can take that on
some sort of advisement.
MEMBER SCHROCK: I want to understand how
and I want to understand how well you have the number
that you're getting.
CHAIRMAN WALLIS: We're going to come back
later in the day. Perhaps you folks can prepare a
more detailed explanation for us.
MR. DAIBER: I think Mehron may be able to.
You're referring to the actual fuel design and how we
build in that radial peaking factor into the core
design itself to lower it in the design itself, versus
CHAIRMAN WALLIS: Maybe you've got some
other slides that show a sort of typical
MEMBER SCHROCK: The power of the plant,
and to increase the power to the plant, you have
certain constraints, and some of those you may be able
to negotiate more freedom on. Others you may not.
But it becomes terribly unclear as to exactly how you
achieve a comfortable increase in power by 7.5
I don't know how I can say it more simply.
The technical basis for it does not come through
clearly, through all of these graphs and thick
documentation of what has been done to achieve the
change in the power, using all approved methodologies
and all of that.
MR. GOLBABAI: May I?
MEMBER SCHROCK: Yes.
MR. GOLBABAI: My name is Mehron Golbabai.
I am with Westinghouse. I'm not a core designer, so
I'll try to make a brief explanation, and if that
doesn't satisfy you, I'll get in touch with someone.
Our understanding is there are three elements that are
involved. One is originally these cores were
designed, of course, with shims and now we have
burnable absorbers. That gives about, let's say three
percent more number of fuel rods that you already
have, compared to when these cores originally were
The second element of course is the number
of batches. You put up a few more assemblies for
every number of reloads and that reduces the general
power that each assembly has to generate. And then
the third element is the Erbia. That being a diluted
poison, that allows the power within each assembly to
be more uniform. Therefore, the peak in a given
assembly is not high with respect to the rest of the
rods in that assembly. So those three elements
combined, but if you like to, I can get more of an
MEMBER SCHROCK: That's a local peaking
consideration, not a core. That's not something you
can explain here in five minutes. What I'm saying is,
the documentation ought to provide enough technical
detail about exchanges and, instead, the documentation
is voluminous but doesn't convey an awful lot of
technical information. That's basically the problem
MEMBER SIEBER: It seems to me you
ordinarily find the detailed explanation of the
analysis as part of the safety evaluation for each
core, which is usually prepared two or three months
before the refueling occurs. And the way those are
done is, at least in the old days, they would use some
steady state core model, which was a diffusion code,
describe the flux and the relationship between flux
and power, both locally within an assembly, and across
And then from that, they would use
correlations of thermal hydraulic mixing correlations
to determine what the rod temperature would be in each
case and the numbers are the peak clad temperature of
2200, which was the final acceptance criteria for ECCS
plus DMBR and these are expressed in terms of peaking
factors that you can measure by looking at things like
axial offset and so forth.
I really didn't expect to see that detail
in this application, but I know that before you can
start up, you have to have an approved safety
evaluation for the reload and modern RSEs don't have
a lot of documentation either, because they rely on
preapproved topicals that all the fuel vendors put in.
So they just list all these and say, this is how the
answer came out, and here are all your limits.
It is, I agree with you, difficult to
understand exactly what they're doing because they've
been doing this for so many years over and over again,
using basically the same methods that they sort of cut
it short I think. Do you agree with that, sir?
MR. GOLBABAI: Yes, things that we are
discussing here are well within the range of what
we've been experiencing in all our plants, and the
analyses are the same methodologies.
CHAIRMAN WALLIS: I think the problem is
you have a big computational system for all kinds of
computer calculations. When you look at the details
as we did with some of the GE cores, we find that the
sort of power distribution jumps all over the place,
depending on how things are reloaded, which is a
burner which is not running. And it's difficult for
someone to get sort of the perspective with all those
details there. How do you actually achieve this power
distribution on the average? You're lost in the
MEMBER SIEBER: When you do core design,
you design for whatever works, as opposed to having a
code system that will optimize fuel. Generally that
comes from experience. There are insertable, burnable
poisons. There are codings. There are integral
burnable poisons like Gadolinia, plus you can zone the
fuel, different enrichments within a rod or different
rods within an assembly. And it's sort of a guessing
game and you keep trying designs until you get one
that works. And then once you get one that works,
that's what you end up building.
MEMBER KRESS: Basically you have to have
more neutrons, more power in the radial directions.
MEMBER SIEBER: That's correct.
MEMBER KRESS: And you do that by putting
in more fuel and taking out some of the poisons.
MEMBER SIEBER: Right. Iron enrichment and
then you'd have to shape that.
MEMBER KRESS: You have to shape it.
MEMBER SCHROCK: Well, when you put this
together with the fact that an uprate of 7.5 percent
is requested based on methodology that is archaic, it
leaves a lot of unanswered questions. I mean there
have been very, very developments in reactor
neutronics analysis in the 19 years that this thing
was put on the street, the Westinghouse plan for
MEMBER SIEBER: Right.
MEMBER SCHROCK: And I'm confident that
some of the basis justifying the request is embedded
in new analytical methods that are available and that
in some way are being used. But it is very unsettling
to understand that the decision finally is going to be
based upon thermal hydraulics analyses that are so
archaic as to essentially reflect no improvement over
those 19 years. It's not a satisfactory situation.
That's my view.
MEMBER KRESS: How well do you know, after
the fact, what your power distribution is?
MR. DAIBER: The cold system on my
monitoring system does verify the core power
MEMBER KRESS: It verifies that you've got
the power distribution you thought you had.
MEMBER SCHROCK: On an assembly basis.
MR. DAIBER: Yes, on an assembly.
MEMBER SCHROCK: Not on a rod basis.
MEMBER KRESS: But that's close enough to
give you a pretty good average.
MR. DAIBER: I think so.
CHAIRMAN WALLIS: So you say even though
it's not a method that's been checked against many of
these real cores, it's really got a solid basis of
empirical evidence behind it?
MR. DAIBER: Yes, and obviously we use
Westinghouse for our core designs, and they've been
designing the cores for comparable CE plants. They
have a wealth of knowledge and experience based on
their prior core designing considerations, and they
use that when looking at our Cycle 16 specific core
MR. KRERSS: And there are tech spec limits
on these core power distributions that you can't
exceed, or not?
MR. DAIBER: There are with respect to ASI
indices. There are limits, and the verification,
there's more of a tech spec with respect to verifying
that the actual predicted and actuals are within
compliance. The verification of the inquiries that
they're measuring is verified I believe on a monthly
basis. Is that correct? On a monthly basis to the
predicted method, the predicted core powers.
MEMBER KRESS: Thank you.
CHAIRMAN WALLIS: Now you have another 10
slides or so before the next speaker?
MR. DAIBER: Yes.
CHAIRMAN WALLIS: Can we get through this
by about quarter past 10:00, we have a break then.
That should decide how it's going for you. But I
think it appropriate to have a break after you
presentation, unless you get really stuck along the
MR. DAIBER: Like I was now? With that,
I'm going to move on to the fourth agenda item, which
are review issues. And within the review issues,
we've kind of reordered some of the sub-bullets here.
The first one we'll be going over is ATWS, and then
containment, and then I'll turn it over. We'll go to
break possibly at that point before we go to the
MEMBER POWERS: Just glancing at your
slides, when you introduce this discussion of ATWS by
explaining an ATWS transient to the panel?
MR. DAIBER: With respect to the PWRS, the
ATWS transients, we consider a lot of the same
initiating events with respect to loss commensurate
backings, loss of feedwater type events, in which the
plant does not, would not have scram by the normal
reactor protective system, and hence resulted in
increased pressures and core powers due to loss of
feed potentially too as a result of that.
When we analyzed as far as the CE design
considerations with respect to ATWS, we don't analyze
those specific events. Based on compliance with 10
CFR 5062, the CE design approach was, rather than to
actually analyze those events where the scram and
feedwater actuations may not have occurred, we have
rather committed to and have already installed a
diverse scram system, a diverse turbine trip system,
and a diverse emergency feedwater actuation system.
So from our design consideration
standpoints, we don't analyze a specific event. We
insure that the probability of design is low enough
and reasonable enough for us to consider. Again,
that's achieved with the installation of the the DSS,
DEFAS and DTT. Those systems that we've installed,
we've verified those design criteria with respect to
those redundant systems, to make sure that under
operating conditions, that the design criteria were
CHAIRMAN WALLIS: These design criteria,
you have diverse systems so that it never really
happens or the probability of it really happening is
very low. Do you have numbers to put on those
MR. DAIBER: I don't have numbers with me.
CHAIRMAN WALLIS: Is the decision made by
the NRC based on some quantitative probalistic
analysis or by some expert estimates or what? How do
you decide it's good enough.
MR. DAIBER: I believe that was decided
with the NRC through the development of the rulemaking
where there is acceptable criteria.
CHAIRMAN WALLIS: A long time ago. It
probably says if you have enough diversity, it's okay.
It probably doesn't stick numbers on it.
MR. DAIBER: I don't know if there were
actual numbers generated at the time.
MR. BOEHNERT: Yes, there were.
CHAIRMAN WALLIS: Okay, there were.
MR. BOEHNERT: I don't remember them but I
know there was extensive work on probablistic
valuations for the development of the rule.
CHAIRMAN WALLIS: From a mathematical
basis. It's not just somebody's estimate?
MEMBER SCHROCK: From the standpoint of
protection of capital investment, wouldn't it be
prudent to know what an ATWS analysis results be?
MR. DAIBER: From the risk perception
MEMBER SCHROCK: Ever been done on the
MR. DAIBER: No. ANO 2 specific analyses
were never looked at. Back during the development of
the rulemaking considerations, there were some generic
analyses performed in bounding nature for the CE class
of plants, the 2800 megawatt thermal and then the
4000, 3800 megawatt thermal plant range.
So there were some generic analyses done
at that point in time, and the decision at that point
was, rather than to pursue analytical methods to
mitigate these, we actually installed additional
hardware to insure that the increased pressures would
not occur, rather than rely on operator action.
The hardware installed from the diverse
scram system is a totally independent diverse and
redundant system to the normal reactor protection
system. In addition to the normal reactor protection
system on high pressurized trip, the CPC plants also
have a high range high pressure trip in the CPCs that
In order for an ANO 2 CPC type plant to
get to this point, CPCs would have had to fail, the
normal high pressurized trip system would have had to
fail, plus the reverse redundant, the scram system
that we've installed would have had to fail. So
getting to that point is very, very low on the CPC
CHAIRMAN WALLIS: There's no operator
intervention which would somehow short circuit all
MR. DAIBER: No. No.
CHAIRMAN WALLIS: The sequence you
described as being unlikely is independent of operator
MR. DAIBER: It's very quick. In the times
we're talking, a very rapid trip response. Now the
operators do have an additional DSS and DEFAS
actuation should all of that still fail. They do have
that luxury. But the timing of such shouldn't be
With respect to the DSS system, the way
the system was installed, again it's a reverse
redundant scram system, installed at ANO 2. The
setpoint it was at on that is set such that it
actuates after the normal reactor protective system
setpoint would actuate, but prior to this primary
safety valves lifting. And the timing on that trip
and the setpoint itself are verified to make sure that
it doesn't interfere with the normal reactor
protective system trip on high pressure.
We reviewed those design criteria and
insured that the current setpoint and settings and
response times are acceptable under operating
MEMBER KRESS: Is this power uprate
strictly for ANO 2?
MR. DAIBER: Yes.
MEMBER KRESS: And does ANO 1 claim to have
one at some time or has it already had one?
MR. LANE: This is Rick Lane again. We're
initiating some studies this year to look at that.
We've done a previous study back in the mid-`90s and
we're going back and re-reviewing that and seeing what
the potential is for ANO 1. But at this point in
time, it's strictly in the study phase.
MEMBER KRESS: And they're both on the same
MR. LANE: Same site. They're on the same
MEMBER KRESS: And that's the only two
plants on that site?
MR. LANE: That's the only two plants on
MR. ADAMS: They (off mike).
MR. LANE: Yes.
MR. DAIBER: With respect to the DEFAS in
a similar fashion, we have installed the diverse
emergency feedwater actuation system, and it also has
a redundant or a low steam generator actuation on
DEFAS. So the normal RPS system actuates EFW at about
22.2 percent, and the diverse actuation occurs at
about 16 percent. The setpoint is set lower, and
response time is set such that won't interfere with
the normal reactor protective system response
Those were reviewed with respect to power
uprate considerations and verified still to be
acceptable under power uprated conditions. So in
conclusion, we reviewed the ATWS design requirements
for ANO 2 and found those to be acceptable.
I'll move on to the containment
considerations and real quickly, I'm just going to go
over it from the analytical perspective now, what we
saw during the RSG effort.
From an overview perspective, we've
looked, when we did the RSG project, we made sure we
accounted for power uprate in those analytical
efforts. Analyses and the methods we used for
determining peak containment pressure design were
based on approved methodology. We used the
Westinghouse former CE methods for determining
mass/energy release for both the LOCA and main steam
line break analyses.
We looked at a spectrum of break sizes,
and we also looked at various power for the steam line
break considerations. We also looked at various
single considerations. He mass and energy released
that's generated with the Westinghouse method is then
put into the Bechtel COPATTA code for determining peak
MEMBER SHACK: What's the limiting break
MR. DAIBER: The limiting break is just
every so slightly a LOCA over a steam line break and
it's a discharge pump break.
MEMBER SCHROCK: But the number of break
sizes specifically shown in the documentation was
three. It's difficult to make a case that you found
the peak in the relationship that peaks within the
range of those three data points by selecting the
highest among them.
MR. DAIBER: You're referring to the LOCA
MEMBER SCHROCK: Right.
MR. DAIBER: Yes, from the LOCA
consideration, the double-ended
MR. DAIBER: Yes, I jumped to combusted
steam line. The limiting is LOCA. And from the LOCA
consideration, the double-ended slot area break, which
is effectively the cross-section of the cold leg pipe
put into a slot formation has historically been
determined to be the peak break consideration for the
last many years.
MEMBER SCHROCK: Let me rephrase the
question, because I think you're not getting it. If
one has to determine the maximum in a value from
several determinations, it's not possible to find the
maximum or to justify that it is the maximum by saying
that the one in the middle is the highest and the two
on the extremes are lower, and we take the one in the
middle from a three point evaluation as being the max.
MR. WILSON: Bryan, what he's asking if I
could help. That's what we presented just to show it
was, that we had looked on both sides. But they
looked at other sizes. The way we submitted it was to
show a size on both sides of the one we picked as a
peak one, but that's not all I believe we looked at.
MEMBER SCHROCK: Let me just say, the
documentation does not show clearly that you in fact
had found the maximum.
MR. WILSON: That's right, it didn't.
CHAIRMAN WALLIS: I take it the argument is
that you have from past experience, from calculating
many breaks on low power
MR. WILSON: Right.
CHAIRMAN WALLIS: you have sort of the
MR. WILSON: Right.
CHAIRMAN WALLIS: Now you've got a curve
and you've got three points which have moved a little
bit from that curve. So it's not perhaps unreasonable
to draw in a curve like the old curve.
MR. WILSON: Right, and then we presented
the maximum one and the one on either side of it.
CHAIRMAN WALLIS: You're saying you already
have the curve.
MR. DAIBER: I think I may be confused
here. When we do the 5046 compliance on peak
temperature, we look at a spectrum of break sizes, and
have looked on both sides. With respect to the peak
building pressure, containment pressure analysis, the
limiting break historically has been determined based
on a four guillotine slot leg break orientation, and
that's what we've looked at here when we did these
So based on historical perspective,
effectively used the same methods that we used
originally, and we zeroed in on those classic limiting
break sizes, again using Westinghouse methodologies
and Westinghouse experience on doing these for not
just ANO 2, but other CE plants, some of which are a
significantly larger power rating than us.
And based on that, we developed our peak
limiting breaks, based on their knowledge of what is
a limiting break, which is a double ended guillotine
slot orientation for the cold leg, and we also looked
at hot leg breaks. We looked at suction, discharge
and hot loge considerations.
Again, all those configurations are based
on the double and the guillotine configurations and
size for determining peak building pressure.
CHAIRMAN WALLIS: Did you resolve the
question of mixing in the containment which the NRC
raised with you?
MR. DAIBER: Yes, with respect to the dose
analysis considerations, we did resolve that.
CHAIRMAN WALLIS: That's only for dose
analysis. You don't worry about that for calculating
MR. DAIBER: No. That issue that raised
CHAIRMAN WALLIS: Is this one node? How
many nodes are there in the containment?
MR. DAIBER: Under the large break LOCA
mass energy release considerations for peak pressure
we model it as one node.
CHAIRMAN WALLIS: It's a well mixed
MR. DAIBER: Yes, under those turbulent
condition, it's a well mixed.
MR. WILSON: Excuse me. Bryan Wilson. Was
there not a confirmatory analysis in one of those?
MR. DAIBER: Yes, that's correct from the
peak building pressure standpoint, there was the NRC
did perform a confirmatory analysis on the peak
building pressure analysis evaluation.
MR. WILSON: And found, I believe in their
analysis they came up with lower numbers than we did.
They found our analysis to be conservative.
CHAIRMAN WALLIS: Okay, so we can ask them
about that then.
MR. WILSON: Yes.
CHAIRMAN WALLIS: Thank you.
MR. DAIBER: So we did perform these
analyses using the methods, approved methodologies
that we've used in the past. The results were bounded
for power uprate, and again this was all done as part
of the RSG effort and approved under the license
amendment 225 already.
The limiting consideration. Again, we
looked at large break LOCA and steam line breaks. We
did look at single considerations, limiting single
fire for the LOCA was a loss of 80g. For a steam line
break, the prior evaluations had indicated a 2770
megawatt thermal power level that is limiting.
We went through a power level verification
as part of the RSG effort, and determined that the
zero power level indication or power was more limiting
under power uprated conditions, and it's really more
a matter of the new steam generator design, the
integral flow restricting nozzle, and the CS AS
actuation signal that we implemented, caused that
change in power level for limiting steam line break.
The peak pressure is actually calculated
with 57.6 per LOCA and 57.4 for the hot zero power
steam line break. There's a typo on the slide there.
So in conclusions, the peak pressures that we
calculated there were within the new uprated design
pressure of 59 pounds, and therefore found to be
CHAIRMAN WALLIS: These peak pressure are
calculated with conservative assumptions, so there's
no need to discuss uncertainty and predictions.
MR. DAIBER: Through the whole process of
developing containment analysis, the LOCA analyses,
5046 analysis and non-LOCA analysis process, when we
developed input considerations, we interfaced with the
field vendor on those methodologies for the most part,
and the methodologies there, or the inputs associated
with that are documented in what we call the ground
So, before we kicked off this effort to do
both RSG and power uprate, we did a thorough review of
those ground rules that we interfaced with and made
sure that we accounted for current operating
conditions and made sure that we accounted for any
conservatisms, and values that we felt we may want to
accommodate additional margins in.
CHAIRMAN WALLIS: That's what I'm asking
about. You give us 57.6. That I think is calculated
with conservative assumptions. The realistic value
would be much lower?
MR. DAIBER: That's correct.
CHAIRMAN WALLIS: Because if this were
realistic value, we'd be really interested in the
MR. DAIBER: Yes.
CHAIRMAN WALLIS: It may be the uncertainty
of five psig would be significant.
MR. DAIBER: Yes. Yes, definitely. When
we developed those inputs, we developed a set of
inputs that we thought would be very conservative and
very bounding. So the peak pressures that we are
calculating are considered very conservative.
CHAIRMAN WALLIS: If you knew they were
MR. DAIBER: Yes.
CHAIRMAN WALLIS: You knew that with good
MR. DAIBER: Yes. We feel that, we know
that they're conservative. In fact, during
CHAIRMAN WALLIS: Not feeling. Feelings
aren't allowed here.
MR. DAIBER: We know they are conservative
because during the steam generator replacement
process, we did try to keep it down below 54 pounds,
so we did pull out some of those conservatisms to get
it down to 54 pounds, and if we really had to get it
down to 54 pounds, we could have gotten it down below
But based on previous experience, we were
running right at 54 pounds for many years. We always
were bumping up against the limit and therefore, we
wanted to continue to run up against that limit. We
went ahead and went over 54 and put margins in the
input assumptions to go along with it.
With that, do you want to take a break?
Or, we could turn it over to Rich.
CHAIRMAN WALLIS: No, I think it's a good
time to take a break. You've finished almost exactly
on time. Thank you very much. We will take a break
(Whereupon, the above-entitled matter went
off the record.)
CHAIRMAN WALLIS: Ready to go? All right,
now we are ready to go.
MR. SWANSON: My name is Rich Swanson. I'm
an operations shift manager and I have a senior
reactor operator license on Unit 2. I'm the officer
representative on the power uprate project, and before
that, I was also on the steam generator replacement
My main functions on the project were to
provide operations oversight, review all the
modifications and evaluations for impact on
operations, and also to review the impact on emergency
Training on the uprated plant has already
started. The simulator has been changed to
accommodate the new uprated plant. We can swap it
back and forth for current cycle and future cycle to
accommodate just in time training. We're providing
two crew training cycles, pretty much dedicated to
power uprate training, and each crew will be evaluated
on the uprated plant prior to outage.
Now I want to point out the changes we're
doing for power uprate have much less impact in steam
generator replacement. Controls and display changes
are minimal or none. There's no physical
modifications to control stations due to power uprate,
and no changes to the formal of the safety parameter
display system. Some display ranges will be re-
scaled, however, to accommodate higher flows and
pressures we'll be seeing.
We have approximately 75 procedures to
change for power uprate. It included emergency,
abnormal, normal operating procedures, but there's no
changes to the type and scope of procedure and we
didn't write any new procedures for power uprate.
There's no changes in the type of nature
or actions in our emergency operating procedures, and
we didn't have to add any new actions to our EOPs.
The power ascension testing will be
heavily coordinated and controlled by operations.
We're involved in development and implementation of
all the tests. We had test teams designated to
perform the testing. During our outage, we'll have
two crews working outage and we'll have a team on each
crew, and these are experienced operators. The leads
on each team were also involved in the testing for the
steam generator replacement.
The power ascension testing will be
basically normal testing until we get up to 90 percent
of the new rating, which is approximately 98 percent
of our current power. From there, we'll step up in
2.5 percent increments with about a 24 to 48-hour hold
at each increment of power, and we'll be doing walk
downs, control system checks and verifying all the
parameters we're seeing against our design parameters,
and any issue that comes up will be resolved prior to
going to the next power level.
MEMBER POWERS: What are you going to be
looking for in the walk downs?
MR. SWANSON: We're walking down for
vibrations mostly and systems. We'll have engineers
out actually taking and measuring vibrations, and
we'll have the operators out there looking at the
systems and making sure it looks right to the
operators, because the operators can see things the
MEMBER POWERS: So it's actually more than
walk downs. You're actually doing the monitoring for
MR. SWANSON: Yes. Here's a power
ascension profile that testing, what we're going to be
doing coming up out of our next outage. Basically up
to 90 percent in CR standard turbine over speed trip
testing, we have three power holds for physics
testing, and then after we get to 90 percent, you show
going up in two percent increments, up to 100 percent.
MEMBER POWERS: How do you decide whether
it's 24 or 48 hours?
MR. SWANSON: However long it takes for
engineers to collect their data and for engineering
and operations to be comfortable with the plant and
that what we're seeing is actually what power we're
MEMBER POWERS: So you're not looking for
something that's time dependent. It's just
MR. SWANSON: That's correct. There's no
time limit. There's no actual limit on that, but it
will take at least 24 hours to collect the data and
And in conclusion, impact and power uprate
on operations training procedures and response time
has been evaluated and it's found to be acceptable.
CHAIRMAN WALLIS: There's some response to
that since it's changed significantly?
MR. SWANSON: As far as emergency operating
procedures, no. We do have, for instance, on a main
peak pump trip, we would have to respond faster to
keep the plant from tripping. But it's faster than it
is this cycle, but it's not faster than it has been in
previous cycles. We gained extra time. We replaced
steam generators to respond to main peak trip.
CHAIRMAN WALLIS: Right.
MR. SWANSON: And that with power uprating,
it basically goes back to about where it was. And if
there's no further questions, I'll turn it over to
Dale James. He can talk about Alloy 600.
MR. JAMES: Thank you, Rich. Good morning.
My name is Dale James. I'm the manager of engineering
programs and components at Arkansas Nuclear One, and
my group has responsibility for the steam generator
integrity, fact program and the Alloy 600 program.
I'd first like to talk about Alloy 600 and
the impact that we see associated with power uprate.
As has been mentioned, we will be increasing the Thot
from it's current condition of just a little over 604
to about the 609 range. Of course, we had a history
of Thot changes ANO. We began at somewhere around 607
during the early operations.
We reduced that temperature back in the
mid `90s to preserve the steam generators down to the
600 level. It's slightly increased, and then with the
steam generator in place, we went up to the 604 area,
and now with power uprate, we'll be going to 609. So
we have a history of changes in Thot at ANO.
MEMBER POWERS: I'm puzzled by the line on
your slide. It says power uprate results in only a
slight change of Thot, but a slight change of Thot was
presumably a significant change of Thot in the past to
preserve steam generators. Why is this one not
significant in the other direction?
MR. JAMES: We felt like when we reduced
Thot on steam generators that we were doing the right
thing. We could continue to generate the power levels
that the plant was designed to, while preserving for
it adding margin. The exact impact of that reduction
in temperature is really not known. Obviously
CHAIRMAN WALLIS: Then are you doing the
wrong thing, increasing the Thot?
MR. JAMES: We will be decreasing margins.
The extent of that decrease is not known. What I will
present to you is how our programs will or will not
change as a result of that increase with respect to
POWERS: Thot is a good representation of
your head temperature?
MR. JAMES: Actually not. Actually on the
ANO Plant and several other combustion plants, I'm not
sure about some other Westinghouse plants, but we do
have a bypass flow into the head region from the cold
leg, and get mixing in that area such that the head
temperature is about 14.5 degrees cooler than the
MR. JAMES: So with respect to the power
uprate and its implications as far as increasing hot
leg temperatures, what we're going to be looking at
its effect on the reactor vessel head penetrations.
That would include the control on the dried mechanisms
as well as our in coil instrument nozzles, and we have
one head vent.
Just for references, 81 control on that
dried mechanism nozzle, 8 ICI nozzles and one vent on
MEMBER SHACK: Now presumably there's an
Alloy one maybe two weld on each of these nozzles,
right that would be focused on Alloy 600? This is a
CE plant, so there's no Alloy 182 butters between
carbon, steel and stainless anywhere in the system?
MR. JAMES: Dan, can you help me out on the
specific design of the welds.
MR. SPOND: Yes. My name is Dan Spond.
I'm an energy engineer. We have butter welds, but
they're not at the CE DM location. The CE DMs, well
they are welded to a butter joint at the J-groove weld
on the erector head. Yes, with 182, and that's really
the same weld metal that the rest of the industry
MEMBER SHACK: Right. Now do you have a
stainless fluridic steel butter anywhere that you've
got a way to weld, aside from these 600 compounds? Do
you have a stainless 182 fluridic? You know, like
Westinghouse has their
MR. SPOND: No, we do not, not on say the
hot legs of the RCS piping.
MEMBER SHACK: No, you wouldn't have it on
the hot leg, but there's nothing in the presurizer, no
MR. SPOND: The pressure on the surge line
is stainless steel, so we do have it coming off of the
hot leg, I guess. And that is part of the ISI
program. So we do inspect those welds.
MR. HASLINGER: Karl Haslinger,
Westinghouse. There are a few locations which have
the 82 182 weld in all the C plants. Typically, there
would be, with the exception of two plants. One has
stainless steel made in coiled loop piping. The other
plant, well most of the plants have 82 182 weld at
the nozzle to the tributary piping weld locations at
the safe ends, and those are being evaluated currently
on the MRP project.
The other location is on the pressurizer,
such as the surge line nozzle, on both ends as well as
the spray nozzles and the relief valve nozzles. So
there are a variety of locations in C plants that have
this problem, which is sort of a result from the VC
Summers evaluations, and those are being looked at
right now from a stress corrosion point of view.
MR. JAMES: Okay, so as far as other nozzle
locations by Alloy 600 material, we also have cold leg
nozzles. We're not going to talk about those, because
actually cold leg temperature has decreased from our
original design down to 551. It's increasing from
this previous cycle to the current cycle, from 553 to
excuse me, 529 to 551. Thank you Bryan.
That's fairly far from the activation
cooling for Alloy 600, so really we anticipate minimal
impact on the cold legs. Also the pressurizer
conditions are not changing as a result of power
uprate, so those nozzles in the pressurizer should not
be impacted as the result of power uprate conditions.
MEMBER POWERS: Can you explain to me what
you mean by the activation point?
MR. JAMES: Well, I think the industry
indicates that somewhere close to 600 degrees is a
point where the Alloy 600 material becomes impacted as
a result of temperatures. That's what we're using as
far as our evaluations on the head with respect to
evaluating it against the conditions that were
evaluated at Oconee, and I'll talk about that in just
a little bit.
MEMBER POWERS: I guess I'm still
perplexed. We're talking about a chemical process,
and you're saying it has a threshold temperature to
MR. JAMES: I think that is a common belief
that there is a threshold somewhere close to 600
MEMBER POWERS: Unremarkable.
MEMBER SHACK: Yes, I would think a lot of
people would disagree with that. I mean it is
probably true that the rates go down as the
temperature goes down. There would be very little
disagreement about that. But an actual threshhold.
MEMBER POWERS: Unusual in chemistry to
find, except phase transitions.
MR. JAMES: Okay, Dennis, let's go to the
next slide. We're going to add our small bore
nozzles. By small bore, I'd be referring here to the
hot leg nozzle. I'm going to cover the head nozzles
in my discussion in the next slide.
We have a program currently underway to
evaluate or to assess damage to these nozzles as the
result of their being exposed to elevated
temperatures, and that basically what we do to address
that is we form inspections. The first inspections
that we perform are generic letter 8005. Those are
the basically boric acid walk down whenever we go hot
shed down, looking for indications of any leakage from
In addition to that evaluation though,
each refueling outage, we do a bare metal examination
of those hot leg nozzles, as well as the nozzles on
the pressurizers to determine if there is any
indications of leakage from those nozzles.
That's how we're addressing it. That's
how we will continue to address the Alloy 600 issues,
associated with these nozzles. But in addition to
that, as we identify leakage and have performed
preventative change outs, we are changing that
material out to a 690 material that has been
determined to be much less susceptible to primary
water stress corrosion cracking.
We have done that on nine of the 19 hot
leg nozzles. All the nozzles below the mid loop level
on the hot legs have been repaired with 690 material
MEMBER POWERS: I'm puzzled by your first
sentence. It says that you have a higher
susceptibility to failure, but no change in safety
significance. That means you've evaluated something
like the risk reduction or risk achievement and the
number doesn't change?
MR. JAMES: What I mean by that is the
failure mechanisms that the industry is saying,
regardless of the temperatures that the small bore
nozzles have been exposed to, have typically been the
traditional axial flaws in the base metal material,
and we have not seen anything that would indicate
there would be any changes in that as a result of the
power uprate for the small bore nozzles that we would
continue to see.
When they do demonstrate indications of
damage, it would be an axial flaw that would not
represent a safety concern with respect to significant
leaky bore ejection. Okay, let's go to the next
slide. We're talking about the upper vessel. We're
talking about the head penetrations. Again, we are
dealing here with the control and dry mechanism
nozzles, as well as the ICI nozzles and the vent
nozzle on the reactor vessel head.
Basically these nozzles have been
evaluated by the industry in accordance with generic
letter or bulletin, excuse me, 2001 01. Industry
response was repaired by that, by the materials
reliability program group, a subcommittee of EPRI, and
their results were documented in the NPR report 48.
And basically what that report did was
perform a ranking of the facility based on the number
of EFPY of operation required for that unit. In this
case, ANO 2, to reach the same number of EFPY as
Aconee Three, normalized for the difference in head
temperature, and using 600 degrees as the starting
point for initiation, that's how they normalize this.
And what we found out when we did that
evaluation originally under the power uprated
condition that we had essentially 17.1 effective full
power years before we would reach a condition similar
to that that Aconee had experienced on March 1st with
Tzero being March 1, 2001.
We then performed an evaluation with the
uprated temperature of the erector vessel head,
associated with the power uprate, and that number
reduced down from 17.1 to 14.2. What that resulted
is, the NRC asked or the industry and NRC agreed to
a categorization with respect to the response of the
utilities as a result of that evaluation back to
ANO 2 originally hit the 17.1 and even at
the 14.2 fell into the moderate category of the third
category. Those are plants that were five to 30 EFPY
away from Aconee conditions. So the response
essentially is unchanged. That response is that we
would perform a visual. It required us to provide an
effective visual examination of the head, which is
basically if you were capable of performing a 100
percent visual examination of the head, you could use
that to determine any risk significance associated
with primary stress and cracking.
Unfortunately for us, the insulation
materials on the Unit 1 head follow the contour and do
not allow for visual examination. So we will be
performing a 100 percent NDE examination during our
upcoming refueling outage to monitor for any type of
damage to those nozzles.
MEMBER SHACK: So that means UT?
MR. JAMES: That is the plan, UT from below
MR. DAIBER: Excuse me. That's using
Westinghouse Robotics system from underneath the head
during the inspection.
MR. JAMES: Exactly what the long-term
plans will be is going to be dictated based upon what
the industry sees as the result of these early
examinations and further evaluation of that to predict
what to project, what additional scope of inspections
will be in the future.
So in summary, the vessel had penetrator
susceptibility as chacterized being in this moderate
category. Even under the power uprated conditions,
essentially our activities or plans to address that
will remain the same. That will be 100 percent UT
examination of those head penetrations. The
programmatic reviews and our continued review of the
industry data will dictate to us, you know, what we'll
be doing going forward to insure that these small bore
nozzles, as well as the head penetrations do not
represent any safety issues associated with in canal
So we believe that the plant can safely be
operated considering the Alloy 600 concerns, even in
the power uprated condition.
Let's go onto flow accelerated corrosion.
Of course, flow accelerated corrosion or FAC as I'll
refer to it as, it affects carbon steel components in
the steam cycle where a processed temperature is above
200 degrees, and there's many factors that go into the
degradation rate. Probably one the significant is the
material composition of the piping itself.
What we've seen is piping with even
minimal contents of chrome are significantly less
susceptible to FAC damage than normal carbon steel.
Also geometry plays a part. Steam quality
temperature, oxygen, the flow of velocities, and Ph of
the liquid itself.
What power uprate is going to do to us
primarily is going to result in increased flow rates.
We also evaluated the impacts on temperature and
pressure changes and industry changes. Chemistry
essentially remaining unchanged under the power
MEMBER SHACK: Now when you took out all
the copper, did you up your ph and your feedwater?
MR. JAMES: We're running above 9.5 ph
MR. DAIBER: Yes, we did.
MR. JAMES: Which is good for FAC. What we
did to evaluate the impacts of these changing
conditions on the power uprate is basically use the
industry Checkworks program. Of course, that's a
program that's been developed by EPRI. That is a
standard program for all the utilities used to do FAC
We plugged these increased parameters, or
these changing parameters into our Checkworks program
to determine what increased conditions, or what
additional susceptibility we may have with the main
stem, main water, reheat steam, high pressure
extraction, low pressure vents and drains, high
pressure vents and drains, all those systems that
could be impacted.
MEMBER KRESS: Had you used Checkworks on
the previous level?
MR. JAMES: Yes.
MEMBER KRESS: So you had already done the
MR. JAMES: Yes, sir. In fact we went back
based upon our most recent inspection, or Checkworks
program prior to performing this evaluation and going
forward with it. But Checkworks has been used at ANO,
as well as many other plants, most of the other plants
in the industry for many years now.
CHAIRMAN WALLIS: What sort of rates do you
measure? What are the highest rates you've been
MR. JAMES: It depends on the system, and
basically what we have seen as a result of the most
susceptible system, we're looking a like a five mil
increase in the wear rate per year. It just depends
on the system as to
CHAIRMAN WALLIS: What was it before then?
Because 5 mils the increase. What was it before?
MR. JAMES: There's a range from zero to
20, 30 mils, and most of the higher wear rate systems
have been replaced with higher alloy chrome.
Geometries have been rearranged to minimize the
conditions associated with geometry, so a lot of those
higher wear rate systems, they've already been
addressed, and been replaced building margin into the
system as a whole.
To do our evaluation that we did, used
worst case conditions, used maximum steaming rates due
to the turbine valves wide open, and basically the
result of the evaluation using the Checkworks program
indicated that we would see no more impact as a result
of the power uprated condition.
Those results are consistent to what other
licensees have predicted, utilizing Checkworks program
associated with power uprates. Also it's consistent
with actual measured values following our power
uprated conditions. So we feel good about that.
Of course, we will continue to monitor our
piping systems as part of our FAC program. We'll be
looking at those piping systems that we believe are
most susceptible as a result of the power uprate
during the next outage, and a part of that process
will be feeding back any deviations from what were
predicted into the checkworks program for future
So, in conclusion, the evaluations that we
performed indicated that FAC wear rate should be
minimally impacted by the power uprated condition and
we will continue to monitor those components that are
affected, to assure that those predictions are, in
fact, accurate and we'll factor in any deviations into
Finally, I'd like to talk about steam
generator integrity, and I think first and foremost
with respect to this part of the presentation is that
the steam generator replacements, which we've already
talked about back in the fall of 2000, the steam
generators that we replaced, our original steam
generators were specifically designed and analyzed for
the uprated power conditions.
There are many significant design
enhancements that were implemented as a result of the
steam generator replacement that were not part of our
original steam generator design, and I could go into
all of these that you'd like. We're very proud of our
new steam generators, and I'm sure Westinghouse would
be glad to do the same for you.
But I think most important is the change
of the tubing material to the 690 thermally treated
material. Also, the increase in the heat transfer
area from a little over 69,000 square feet to a little
over 108.7 thousand square feet. That increase in
heat transfer area, not only allowed us to accommodate
power uprate, but it allowed us to accommodate any
plugging margin, as well as kept the Thot increase to
a fairly minor increase by pushing that much heat
transfer area into the generators.
MEMBER SHACK: Who manufactured these
MR. JAMES: These replacement steam
generators were manufactured by Westinghouse, and the
design also is typical of a replacement design. These
generators have the most recent enhancements, but
generally speaking the Unit 2 steam generators are
very similar to most of the Westinghouse newly-
designed generators, and these flow rates that we'll
be experienced in the power uprate conditions are
typical of the new generator design.
We did perform an evaluation for the
repair criteria in accordance with the NRC Regulatory
Guide 1.121. That evaluation considered the
structural integrity margins and leakage margins
required. We dried a 40 percent through-wall plugging
criteria for the new steam generators, which is
consistent with the original steam generator design,
even though we're using smaller tubing with thinner
walls. Included in that evaluation was a wear rate in
the upper bundle.
MEMBER SHACK: What is the actual tube
diameter? Everybody keeps saying smaller.
MR. JAMES: We went from a 3/4 inch tubing
to a 11/16.
(Off mike conversation.)
MR. JAMES: Included in that evaluation was
a wear rate calculation for the upper bundle, where
most of the wearing will occur at the anti vibration
bars. Their anticipated maximum wear rate is around
0.34 percent per year, so that was evaluated and was
included in this repair criteria as far as growth
rate. We didn't anticipate on any flaws.
We will have 400 percent baseline
inspection before the generators are actually
installed, and will be performing another 100 percent
examination during this first refueling outage to
validate the projections associated with the new steam
generators in accordance with EFRI guidelines.
So, in conclusion, the replacement of
steam generators specifically analyzed and designed
for the power uprated condition, incorporating many
enhancements over the original steam generator design.
Inspections of those generators will be performed to
insure the integrity of the tubing under this uprated
condition. Thank you very much.
CHAIRMAN WALLIS: Thank you.
MR. JAMES: By the way, let me introduce
Jamie GoBell. Jamie's out of our design engineering
group and will be discussing our piping analysis.
MR. GoBELL: Good morning. The scope of
the analysis that was performed can be defined
basically on the changes that we did that caused us to
reanalyze the piping and the physical boundaries of
where the piping was.
The changes in the replacement steam
generator and the power uprate, and we have piping
inside containment and piping outside containment, and
those are physically structured separated from
Most of this analysis was done for the
replacement steam generator effort. It was done at
power uprate conditions. But I'm going to go ahead
and talk about what was done for replacement steam
generator just for completeness, even thought the
impact from power uprate was minimal.
Inside containment, we started out by
validating the original design basis and verifying we
knew what the margins were and what was contained in
that. For most of the piping inside there, we
performed rigorous re-analysis at power uprated
conditions. Because the replacement steam generators
were heavier, we had to analyze for new seismic and
dead weight loadings. Because the containment
pressure went up, we had to look at the piping of
vessels inside containment to make sure they were
qualified for that external pressure both for the
design and the structural integrity test pressure.
As part of our re-analysis of a lot of
that piping, we implemented leak for break analysis,
or technology, where we switched from the main coolant
line breaks to the branch line breaks and the
tributary lines, and we also included asymmetric
compartment pressurization loads on the vessels and
We looked at our design transience and
revised those to reflect the operating
MEMBER SHACK: When you did the leak before
break, what did that let you do?
MR. GoBELL: The original analysis used
breaks of the main coolant line piping, and we were
able to eliminate the dynamic effects of that so the
loads that we had to impose on the piping and the
vessels we were able to reduce significantly because
now we only consider breaks at the tributary line
MEMBER SHACK: But did you make any
physical changes in the plant? Did you get rid of any
MR. GoBELL: No.
MEMBER SHACK: No, nothing.
MR. GoBELL: No changes because of that
analysis. On the transients, we updated those to
reflect any impact from replacement steam generator
and power uprate and to reflect any operating history
of the plant, the number of cycles we've seen.
We also, in anticipation of a license
renewal, we went ahead and increased the cycles. We
did the analysis to a 60-year life to qualify at
license renewal effort. We maintained and improved
the original code of record, and the analytical
techniques that we used in the design basis, and the
goal of course was to satisfy the code stress and
fatigue usage requirements on that piping.
MEMBER SIEBER: What is the code of record
that you used?
MR. GoBELL: It's very that depends on
what you're talking about. The different piping
systems and the different components are designed to
different codes of record. Examples would be the
coolant pumps I believe for 1965 through `67 addenda.
A lot of the piping was 1971 vintage for the code of
MEMBER SIEBER: And this is B-31 at one
MR. GoBELL: On the secondary side, yes it
is out on the secondary side. I can classify it on
the primary side and Class 1 and 2 was ASME, Class 1,
2 and 3, 1971 typically.
MEMBER SIEBER: All right.
MR. GoBELL: And onto the piping outside
containment. The main changes there were changes in
pressure and temperature of the process fluids. We
evaluated those systems against the analysis of
record. Usually if the change in pressure or
temperature, we developed a scaling factor, which we
multiplied the highest stress in that system or nozzle
load, support load type thing, against a scaling
factor that was basically a ratio of the increase, and
showed qualification of the system based on that.
We also did, looked at the dynamic
loading, specifically on the main steam line because
the mass flow rate had increased and the pressure has
increased. We developed new reinforcing functions for
the stop valve, fast closure transient, and qualified
the piping associated with that to those new loads.
MEMBER SHACK: It says that the mass flow
rate increases, the steam velocity of kinetic energy
MR. GoBELL: From the Cycle 14, was the
last cycle we had the degraded old steam generators
MEMBER SHACK: Everything's in comparison
to Cycle 14. If I went back and looked at Cycle 12,
I'd find what I expect to find.
MR. GoBELL: Yes.
MEMBER SHACK: Yes.
MR. GoBELL: Yes, we are going to be higher
than original design which would be Cycle 12, but
lower than what we were experiencing in Cycle 14.
MEMBER SHACK: In 14.
MR. GoBELL: That's just a function f the
main steam pressure we reduced to degrade the steam
We also looked at the changes that the
pressure and temperature could have on the downstream
effects, things like line break, missile hazards,
corrosion, minimum wall thickness required for FAC
evaluations, thermal movement of the piping situations
FAR evaluations that may have been performed in the
past that could be affected by those changes and the
effect on the expansion joints and piping.
And in conclusion, we only had a couple
modifications that were directly related to the
piping. We changed the setting on a couple spring
cans just to reduce the nozzle loads on dry turbines,
and we have a modification that's going to be
implemented in the upcoming outage. It's really
resulting from a heightened awareness of vibration.
We're going to go in and harden a lot of the small
bore dents and drains and branch lines off the main
steam feedwater. We have a section we're going to
reduce mass, try to increase natural frequency and
just make it more resistant to vibration.
We performed comprehensive review and
analysis of all the systems involved and all the
changes that we're looking at and the conclusion was
the piping remains qualified for all those changes.
MEMBER SHACK: Do you have a plant history
of failures in small diameter lines due to vibrations?
MR. GoBELL: That is typically where you
see your vibration failures, usually in the socketweld
of the small branch vent or drain. We haven't seen
that in large oh yes. We've been addressing that
and have become a lot more sensitive to it over the
last five to seven years. We've got a lot of
operators calling us saying, hey this is shaking.
Come look at it, and maintenance, that sort of thing.
So we've done quite a bit of work.
MEMBER SIEBER: Have you ever gone through
the reactor cooling system when you were hot on the
power and measured the vibration on the branch lines
to try to predict which one's going to fail first, or
MR. GoBELL: We have gone in and gotten
handheld vibration data at different locations where
we found leaks in the past. We've looked at a lot of
the systems, especially around the reactor coolant
pumps. We had the 100 Hertz driving frequency and
that sort of thing and gotten a lot of data there with
actual operating conditions.
MEMBER SIEBER: One of the problems is that
when a lot of these plants were constructed, they
would take the vents and drains and make them pretty
long and then put a heavy valve at the top, which it
would do a real job on the socket weld.
MR. GoBELL: Well that concludes the piping
analysis. I'd like to turn it back over to Bryan to
talk about the next agenda item, the ECCS.
CHAIRMAN WALLIS: Thank you.
MR. DAIBER: Before I start into the ECCS,
I'd like to go back and try to cover a few items. I
want to make one clarification. I want to make sure
that there's no confusion. There's several topicals,
a GE topical and a Westinghouse topical that we
referenced. We're not a GE plant, obviously, or
Westinghouse plant, so we didn't use the methodologies
defining those topicals. We used CE methodologies
when we did all of our analysis work from field design
LOCA to non-LOCA considerations.
Those methodologies were really just
utilized as a guideline to give us an insight into
what kind of information we needed to provide in our
submittal and what we need to look at to do power
MEMBER SCHROCK: But you cited proprietary
reports. My question was how you arranged to have
access to a proprietary report.
MR. DAIBER: Entergy does have a lot of
power plants. Some of them are GE boilers. With
respect to the fuel design codes and considerations,
those thermal hydraulic codes that are used and the
FACS code and the ROCS codes for flux considerations,
those are really looked at from an ongoing basis.
The ROCS codes, we look at the core flux
designs and we benchmark. Each CPC plant updates
their verifications on their flux with predicted
values, and those codes have been proven to be very
reliable in predicting the fluxes in past cycles, and
so we continue to believe that they're going to do a
good job on the future design code considerations.
Also from the core design and thermal
hydraulics standpoint, where we expect to go with the
Unit 2 uprated core design, we don't believe we're
moving into a region that hasn't already been operated
at by other CE plants with higher power ratings, given
all the input considerations with respect to peaking
factors, RCS flows and the cold hot considerations.
So I wanted to clarify that. With respect
to the ECCS analysis, again we used, if it's all right
I'm going to call it CE methods. We used the CE
methods for performing the large break LOCA, the small
break LOCA and Boric acid precipitation considerations
when we did the power uprate efforts. And real
briefly, I'm going to go through the methodologies,
assumptions, acceptance criteria and results for each
of these various areas, starting with the large break
The large break LOCA, as I discussed
earlier, we changed methodologies for large break
LOCA. We did use an approved methodology. It's the
latest approved methodology. It's what's referred to
as the 1999 EM. It's the latest approved methodology
that CE has and we applied that methodology to ANO 2
for under the operating conditions. It's documented
MEMBER SCHROCK: Can you give us a summary
of what's new about it?
MR. GoBELL: Joe Cleary's here from
Westinghouse Combustion. He can discuss those
methodology changes and the topical report much better
than I can.
MR. CLEARY: My name is Joe Cleary from
Westinghouse. There were three major types of changes
made to the 1999 EM. The version of EM that it
replaced, by the way, is the 1985 EM and they're both
Appendix K evaluation models. The three types of
changes, number one were process changes basically, to
allow us to run the code in a more unified way, less
analyst intervention, transferring data between the
The second modification was the removal of
Dougall-Rohsanow as required by 5046 in Appendix K for
changes that are within Appendix K.
The third set is number of improvements.
There were roughly five or six minor changes, the low
hanging fruit, so to speak, changes that we were able
to make with very little regulatory risk. In sum
total, they may have produced a reduction in peak clad
temperature in the ballpark of 150 degree, peak
The type of changes in particular, I'll
give you a few examples. There was a change to the
reflood methodology to decrease the steam venting
resistance during reflood. We incorporated a steam
generator heat transfer model that removed some of the
energy from the steam so it was less super heated.
The previous version of the model just had
a constant temperature, or constant specific volume
really for the steam. We improved the model that
represents the interaction of steam and water with
nitrogen, during the nitrogen discharge phase of the
safe ejection tanks.
We made a small change to our Flec base
reflood heat transfer coefficient correlation to make
use of some FLECHTSEASET data that was not used as the
basis for our earlier model. We improved the one
aspect of the blow down hydraulics code to introduce
a variable gap pressure during the blow down
Those are probably the most significant
changes that we've made to the model. In sum total,
like I said, none of them presented a significant
change by themselves, the peak cladding temperature,
but in total approximately 150 degrees in the sample
calculation we showed in the topical.
MEMBER SCHROCK: You have a peak clad
temperature prediction in large break LOCAs, as I
understood it, of 2166, and that results from analysis
which reduced that prediction by 150 degrees roughly
compared to older predictions by the Appendix K
MR. CLEARY: Yes, the methodology results
in approximately a 150 degree decrease.
CHAIRMAN WALLIS: So I'm not quite sure
what you're saying. If you'd have gone by your method,
would you have a higher temperature?
MR. CLEARY: Yes.
CHAIRMAN WALLIS: 2300 and something.
MR. CLEARY: If we had used the older in
addition to changing the methodology and the power
uprate, there were a few other changes to the
analysis. All other changes all other things being
equal, we would have calculated temperature
approximately 150 degrees higher with the new
methodology versus the old.
MEMBER SCHROCK: Have you the conclusion
for a position as to whether 7.5 percent is the limit
of uprate that could be achieved using Appendix K, and
did you have any interest in pursuing the best
estimate approach, rather than Appendix K?
MR. DAIBER: At this point in time, with
the current 7.5 percent uprate and even considering
the potential for an ECCS uprate, we feel it's more
than adequate margin in the methodologies we're
currently using, the 1999 EM. So, under
MEMBER SCHROCK: I don't understand that
statement. The residual 36 degrees you characterize
as more than adequate.
MR. DAIBER: Again
MEMBER SCHROCK: Is that what I've heard?
MR. DAIBER: Yes. Well, there's also
margin in the input assumptions. Again, when we did
this process, we made sure that we developed input
assumptions that were very conservative and very
bounding for where we expected to operate the plant.
So the input assumptions along with the
methodology itself, provide conservatisms that are
there. So although there's only a 36 degree margin to
the limit, the assumptions we used are very
conservative and very bounding for where we anticipate
to operate the plant.
MEMBER SCHROCK: But with regard to the
other question, have you considered would it be to
advantage to use best estimate, and would best
estimate be needed if you were going to go for a
MR. DAIBER: Yes. If we went to a
substantially higher power rating than the 7.5 percent
that we've considered, then definitely we'd look at a
combination of best estimate, large break LOCA and I
believe CE Westinghouse are comparing their methods
now that they're one, and I believe they're showing
some benefits with just the Westinghouse approach or
with CE approach.
MR. CLEARY: CE does not have best estimate
methodology. Westinghouse has a best estimate large
break model, as I'm sure you're well aware. We've
done a little bit of comparison and we've concluded
that the Westinghouse Appendix K model calculates
lower peak cladding temperatures than our Appendix K
model, and their large break, best estimate model
obviously produces lower peak cladding temperatures
than either of the Appendix K models.
At this point in time, we don't have any
commercial drivers to warrant submitting the
Westinghouse best estimate model to NRC review for
application to CE design and SSSs. If that changes in
the future, if we need it for support of any of our
uprates, then that's a path we are prepared to go
CHAIRMAN WALLIS: So this new methodology
is 1999. That's something that was carefully looked
up by the staff and they've approved all those changes
that you made?
MR. CLEARY: Yes. It's an approved
valuation model in compliance with Appendix K.
CHAIRMAN WALLIS: You seem to have gained
a lot, 170 degrees?
MR. CLEARY: 150 degrees, yes.
CHAIRMAN WALLIS: Is it the reflood heat
transfer coefficient that's the main actor there?
MR. CLEARY: It's the reflood related, yes.
Both the improvement to the flood correlation and the
hydraulic aspect of decreasing the steam venting
resistance, and therefore getting higher reflood rate,
particularly the less than one inch per second reflood
rate that drives the flood correlation.
MR. DAIBER: As Joe alluded to, when we
applied the 99 EM, we obviously accounted for power
up. Next slide, Dennis. We obviously accounted for
the increase in the power rating, but we also changed
some of the other input parameters. Linear heat rate
was increased from 13.5 to 13.7, and the range of SIT
Tank pressures and inventories was also increased in
the analysis arean.
So the analysis incorporated very
conservative boundary assumptions with respect to the
SIT tank conditions, although the current tech specs
and operating conditions don't exercise that broad a
The results of the large break LOCA
analysis, the spectrum was revisited. The limiting
peak clad temperature was 2154 for the .4 double ended
guillotine pump discharge break, which is slightly
different than the .6 break size currently is our
limiting break size, using the 1985 evaluation model.
So, we also compared the results fro Cycle
15 to Cycle 16, realizing the methodologies here are
different than some of those parameters I just
mentioned have just changes. For Cycle 15, when we
looked at the new RSGs, the peak clad temperature
there was 2029, and for Cycle 16 we're now at 2154, as
I just mentioned.
With respect to the maximum oxidation,
core wide oxidation, we also verified acceptable
results there, making sure within 10 CFR 5046
compliance on those criteria.
CHAIRMAN WALLIS: To get back to the
previous slide, is there something in the regulations
that says you should evaluate these particular break
sizes? I'm going back to my colleague's earlier
question. If you had looked and it's 8.5, it doesn't
mean that wouldn't have been above 2200.
MR. CLEARY: The regulations specifically
address looking at the three discharge coefficients of
1.0.8 and .6. We start out our analysis looking at
those three and if we find that the .6 is of more
limit, the most limiting of those three, we go down
using the same increment, i.e. to .4 guillotine.
This is our first analysis where the .4
was shown to be limiting. So we continue to decrease
the break size to get a break that showed a local
peak, and we decided to drop by a tenth of a fraction
rather than two-tenths in that case, because now the
absolute values of those numbers are getting lower.
CHAIRMAN WALLIS: It's a funny shaped
curve, because everything is between 2200, except for
that 2154. So it looks as if it's above peak. It's
more or less a plateau. It's a bit odd. Why is that.
Do you have any idea?
MR. CLEARY: There is one hydraulic
difference between the four biggest breaks there that
I think is the major contributor to that dissimilarity
and that is the tying of the reflood rate drop below
one inch per second. It was earlier for the .4
guillotine comparatively speaking looking at the
trends, than for the breaks. Consequently, there is
a somewhat larger period of time, I'm talking maybe 15
to 20 seconds during reflood that the temperature is
using the lower one inch per second reflood rates for
that break size compared to the others.
CHAIRMAN WALLIS: So is this a step in the
calculation method or something when you go to these
MR. CLEARY: Yes, it is required by
Appendix K. One can not use the flood heat transfer
coefficients below where reflood rate is.
CHAIRMAN WALLIS: It's a step in the
calculation procedure to do this sort of step in the
results. So it's a peculiarity of the sort of non-
smoothness of the Appendix K method.
MR. CLEARY: That's right. Discontinuity
in two ways, one for any break size, there's a
dramatic change in the reflood heat transfer
coefficients once the reflood rate falls below one
inch per second.
CHAIRMAN WALLIS: Physically incorrect.
MR. CLEARY: That's correct.
CHAIRMAN WALLIS: It's a requirement.
MR. CLEARY: That's right. Substantive
research since `74 has shown that there really is no
change in phenomena for the reflood rates as they step
below one inch per second. The other similarity is
now between the .4 and the others in that the
hydraulic analysis calculated a little bit earlier
time for that. So the discontinuity occurred somewhat
earlier for that one break.
MEMBER SCHROCK: It seems that if you look
at the big picture here it was far more important for
you to change your Appendix K model than it was to
attempt to do any peak shaving or flux flattening in
the fuel design. Is that correct? You just wouldn't
have been able to ask for an uprate.
MR. DAIBER: Yes, it was necessary for us
to move to the 1999 EM. In fact, we did request that
the review schedule of that be consistent with our
need for power uprate. So the 1999 EM was approved in
relation to the need for ANO 2 as a part of the uprate
CHAIRMAN WALLIS: Did the ACRS ever see
this `99 valuation model? I don't think they did.
MR. CLEARY: No, it was not discussed with
CHAIRMAN WALLIS: But this is a key aspect
of the upreate.
MR. DAIBER: Move onto the small break
LOCA. The methodology for small break LOCA, we used
the same current analysis methodology of record for
Cycle 16 uprated conditions, referred to as the S2M
document in CENPD-137, Supplement 2-P-A. This
methodology was the same, which will help in
comparison in later slides with Cycle 15 analyses.
Some of the assumption changes with
respect to small break LOCA, obviously again the power
uprate was considered, linear heat rate was also
accounted for. That broader range of SIT tank
pressures was also accommodated in the small break
LOCA and I note here the high pressure safety
injection flows were kept the same in Cycle 15 and
Cycle 16. That's a critical parameter there.
The results of the small break LOCA
analysis indicated that the .4 square foot pump
discharge break, which is our current limiting break
remained the same. The peak clad temperature is now
2066, with a little footnote that it's actually 2090.
There was a code there identified after we ran our
analyses and the limiting breaks was rerun correcting
that and the official
CHAIRMAN WALLIS: Did you miss slide 78?
I was going to ask about the core wide oxidation.
MR. DAIBER: Sure.
CHAIRMAN WALLIS: I wasn't sure that that
was something that could be predicted. And then
you've got a .99 versus a criterion of 1.
MR. DAIBER: The methodology there --
CHAIRMAN WALLIS: In all cases?
MR. DAIBER: Yes, the methodology there is
very conservative. I believe it's based on the peak
pin through the whole core.
MR. CLEARY: In small break. In this
case, we a number of years ago started reporting the
core wide oxidation result as less than 0.99. In
actuality, the actual calculated numbers for that
break spectrum is in the ballpark of about .4 for the
CHAIRMAN WALLIS: Why didn't you report
4.4. That would give me a much better feeling.
MR. CLEARY: I guess the answer is to
avoid having to make cycle to cycle variations to that
number by -- in the reload safety valuation reports.
If we continue to show less than .99 --
MR. BOEHNERT: Oh, so that should less
MR. CLEARY: Yes, that is correct.
MR. BOEHNERT: That's the problem.
CHAIRMAN WALLIS: This is oxidation from
the outside in?
MR. CLEARY: Yes, and also in our
methodology we assume that the entire core ruptures at
the same elevation that we predict rupture for the hot
rod and the inside of the cladding, after ruptured
node oxidizes as well and contributes to the corewide.
MEMBER SCHROCK: What is your accuracy
level for that prediction?
MR. CLEARY: I'm not sure if I can address
accuracy. It's a very conservative model based on
Baker-Just oxidation model. I guess, could you
explain what you mean by accuracy in this case?
MEMBER SCHROCK: Yes, compare it with some
data and so what kind of predictive capability do you
really have as compared to some real experimental
MR. CLEARY: The basic --
MEMBER SCHROCK: Dr. Wallis' comment about
the .99, for example, do you believe you can predict
it within 1/10th of 1 percent, 1/100th of 1 percent,
MR. CLEARY: Well, from my perspective
we're not trying to predict reality with an Appendix
K model. We have conservative component models, in
particular in this case, Baker-Just driving the
calculation. So to the extent that the Baker-Just
model predicts reality, or predicts an oxidation we
report that as the -- using very conservative pin
sensors for representing the power in all the rods in
the core and other conservatisms in the methodology.
So I would say --
MEMBER SCHROCK: Essentially, being
Appendix K evaluation means that there is no
consideration of repeal of the ability of the
predictive method? That's not a consideration. It's
only a question of whether the method was approved.
MR. CLEARY: I think the sensor rod here,
the point you're making, that's correct. The actual
calculated number of about .4 probably is very
conservative relative to a realistic calculation of
CHAIRMAN WALLIS: This is .4 for cycle 16
with the new upgrade?
MR. CLEARY: It's .4 for a bounding
calculation that is expected to apply for cycle 16 and
going forward as long as the plant configuration --
CHAIRMAN WALLIS: What is it for cycle 15
if it wasn't .99?
MR. CLEARY: I didn't review those numbers
before this meeting. I believe they would have been
a little bit higher than the .4 that we calculated
using 1999 EM, primarily because the 1999 EM with the
automated code system does a more precise application
of our methodology.
Previously, when we did it by hand, the
analysts took conservative measures to do the analysis
one time and not have to repeat the somewhat
cumbersome calculation, so adding in those
discretionary conservatisms generally resulted in
numbers that were higher than .4, but less than .99.
CHAIRMAN WALLIS: This must be 40 or 50
MEMBER SCHROCK: Not very good either.
MEMBER POWERS: It depends on how much you
believe in breakaway oxidation. If you believe in
breakaway oxidation, the ability under dynamic events,
Baker-Just is not all that bad.
MR. DAIBER: Moving to slide 81 on small
break LOCA results, compares -- looking at the results
here, again the limiting break size stayed the same at
.04 with a peak clad temperature of 2090.
In the next slide we compare the results
to the acceptance criteria, but we also compare it to
cycle 15 results. Here, the methodology stayed the
same and the input assumptions relatively stayed the
same except for core power and the peak clad
temperature went up from 1905 in cycle 15 to 2066 in
cycle 16. That comparison is based on the same
version of the code.
The results for cycle 16 all indicated
acceptable results with respect to 5046 acceptance
MEMBER SCHROCK: Did you skip over some
MR. DAIBER: We jumped back. Moving on to
the boric acid precipitation analysis. For boric
acid precipitation analysis, we did switch methodology
in cycle 16. We utilized again an approved
methodology. It's the CE approved methodology for
boric acid precipitation. This methodology that we
applied we know is more conservative than the methods
that we were currently, originally licensed to.
We did account for the power uprate and
the original analysis of record from cycle 1 had been
maintained over the last 15 cycles so there were
various other miscellaneous input parameters that we
updated when we did the analysis.
The results of that analysis indicated
that assuming a hot leg injection started at 5 hours,
the maximum boric acid concentration attained a weight
percent of 23.3. This is less than the acceptance
criteria of 27.6 weight percent. And verifying that
our current DOP guidance that we've used over the
years of initiation of hot leg injection between 2 to
4 hours still remains valid under the power uprated
CHAIRMAN WALLIS: Is this where we get to
the mixing part?
MR. DAIBER: Yes, this is the mixing
issue. There was an issue raised by the staff with
respect to the volume assumed in our analysis in
implementing this new methodology. The volume we used
includes the core region and the region of the lower
plenum below the core for that mixing. That's
consistent with what we had used in our original
methodology and we consistently use that same volume
when we apply --
CHAIRMAN WALLIS: It's not easy for me to
see why they should be well mixed together. The core
is up here with all kinds of stuff in it and the lower
plenum is down here. It's not clear to me why they
MR. DAIBER: There possibly are some valid
considerations with respect to the mixing concerns.
And taken as an individual issue, it's one thing, but
taken with respect to the overall conservatisms
embedded in the methodology, we believe that the
overall methodology utilized to determine long-term
core cooling is a very conservative methodology.
CHAIRMAN WALLIS: You said something about
a recriticality or something. What's the concern?
Why worry about this?
MR. DAIBER: Flow blockage, boric acid
precipitating out and causing flow blockage
CHAIRMAN WALLIS: Flow blockage,
coolability of the core. Nothing to do with nuclear
MR. DAIBER: That's correct.
CHAIRMAN WALLIS: Is this something that's
well understood, this precipitation of boron?
MR. DAIBER: The time at which or the rate
concentration at which it precipitates out has been
looked at and there's some data available with respect
to what point and what weight percent versus
temperature at which the precipitation would occur.
The phenomena here is dealing with a cold leg break
situation where the excess ECCS fluid is spilling off
the side and you're only really getting boil off in
the core and steaming since leaving behind the boric
acid consideration. So it's a very conservative
assumption and modeling consideration.
CHAIRMAN WALLIS: So you're boiling and
it's getting richer and richer in boric acid?
MR. DAIBER: Right, that's the
conservative modeling assumption that's utilized to
develop this time --
CHAIRMAN WALLIS: It precipitates, it
sticks. It doesn't fall out or --
MR. DAIBER: That's right, right. It's
assuming that once it reached that weight percent, it
CHAIRMAN WALLIS: Is there an experimental
basis for all of this? People have actually done
realistic experiments to figure out what the
precipitation is and how tough it is and what its
shape is and all kinds of things, issues that I can
think of. I just wonder what the basis is for
MR. CLEARY: I think by calculating a
concentration using conservative methodology that a
maximum concentration that's below the solubility
limit it avoids having to address all those issues
which you bring up.
CHAIRMAN WALLIS: It assumes it's mixed.
There aren't regions where, for some reason or other,
it's got more concentration?
MR. CLEARY: That's correct, within a
mixing volume and there was, as you pointed out,
difference of opinion as to what constitutes an
acceptable mixing volume. But within the mixing
volume, yes, there is uniform concentration.
CHAIRMAN WALLIS: Do you agree with the
MR. CLEARY: We came to a resolution, an
agreement that the Arkansas analysis is appropriately
conservative. I believe the staff may be -- will be
dealing with the CE methodology on a generic basis
going forward in the future.
MR. DAIBER: From a conservative
standpoint, we believe the methodology is
conservative, eventually in the long term what we do
is we initiate hot leg injection. Once hot let
injection is there, then there's adequate -- we
definitely know at that point there's going to be
adequate mixing and adequate flow coming out of the
top of the core and spillage and covering it. So it's
really just a matter of time at which you actuate
We also know that the methodology that CE
Westinghouse uses here is very conservative. In fact,
one of the most -- one of the conservative assumptions
in the methodology is that all the charging flow which
comes from the BAM tanks goes directly to the core.
In reality, that doesn't happen. It mixes with LPSI
flow at several thousand GPM. The charging flow is
coming in at about 138 GPM. The LPSI flow is coming
in at about 3,000 or 4,000 and LPSI-HPSI combination
is well over 4,000 GPM and it truly mixes and most of
that would actually fall on the floor and not go to
However, here, we assume everything in
that tank goes directly to the core, concentrating it
very quickly, so the methodology in and of itself does
embed some very conservative assumptions all with
respect to the volume that's used and the spillage
that's considered. We believe that the methodology in
and of itself is very inherently conservative.
With respect to the ECCS analysis we
reviewed the 5046 acceptance criteria and verified, as
we indicated for small/large break LOCA and boron
precipitation that we met the design criteria and
under operating conditions, power upgraded conditions,
we believe that ANO-2 is acceptable.
With that I'd like to move on to the
resolution of open items on the agenda.
There are no current open items with
respect to the ANO-2 power uprate submittal. Due to
the timing at which the draft SER went out and the
resolution of several questions that were still open,
there were in the draft SER several open items still
identified. Since that time we have worked with the
staff and provided them additional information to
respond to those questions and at this time there are
no current open items.
However, what I'll do now is -- there were
three items there. We'll go through each of those
items and address the issue and the resolution of
those items, dealing with seam generator tube
ruptures, radiological consequences, the MHA
radiological consequences which is a mixing issue and
the control and doses.
First, we'll go over the steam generator
tube rupture dose considerations. During the original
submittal to the NRC, we were using 30 minutes
operator response time to generate our doses for tube
rupture. Subsequent to that time we changed that to
60 minutes to give our operators more than adequate
margin to address this particular event. Those
calculations were submitted at a later time. They
have now had the chance to review that and accept the
results that we have presented for a steam generator
With respect to the LOCA, there were some
issues with respect to the spray versus unsprayed
region, the mixing that occurred and accredited in our
off-site release calculations, also our limiting event
for controlling dose considerations.
We do credit two interchanges between the
sprayed and unsprayed regions per hour in our off-site
release calculations and control room dose
In resolution of this issue with the
staff, what we did was we went and we looked at where
containment fans are located because at two
interchanges per hour an assumption is based on the
air flow coming from our containment cooling fans. We
looked at the location of those fans where the intake
was, where the discharge was and compared that
relative to what we considered sprayed and unsprayed
regions and we did an extensive review and
verification of where those regions were and provided
quite a bit of information with the staff with respect
to where the intake is and where the discharges are
and we were able to demonstrate that the two
interchanges per hour is a very conservative
CHAIRMAN WALLIS: Now is that based on
just discursive arguments or is it some analysis?
MR. DAIBER: It's based on the geometry
and the airflows with respect to where those volumes
are. Most of the containment is sprayed, about 78
percent of it is sprayed and about 22 percent of it is
unsprayed. The fans are located, themselves, under a
roof per se. There's a concrete floor above them.
But it's a very small volume at which they intake air.
CHAIRMAN WALLIS: So you look at the flow
rates with the fans and the volume you have to clear
and you figure out how long it takes to do that?
MR. DAIBER: Yes, the fan itself is
drawing in what would be called an unsprayed region,
but the volume that it draws in from is so small that
it's effectively interchanging that volume.
CHAIRMAN WALLIS: So you're going to claim
-- in reality it's more like 10 interchanges per hour
or something, so you need credit for two? There is
some sort of analysis behind it that says what it
really is is thus and so and therefore conservative
assumption is reasonable?
MR. DAIBER: Yes. It's based on a
qualitative argument based on the geometries and the
intake in the sprayed regions --
CHAIRMAN WALLIS: Is this written down,
this qualitative argument?
MR. DAIBER: Yes, it is, quite extensively
CHAIRMAN WALLIS: Do you have it so we can
read it over lunch or something?
MR. DAIBER: Yes, yes. In response to the
NRC questions it's written down. And it's fairly
extensive with pictures, all sorts of graphs.
The control room dose issue, as we
discussed earlier our control room dose calculations
were performed based on 10 CFM and leakage
considerations. In November of last year we did a
control room envelope in leakage test and the results
of that test indicated a natural in leakage value of
MR. BOEHNERT: What kind of in leakage
tests did you do?
MR. DAIBER: A tracer gas.
MR. BOEHNERT: Tracer gas.
MR. DAIBER: The 134 SCFM includes 10 CFM
for operating ingress and egress.
CHAIRMAN WALLIS: 10 SCFM is very, very
difficult to achieve.
MR. DAIBER: I'm sorry?
CHAIRMAN WALLIS: 10 SCFM leakage is very
difficult to achieve.
MR. DAIBER: Yes, and the basis for that
really goes back to just ingress and egress from the
operators. So what we've done to resolve this
particular issue is we've submitted to the staff a
dose calculation associated with the MHA which is our
limiting event for LOCA considerations, using 61 SCFM
as the new bounding allowable in leakage and that
value is actually back-calculated as the maximum
allowable in leakage that we can have and still meet
the GDC 19 control room operating dose considerations.
To further get our in leakage values down
to verify that we're below 61 SCFM, we've also
committed to replace the seals on VSF-9 which is one
of the control room emergency ventilation filter fan
housing units. That seal during the in leakage test
was attributed to about 45 SCFM in leakage so we're
replacing the seal on that to essentially eliminate
that in leakage. The other area of in leakage was
related to the pressurization of the north wall of the
back of the control room. We're also making
commitments to ensure that that room would not
pressurize. The pressurization comes from 2VEF-56
operating. So we've also made commitments to make
sure that that room will not be pressurized to reduce
the in leakage there by another 49 SCFM in leakage.
Therefore, we're effectively giving our in leakage
values down well below the 61 SCFM.
CHAIRMAN WALLIS: Are you doing to do some
MR. DAIBER: I'm sorry?
CHAIRMAN WALLIS: Are you going to do some
periodic testing and checking of what the actual
MR. DAIBER: At this point in time we are
not committing to any periodic testing associated with
CHAIRMAN WALLIS: I remember this issue
came before the Committee and we had all kinds of
evidence about what really happens in these things.
The main problem is that somebody leaves something
open. Someone repairs something and leaves something
open and then your leakage is 400 CFM or something and
until someone realizes they've left something open
which may be days, your leakage is way beyond what you
MR. JAMES: Bryan, this is Dale James. We
are implementing a control room boundary program to
address those very issues. There is some industry
guidance, NUMARC guidance, NEI guidance, excuse me,
out on control room boundary control programs which we
will be implementing.
CHAIRMAN WALLIS: So you are going to
monitor, not perhaps measure, but you're going to
check all the things which contribute to linkage on a
MR. JAMES: I'm not positive, but I think
there is some criteria in there about periodic
testing, depending upon the quality of the program.
MR. BOEHNERT: Yes, the staff has under
consideration and I guess a generic letter and a set
of Reg. Guides which we're going to hear about a
little bit later this year.
MEMBER POWERS: Graham, the question I
would worry about is you tested this thing, you've
gotten this huge leakage from a couple of major
sources. You fix those major sources. Are they
hiding? Are those major leaks hiding, minor leaks, so
if you went back and tested, instead of reducing to 94
CFM, you reduced it by 25, 30? I mean that seems to
me to be the question that comes immediately to my
The second question that comes up is you
tested it for some set of conditions that you could
reproduce conveniently and you're applying this to a
different of conditions for an accident. It's not
obvious to me how that changes your leakage.
MR. DAIBER: Dan, can you address some of
this? I know when they did the testing on this, they
did look at the action and condition configurations
and I think Dan can address that better.
MR. FOUTS: Yes. I'm Dan Fouts. I'm
supervisor of Safety Analysis. We actually did four
tests. The first one was with 2 VSF 9, as we call it
and we got 27 CFM leakage and we were able to account
for all of that in leakage being upstream of the
filter unit, so we knew where it was coming from and
basically we were able to confirm we have an intact
control room at that point.
The second test was at VSF 9 and I believe
it was around 89 SCFM in leakage. We then turned on
the 56 fans and noticed the pressurization caused us
to go to the 134 which was the maximum that we got.
So at that point we knew that the delta between having
the 56s on or not on, we knew the delta between the
VSF 9 and the 2 FSF 9 fans and so we knew that if we
took care of the leakage on the VSF 9, that we could
reduce by the 45 and take care of the 56s being on,
we'd reduce by the additional amount and get us down
to where we are.
CHAIRMAN WALLIS: It's a whole system.
And this VSF 56 is somewhere else.
MR. FOUTS: 2 VSF 56 --
CHAIRMAN WALLIS: The environmental
pressure around the, on the north wall.
MR. FOUTS: The 2 VSF 56s suck out of the
emergency switch gear rooms and they discharge into
our controlled access area which is a wall just on the
other side of the control room and pressurize that and
we did make pressure sweeps of the whole area, so we
knew what the delta pressures were between the
different areas. When we did the testing we simulated
accident conditions as best we could, so we turned off
fans that weren't -- that may or may not be lost
during the accident. We turned on the ones that could
possibly come on, post-accident.
MR. DAIBER: Now in conclusion, as I had
mentioned earlier, there are no current open items
with the ANO-2 power uprate issues.
MEMBER KRESS: On this in leakage question
again, you had that in leakage whether you have a
power uprate or not and the power uprate doesn't
really -- you got to deal with that whether you've
have a power uprate?
MR. DAIBER: That's correct. The power
uprate is only an incremental impact.
MEMBER KRESS: It gives you a little more
MR. DAIBER: That's correct.
CHAIRMAN WALLIS: Are we going to make it
MR. BOEHNERT: Yes. I think --
MR. DAIBER: This is the last topic. It's
the risk impact.
CHAIRMAN WALLIS: Good topic to lose an
MEMBER POWERS: Think how fortunate you
are not to have the chairman here and having to read
the words qualitative risk.
CHAIRMAN WALLIS: Oh, I don't believe in
MEMBER POWERS: Yes, but you don't get
histrionic over it like the chairman does.
CHAIRMAN WALLIS: Do you want me to do an
MEMBER POWERS: Oh please.
MR. DAIBER: ANO-2 did address the risk
impacts associated with power uprate. Our submittal
is now the risk-informed submittal. However, a risk
analysis was done in consideration of the power uprate
efforts for ANO-2.
We did this in several forms. With
respect to the level 1 and level 2 CDF core damage
frequency, large early release fractions and fire
vulnerability considerations, we did a quantitative
assessment of those particular considerations.
A qualitative impact was performed at
power uprate for the impacts with respect to the
seismic vulnerabilities, external events and we also
did a qualitative impact with respect to shutdown risk
and I'll go into each of those.
MEMBER KRESS: Has your PRA gone through
the industry peer review process certification for
MR. DAIBER: The model that we utilized
for this particular effort has not or did not go
through that certification. The revision 3 model
which is our current model is going under that
certification review as we speak right now. The
results from that model have reduced our CDF values
lower than what I'll be talking about here.
When we started off this effort, we
started with what we had available to us which was a
1997 plant model. We have updated the IPEEE model
over the years to make sure the Level 1 internal event
model most, as best we can represents the plant. With
respect to the LERF considerations that model is
effectively the same as that associated with the IPEEE
With respect to external events and fire
considerations, we utilized for the fire the latest
model available which had some updated initiating
event frequencies associated with it. However, the P2
values conversion values from frequencies to core
damage considerations, those were effectively the same
as the original IPEEE considerations. And with
respect to the seismic and the external events again
we started with the latest available IPEEE models that
were available at the time.
I'm now going to go over the internal
event considerations on core damage frequency and
we'll address the following areas: initiating events,
frequencies, success criteria, component failure
rates, system fault tree analyses and operator
The initiating events and frequencies, we
first looked at those and made sure that there were no
new initiates identified and no new increase in
initiated frequency. There was one modification that
we made. It was that CSAS actuation. That was very
similar to an already modeled MSIS actuation which
secures main feed and loss condenser. However, due to
the fact that we've already modeled the MSIS to CSAS
actuation signal wasn't a new initiator and the
frequency of the MSIS was determined to be
conservative with respect to the bounding issue of the
new addition. And the reason for that was when we
installed the CSAS actuation we installed it, keeping
in mind trip hardening facets and we went back and we
also trip hardened the MSIS actuation signals, so it's
a frequency of an inverted MSIS which was actually
reduced, even though we added the new signal.
As a result of that, there were no changes
required to the current model for up rated conditions
with respect to initiating event frequencies.
The success criteria was also reviewed as
a result of the power up rate considerations and along
the lines of success criteria, there was one change
that was noted to be necessary to update the success
criteria and that was associated with large break
LOCA, the amount of HPSI flow required at time of
recirculation. The current evaluation model, the
current power considerations uses two of four HPSI
valves per pump as the acceptance criteria,
recognizing the increase in decay heat associated with
power uprate, we increased that requirement from 2 to
4 to 3 to 4 valves on the uprated conditions.
The other criteria associated with some of
the transient event considerations, we went back and
verified the success criteria there and the method of
verification was the use of the code CENTS. CENTS is
the CE Westinghouse methodology effectively used for
doing the Chapter 15 events. We applied it in the
best estimate fashion here to verify that the success
criteria, the other success criterias remain value
under uprated conditions.
So the only fault tree topologic change
necessary for power uprate was the success criteria
with respect to large break LOCA considerations at
We also went through and looked at the
component failure rates and the eventual impact of
power uprate on component failure rates. And as we
discussed earlier this morning, all the plant systems
and components were reviewed for verification that
they could operate within the uprated conditions and
still meet their design requirements. And appropriate
modifications and/or set points were made to ensure
that those components would still operate within the
Based on that and the fact that we do have
on-going monitored programs and look at the components
themselves and trend components considerations, we
determined that there was no adverse effects on the
component failure rates associated with extended power
uprate for Unit 2.
MEMBER POWERS: I guess -- explain to me
again. Existing monitoring programs will account for
additional wear. That means you'll know when it's
MR. DAIBER: Yes and/or --
MEMBER POWERS: Surely, the fact that it
has occurred must increase failure rates?
MR. DAIBER: It will -- if there is -- if
there is a result of that, we will pick that up as
part of the monitoring programs and ultimately update
the data base as necessary. But also, it allows us to
watch the components and make sure we're performing
predictive maintenance on a more appropriate schedule
MEMBER POWERS: But you've got to reflect
the fact that the additional wear is occurring in your
component failure rates that you use the PRA model.
Surely, you can't say you're going to go fix something
that's going bad on you, does not mean that you didn't
experience a period of risk while it was bad.
MR. DAIBER: From the component design
standpoint, we made sure that all the components were
operating within the design criteria and upgraded the
MEMBER POWERS: That doesn't have anything
to do with how you set your component failure rates.
MR. DAIBER: To actually try to predict
some of that is very challenging. If the components,
the pumps operating at a higher speed and the wear
rate expected under the higher speed or conditions
causes it to fail more frequently than if it were not,
that data is not really available on a generic basis.
We do take into account actual plant operating
conditions to accommodate failure rates associated
with components and based on that experience we do on
a regular basis update component, the failure rate.
So to the exact science of getting that data and
predicting that data, it's very difficult. However,
from a long term perspective, the component failure
rates for a specific components will be rolled into
the model as we gain experience under the operating
MEMBER SCHROCK: Could you give an example
of what that first bullet means and equipment verified
to operate within design limits?
MR. DAIBER: With respect to components,
design requirements, their ratings, their pressures,
their flow rate requirements, they were all verified
to be -- that the components actually were within what
the vendor would recommend for the design of those
MEMBER SCHROCK: What does that say about
MR. DAIBER: It gives us a good level of
comfort that we're operating within where the vendor
would recommend and that there would be no substantive
change in the failure rates that we would expect for
that component over what we've seen in the past.
CHAIRMAN WALLIS: So your failure rates
are based on your experience of failure rates?
MR. DAIBER: A combination of generic
plant data and review of our plant specific data with
respect to components.
CHAIRMAN WALLIS: It is based on
experience of either your plant or a group of plants?
It's not based on guesswork from what some
MR. DAIBER: No. That's right. It's
based on actual operating experience.
MEMBER KRESS: That's standard PRA
procedure. There doesn't seem to be any other --
there doesn't seem to be any other way to do it.
MEMBER POWERS: No, it's not standard PRA
procedure is to take into effect zero. You know it
exists. I mean you're having to put things in here.
MEMBER KRESS: Yes, but you don't have any
way to --
MEMBER POWERS: Yes, you do. Run a
sensitivity analysis and say suppose my component
failure rates change by the ratio of frequencies of
MEMBER KRESS: You can do the sensitivity
MEMBER POWERS: Sure.
MEMBER KRESS: You don't know the ratio of
frequency of repair just yet though. You will over
MEMBER POWERS: I will bet that the
rotating equipment you can take number of revolutions.
MEMBER KRESS: That would be one process
to do it, but the fact is there's just no way to
estimate what a power uprate will do --
MEMBER POWERS: The worst way to do it is
to ignore it.
CHAIRMAN WALLIS: That seems
MR. DAIBER: We will have to -- I will
point out that from the safety-related equipment
that's typically required to operate post event, all
that equipment was verified to essentially operate
within the current design requirements. There were no
additional design requirements identified associated
with any of the safety-related equipment needed to
mitigate these events most of the considerations with
respect to where we'd come with normal operating
MEMBER POWERS: Which is the initiating
events. There are two parts to the equation.
MR. DAIBER: Right.
MEMBER POWERS: There's the initiators and
the mitigators. The mitigators are okay does not mean
that the initiators are okay.
MEMBER SCHROCK: Failure rates, it seems
to me, depend on the way the thing is operated, a wide
range of things, the exposure to transients that may
be damaging any number of things in the operation, but
also to variations int he manufacturing process, what
the thing was initially. Rotating machinery, surely
related to maintenance factors. There's so many
things that go together to do it, but what puzzles me
is how any correlation is developed between design
operation within design limits and the failure rate.
MR. DAIBER: The only --
MEMBER SCHROCK: Surely, if you operate
outside design limits you would subject the thing to
a higher failure rate, but how is that used in fixing
failure rates that you're going to plug into your PRA.
MR. DAIBER: The real assurance that you
get is the fact that you don't see any substantive
changes in the component failure rates. Obviously,
we're operating within what the design manufacturer
recommends and although there may be small changes as
a result, there are no substantive changes expected as
a result of the failure, component failure rates.
MEMBER KRESS: It's just that PRAs are not
sensitive to the level of a 7 percent power increase
in terms of inputting failure rates and initiating
frequencies. You just can't distinguish those things
at that level for a specific plant in a PRA and that's
why one of the nice things to do with PRAs is to have
a good uncertainty analysis. And I'm sure the
uncertainty element would far and away swamp the
change in 7.5 percent, but of course we don't get
uncertainties when we get PRAs very often, but if we
had them, I'm sure it would swamp anything 7.5 percent
would do to those things.
MR. DAIBER: That's a good point and the
other thing is as we'll get into later here, operator
actions and response times were identified as one of
the more critical areas and any sensitivities you
would see as a result of component failure rates would
be overwhelmed by the sensitivities we did see as a
result of operator action considerations.
MEMBER POWERS: As far as I can tell it's
all due to rampant speculation. I don't think you can
substantiate your statements about uncertainty and I
don't think you can substantiate statements about the
relevant importance of operator actions and component
failure rates. I mean it's just speculation. You
just don't have the numbers.
MEMBER KRESS: I think you're right. If
you don't have the numbers, it is speculation. Those
are tough numbers to come by.
I can do the uncertainty, probably, pretty
well because there is enough data to incorporate
uncertainties. I just can't do the other half and
that's what the 7.5 percent of power uprate will do to
that uncertainty distribution, I don't have that data.
MR. FOUTS: This is Dan Fouts. I would
like to point out one other item here. We do use a
substantial amount of generic data and the equipment
components and so forth that we have in the plant that
we're going to operate it at uprated conditions or
current conditions is not seeing anything unlike what
these components see all over the country as it is.
So this generic data already includes to some extent
whatever uprates we may be using.
MEMBER POWERS: I mean it's all bearing on
unbelief here. I'm going to change things. I know
clearly I am making it worse. Maybe it's incremental
worse, I'm making it worse, but I leave things the
same because I can't estimate the increment. I can
estimate the increment, change the component failure
rates by 10 percent and see if it makes any
difference. I mean this is -- it doesn't strike me as
even a typical thing to do. Change them by 50
percent, see if it makes any difference. If it
doesn't make any difference, then the point is
MEMBER KRESS: I've got to tell you, it
would make some difference if you changed it by 50
MEMBER POWERS: And if it did, then we
would get down into a discussion of whether it was 10
percent or 50 percent is the appropriate thing.
CHAIRMAN WALLIS: Are you going to show us
later on the operator actions dominate so you could be
off by say a factor of two and component failure rates
wouldn't make any difference?
MR. DAIBER: With respect to operator
actions, the dominant effect in change in core damage
frequency was on the order of 16 percent increase as
a result of the reduced time available to operator
CHAIRMAN WALLIS: Are you going to argue
if you had -- maybe you didn't do this, you didn't
double your component failure rates and see the
MR. DAIBER: No, we did not do a
sensitivity analysis when we did this.
Again, we expected all the components to
be operated within current design parameters which is
what generic data is based on and we may see a more
rapid degradation in certain areas when we do our
inspections, but that just means we would take
correction action sooner, whether it's predictive
maintenance or fact program or whatever. If there's
an impact from power uprate on that, we would take
action before we would ever get to the point that we
would see a failure. And if we happen to miss all of
that, then we'll pick it up in our periodic reviews of
component failures and the other maintenance rule,
updating the model for initiating event frequencies,
whatever or a period of time. We're just not
anticipating it based on our review of all the data
that we've seen before.
Are you using generic data for that?
Again, the safety related components, there were no
significantly new challenge from the design--
MEMBER POWERS: I want to make sure that
everybody understands. When you say you're using a
generic data you mean you're using an applicable data?
MR. DAIBER: Applicable data --
MEMBER POWERS: Inapplicable data. When
you say the word generic, you're admitting you don't
have data for the existing thing. You're using the
best you have available and unfortunately, that's just
not directly applicable.
CHAIRMAN WALLIS: So there's a lot of
uncertainty associated with that.
MR. FOUTS: Well, we use generic data
because we haven't had any failures on our plants so
that's the best we've got available.
CHAIRMAN WALLIS: Can we move on now?
MR. DAIBER: Sure.
MEMBER POWERS: We may come back to this
in the full committee.
MR. DAIBER: With respect to the system
fault tree considerations, again we reviewed the plant
modifications that were proposed for power uprate
considerations and verified the impacts or lack of
impact upon the system fault tree models. The only
real modification that impacted the system fault tree
models again was the CSAS actuation component. That
CSAS actuation was sent to the main steam and main
feed isolation valves. We did upgrade the system
fault trees to accommodate that modification.
We did review operator actions associated
with the PRA model. We looked at both current
operating conditions and uprated conditions and to
quantify the effect on associated operator actions, we
used a thermal hydroscope CENTS again in this
situation and we ensured that the -- we quantified the
actual change and available operator response times
for a range of sequence of events in the uprated
model. And we did that in a comparison basis both
between current power and uprated conditions. We then
were able to incorporate these new times in to the HRA
models and quantify new HRA times and we did that, we
went back and both quantified it, the CENTS is a new
methodology that was not used originally for the
original quantification for HRA, so we went back and
we requantified the HRA at current power rate of
conditions and to uprate it to make sure we had a good
apples to apples comparison for the effect of HRA.
MEMBER POWERS: And for your human
reliability analysis what were you using?
MR. DAIBER: The methodology?
MEMBER POWERS: Uh-huh.
MR. DAIBER: We used EPRI methods for the
post-proceduralized operator action considerations and
we used a combination of the most conservative of the
cause based and cognizant reliability methods. So we
looked at both of them, EPRI -- both of them based on
EPRI methodologies and we take the conservative of the
two, so we believe that our assumptions with respect
to HRA are very conservative and the implications of
power uprate impacts are somewhat amplified due to
that conservative approach that we take.
So we developed effectively two PRA
models, what we'll refer to as the 2A, the pre-uprate
model and then a 2B model essentially incorporated the
changes in success criteria that we discussed, the
changes in HRA considerations, where it rolled up into
the 2B model. We quantified both of these cases and
then did the comparison to get a change in CDF as a
result of these impacts for power uprate
The change in CDF that we quantified on
this was 2.7 E-6 which is essentially a 16 percent
increase in CDF. This change in CDF falls within
Region II, a small change per the guidance of Reg.
Then for the LERF considerations we
reviewed the current IPE binning criteria that was
established and verified that the power uprate
considerations did not have any change or effect on
those plant damage state considerations, in
particular, those plant damage states related to the
large early relief frequency considerations.
We then rolled in the Level 1 results that
we just discussed on top of those plant damage state
fractions to come up with a change in the large early
release fraction. The delta LERF then was calculated
to be 9.3E-8 which effectively resulted in a 24
increase, 24 percent increase in the large early
release fraction considerations. This now falls
within Region III which is considered the very small
changes with respect to Reg. Guide 1.174 criteria.
CHAIRMAN WALLIS: It's very interesting.
There's nothing about the benefit achieved from these
small changes in risk. It's an interesting way to
regulate. Benefit is not part of the equation.
MR. DAIBER: The additional megawatts
electric, ratio to megawatts electric, yes.
MEMBER POWERS: I'm perplexed.
CHAIRMAN WALLIS: You are what? You are
MEMBER POWERS: I spend my life perplexed.
CHAIRMAN WALLIS: I think from the public
point of view they're getting a benefit and they're
getting an increased risk. All that the Agency
measures is the increased risk and so it's okay.
There's no risk benefit balance. In reality, that's
what's going on.
MEMBER KRESS: If one had did the safety
goals correctly, one would have factored the benefit
CHAIRMAN WALLIS: Yes, you have to do
MEMBER KRESS: So that would have been in
the criteria in the first place.
CHAIRMAN WALLIS: I understand.
MEMBER POWERS: I'm willing to infer that
they did do that.
MEMBER KRESS: They did account for it.
MEMBER POWERS: And they accounted to the
benefit. What we, of course, don't have in these
numbers is any quantification of the impacts of
external events or shutdown risk.
CHAIRMAN WALLIS: Like some of the events
that are coming up later on, I think.
MEMBER POWERS: We won't get any
CHAIRMAN WALLIS: Well, we're going to get
something before 110 or something like that.
MR. DAIBER: There won't be numbers
CHAIRMAN WALLIS: This is well within the
regions and Reg. Guides, it's not near the boundaries?
MEMBER POWERS: I mean if you leave out
half the effects, you get small numbers and everybody
is happy with this myth.
MR. DAIBER: The internal fire analysis,
we also looked at external events, including fire
considerations. We reviewed their frequencies with
respect to fire, the loading considerations and on the
uprated conditions there were no effects on the
combustible loading requirements, hence no change in
the frequencies and the current frequencies used in
the ANO-2 model are very conservative.
MEMBER POWERS: What is your prior IPEEE
MR. DAIBER: We use EPRI 5 methodology for
MEMBER POWERS: And what did you come up
with? There's a number there.
MR. DAIBER: The EPRI 5 methodology is a
MEMBER POWERS: Right.
MR. DAIBER: So it's utilized to screen
zones. We don't do a thorough quantification of the
actual risk associated with fire for using that
methodology. It's used essentially to determine
insights and vulnerabilities and those places where
enhanced operator guidances necessary is implemented
But as far as determining an explicit
value we don't quantify that with respect to--
MEMBER POWERS: Is there a reported value?
MR. DAIBER: We report values based on the
screening criteria, that is correct. For particular
zones, we do calculate values and what we do when we
do the screening though is we look at a particular
zone. We assume everything in the zone is failed as
a result of the fire, conservatively assume that it
fails and see if it still falls below a screening
criteria of 1E-6. If it falls below that, we're done.
If it stays above that we may look at a little more
detail. Or if it still falls within acceptance
criteria at that point with appropriate operator
action, we consider ourselves done with that point
too. We don't necessarily look at it and truly say
okay in this zone, in this particular region, this
fire would only affect these particular components and
only these particular components and look at it from
that perspective. It's more of a graded approach and
to point out vulnerabilities and show that we have
adequate procedures in place to accommodate the risk
associated with fires in certain regions.
MEMBER KRESS: How many zones do you look
MR. DAIBER: I believe we have -- I don't
know the total number that was used with respect to
the unscreened, there were 15 unscreened zones. The
rest of the zones screened out.
MEMBER POWERS: Somehow Dr. Shack reminded
me that somewhere on this documentation I read 9.5 x
MR. DAIBER: Yes, if you add up the values
that we presented, I don't think I have a slide on
CHAIRMAN WALLIS: Are we going to get
MR. DAIBER: Yes, I do have a slide, a
CHAIRMAN WALLIS: It doesn't seem to be on
MR. DAIBER: No, I have a backup slide.
MEMBER KRESS: If you take the 15 and
multiply it 1.5 times --
MR. DAIBER: 134, 135.
MEMBER KRESS: Probably where it came
MEMBER POWERS: My recollection of --
MR. DAIBER: 134, 135.
MEMBER POWERS: Insights document is this
plant has a fire risk reported. It's adequately
characterized in the nature of accurately
characterized the nature of that number. I would be
effusive in my abuse of the reliability of that number
because it's as conservative as he says.
But I mean it does put in perspective the
distinction between the normal operating events and
fire as an initiator and yet we focus all of our
attentions on the normal operating events.
MEMBER KRESS: Yes, the normal operating
was something like CDF of 10-6. The normal operating
events was something like 10-6.
CHAIRMAN WALLIS: Fire is an order of
MEMBER KRESS: Yes, it is an order of
CHAIRMAN WALLIS: Do you have the bottom
MR. DAIBER: I don't have these added up.
CHAIRMAN WALLIS: You get to 1E-4.
MR. DAIBER: Right.
CHAIRMAN WALLIS: Which is above--
MR. DAIBER: That is correct. If you
would add these numbers up, it comes up more than 1E-
CHAIRMAN WALLIS: So it looks as if fire
is really a significant event for these plants.
MR. DAIBER: No, we don't believe that to
be the case at all. We believe that if we truly went
in and applied the same level of rigor to these
numbers as we do to the IPE level of rigor to these
numbers and to these events, we would get that number
much lower. But that's not the methodology we
utilized when we submitted our IPEEE results. The
accepted methodology, the EPRI methodology that we did
utilize did not require that to be done. So if one
truly wanted to come up with a core damage frequency
associated with fire, we would apply much greater
rigor and reviewing what components truly would fail
in a room as a result of the fire, what available
operator actions are available, what backup equipment
is truly available and apply all that additional
recovery considerations to the CDF values.
So what we see here are very, very
MEMBER POWERS: Let's also hasten to point
out that the requirements for the fire equipment do
not approach the requirements they have for the
recovery and mitigation systems in normal operating
events. And so inherently you have something that is
less reliable. You're not, for instance, required to
meet the single failure criterion for fire protection
equipment. So yes, you'd probably get some reduction,
but I don't expect that it's going to be enormous
Then you run into a fundamental problem in
the reliability of equipment, without redundancy, is
limited. It's tough to get 10-6.
CHAIRMAN WALLIS: Do we need to look at
the other accidental events or external events?
MR. DAIBER: The other external events are
CHAIRMAN WALLIS: It seems to be no impact
to other external events.
MR. DAIBER: Right, with respect to other
external events, the power uprate effects are really
considered negligible. There is no real impact as a
result of power uprates associated with all the other
external event considerations.
You want to go back to --
MR. BOYD: I'm trying.
MR. DAIBER: So am I.
MR. DAIBER: Seismic margins--
CHAIRMAN WALLIS: Maybe we won't need to
go through all of this. There's nothing that --
MEMBER POWERS: I mean what you did is one
assurance, the shutdown risk is not evaluated, but
what you know is that operator times are a little bit
shortened here and there, especially in mode 4 and
that it's acceptable.
That's about all I expect out of human
reliability analysis anyway, so it's not such a bad
MEMBER SIEBER: So directly to Slide 111.
CHAIRMAN WALLIS: I'm suggesting we go to
MR. LANE: I think that's my cue. Is
there anything else you want to say relative to --
MR. DAIBER: No. I guess if that's --
real quick with respect to shutdown risks, we do look
at shutdown risks. We look at the safe shutdown
considerations of the plant. We do monitor that
power uprate from the perspective of anything else
that goes on during the outage is really within the
range of what is considered during an outage and the
risk associated that is managed by the plant
procedures and the automated ORAM code for
consideration of all these risks.
That concludes our presentation and with
great pleasure I now turn this over to Rick Lane.
MR. LANE: Thank you, Bryan. I'll go
ahead and make my concluding remarks from here because
I know we're getting close -- into the lunch period
here,so we'll make it short. I would like to thank
the ACRS subcommittee today. I really appreciate the
interaction and also I would like to change the NRC
staff. We've gone through a very thorough review
here. We have worked hard to achieve, as Bryan
mentioned earlier, the actions at this point in time
with the staff and do appreciate the rigorous effort
that this review has taken.
We feel that we have met the key
objectives and goals that I identified in my
introduction and that is first and foremost to safely
uprate this unit by performing the rigorous analysis
and modifications and the appropriate testing to make
sure that we appropriately achieve and safely achieve
the 7.5 percent uprate.
We also, very important to us, is to
maintain adequate operating and design margins. We
believe that the plant and the plant staff are ready
for this uprate and I thank you today for the
interaction and that concludes my remarks.
CHAIRMAN WALLIS: Thank you.
MR. LANE: Thank you.
CHAIRMAN WALLIS: I think that concludes
this morning's session and then we're going to hear
from the staff on all of these matters this afternoon.
After that we have yet another topic to go
into so we have a busy set of activities this
In light of that, I'm wondering if we
could have at least a somewhat shorter lunch break.
Can we meet here at 12:15? Is that acceptable? 1:15,
thank you very much.
MEMBER KRESS: Yes.
CHAIRMAN WALLIS: Can we meet here at
1:15, is that acceptable?
MEMBER KRESS: Yes.
CHAIRMAN WALLIS: We don't need an hour
for lunch, so we will recess until 1:15. Thank you
very much for your presentations.
(Whereupon, at 12:29 a.m., the meeting was
recessed, to reconvene at 1:15 p.m.)
CHAIRMAN WALLIS: We come back into
session. We are now going to hear from the staff on
the application of Arkansas Nuclear One, Unit 2, for
extended power uprate, and I believe that Tad Marsh of
the NRC staff will get us going.
MR. MARSH: I do thank you. Good
afternoon. My name is Tad Marsh, and I am the Deputy
Director of the Division of Licensing Project
Management at NRR.
The staff is here to present to you this
afternoon two extended power uprate reviews. The
first is going to be the seven and a half percent
uprate for Arkansas Unit Two.
Just by background, this is the largest
extended power uprate for a PWR that we have seen to
date. Based on discussions with Westinghouse during
the July 2001 meeting, the staff expects submittals
for extended power uprates for PWRs in the range of
10-20 percent. So this is the first, the beginning.
Following our presentation for Arkansas,
we will present the 20 percent power uprate for the
Clinton plant. The Clinton power uprate is similar to
Duane Arnold, Dresden and Quad Cities which you have
seen as late last year.
Clinton's application deviates from the
ELTR-1 and 2 for the GD-BWR extended power uprates in
four areas. These areas are transient analysis, LOCA
analysis, stability and large transient testing.
We will discuss our review of these first
three deviations with you, and we will also be
discussing some of the background associated with the
large transient testing.
Before we start our presentations, I'd
like to touch on the feedback that we have received
from the ACRS on Duane Arnold, Dresden and Quad Cities
and our response to the ACRS in our letter of February
I'd like to start by emphasizing that our
reviews of extended power uprate, we believe to be
thorough and in depth. I believe that the issues
raised in your letters are related to documentation of
the review, not the review itself and, as we outlined
in our letter, we received somewhat similar responses
regarding documentation from the Office of the
Inspector General on another issue.
In addition, our own self-assessment has
identified documentation weaknesses which we will
address. In order to improve the documentation of our
reviews, we are committed to a broad review of agency
documentation practices. This effort is broader than
NRR, and we are working with other offices.
In addition, at NRR we have included an
issue of documentation in the NRR integrated quality
plan to ensure that this issue receives the proper
attention. We expect our documentation to continue to
improve. I have seen significant improvements
between our draft safety evaluations forwarded to the
ACRS and our final safety evaluation reports. We will
continue to strive for improvements in documentation.
We are attempting to ensure that our
drafts meet the guidance contained in our NRR office
letter LIC 101 and other guidance documents and
management directives and the template safety
evaluations for power uprates.
NRR management is committed to ensuring
that our safety evaluations will continue to improve.
We believe that the ongoing efforts related to
documentation will more fully address the issues
raised in your letters for further applications.
With regard to your recommendation for the
staff to develop a standard review plan for power
uprates, the staff has been tasked by the Commission
to evaluate the merits of developing such an SRP, and
we have committed to complete such an evaluation by
May 1, 2002.
Our evaluation will address -- and this is
described in the letter -- the merits of developing an
SRP section specifically for extended power uprates
for the utilization of SE templates, building on
safety evaluations already that are done, and any key
improvements stemming from the integrated quality
plan. We will keep you informed, of course, in this
A key change to the review in BWRs is
anticipated to occur on the approval of the GE topic
report for CPPU. That's the constant pressure power
I would like to also say that in the arena
briefing that we had with the Commission last week,
there was a lot of discussion about power uprates, and
the SRM coming from the Commission asks us to look at
ways to improve the efficiency and effectiveness of
the power uprate reviews.
We will get back to the Commission on a
plan by June 26th, and there is a Commission meeting
on license renewal and on power uprates on July 10th.
There was a great deal of discussion with the
Commission regarding the need for an SRP, quality of
safety evaluations, the number of plants that we see
coming with their applications for power uprates. So
this is an item of interest not just to the staff but
to the Commission.
Moving on to the Arkansas and Clinton
reviews, I would like to emphasize that we have
conducted thorough reviews of these applications in
all areas potentially affected by the power uprates,
but the focus on the review is being on safety.
We have conducted our reviews consistent
with the existing practices, including the lessons
learned from the Maine Yankee experience. All the
areas that are affected by power uprates have been
reviewed and evaluated.
The staff has critically examined the
methodologies and their application for these power
uprate requests, and we have concluded that all of
analytical codes and methodologies that have been used
for licensing analysis are acceptable for these
Although we reviewed information in many
areas, we intend to focus our presentations today on
areas which we believe to be the most important for
power uprates. We also have NRR staff here to address
any questions which you may like to be discussed.
Now I'd like to turn the presentation over
to Tom Alexion, the NRR Project Manager for Arkansas.
Tom will give an overview of the review process used
for Arkansas application and the order of the
Before I do that, can I answer any
questions you may have? Thank you.
CHAIRMAN WALLIS: Thanks very much.
MR. ALEXION: Good afternoon. My name is
Tom Alexion, and I am the NRC Project Manager assigned
By way of background, the seven and a half
percent power uprate application by entity represents
the largest PWR upgrade to date. The highest PWR
power uprate previously approved by the NRC is five
As you heard this morning, ANO-2 is a CE
designed PWR. The architect/engineer and constructor
were Bechtel. The full power license was issued on
September 1, 1978. The current license maximum
reactor power level is 2815 megawatts thermal, and the
current net maximum dependable capacity is 850
megawatts electric. The ANO-2 has a large dry
Also as you heard this morning, the steam
generators were replaced at ANO-2 in the fall of 2000.
Some differences between the old and the replacement
steam generators are listed on this slide.
The licensee has designed the replacement
steam generators to accommodate the increase in power.
I would also like to note that, when reviewing the
power uprate application, the NRR staff relied upon
analysis previously done at the uprated power level
and supported license amendments that were issued to
support steam generator replacement in the fall of
The NRR staff used the Farley five percent
power uprate as a guide for the scope and depth of its
review. For further review guidance in specific
technical areas, the Standard Review Plan was
MEMBER SCHROCK: Excuse me. Was the
Farley uprate reviewed by the ACRS?
MR. ALEXION: No, because it was a five
MEMBER POWERS: We did, however, have one
of our senior fellows go through the Farley uprate
and provided us a brief assessment for it. Virgil, if
you don't have a copy of that, we should get you one.
MEMBER SCHROCK: Thanks.
MEMBER POWERS: You are aware of that,
MR. BOEHNERT: Yes. No, in fact, I think
he has a copy. I think I sent it to him.
MEMBER SCHROCK: You think I have?
MR. BOEHNERT: Yes.
MEMBER SCHROCK: Probably.
MR. ALEXION: The staff reviewed the
licensee's application of acceptable codes and
methodologies to see that they are used within the
appropriate restrictions and limitations and to ensure
that they are applicable to the power uprate
MEMBER POWERS: Can I bring you back to
the -- Use the Standard Review Plan -- that's a
massive document. It's on CD-ROM. So it's not too
difficult to get around in it.
When you say they used the standard the
Standard Review Plan, that was left to the discretion
of each of the reviewers to pick and choose what they
used out of that?
MR. ALEXION: That's correct.
MEMBER POWERS: Were they -- and of
course, the presentation indicated to us what
particular sections they used?
MR. ALEXION: I believe some of them do.
I'm not for sure if all of them do, but I know, like
for BOP, a very extensive list of SRP sections.
During the course of its review, the staff
also issued many requests for additional information,
and the licensee has responded to all of them. The
staff also audited the licensee's risk evaluation for
power upgrades, performed independent calculations
with the dose assessments for those postulated
accidents that result in increased dose consequences,
and had a contractor perform independent calculations
of the peak containment pressures and temperature
following a postulated LOCA and main steamline break.
The principal areas of review are the NSSS
and accident analysis, evaluations of systems
structures and components, BOP systems, human factors,
radiological analyses, and the risk assessment for
MEMBER POWERS: Will you -- Did you look
at a rod ejection accident?
MR. ALEXION: I think Reactor Systems did,
MEMBER POWERS: And then when you come to
the ability to fuel the sustained -- the powered
input, what do you do there?
MR. ATTARD: I'm Tony Attard from Reactor
Systems. That's one of the Chapter 15 events. So
that's where we -- you know, when we did the review to
make sure that that was done in accordance with the
criteria specified in that section.
MEMBER POWERS: But we knew that the fuel
at modern burnups can't sustain 225 calories per gram
power inputs or even 100 calories per gram power
inputs. What do you do?
MR. ATTARD: Well, I believe those kind of
calories were for particularly high burnup fuel. So
we made sure or see that they still meet the 280, you
know, for new fuel like they specify.
MEMBER POWERS: Okay. So you essentially
go in and say did the rod ejection accident produce
280 calories per gram. Answer is no. Therefore,
everything is okay.
MR. ATTARD: Well, if they meet the
criterion and they used approved methodologies, we
MEMBER POWERS: I understand.
MR. ALEXION: The order of presentation is
as shown. The only open items in the draft safety
evaluation were the radiological assessment area. All
of the open items have since been closed, and the
closure of these items will be discussed in the
radiological assessment presentation.
CHAIRMAN WALLIS: How many of these
reviews contained confirmatory analyses by the staff
-- by any staff?
MR. ALEXION: I think we just had the ones
CHAIRMAN WALLIS: You did something on the
containment, I understand, didn't you?
MR. ALEXION: Yes, we had somebody --
Pressures and temperatures, we had those consequences.
You said independent calculations was your question?
I believe those were the two. Staff can correct me if
MR. RICHARDS: Why don't we just ask the
presenters to make sure they touch on that, if they
did do some of those.
MR. ALEXION: As was previous discussed,
the NRR staff has no open items. That concludes my
opening remarks. With that, we'll go to the Reactor
MR. LIANG: My name is Chu Liang. I'm a
Reactor Systems Branch reviewer to review this ANO
Unit 2 power uprate. There are a few other staff of
the branch also participated in this review in
specific areas. Next slide.
This slide identified the major review
areas that we performed in Reactor Systems Branch.
The first is the reactor cooling systems, ECCS and
shutdown cooling systems. These safety reactor
systems are reviewed and verified that there are no
system modifications required to perform their design
safety function under power operated conditions.
The second item, we reviewed the fuel
performance. We verified that all fuel design
requirements and limits are met under power operated
conditions -- operating conditions.
We also reviewed --
CHAIRMAN WALLIS: You say you verified.
You mean you had a statement from the licensee that
they had made these calculations?
MR. LIANG: The licensee provided some
analysis per our request, and verified a few things,
that there were a few the review has some concern, and
we review them, and we confirm that all the design
requirements are met.
CHAIRMAN WALLIS: And you are convinced
that they have done them correctly, because of, what,
a history of doing them using approved methods, or
what? How do you assure yourself that these
calculations are okay?
MR. ASTELUWICZ: This is Frank Asteluwicz,
the Reactor Systems Section Chief. The answer to your
question is some yes and some no. We do rely on the
fact that the methods have been approved in the past,
and we did look at the limitations imposed on those
methods as part of our review, and confirmed that, in
fact, the licensee satisfied whatever limitations were
imposed on the application of those particular codes.
In most cases, we did not do an
independent analysis that stuck numbers into the codes
to confirm that the numbers calculated are, in fact,
the numbers that the licensee generated. That's part
of the way we do our analysis these days.
We rely heavily on the fact that the codes
have been examined carefully or the processes are
determined carefully, and then rely on the licensees
to -- Basically, we audit the calculations and rely on
the licensees to do them correctly.
MEMBER KRESS: Consider, for example, the
ECCS code for Appendix K. Do you go back and review
the validation basis for that to see if it --
including the kind of power profiles that you get with
the upgrade or were they done with a different power
MR. ASTELUWICZ: The only thing I could
answer -- The only way I could answer that question is
that, if there were no limitations put on the use of
that particular application at the time the staff
looked at it, we would not generally go back to look
at that. If we had some knowledge that there may be
some issue in dispute, then we would go back and look
to make sure that the range of applicability still
occurred, but absent some unique knowledge, we would
not do that.
CHAIRMAN WALLIS: So it sounds as if you
are not raising new questions. You are going back to
see that the old questions were suitably answered in
sort of the historical record, but you don't come up
with new questions to ask.
MR. ASTELUWICZ: Well, no, we do ask new
questions. I'm not sure how to answer that question.
We don't go back and challenge the foundation of the
codes once they were approved, and I'm not sure that
that's the question that you are asking. I mean, if
you are asking are --
CHAIRMAN WALLIS: If somebody put
limitations on the codes, it's not clear that they
anticipated the kind of use that they are being put to
today when they put those limitations on. That's the
thing I'm concerned about.
MR. ASTELUWICZ: I understand. We do
question whether or not the codes are applicable in
the range that they are being used, but we don't go
back and resurrect the data and confirm for ourselves
that that's true. I mean, we do ask questions about
MR. MARSH: Mr. Chairman, just with
respect to the confirmatory analyses, the questions
that you have been asking about that, whatever you
would prefer doing in terms of answering that
question, we can come back to the full committee at
the full committee time and give you a complete and
thorough list; because not all of the staff's reviews
are here today, if you would like to have that type of
In terms of confirmation of codes, in the
Duane Arnold, Dresden, Quad Cities reviews in terms of
the transient testing, recall that G.E. had said to
us, and we had agreed with that, that the performance
of the plant on which they were basing their transient
testing hypothesis behaved very well with respect to
the modeling. So there was a confirmation using
empirical data of the models that were used for that
plant compared to how it actually behaved.
So there is some confirmation. I'm ont
sure here with respect to the transients of the
reactor coolant system or ECCS, but there is some at
least in that context.
MR. LIANG: We reviewed steam supply
system design transients. The licensee redefined
them, and as modified slightly. Those design
transients are used for design of the steam supply
system to assure the system design as designed, were
not -- during operation were not exceeding its stress
limit, and other limitations, and we verify to assure
that number of occurrences of any given transient
selected for design purpose were exceeding the
expected number over lifetime of the plant, and was a
slightly change in the loss of feedwater transient.
Change increased the number due to past experience,
and changed the hydrotest requirement to less frequent
due to ASME code changes.
We reviewed the LOCA and the Non-LOCA
accident analyses to see there are some change in the
code used, and the results of analysis meeting
acceptance criteria. Next slide, please.
MR. LIANG: The Reactor Systems Branch
review process: The first bullet is reviewed
application to current licensing basis. We were just
review the effect of the increased power to the
Next we verify plant modifications meeting
SRP acceptance criteria.
Many transients and accidents previously
reviewed at the uprated power levels in previous
Amendment submitted for steam generator replacement we
already reviewed and accepted during that review.
The transient and accident analyses
submitted in this submittal we reviewed against assure
approved codes and the methodologies are used and the
methodology codes are applicable to ANO Unit 2 to
support power uprate. And we verified the results to
assure the acceptance criteria for each event
specified in the SRP are met. Next slide.
MR. LIANG: Reactor System Branch review
results for transient and accident analyses are
meeting the acceptance criteria for each event
specified in the SRP.
All transient and accident analyses were
analyzed using staff approved codes and methodologies
with all limitations and restrictions specified for
each code applicable conformed and is applicable to
ANO power uprate application.
All transient and accident analyses inputs
are conservative and consistent with tech specs limit.
MEMBER POWERS: In the presentation made
by the applicant for one of his LOCA analyses, he
indicated that a code error had been found. Could you
tell us what that code error was?
MR. LIANG: Somebody help.
MR. ASTELUWICZ: We don't have that
available to us right now. If you want to, we'll get
back to you on that.
MR. LIANG: We also concluded the fuel
design meets all design requirements and limits. That
concludes our presentation.
MEMBER POWERS: Have the design
requirement limits on fuel with Erbium poison in place
of GadolinIum poisons been examined? Has there been
MR. WU: This is Shu Lang Wu. Yes, we
approved gadolinium and Erbium fuel for combustion
MR. POWER: So you've examined the
peculiarities there. Now could you tell me how
replacing gadolinium with Erbium changes the oxygen
potential of the fuel?
MR. WU: Oxygen?
MEMBER POWERS: Oxygen potential of the
MR. WU: I don't know about the answer.
MEMBER POWERS: It must change it, putting
in basically a trivalent element in place of a
tetravalent element. So you have to induce some
vacancies. It must change it.
MR. WU: You're talking about the number
of rod or what? I don't --
MEMBER POWERS: No. I'm talking about the
oxygen potential in the fuel itself. Propensity to
oxidize the inside of the clad is what I'm most
MR. WU: Well, I'm sorry. I don't work
CHAIRMAN WALLIS: There's no acceptance
criterion for this?
MEMBER POWERS: I think there is not. I
mean, there may be -- It may come in a round and about
fashion because of total oxidation that you have to
worry about, but it's a round-about.
CHAIRMAN WALLIS: So they are from the
outside in, not inside out.
MEMBER KRESS: Yes, but it has to do with
the failure of the clad.
MEMBER POWERS: You worry about the
failure of clad. You also probably worry a little bit
about the gap inventory changing as a result of it.
I myself don't have any preconceived notions on this
MR. WU: Yes. We will get back to you.
CHAIRMAN WALLIS: Well, this is a summary
slide that says everything is fine. Were there any
particular transient analyses that you had to go back
and carefully examine or anything in particular that
caught your eye as requiring extra work on your part
to check over or anything like that?
MR. LIANG: Yes. We asked a lot of
questions, and the utility answered them, and we
reviewed the assumptions, the input data to the
transient and accident analysis of interest, and we
also asked the code and the computed code and the
methodology applicability to the ANO application, and
we questioned these assumptions and got back the
response to questions. We reviewed them, and we find
that we satisfied some of them.
We asked questions, we have problem,
because deviate from SRP a little bit, but we
confirmed that those assumptions are consistent with
the current licensing basis. So we accepted them
based on the current licensing basis be honored, and
finally we conclude all the analysis meeting
acceptance criteria and the analyses were
MEMBER KRESS: What code was used for the
Appendix K LOCA analyses?
MR. ASTELUWICZ: I'm not sure. Your
specific question is it was an approved topical. The
number was on the licensee slide, CEN-199, whatever
that number was. I don't recall off the top of my
MEMBER KRESS: No. What computer code did
the licensee use to calculate the figures of merit for
the Appendix K LOCA analyses? They used some sort of
MR. ASTELUWICZ: Yes. I'm not sure. I
think Westinghouse, they used BASH and BART. Is that
what you are asking? I'm not sure I understand the
MEMBER KRESS: Yes, that's what I want to
know, the name of the code. I'd also be interested to
know when it was reviewed and approved by the staff.
MR. LIANG: Yes. All the code -- In
response to staff's request, the licensee provided a
big submittal of this proprietary information and
identified each event, what code and methodology was
applied, and the staff review SER, identified the
restrictions and limitations and how they conformed
MEMBER KRESS: When were these
restrictions and limitations placed on the use of the
MR. LIANG: This part is proprietary, and
will be made available.
MEMBER KRESS: The when wouldn't be
MR. LIANG: Yeah, yeah. The code, when
approved, those limitations specified in staff's SER,
MEMBER KRESS: Which was when?
MR. ALEXION: Each one has a different
MR. LIANG: Yeah, each one have different
date. Start from 1975 and until recent, and different
because we involve about 30 codes.
MEMBER KRESS: But these codes were
vintage of like '75, that time frame?
MR. LIANG: Seventy-five to recent, and
the LOCA codes about 14 of them, and the non-LOCA
transients using another 15.
MEMBER KRESS: They used 14 different
MR. LIANG: Involved, you know, in this --
to support this application. In total, it's about --
a lot involved to support this power uprate.
CHAIRMAN WALLIS: Well, now I asked you
about -- This is a very summary slide. So it doesn't
give a story of something you worried about, and then
you told me that when you did have concerns, you went
back and had these RAIs and around and around and
around and around.
MR. LIANG: Yeah, yeah. We tried to --
CHAIRMAN WALLIS: Is there some example
you can give me of some concern you had that maybe you
didn't bring it, but it would help a lot if we could
sort of see your modus operandi. So if you could sort
of convince us that the way that you went about things
was thorough, then you got -- It would be nice if you
had an example of thoroughness which we could look at
and say, gee whiz, those guys were really thorough.
Is there some example you can give us like that?
MR. LIANG: Examples, like --
CHAIRMAN WALLIS: Some example of where
you had to be thorough.
MR. LIANG: We've taken a look at their
assumptions, and --
MR. ASTELUWICZ: Chu, let me interrupt.
Let me try. This is Frank Asteluwicz again.
A specific example: One of the areas that
we looked at carefully was the issue of long term
cooling, the boron precipitation question, because we
had concerns in that area.
Another area that we looked at were some
of the control rod withdrawal events where in the
course of a review at a sister plant, we uncovered the
case where a potential tech spec was being violated,
and we proceeded to probe that area on Arkansas and
have them reassess it, and they are in the process of
changing their tech specs to account for that
Can I give you anymore specifics?
Probably not off the top of my head.
CHAIRMAN WALLIS: That's the sort of
thing, I think, would help, because otherwise it's
just so general.
MR. ASTELUWICZ: I understand.
CHAIRMAN WALLIS: And if we are trying to
evaluate -- I don't want to use the word credibility,
but something like that. I mean, I'd like to sort of
get the good feeling that you've done a thorough job.
How do I get that? I have to sort of see examples of
a thorough job, which means digging in in some depth
on some issue which is of concern.
MR. ASTELUWICZ: Right.
CHAIRMAN WALLIS: I don't know how we can
MR. ASTELUWICZ: There will be other
examples forthcoming in some of the other areas. The
other -- I forgot which one I wanted to bring up, but
-- I forgot. I'm sorry. But we did -- ATWS is
another area we had a lot of questions, and you heard
the discussions early this morning about how they have
the DSS, and that was sufficient to meet the rule. We
asked them, you know, to go back and make sure that
the design of that particular facility -- or the
design of that system would meet the intent of its
function for ATWS.
CHAIRMAN WALLIS: This is the ATWS?
MR. ASTELUWICZ: Yes.
CHAIRMAN WALLIS: So to me, this is an
unusual way of satisfying at ATWS criterion. Is this
an unusual way of doing it?
MR. ASTELUWICZ: The rule in this area is
pretty specific. When the staff went back to
rulemaking, the two specific reactor vendor types, the
CE design and the B&W design, were viewed to have such
a high frequency for ATWS events that the Commission
felt it was appropriate to impose a modification at
The Westinghouse units do not have that.
So the variation between the Westinghouse designs and
the B&W and CE designs are a little bit different, and
we asked a different set of questions for Westinghouse
units than we do for the B&W and CE types.
MR. BOEHNERT: Well, Westinghouse also had
additional relieving capacity. So it had lower
MR. ASTELUWICZ: That's correct. It was
a combination of everything.
MR. ALEXION: Go ahead.
CHAIRMAN WALLIS: So there's going to be
-- What we are going to hear later on is going to come
a little closer to what I was asking for with my last
MR. MARSH: Mr. Chairman, we produced some
details we can give you in the containment analysis as
well to demonstrate some in depth types of analyses,
but I also want to point out that this review was done
in concert with the steam generator replacement
review, too. So there's thoroughness that went on in
that review, which you are probably not hearing right
now as well.
CHAIRMAN WALLIS: I guess we didn't have
the benefit of that here?
MR. MARSH: That's right. I think many
of the analyses that were done associated with the
power uprate were done in the context of the steam
generator replacement. Okay, Tom, want to move on?
MR. ALEXION: Let's move on to the Plant
Systems Branch review.
MR. CULLISON: Good afternoon. I am Dave
Cullison from the Plant Systems Branch. With me is
Rich O'Dell sitting over there. He performed the
reviews -- the containment reviews for the steam
generator replacement, and he can answer any of the
questions about those reviews.
MR. CULLISON: I'll start off with the
next two slides are the list of the SRP sections I
used as guidance for conducting my review.
MEMBER POWERS: Let me just ask, when
should we ask about the steam generator reviews?
MR. CULLISON: I'll get to those a little
MEMBER POWERS: Okay.
MR. CULLISON: I also used the Farley
safety evaluation as a guide in performing my reviews.
MR. CULLISON: Based on the review,
essentially we found no significant impact on any of
the these systems. We -- In other words, we didn't
find anything that was unacceptable.
The areas I have marked with an asterisk
are the ones that were reviewed for the steam
generator replacement, and Rich can speak to those in
MR. ALEXION: Two slides over?
MR. CULLISON: Yes, two slides over.
CHAIRMAN WALLIS: Are you going to say
anything more about spent fuel pool coolant?
MR. CULLISON: Yes, I am.
CHAIRMAN WALLIS: All right.
MR. CULLISON: I had three areas which I
focused on, basically because there wasn't -- I
didn't think there was sufficient information in the
submittal to draw a conclusion. So I asked questions
of the licensee to provide that information.
Those were the fuel pool system, service
water system and the emergency feedwater system. On
the fuel pool system, they are a little bit different
than probably most plants. They don't do a bounding
calculation. They do a cyclic calculation, but their
backup system is boiling, boiling from fill.
So we had discussions to make sure that
they had -- We, really using administrative controls,
we obtained their licensee basis of keeping the pool
below 150 degrees, regardless of the heat load from
CHAIRMAN WALLIS: It depends on the
temperature of the water they are putting in, doesn't
MR. CULLISON: Right. They do a
combination of monitoring the reservoir water
temperature and the decay time on the spent fuel, and
they developed a graph so they could go to it,
depending -- based on one pump, two pump.
CHAIRMAN WALLIS: So if the reservoir gets
too warm, they just increase the flow rate. Is that
what they do?
MR. CULLISON: Well, they can do that, and
they also can let the fuel decay a little bit longer,
do a calculation.
CHAIRMAN WALLIS: It may overheat while
you're waiting for it to decay.
MR. CULLISON: Well, no, this is before
they remove it for --
CHAIRMAN WALLIS: Oh, before it goes in?
MR. CULLISON: Before it goes into the
CHAIRMAN WALLIS: Where is it then? It's
in the reactor?
MR. CULLISON: It's in the reactor.
CHAIRMAN WALLIS: It's still decaying?
Oh, you shut the reactor down --
MR. CULLISON: This is after they shut
down, before they --
MEMBER SIEBER: Three days maybe.
MEMBER POWERS: I mean, in the past there
have been some fairly heroic times. The thrust
nowadays is to continuously shorten that time. I
mean, it is the great fallacy that Mode 4 is such a
low risk event. It's becoming higher risk all the
MR. CULLISON: The licensee's -- what they
told me is that what they try to do is match the
additional heat load from the spent fuel with the
capacity of the cooling system. So they never really
increase the temperature of the pool. I found that to
On the service water system, I verified
that the safety related service water system had the
capacity to meet any heat loads -- any increased heat
loads from the power uprate.
MR. CULLISON: On the emergency feedwater,
at the time I was doing my review there was a
nonrelated license amendment to change the way they
calculated the necessary amount of water in the
condensate storage tanks. The idea was to go to a 30-
minute supply, which would give them time to bring
service water online to provide water to the emergency
That part of that amendment request was
eventually withdrawn, and I had to go with the
question to verify that they had adequate amount of
water in the CSTs to meet the demands for the power
uprate. They came back with the answer, and it was
That's what I have. I have back-up slides
on the continuing response analyses, and if you would
like to see those or any --
MEMBER POWERS: Any areas that you listed
but didn't go into are interestingly labeled control
MR. CULLISON: That's a little -- I hadn't
seen that before.
MEMBER POWERS: That's okay.
MR. CULLISON: But what that is is the --
if they have to evacuate the control room in the case
of any event other than an Appendix R, that they have
the ability to safely shut down the reactor. Based on
my review of the information they provided, it's
MEMBER POWERS: Okay. So this does not
have to do with the dosage in the control room?
MR. CULLISON: No, it's different.
CHAIRMAN WALLIS: Are you going to talk
about containment or is someone else going to talk
MR. CULLISON: Rich O'Dell. I've got
back-up slides. At the time I developed this
presentation, I didn't know how much interest there
would have been in the --
MEMBER SIEBER: I wouldn't mind having you
go through that portion that you have as back-up.
MR. CULLISON: Okay, I'll go through the
slides, and Rich can answer any of the questions.
CHAIRMAN WALLIS: I think all you have in
detail that illustrates thoroughness, the better off
we'll all be.
MR. CULLISON: Okay.
CHAIRMAN WALLIS: As long as it doesn't
take forever. I guess if it takes forever, we'll
MR. CULLISON: One of the issues for the
steam generator replacement was containment cooling.
The licensee brought that up this morning. Based on
their evaluations, they had to do equipment
modification to the fan blades -- this is for the
safety related portion of the system -- and --
CHAIRMAN WALLIS: Do you understand that
business of the fan blades?
MR. CULLISON: They had to change the
CHAIRMAN WALLIS: Yes, but it did
something odd, and I couldn't quite understand it. It
changed the flow rate, and it changed the
temperatures. I couldn't follow that.
MR. CULLISON: The changed capacity of
each cooler minimized the capacity of each cooler.
CHAIRMAN WALLIS: It reduced the flow
MR. CULLISON: Reduced the flow rate.
CHAIRMAN WALLIS: Why would you reduce the
flow rate if you want more cooling?
MEMBER SIEBER: Well, the issue is you
burn out the motor on the fan.
CHAIRMAN WALLIS: Yes, that's right. So
you protect the motor on the fan. So it's a
restriction. So it reduces your ability to cool.
MR. CULLISON: Right. But to have enough
capacity, they changed the tech spec to have both
trains operable. They used to have -- required to
have one train operable. Now they have both trains
CHAIRMAN WALLIS: So now both trains are
operable. Then does this involve also their analysis
of mixing in the containment or they assume it's well
MR. CULLISON: I think it's well mixed.
Go ahead, Rich.
MR. O'DELL: No. Containment mixing
doesn't figure into this analysis. It's just heat
CHAIRMAN WALLIS: But it goes back to the
one node containment mode?
MR. O'DELL: It's a one node containment
CHAIRMAN WALLIS: Are you satisfied with
the one node containment model?
MR. O'DELL: The one node containment
CHAIRMAN WALLIS: Enough for this purpose?
MR. O'DELL: This is Richard O'Dell from
Plant Systems Branch. The one node containment model
is the standard model that most licensees use.
CHAIRMAN WALLIS: -- the paperwork.
MR. O'DELL: And the feeling is --
CHAIRMAN WALLIS: So they were concerned
about mixing because of the spray for the thing, the
spray in the unsprayed region. That's why you get
involved with a more than one node idea.
MR. RICHARDS: Tom, correct me if I'm
wrong, but I think that's addressed by a different
tech branch later on in the presentation.
MR. ALEXION: Yes, that's in the dose
CHAIRMAN WALLIS: So at least there, there
are about two different regions in the containment.
MR. RICHARDS: WE have a discussion about
that coming up. It's just a little later in the
CHAIRMAN WALLIS: So if there's a concern
about containment cooling, then it might be worthwhile
to revisit the assumption of adequate mixing in the
containment. That's something I might do if I were a
MR. O'DELL: The conventional wisdom is
that a one node model is actually conservative, that
if you have a one node model, you are mixing the steam
with the air, and it reduces the heat transfer over
the case where you've had stratification and you would
have the steam at the top condensing rapidly, and the
air forced down to the bottom.
So you have a part of the containment that
has very good heat transfer and part that doesn't. As
you know from another briefing, two licensees are
planning to come in any day now with a map containment
model that's a multi-node model, and the staff will
have a chance to review that.
CHAIRMAN WALLIS: Are they going to come
in with that before we get to approve the model
itself? We had some questions about the model itself.
We're getting a bit away from this, but I would hope
that we get to thoroughly look at the basis for the
model itself before these licensees come in and ask us
to accept the use of it.
MR. O'DELL: Well, it's pretty much at the
same time, but yes, that will definitely be part of
CHAIRMAN WALLIS: It's another one of
these express trains we are standing in front of.
MR. O'DELL: We got a year, and then the
train is at our intersection.
MEMBER SIEBER: I'd like to go back to the
question of the fan coolers. What steps did you take
after they decided they needed to change the blade
pitch to assure that the motors would not burn out or
fail during a DBA with full containment pressure?
MR. O'DELL: Is that an environmental
containment issue? Is that an environmental
qualification question you are asking?
MEMBER SIEBER: No. It isn't. It's a
load question. You've got a very dense atmosphere in
containment when you've got 60 pounds of pressure in
there, and the motors have to drive the fans. They
continue to run through the action. Is that not
MR. O'DELL: I don't think -- Tom, correct
me if I'm wrong. I don't think we looked at that.
There are things like that when a licensee comes in
and says that they are making a change, an engineering
change like that, and it appears to us, just from
making the change, that they've thought through what
needed to be done. That area wasn't looked at. The
assumption is the licensee's engineering people can
MEMBER SIEBER: Know how to engineer it.
Right. On the other hand, those fans do provide a
function during an accident. Right? And are a part
of the protection of containment to assure that
containment will, in fact, function. Is that not
MR. O'DELL: Yes, they are. They are, and
your question is a legitimate question. It just
wasn't addressed in this review. There's always more
questions you can ask and, like I say, your question
is legitimate. It's certainly a question we could
have, maybe should have, asked. But we didn't.
MR. MARSH: This is Tad Marsh on the
staff. Plant changes of that sort are conducted
through a 5059 process which, as you know, has you do
evaluations, and then they are audited by the staff as
part of the inspection process or as part of the
normal follow-up review.
It sounds like this type of change was not
part of the licensing process. This was another type
of evaluation that they had done.
MEMBER SIEBER: Yes. On the other hand,
it's a modification that you are making to accommodate
a power uprate. So it's a -- To my mind, it's a
condition that the power upgrade caused in the plant,
and I'm curious as to whether you looked at it.
In an earlier life, I paid to have motors
rewound. So there's reason for me to ask this
MR. O'DELL: This may be a good time to
answer a previous question about specific areas that
were looked at in the review that we spent some time
on, and the fan coolers was an area where we had
several telephone calls with the licensee and got some
significant clarification from what was in the first
The licensee wasn't hiding anything. They
made a statement in the original submittal that --
along the lines that they had done some analysis with
the GOTHIC code concerning possible boiling in the
service water, and we spent a lot of time with that
and asking for the details of how the calculation was
done, and they provided a lot of information that
satisfied us that the boiling was a condition that was
temporary and would only be a problem at a pressure
below the pressure -- the normal pressure of the
service water system.
I also asked a couple of times about the
technical specification requiring all four fan cooler
units, because we had just -- I had just gotten done
a little while before with an emergency tech spec
amendment for another Entergy plant where they had a
tech spec that required all four fan coolers to be
operable, and one of them wasn't operable anymore, and
it put them in a bad situation.
I questioned whether they really wanted to
put themselves in the same situation. But at the
time, there wasn't anything in the near term that
could be done. So we approved the amendment as it
So that's an example, for what it's worth,
of an area where there was discussion and a lot more
information was asked for, and clarification, and
results of analyses.
CHAIRMAN WALLIS: If you get boiling in a
fan cooler, what happens? Does it come out into the
piping? Do the voids come out into the piping or they
stay in the fan cooler?
MR. O'DELL; It just limits the cooling.
CHAIRMAN WALLIS: Just a very local thing?
MR. O'DELL: Yes.
MR. MARSH: This was looked at in the
context of Generic Letter -- help me. I believe it
was 96-06 where we looked at the transient performance
of fan coolers because of momentary heating because of
temporary loss of flow. Licensees had to evaluate the
performance of piping systems with the re-initiation
of service water to ensure there wasn't any water
hammer and loss of function of the fan coolers.
CHAIRMAN WALLIS: Been that route, too.
Yes. But it's not the same thing. It's not the same
problem, is it?
MR. MARSH: Well, if there's boiling in
the coils of the fan cooler.
CHAIRMAN WALLIS: Unless the voids are
transferred to the service water mains, it doesn't
matter, does it?
MR. O'DELL: It just limits the heat
transfer that you are expecting from the engineered
CHAIRMAN WALLIS: Okay.
MR. MARSH: Okay.
MR. ALEXION: Want the next slide?
MR. CULLISON: Yes, go ahead with the next
CHAIRMAN WALLIS: What is the ultimate
heat sink for this?
MR. CULLISON: It's an emergency cooling
pond which is a large pond that -- They actually have
two. They have their reservoir and the pond, and the
true ultimate heat sink is the pond, just in case the
reservoir goes away.
In containment response analysis, this is
an area where the staff did --
CHAIRMAN WALLIS: You're off this slide.
There's a new one?
MR. CULLISON: Right. This is the one I'm
on. And the containment response analysis -- this is
also done as part of the steam generator replacement,
and this is an example where a confirmatory
calculation was performed.
CHAIRMAN WALLIS: Using a different code?
MR. O'DELL; We asked Los Alamos to do a
calculation for us. They were comfortable with the
MELCOR code. So they used the MELCOR code to do the
analysis as a design basis analysis. It didn't
include all the fission product and other types of
models that MELCOR can handle and melting of fuel and
that kind of thing. It was just a design basis
analysis of the containment. But they used the MELCOR
They looked at LOCA in a main steamline
break, and it wasn't -- It wasn't a great example of
a confirmatory analysis. There were problems. The
contractor had an error it took a while to recognize
and fix, and the licensee identified some changes they
wanted to make to the input after a lot of our
analysis is done. But the contractor did a lot of
sensitivity studies, looking for what things were most
important, and went back and adjusted the input and
redid some of the calculations.
CHAIRMAN WALLIS: What numbers did they
come up with?
MR. O'DELL: I believe the pressures were
within a psi or so of each other.
CHAIRMAN WALLIS: A 57.6 or whatever?
MR. O'DELL: It was like 55 and 57, that
kind of number.
CHAIRMAN WALLIS: That's after they
adjusted some things?
MR. O'DELL: But I would rather not put
too much stress on the final answers, because it
wasn't that pretty of an analysis.
CHAIRMAN WALLIS: It is reassuring that at
least some time in their confirmatory calculation is
MR. O'DELL: In the case of the steamline
break, there was a very large difference between the
licensee and the contractor's calculations, and we
talked with the licensee, and the licensee identified
to us that they used a very conservative value for the
efficiency of the containment spray.
We went back and did a sensitivity study
based on that, and got answers that were very close to
the licensee's values. The licensee was much more
conservative than the contractor's calculation.
CHAIRMAN WALLIS: These sorts of things
are helpful to me, these kinds of details. Thank you.
MR. MARSH: Mr. Chairman, we were unaware
that you wanted that level of detail for this
CHAIRMAN WALLIS: We ask for whatever
level of detail we think is appropriate.
MR. MARSH: We thought we were to give an
CHAIRMAN WALLIS: Yes, but that's been the
problem all along, I think. If you read between the
lines of our letters, we say, yes, the overview looks
fine, but the real work is in the detail. So where's
our assurance that the real work was good? That's the
question we've been asking all along in these reviews.
MR. MARSH: Right. For today's
presentation we were asked to come for an hour and a
half to give you an overview.
CHAIRMAN WALLIS: I know.
MR. MARSH: Okay? And that's sort of
where we are.
CHAIRMAN WALLIS: We don't have enough
MR. MARSH: Right.
CHAIRMAN WALLIS: But I think you
understand why we are going to dig deeper.
MR. MARSH: And we would have come
CHAIRMAN WALLIS: That's okay. I mean,
you're not prepared. Sometimes that's better.
MR. MARSH: Depends on your viewpoint.
MEMBER POWERS: I would just comment here
that, as we progress through this, when we want a
little more detail, that may want to color what we do
in a final presentation on some of this stuff.
Sometimes the oral expression is enough.
MR. O'DELL: Could I just add that the
calculations, the Los Alamos calculations, are in
Adams. So they are available to the public, and --
MEMBER SIEBER: Well.
MR. O'DELL: Well, we all know where that
stands. But they are available to the public, and the
accession numbers referenced in the SER.
MEMBER POWERS: I'll just remind people
that Los Alamos is north of Sandia.
MEMBER SIEBER: Well, getting back to this
question, I think it's important that in some areas
you give us some detail, as Dr. Wallis has said, so
that we have a feeling as to what depth you went to to
confirm the licensee's application; because otherwise
it's -- you know, the acceptance criteria were met,
and page after page after page of that, which doesn't
So that's why I asked for this. I think
we can go on and finish this up here.
MR. ALEXION: Okay. We'll go on to the
next presenter then. The next presentation will be
Mechanical Engineering Branch.
CHAIRMAN WALLIS: I think that's
important. We know that you are going to say the
acceptance criteria were all met, and we want to know
what's behind it. That's the real question.
MEMBER POWERS: You know, they wouldn't
even be here if the acceptance hadn't been met.
CHAIRMAN WALLIS: That's right. So we
know that. That's a given.
MR. MANOLY: Good afternoon. My name is
Kamal Manoly. I'm the Section Chief in the Mechanical
Engineering Branch where the bulk of the review was
MR. MANOLY: Just up front, I would like
to let you know that the review in the mechanical area
is pretty much the same in the -- for the pressurized
as was in the boiler.
Just some components changed, like the
steam generator and the moisture separators in the
boilers, but the piping and the balance of plant
piping essentially all the same. We look at fatigue
usage in terms of compliance with ASME code they
So essentially, we're doing the same
review we've done before. The components that we
looked at are the reactor vessel, internals, nozzles
CRDMs, the same. The steam generator is the only
measured difference here, and the reactor coolant
pumps, pressurizer and nozzles, and the NSSS and BOP
piping the same, and the safety related valves. That's
MR. MANOLY: Scope of review, still the
same. We look at the methodology and the loads
specified, stresses in the piping and components, and
the usage factors for thermal fatigue, and also look
at the acceptance criteria and the codes they
committed to, and functionality of the valves,
specifically in regard to Generic Letters 89-10 for
MOVs and 95-07 for the pressure locking and thermal
binding, and 96-06 for pressurization of isolated
MEMBER POWERS: When you looked at
fatigue, you were looking at cyclic mechanical
MR. MANOLY: When I say COF is thermal
MEMBER POWERS: Thermal fatigue? Okay.
MR. MANOLY: The cyclic for the flow
induced, that's for the steam generator, and that's
the next slide.
MEMBER POWERS: When you just mentioned
that the scope was similar to the BWR, somehow --
MR. MANOLY: Yes, except for the steam
generator. That's all.
MEMBER POWERS: Well, obviously, the steam
generator. There seemed to be more concern about flow
induced vibration here and, in fact, I mean, the
licensee made the comment that --
MR. MANOLY: Yes.
MEMBER POWERS: Is there more concern with
flow induced vibration in these systems for some
MR. MANOLY: You are on the last slide.
MR. MANOLY: Okay, for the steam generator
replacement, we looked at the finite element analysis
done by the licensee. The used the ANSYS code which
is one of the two mostly used codes in the country.
We looked at the CUF for fatigue and also
for the allowables on the components and supports.
The flow induced vibration for the steam generator,
they maintained a stability ratio of .75, less than
the limit of 1.0. So that was the limit imposed by
the licensee on their tubes.
MEMBER POWERS: Now is this, again, a
piping analysis or is this a more full blown detailed
MR. MANOLY: The steam generator
replacement, that is a piping -- components, just
typical piping analysis, you know.
MEMBER POWERS: Even though they are using
MR. MANOLY: ANSYS, yes. The next one is
pretty much identical to the boiler, NSSS and BOP
piping. They used Bechtel ME101 which is used
industrywide, and again you compare the limits -- the
stresses to the limits in the ASME code, depending on
the class of piping being evaluated.
They also calculated the CUFs for the
Class 1 piping based on 60 years.
MR. MANOLY: And the last slide that you
were interested in was about the flow induced
vibration in the main steam piping. The main steam
piping was the most sensitive system to the flow
induced vibration issue.
There's a study done by SWRI that the
kinetic energy is basically driving force behind the
flow induced vibration.
CHAIRMAN WALLIS: Doesn't seem
dimensionally correct somehow.
MR. MANOLY: Excuse me? I didn't get the
MEMBER POWERS: Take a derivative.
CHAIRMAN WALLIS: I think you mean a
momentum flux or something like that.
MR. MANOLY: No. The kinetic energy --
CHAIRMAN WALLIS: No, I think you mean a
MR. MANOLY: As presented by the rho V2?
CHAIRMAN WALLIS: Yes, something.
MR. MANOLY: Okay. That's what's
CHAIRMAN WALLIS: I think you mean a
momentum flux. That's okay.
MR. MANOLY: It's flow induced vibration.
CHAIRMAN WALLIS: These always -- This
always bothers me a bit, this assumption that all
forces are proportionate to the rho V2; therefore,
flow induced vibration is; because flow induced
vibration is a kind of coupling between mechanical and
fluid, and sometimes you can get odd resonances or
things happening --
MR. MANOLY: That's true.
CHAIRMAN WALLIS: -- that are not
reflected just in the momentum flux.
MR. MANOLY: That's true, but also the
clear change in numbers and the values, like the cycle
pressure was 769.
CHAIRMAN WALLIS: As long as you are away
from resonance, it's fine. When you get near
resonance, everything is quite different.
MR. MANOLY: Very true. But the fact is
that the flow vibration issue is better with the
replacement generators and the part operates regime.
Despite that, they are going to be doing monitoring
during start-up using the procedure in OM-3, using
hand held devices which is acceptable.
CHAIRMAN WALLIS: What's a hand held
devices? Hold it up to the pipe and see how much it's
MR. MANOLY: Yes. That's basically what
we can prepare to address.
CHAIRMAN WALLIS: It's an accelerarometer
or something or is it something you just feel?
MR. MANOLY: No, no. It is right against
CHAIRMAN WALLIS: It's an accelerarometer,
though, isn't it?
MR. MANOLY: Yes.
MEMBER SIEBER: It's the differential
between how much the pipes are shaking and how much
the engineer is shaking.
MR. MANOLY: Are there any questions you
CHAIRMAN WALLIS: What sort of frequencies
does it vibrate at, range?
MR. MANOLY: I don't have the numbers.
Maybe, Dr. Wu, do you have the numbers for the
CHAIRMAN WALLIS: Order of magnitude?
MR. ALEXION: Low frequency.
MR. MANOLY: We can get it to you. We
don't have it right now.
CHAIRMAN WALLIS: Well, is it hertz or
kilohertz or --
MEMBER SIEBER: It may be hertz.
CHAIRMAN WALLIS: I'm just trying to see
if they scaled it right.
MR. MANOLY: But I just didn't have the
CHAIRMAN WALLIS: Is it sub-hertz?
MR. WU: This is a low frequency fatigue.
So low frequency.
CHAIRMAN WALLIS: Less than a hertz, isn't
it? Less than a hertz?
MR. WU: Well, it could be -- Should be
greater than one hertz.
CHAIRMAN WALLIS: Should be greater than
MR. WU: One hertz, yes.
MEMBER SIEBER: Five to ten.
MR. MARSH: Five to ten.
MR. MANOLY: Any other questions? Okay,
CHAIRMAN WALLIS: Thank you.
MR. MARSH: Next we'll hear from the
Materials and Chemical Engineering Branch.
CHAIRMAN WALLIS: Well, I'm just curious
here. What sort of amplitude do you get? When do you
get an amplitude that concerns you? Are you looking
at amplitudes of a millimeter or a meter or what?
MEMBER SIEBER: That would be in the lower
MR. WU: Yes, lower amplitudes. They are
measured by the micro-inch, very small, yes, very
MEMBER SHACK: The piece above the
threshold for high frequency fatigue, he's got a
CHAIRMAN WALLIS: Right.
MEMBER POWERS: What you want to do it
talk to Jit and have this -- when they go through this
power ramping up, you can visit the plant and help the
engineers do the hand held.
CHAIRMAN WALLIS: Well, when you go to oil
refineries, you do get motions of several centimeters.
MEMBER SIEBER: Yes, and you do in power
MEMBER POWERS: Not for a great deal of
MEMBER SIEBER: They don't necessarily
occur at full power either.
CHAIRMAN WALLIS: No.
MEMBER SIEBER: You know, it could be at
any power level. It depends on the tuning of the
MR. MARSH: Depends whether it's in a
resonance region or whether you are far from resonance
CHAIRMAN WALLIS: That's the whole
question. That's why just rho V2 doesn't really
MR. MARSH: Right. Sometimes they measure
acceleration as well as velocities and displacements,
because acceleration is a more meaningful parameter
for some of these systems.
CHAIRMAN WALLIS: Okay, thank you.
MR. ELLIOT: Hi. I'm Barry Elliot from
Materials and Chemical Engineering Branch. Next
MR. ELLIOT: We review -- In the Branch,
we review nine systems components and analyses. They
are listed up on the slide. We review the fuel pool
capability to remove decay heat and fission products
from the following power uprate.
I want to explain how I am going to do
this presentation. The first six items I'm going to
run through rather quickly, and the last three items
I'm going to go through in a little more detail.
So I'm just going to say for the first six
items what we review -- basically what we review. We
determined if they were adequate.
The second item is we review the clean-up
and shutdown capability of the CBCS following power
uprate. We review containment spray systems' ability
to remove iodine following LOCA for power uprate
MEMBER POWERS: Say that again. You look
at the containment spray system for what?
MR. ELLIOT: Ability to remove iodine
following LOCA for power uprate conditions.
MEMBER POWERS: And find it's poorer all
CHAIRMAN WALLIS: That's the only stuff it
MR. POWER: That's the only thing they
give credit in PWRs for. BWRs, on the other hand --
water is different in the two.
MR. ELLIOT: We review the impact of power
uprate on the previous review leak before break
analyses. We review the impact of increases in
primary system temperature and secondary flow rate on
the water chemistry program, and we review the impact
of power uprate conditions on flow assisted corrosion
MEMBER POWERS: Now you have elected to go
quickly through the FAC analysis, but that strikes me
as very important, and I'm concerned about the
licensee's analysis here. I mean, he can't be very
familiar with the code. He doesn't even spell the
name of it correctly in his Vu-Graph.
So did you look -- I mean, what did you do
to look at his analyses?
MR. ELLIOT: We know that there is a small
increase in the corrosion rate temperature, and what
we just look at to see is if the code is capable of --
We were depending on our CHECKWORKS code to predict
the locations that are susceptible and, therefore,
That code still can be used for the power
uprate. We determined that, and so we are relying on
that code to predict where to look and inspect for the
flow assisted corrosion.
MEMBER POWERS: And none of those
vulnerable locations were found to change, I think.
MR. ELLIOT: I don't know if they're found
to change or not. Chris, do you know if they found a
MR. BARCHEVSKY: I didn't hear that
MR. ELLIOT: The question is, did any
locations change, critical locations change?
MR. BOEHNERT: Identify yourself, please.
MR. BARCHEVSKY: Yes, there was some --
Chris Barchevsky. There were some changes in the code
which have to be modified. So the code was slightly
modified to predict, you know, erosion/corrosion.
MEMBER POWERS: The question is: In the
piping system that they have in the plant now, they
have certain areas that they monitor closely for flow
assisted corrosion. Did any new areas appear that --
MR. BARCHEVSKY: No.
MEMBER POWERS: No? Just all the same
MR. BARCHEVSKY: The same places.
MEMBER POWERS: And you are content with
that, I take it?
MR. MANOLY: Yes.
MEMBER SHACK: Now what changes were
necessary in the code?
MR. BARCHEVSKY: Of changes? Well --
MEMBER POWERS: Changes in parameters or
changes in the code?
MR. BARCHEVSKY: Yes. The changes were
mainly velocity. The velocity is different. The
velocity parameter had to be modified, hanged.
MEMBER SHACK: Okay. I mean, so we're
talking about input changes.
MR. BARCHEVSKY: That's right, inputs in
CHAIRMAN WALLIS: Is this a rho V2 effect,
MEMBER SIEBER: Everything is.
MEMBER POWERS: Well, you could certainly
cast it as a rho v2. We usually don't, but to
accommodate you, I think we could.
MR. ELLIOT: Next we are going to talk
about the Alloy 600 program.
MR. ELLIOT: The concern here is primary
water stress corrosion cracking of piping that is
connected to the RCS, the pressurizer and the vessel
head penetration. Cracking in the vessel head
penetrations were subject of an NRC bulletin, Bulletin
In this part of this program, PWRs were
ranked by the MRP according to the operating time and
effective full power years required for the plant to
reach an effective time and temperature equivalent to
Oconee Unit 3 at the time that circumferential
cracking was identified in that unit.
The licensee has performed that type of
calculation. It turned out that the uprate increases
at Thot from 604 to 609. The impact on the head was to
increase the ranking to, I think, 14.5 EFPYs -- or
decreased -- It would increase susceptibility and,
therefore, its ranking was 14.5 EFPYs.
Also there is the increase in Thot would
not substantially increase the primary water stress
corrosion cracking initiation in growth rate.
CHAIRMAN WALLIS: When you read these, it
sounds as if you are the licensee. What makes it
different when it's a presentation by you and the
MR. ELLIOT: In this case here, we do
check. We confirm the susceptibility ranking
ourselves. Using the inputs from the temperatures, we
confirm their ranking, and that's one of the things
that we do for the staff.
CHAIRMAN WALLIS: How do you -- What
process do you go through to confirm their rankings?
MR. ELLIOT: Well, we talk to them about
what temperature the head is, what temperatures the
nozzles are at, and we know how long they operate for.
They give us that, and then we put the time and
temperature into the equations --
CHAIRMAN WALLIS: Pretty simple.
MR. ELLIOT: -- and determine the
effective full power years to reach equivalent to
MEMBER POWERS: I guess I'm a little
perplexed -- as I say, I spend a lot of time being
perplexed -- that the numbers you quote up here for
temperatures are not the temperatures of the head.
MR. ELLIOT: No, they are not. The
temperature at head is 14.5 degrees below those
MEMBER SIEBER: It's a cold head.
MEMBER POWERS: See, when I try back of an
envelope calculation here, and based on the changes in
time, I come back, and say that you are using an
activation energy for stress corrosion cracking, must
be around 40 kilocalories. Is that roughly correct?
MR. ELLIOT: Alan, you want to tell them
how we do this in more detail?
MR. HIZER: This is Alan Hizer of NRR.
Actually, I think it was on the order of 32.
MEMBER POWERS: Thirty-two? Does that
strike you as a little low for stress corrosion
cracking? Not a bad guess, by the way, to get 40.
MEMBER SHACK: Actually, the growth rates
are typically around 32. Initiation is typically more
like 40 to 45. I think they actually use a slightly
higher number for initiation. I thought it was like
MR. HIZER: For the susceptibility
rankings, since a lot of that was thought to be growth
MEMBER SHACK: Growth driven, you use the
crack growth initiation. Okay.
MR. POWERS; Okay. My numbers are roughly
correct. Not a bad guess.
MEMBER SIEBER: On the other hand, the
relationship between susceptibility and temperature is
not linear. Right?
MEMBER POWERS: No, no.
MEMBER SIEBER: Okay. And the reason why
this plant comes in okay is because it's a cold head
plant. Is that true?
MR. ELLIOT: Right. We have plants that
operate at higher temperatures than this.
MEMBER SIEBER: If the head were operating
at 609, would you be concerned?
MR. ELLIOT: At what?
MEMBER SIEBER: Would you be concerned?
MR. ELLIOT: We would be a lot more
concerned. We are only talking about five degrees
here. You're talking about increases by 14. That's
MEMBER SIEBER: Yes, and it's nonlinear,
MR. ELLIOT: Right.
MR. HIZER: Just as a reference point,
before the power uprate conditions they had a
susceptibility ranking of a little over 17 EFPY. So
just the five degrees dropped them by a little over 2
EFPY. So that's -- But it kept them within the same
bin, if you will, from the Bulletin, the moderate
MR. ELLIOT: A higher temperature like
you're talking about could put them in a higher bin.
Just means they have to do a different inspection, but
what they talked about this morning was they're
planning on doing an ultrasonic inspection. So even
if they were in the higher bin, they would still do --
they are coming out doing what would be necessary for
a more susceptible plant.
MEMBER SIEBER: But when you look at
susceptibility, regardless of whether it's a hot head
or a cold head, you look at the hotleg safe ends.
That should be an issue and an area that would gather
more of your attention. Could you describe to us what
you did related to the safe end welds?
MR. ELLIOT: -- two welds on this plant
are piping connected to the reactor coolant pumps, and
MEMBER SIEBER: And the vessel.
MR. ELLIOT: No, the vessel is -- This
piping is ferritic.
MEMBER SIEBER: Oh, okay.
MR. ELLIOT: So it doesn't have -- Then
you have the surge line that has connections -- and
then there's instrument lines that go into --
MEMBER SIEBER: Small bore, right.
MR. ELLIOT: Yes, that have that. So they
are part of the Bulletin 2001-01 susceptibility
ranking. For those, we are relying on the Generic
Letter 88--5, walkdowns and the in-service inspection
program. And the small increase in temperature really
has no impact on the ability of those programs to do
an effective job. They will still do their effective
job on those types of plants that are not part of the
MEMBER SIEBER: And other than saying it's
a small change, no other work was done. Right? This
is more of a judgment call?
MR. ELLIOT: The key area here is that
there is a change in the growth rate. It initiates
sooner, but we have plants that operate higher than
609. They have operated many years higher than 609.
Maybe it's a hotleg temperature, and so our experience
with those are very good.
The programs that -- The walkdown programs
and the inspection programs are adequate. So they
should be adequate for this plant, because they aren't
increasing it that much temperature.
MEMBER SIEBER: Okay.
MR. ELLIOT: The rest of this slide is
The next issue is really dear to my heart,
neutron fluence and reactor vessel integrity.
Appendix D, 10 C.F.R. establishes Scharpey upper shelf
screening criteria, and 10 C.F.R. 50.61 establishes
RTPTS screening criteria for pressurized thermal shock.
Appendix G, 10 C.F.R. Part 50 established
fracture toughness criteria for pressure temperature
limits, and are also used for low temperature
overpressure protection setpoints for operation of the
reactor pressure vessel during heat-up, cooldown, and
hydrostatic test conditions.
Now the upper shelf energy and RTPTS values
have -- are screening criteria. The pressure
temperature limits are not screening criteria. They
just updated based upon the fracture toughness of the
CHAIRMAN WALLIS: Does the fluence go up
or down at this?
MR. ELLIOT: The fluence goes up here with
CHAIRMAN WALLIS: Does it go up
significantly? How much?
MR. ELLIOT: I don't know how much it goes
up, but let me explain it to you. We don't -- I don't
know if Lambrose can talk to fluence, but I would let
him talk if you want to talk about it. But I want to
give you my answer first.
We take the fluence evaluation, our group,
and we take the results of the fluence evaluation and
we see whether or not it meets the screening -- how
much it affects the screening criteria for the upper
shelf energy and the RTPTS, and we've done that. We do
that ourselves, in addition to the applicant.
It turns out this plant doesn't have a
high embrittlement rate. It has a very low
embrittlement rate. Its RTPTS value after uprate is
only like 130 or 125 versus the screening criteria of
275 to 300. So this is not going to -- This uprate is
not going to impact -- No matter how much fluence we
increase it, it is not going to affect that.
The upper shelf energy, even after the
uprate, are in the Sixties. We've checked that, and
we have plants that are in the Forties, you know, and
Again, how we change the fluence here, ten
percent, 20 percent, is not going to really impact
CHAIRMAN WALLIS: None of this is a
problem. Can we move on then? I don't think we need
to go on.
MR. ELLIOT: Okay. The pressure
temperature limits are being reviewed by the staff,
and they are for 32 effective full power years, and
it's under a separate application.
It won't limit the plant's life. We just
-- If we find that they did something wrong, they have
to recalculate the curves or they have to bring back
the curves to a different effective full power years,
and they are a long way from 32 effective full power
years. Therefore, reactor vessel integrity is
MR. ELLIOT: As far as steam generator
integrity is concerned, this plant has Alloy 690 tubes
which are more resistant to stress corrosion cracking
than the Alloy 600 tubes.
Degradation of tubes resulting from
deposition of copper was eliminated by removing copper
from the secondary side. Redundancy and analysis of
vibrational frequency responses of anti-vibration bars
minimizes wear, and the RG 1.121 analysis ensures
Therefore, there is no -- As a result of
the uprate, there is no change in the tube inspection
MEMBER SHACK: Oh, as a result -- They are
not going to continue doing 100 percent inspections,
which is presumably what they were doing with the old
MR. ELLIOT: I don't know what their
program is. Ken will tell you the details of their
MR. KARWOSKY: Ken Karwosky from the NRC
staff. As you may be aware, they would still have to
comply with their current tech specs, which specifies
the minimum three percent. Many utilities with these
newer types of steam generators do not perform as many
inspections as utilities with mill annealed Alloy 600.
But, you know, the criteria that they would still need
to meet at this point would be the tech specs.
It is possible that they would reduce
potentially the frequency of inspection, also the
number of tubes inspected as a result of --
MEMBER SHACK: I thought the industry
group was proposing a 20 percent instead of a three
MR. KARWOSKY: That's correct. The
industry committed to NEI 97-06, which are the steam
generator program guidelines, and that has different
criteria. I was speaking to the technical
MEMBER POWERS: Ken, as long as you are
there, what do we know about these thinner tubes,
MR. KARWOSKY: Experience-wise, we are --
With respect to the resistance to stress corrosion
cracking, not just 690 but thermal treated 600 tends
to be much more resistant to stress corrosion cracking
than mill annealed Alloy 600. So the operating
experience has been better.
We are in the process of obtaining some
more detailed information as part of our review of NEI
97-06 on foreign operating experience, for example, to
get information on whether or not there's been stress
corrosion cracking and under what conditions it may
have been observed in other plants. But domestic
operating experience has been favorable.
MEMBER POWERS: Are we running any
experimental programs with these materials?
MR. KARWOSKY: Research has plants to
conduct some testing with some of these advanced
materials to determine under what conditions they
would crack, initiation times, crack growth rates.
There is a long term research program.
MEMBER POWERS: How about correlations
between voltage signals and leakages and things like
MR. KARWOSKY: There's also research in
that area, but in the case of 690 a lot of those
correlations that exist for 600 would not necessarily
apply. So for the 690 tubes at Arkansas, those
correlations wouldn't apply. I don't believe there is
any testing with respect to voltage versus crack
severity in that program as of yet, just because of
the lack of operating experience.
MEMBER POWERS: Well, if they don't crack,
it's going to be hard to get anything.
MR. KARWOSKY: But nobody is going to say
they won't crack.
MR. POWERS; I got confidence in the
corrosion guys. They can make anything crack, if they
put their minds to it.
MR. KARWOSKY: Yes.
MEMBER SHACK: Is this a unique generator
with this diameter tube?
MR. KARWOSKY: I would have to -- I'm not
sure. I'm not sure. These are some of the larger
MEMBER SHACK: Have we got any -- Do we
have other CE plants that now have Westinghouse steam
MR. KARWOSKY: We have other CE plants
that have, like B&W Canada replacement steam
MEMBER SHACK: Those look a lot more like
a CE steam generator, don't they? I mean, they've got
egg crates and all that sort of stuff.
MR. KARWOSKY: Right. As far as I'm
aware, this is the first Westinghouse replacement
steam generator in a CE plant.
MEMBER POWERS: I get the feeling that at
sometime it might really be worthwhile to have our
Materials and Metallurgy Subcommittee host a
presentation of the full Committee on these new
materials and what you know and things like that, just
for educational purposes. I mean, they are coming
about. People have great faith in them. It would be
nice to know what we know and don't know and what we
ought to know.
MR. KARWOSKY: Right. I think some of
that would definitely be planned as part of our review
of NEI 97-06, I believe. We have discussed with the
Committee before with respect to, you know, we will
provide that operating experience in support of longer
MEMBER POWERS: I was thinking of maybe
having somebody with -- one of the corrosion guys,
specialists, come talk and say what do we know from
the science on this material, and what kinds of things
could we -- should we be worrying about and what-not.
MR. KARWOSKY: Sure.
CHAIRMAN WALLIS: Is it time to move on?
MR. ELLIOT: Okay.
CHAIRMAN WALLIS: Thanks very much.
MR. ALEXION: Next we will hear from Dose
CHAIRMAN WALLIS: I wondered if the dose
assessment we might just go to the open items.
MR. ALEXION: Okay.
CHAIRMAN WALLIS: It might gain us a
little time, and the resolution of the open items. Is
that okay with the presenter? Would you agree to do
MEMBER POWERS: You are no fun. You can
argue with him. So you prepared, by gosh.
MS. HART: Actually, that is the way I
CHAIRMAN WALLIS: Tell me what you're not
prepared about, and we'll ask questions on it.
MS. HART: My name is Michelle Hart. I'm
with the Probabilistic Safety Assessment Branch. I
feel duty bound to tell you I did not do the review
for this. The person who did that is unavailable
MEMBER POWERS: And because of the review?
MS. HART: Perhaps. I'm unaware of what
MS. HART: As you can see, the regulatory
requirements we review against are 10 CFR Part 100 for
offsite doses and GDS 19 for in the control room, and
all the reviews were conducted in accordance with the
particular applicable SRP Section 15 sections.
MR. HART: Analyzed: The accidents we
analyzed for the power uprate were the maximum
hypothetical accident, which is the LOCA; the control
assembly -- element assembly ejection; the steam
generator tube rupture; and the fuel handling
The seized rotor, main steamline break and
feedwater line break were previously reviewed for the
steam generator replacement.
MS. HART: In the draft SE there were
three open items. One was the control room
habitability review, the steam generator tube rupture,
and the reactor building mixing for the maximum
MS. HART: In the control room
habitability assessment, there was concern with
unfiltered in-leakage, and the licensee had done that
testing that they had discussed this morning and had
come up with an action plan to address our concerns
and also, I am sure, their concerns with this control
room envelop unfiltered in-leakage uncertainty and
these modifications, which are a procedural change
and sealing which will be completed before they start
They have a new licensing basis in-leakage
value based on their tracer gas testing, and we have
confirmed acceptability through doing a confirmatory
analyses of all the accidents for this uprate review.
MR. POWERS; I mean, they found a terribly
high in-leakage relative to what they had assumed in
the past, and so they fixed a bunch of things. But
their in-leakage is still six times what they assumed
in the past.
MS. HART: That's correct.
MEMBER POWERS: So I assume that you found
that the dose to the operators was six times what they
found in the past.
MS. HART: Not exactly.
MEMBER POWERS: Ah. Why not exactly?
MS. HART: Unfortunately, I can't speak
exactly to that. There were other changes that are
made in the analysis and things like that. Like I
said, I didn't do the review. So I can't speak
CHAIRMAN WALLIS: This isn't a power
uprate dependent issue, is it?
MS. HART: Not really, no. It is
something we look at for the larger uprates --
CHAIRMAN WALLIS: And it would be an issue
whether or not they were uprating the power.
MS. HART: That is correct. And as you
all know, we are working on a generic solution for
this issue with our Reg Guides and a possible Generic
Letter. We're not sure about that.
CHAIRMAN WALLIS: Assessement -- must be
French or something, up at the top there.
MR. CARUSSO: This is Mark Carusso. I
might just add a comment here in response to your
question. I am in the same branch with Michelle, and
I am her Acting boss today. That means I'm not the
guy who reviewed the work she didn't do, but anyway
I'll try to help you, although I can't provide anymore
detail either. I'm not familiar with the details of
Arkansas' analysis and our review.
I think typically licensees that are doing
these tests and are finding these flow rates higher
than what they assumed before, when they do come in
with their new package, they are modifying their
methods. They are using better meteorological
This is generally. I'm not saying
Arkansas did this. I don't know exactly what they
did, but you know, they are sharpening their pencil
and their methods, and so they come in with a package
that, well, I've got more, you know, in-leakage flow
rate, but I've sharpened my pencil over here. And so
you get a new number and it's pretty hard to say,
well, you know, in answer to your question, shouldn't
it be six times higher, you can't sometimes tell that;
because there's been a number of changes in the
analysis, assumptions and methods.
CHAIRMAN WALLIS: I think we should move
on. I know that the control room habitability is
another issue entirely.
MR. CARUSSO: Yes.
CHAIRMAN WALLIS: It's before the ACRS in
another context. It's not related to power uprate.
So maybe we should move on.
MR. CARUSSO: Go ahead, Michelle.
MS. HART: Okay. The next one was the
steam generator tube rupture. The open item was
because this analysis was unavailable for review
before the draft SE was put out.
When we did finally get the review, we did
have some concerns with the distribution of iodine
isotopes within the RCS for analysis. The licensee
did provide a revised distribution, and we came to an
agreement on acceptability of use of this distribution
for this uprate.
CHAIRMAN WALLIS: Does the uprate make a
big difference? Why does the uprate affect the iodine
MS. HART: The uprate doesn't affect it
much, if at all. It was just that they had used the
core distribution instead of a RCS distribution to do
their analysis for like the steam generator tube
rupture, main steamline break, things like that. They
didn't do main steamline break in this, though.
MR. CARUSSO: This is mark Carusso again.
Normally we expect to see -- In these analyses we
expect to see the concentration in the reactor coolant
system, the distribution in the coolant system, not
what's in the fuel.
They came in with what was in the fuel,
and the reviewers said that doesn't match with what we
normally see; show it to me with the coolant. He came
back and said, okay, I agree, it's inappropriate; I
did it with the fuel, and I actually got a worse
answer with the fuel, slightly worse, but I'll do it
again for you with the distribution in the reactor
coolant system. We said fine.
CHAIRMAN WALLIS: It doesn't sounds like
that's a key issue for the power uprate.
MR. CARUSSO: Not at all.
MS. HART: Not because of the power
MR. CARUSSO: Not a power uprate issue.
MS. HART: The next issue is the reactor
building mixing issue. The concern the staff had is
that in determining -- well, in using that mixing they
had all of the return air to the unsprayed region was
all from the sprayed region, which we thought was
perhaps a bit nonconservative.
The licensee did provide clarifying
details of their mixing model, which is in that RAI
that was discussed earlier, and through much
discussion and also some confirmatory independent,
back of the envelope kind of calculations, we
determined that the mixing -- although they said it
was 100 percent, we came to around 97 percent or so we
thought would be coming from the sprayed region to the
CHAIRMAN WALLIS: Is your confirmatory
analysis any less hand waving than their responsive to
MS. HART: I can't speak to the exact --
CHAIRMAN WALLIS: It is. It's very
MS. HART: Right.
CHAIRMAN WALLIS: So it's really not much
of a physical model about what happened. So let's
assume that it's sort of equally distributed between
this and that, and let's assume there's --
MS. HART: Right. The original assumption
the reviewer thought might be more applicable is you
have -- I can't remember the exact amounts, but let's
say 76 percent of the containment is sprayed and the
rest is unsprayed. So it should be that same ratio
coming back to the unsprayed, and they said it was 100
percent on the sprayed.
CHAIRMAN WALLIS: Like it was liberal arts
MS. HART: Right. Right. So he did some
more calculations based on the concentration in the
containment and determined that, well, 100 is maybe
not so far off that we need to argue it at this time.
CHAIRMAN WALLIS: Why is this an issue for
MS. HART: This is not a power --
particularly for power uprate, no.
CHAIRMAN WALLIS: So it may be something
that we might well question in terms of model, but
apparently it's not really important for power uprate?
MS. HART: Not really important for power
CHAIRMAN WALLIS: We should just forget
it, because it's not important?
MS. HART: Well, I wouldn't say that, no.
It's not important when the --
CHAIRMAN WALLIS: If all issues were
treated this way, I think we might be a little
MR. MR. CARUSSO: Can I interject for a
moment here. I think in talking with the reviewer, he
looked at this in terms of what doses were they
getting and saying, well, you know, if it is, you
know, a 78/22 split versus up to 100, that could --
and looking at what margin they had in the doses, that
could be a problem.
So that's why he dug into this. It's not
a power uprate issue. HE just said, gee, you know,
this sounds convenient. You know, it comes in at
22/68, and it mixes perfectly, and that helps their
dose, looks convenient, how did you do it. He asked
them the question.
They came back with, you know, I'd say --
I wouldn't call it purely qualitative. I would say
it's certainly quantitative in terms of how they broke
up the containment.
CHAIRMAN WALLIS: There are also numbers
in it. That's true.
MR. CARUSSO: Yes. So he looked at what
they sent in and said this is a reasonable assessment
of mixing, reasonable enough to support the assumption
that I'm within seven or eight percent.
CHAIRMAN WALLIS: Okay. Effects on dose
are relative small anyway.
MS. HART: That's correct.
CHAIRMAN WALLIS: It doesn't seem to be a
critical issue for power uprate anyway.
MR. CARUSSO: No.
MS. HART: Right. And as a result of our
reviews, all of the different accidents we did do
confirmatory analyses using mainly the same
assumptions that the licensee had used. We did check
into those assumptions.
MS. HART: Their dose results: They meet
Part 100, and they also meet GDC 19.
Are there anymore questions?
MR. ALEXION: Okay. We will move on then
to the risk assessment.
CHAIRMAN WALLIS: This is the dessert this
time, isn't it?
MR. ALEXION: I hope so.
MEMBER POWERS: I think desert is the word
you were looking for. Desert.
CHAIRMAN WALLIS: It becomes the oasis of
rationality, isn't it?
MEMBER POWERS: I think we're seeing where
the limitations of risk really come to the fore, and
maybe some of the capacity for looking at bottom lines
without looking at the intervening materials.
CHAIRMAN WALLIS: Please go on.
MR. HARRISON: Good afternoon. My name is
Danny Harrison. I'm with the PRA Branch. I'm in the
Safety Program Section, and I'm here to just give you
what we've done on the risk assessment review part of
the power uprate.
MEMBER POWERS: Do you have a SPAR model
for this plant?
MR. HARRISON: I believe there's a SPAR
model. I didn't manipulate a SPAR model on this.
This slide just shows the fact that, even
though it's not risk informed, the license, he did
provide risk information either through a supplemental
submittal that he made or in response to specific
questions the staff asked.
The areas covered are the four listed
here: Internal events; external events; shutdown
operations; and the quality of their PRAR.
CHAIRMAN WALLIS: I think this is what we
should see in the perspective. When we look at these
PRAs and there's all kind of things to question or
we're a little unsure about, but the purpose of using
it in this context is to see if you learn something
from it that says now we had better go back and dig
into that. You're looking for insights.
You're not really taking seriously the
numbers for the point of making a decision, because
it's not risk informed. It's does something come up
here which says we'd better go back and think about
that some more.
MR. RUBIN: That's absolutely correct.
Mark Rubin from the PRA Branch.
Essentially, what you are doing here is
reconfirming the original IPE now there have been some
MR. HARRISON: And to make sure there's no
MEMBER POWERS: If you come in and say I'm
going to run my motors faster, but it's tough to get
-- to understand how the change in failure frequencies
are there, and so I'm going to leave it out, and then
you find there's no change in the PRA, there's no
change in the risk significance of the items. These
are not insightful conclusions, it strikes me.
MR. HARRISON: Well, certainly, a thing
like that would not be an insightful conclusion, but
you could get some insights on changes, success
criteria, timing changes, some HRA insights. The types
of issues you mentioned, of course, they are very
difficult to deal with.
That's one of the reasons why we and the
licensees look at monitoring system performance to try
to pick up insights on performance degradation from
operating experience data.
MEMBER POWERS: I mean, what you are doing
there is you are getting -- You have insights despite
the PRA there. I mean, this is risk and informed
safety analysis here.
MR. HARRISON: Well, you can gain some
insights. What you can look at is, if I know I am
going to overload a motor, you can then postulate that
that motor is going to -- or main transformer that's
being overloaded, you might postulate I'm going to get
a failure of that transformer more frequently.
If you are, though, within the operating
design limits of that piece of equipment, the data is
not going to support, because it's done for pumps, not
pumps that are outside its design. So that you've
got, if you will, a philosophical problem with that.
It's a --
MEMBER POWERS: That brings me to another
philosophical issue. Here we have this interesting
situation. We got a plant with a operating event PRA,
core damage frequency -- what? -- 10-5 roughly, and
you got an IPEEEE submittal that says 9 x 10-5.
If I'm risk informed, don't I spend all my
attention looking to see how power uprate affects fire
MR. HARRISON: Well, I would say on that
is you would definitely look into it, and that's what
the staff has done. We saw that the fire analysis
results were high. They used the five methodology
with not a whole lot of manipulation.
If you look at other five methodology
plants out there, they are all probably pretty close
to 10-4. So can you gain insights from that? Yes,
you can gain insights.
You can look at it and say what's the
criteria for accepting that level? The licensee used
NUMARC 91-04 as a way to close out each zone. So in
closing it out, you can say, if any zone contributes
more than 50 percent to the CDF for fires, I have to
do something else, supposedly by the NUMARC criteria.
They don't. It was 30 percent. It stays
MEMBER POWERS: That's going through the
NUMARC criteria. Here we're looking at a power
uprate, and it seems to me that you ask the question:
I've got a methodology that is probably conservative,
certainly round number-ish kind. Is there anything in
the power uprate that is going to change anything with
respect to fire?
MR. HARRISON: Right.
MEMBER POWERS: And I mean, things cross
your mind, but I mean, I don't have a smoking gun
here. I mean, have you guys looked to see if there is
MR. HARRISON: The main impact that we saw
would be in the operator response times, and that's
what the licensee manipulated in their model.
MEMBER POWERS: There is no -- You don't
have increased frequencies of fires just due to
current loads or things like that?
MR. HARRISON: We didn't postulate any,
CHAIRMAN WALLIS: The changes in the fire
CDF are about the same proportionally as the internal
MR. HARRISON: Yes.
CHAIRMAN WALLIS: And they are mostly
attributable to operator response?
MR. HARRISON: Almost 100 percent of it is
operator response time.
MEMBER SIEBER: I have a question on the
last slide, but don't go back to it, because it's a
One of the sub-bullets was PRA quality.
My overall impression was that this was maybe not an
outstanding PRA. How did the staff judge the quality
of this PRA, being as it didn't meet the standard,
wasn't peer reviewed?
MR. HARRISON: I wouldn't say that it
hasn't met the standard, and I wouldn't call it a bad
PRA either. It hasn't been through the peer review
process of NEI. However, back in the IPE, I believe
there was an engineering team review. In the IPEEE
they did a review, outsider review.
If you look at the SEs on those, they will
make mention of different reviewers doing reviews. So
I wouldn't say that this is a sub-par PRA at all. It
just hasn't been through the peer review process, and
that's just to be recognized. That's where they are.
MEMBER SIEBER: And it might be, what,
three years old?
MR. HARRISON: Yes, '97 time frame.
MEMBER SIEBER: Five years old.
MR. HARRISON: They added in -- Some of
the things from the steam generator replacement
project got added into the power uprate model so that
they could compare that back to where the base model
was. So actually, they took a hit there for something
they have already done.
MEMBER SIEBER: I'm just trying to get a
feeling as to where to place this in the overall list
of PRAs that are out there, to know whether it's
really giving us insights or not.
MR. HARRISON: Yes. One of the things
that I do when I do these reviews, I go back to the
SEs that were written on the IPEs and the IPEEEs, and
I look to see do they have any particular heartburn.
They may have bought off eventually on
something, sensitivity calcs or whatever, but where
were the issues - they thought the issues were coming
out, and then a lot of times I'll pursue those further
with the licensee.
MEMBER SIEBER: And did you do that with
this particular one?
MR. HARRISON: Yes, I do that with every
one of them.
MEMBER SIEBER: Did you find anything
MR. HARRISON: Nothing came outstanding.
The question that you get here would be -- I think the
IPE had a couple of questions on the containment
analysis, but on the PRA part of -- the IPE part of
it, I don't recall any chillers in the review that was
MEMBER SIEBER: Thank you very much.
MEMBER POWERS: When the reviews were done
on the IPE submittals, my recollection was, as they
came in, some large fraction of them had questions
about the human reliability analysis.
MR. HARRISON: Right.
MEMBER POWERS: Here we've got changes in
the CDF and everything else in these is associated
with human reliability analysis. Did you look at what
MR. HARRISON: Yes. Because of the fire
numbers being so high and because the operator actions
are typically where you get the hit on power uprates,
we took a visit to the site, took a look at both their
fire analysis to see how closely do they follow the
five methodology, where did they take liberties by
using maybe the EPRI risk assessment guidelines.
We also looked at how closely they
followed the methodology for doing the human
reliability analysis. Arkansas has a spreadsheet on
a computer that they use to manipulate the curves that
they use, if you will.
We walked through a number of operator
actions, actually went in and said, well, what if I
change this number to this, what if you have an extra
crew or not, and looked to see what the impact was, to
see if it would match up with the numbers that are in
the EPRI guide.
In fact, I think the Arkansas
documentation -- If you were to look at it and then
set the EPRI guidance on how to do it next to it, they
are nearly identical, page for page. I mean, you can
-- It's a cut and paste job, and the methodology picks
that right up.
So we walked through that. We asked a
couple of questions about why did this operator action
not show up that we expected to show up. We found it
was an oversight. They did model it. It's just that
they missed it when they made their list of impacts.
So there's that part of it that we
actually look at in depth.
MEMBER SIEBER: So your final slide is
everything is okay?
MR. HARRISON: The bottom line is you have
to answer that last bullet, which is: Is there
anything that shows up that would say that this plant
-- you would question adequate protection?
They have a high fire number based on the
five methodology, but it's no higher than what you
will see for other plants that use that methodology.
Nothing triggers you to question adequate protection,
and at that point then we end our review. We don't
pursue it further.
MEMBER SIEBER: Good. Thank you.
CHAIRMAN WALLIS: Thank you. I think we
are ready to move on to the other bottom line items.
MR. ALEXION: Okay.
CHAIRMAN WALLIS: It looked like the
MR. ALEXION: Good. Just a very short
conclusion. Just a second here.
CHAIRMAN WALLIS: Tom, we may have all
read it by the time you get it up there.
MR. ALEXION: Okay. The staff feels like
we've done an extensive review. We have no open
items, and we feel that the application meets the
regulations, and staff recommends approval of the
MR. RICHARDS: I'm Stu Richards. I'm the
Projects Branch Chief for Arkansas, and we would just
like to thank the Committee for the opportunity to
present our review of ANO today. As Tom already
mentioned, we think that we did an extensive review.
It is the first extended power uprate for
a PWR, but I'm sure there's more to follow. This
concludes our presentation. We would be happy to try
and address any other questions you have.
CHAIRMAN WALLIS: Thank you.
MEMBER POWERS: I have just a comment from
my perspective. We've offered several suggestions on
how the presentation could be improved, but quite
frankly, this was orders of magnitude better staff
presentation than we've had in the past for the BWR
I found it -- I mean, maybe because you
were misled a little bit on guidance coming in, it's
still a little summary in nature, but it's certainly
articulate, and I found the responses to our questions
to be forthcoming.
MR. RICHARDS: We have tried to learn from
some of your feedback that you provided in past
presentations. So we appreciate getting that positive
feedback, and we will build on what we heard today.
I think one thing we need to work with the
ACRS staff on is the timing. We looked at having 90
minutes with six branches, and when you do the math,
that doesn't come out to a very extensive
presentation. But then, of course, the Committee, I
think, desires to get into some detail in particular
areas. So we need to figure out how we can make those
competing demands match up.
MR. BOEHNERT: Well, if we didn't have two
uprates back to back, we might have been in a little
MEMBER POWERS: You just understand our
position. Sooner or later we have to go attest to the
Commission that we have --
MR. RICHARDS: We understand that, but you
know, I personally told the staff to cut back on their
presentation, because I figured about seven minutes
per branch and then another seven minutes for
questions when you get 90 minutes. So when people get
up there and say, hey, we don't have enough detail,
that was a conscious decision, at least on my part.
MR. MARSH: Mr. Chairman, we want to be
responsive to your needs. If you need more detail on
anything, whether it comes up in the meeting or in
advance of the meeting, we want to provide that to
you. We don't want to leave the impression with you
in some areas that we haven't gone into some detail.
So we want to fill that need of yours.
MEMBER SIEBER: I think it would be a good
idea that, when you are all done with the SER, that
you would look at it and say here are three or four of
the important issues we dealt with, particularly where
the analysis was concerned, confirmatory analysis, and
then give us a little picture of what was done for
those three of four.
MR. MARSH: Okay.
MEMBER SIEBER: And that then helps to
establish some confidence that, yeah, there was depth
in the review as opposed to, you know, 60 bullets that
say everything worked out okay.
MR. MARSH: So let me play that back.
Maybe in preparation for further presentations, if you
get either an advance or maybe in an introduction
about some of the key areas that we went into more
detail, because we were concerned about them or
because we want to demonstrate to you some of the
depth of issues that we may have, as either
preparation for the meeting or in the preamble for the
MEMBER SIEBER: I think that would help me
to get an appreciation for what all you did. Okay?
MR. MARSH: Okay.
MEMBER SIEBER: And to what extent did you
MR. MARSH: Right.
MR. RICHARDS: We have also made notes of
some questions that you've asked today that were
unable to answer. I think we've made commitments that
we will get back to you with that information. So
we'll do that.
CHAIRMAN WALLIS: Bill, do you want make
any comments? Tom?
Well, my colleague, Dana Powers, was
remarkably complimentary. I felt we didn't have very
much time today, and I'm not quite sure why it was so
short, since this is the first time we are seeing such
a big uprate for a PWR. I think it's important that
we get it right.
MR. MARSH: Right.
CHAIRMAN WALLIS: And I just don't want --
You want us to write a letter at the next meeting,
whenever it is, this March or April meeting. I just
hope that what goes into that letter doesn't suffer
because we just didn't schedule enough time to go into
I agree with my colleagues here. We know
we are going to see in the SER that they met all the
requirements, and if they didn't, they wouldn't write
an SER. So we're not really interested, I think, in
We read it. We see it, and we don't need
to see it again on the transparency. What we have to
do is, as my colleague, Jack, says here, we need to
get some confidence that when there was an issue that
you had to dig into, that you dug into it in
appropriate depth, that you did your own thinking and
maybe you brought in a consultant or somebody if you
had to, and that then -- so we have confidence that
you reached the right conclusion. That's the sort of
thing we need.
MR. MARSH: I think you are picking up on
what we were trying to say. We have 90 minutes in
which to present to you a range of issues, a range of
branches and a range of issues, to demonstrate to you
the breadth of issues that we go into -- the breadth
as opposed to the depth.
CHAIRMAN WALLIS: I think where we
learned more was when we asked you questions on things
you weren't prepared about. The same thing that you
get with a sort of student thesis. When you ask them
questions that they didn't prepare for, you often
learn far more than when you get this sort of thing
which is all prepared, because it looks --
MR. MARSH: Perhaps then you don't want a
breadth presentation. You want a depth presentation.
You don't want to know the range of issues that we
look at. You would like us to pick out a few issues
and demonstrate depth.
CHAIRMAN WALLIS: Well, I think you need
to talk about perhaps briefly but then to get
confidence, I think it would help if you pick a few
examples and say this is an example of how went in in
depth into something.
MR. MARSH: Okay.
MEMBER SIEBER: I think that, to get a
picture of the breadth of issues, you could almost
give us a list: These are the things that we
reviewed; in general they all come out okay, but here
are the concerns we had, and here's how we --
CHAIRMAN WALLIS: In fact, it's obvious.
Just look at the SER. There's a tremendous number of
items in there which are covered. So I'm very
impressed with the breadth. There's no need to defend
MR. MARSH; Okay.
CHAIRMAN WALLIS: Are we ready to break?
MR. BOEHNERT: Well, since this ANO will
be moving on, you need to let them know that we have
this scheduled for the March meeting. It's going to
be on the seventh of March. I think it's right after
lunch in the afternoon, two hour presentation time.
Total time is two hours that's been scheduled.
CHAIRMAN WALLIS: The knowns are the
seventh. That's okay. The Ides are the 15th.
MR. BOEHNERT: That's right.
CHAIRMAN WALLIS: That's not the Ides of
MR. MARSH: Back to your issue of a
letter, if you feel -- the Committee feels like you
are unfulfilled in a particular area, that we haven't
demonstrated to your satisfaction a thoroughness of
review, allow us to answer any questions that you may
have or to come back to you with concerns.
I wouldn't want the brevity of the meeting
to result in a letter that may demonstrate something
we don't want to.
CHAIRMAN WALLIS: But it was too much
MR. MARSH: Right.
CHAIRMAN WALLIS: I think it's not just a
matter of the Committee being satisfied. I think,
when you've got this down in the record, it's a public
document. The more satisfied we are, the more we can
say that in a letter. So it's not just a question of
interactions within this community. It goes out into
MEMBER POWERS: I think we owe Tad some
guidance on what he could present to the full
Committee and what-not. I think your slides that your
presenters had that had the list of all the things
that were in there could certainly be included in the
package, but say most -- I'm not sure 100 percent, but
most of the members can read -- and say here are the
ones that I think are most important.
I think one of your speakers did that. He
said here's five things, I want to concentrate on the
last three, and of these last three here, I want to
show you what I had to do here to satisfy myself,that
kind of a trend.
You may want to cut down on the number,
because there are clearly some that are of higher
importance and greater interest.
MR. MARSH: Okay.
MEMBER POWERS: Myself, I think that, if
I were designing it, I would have worried like the
plague going into the PRA region, just knowing the
Committee and knowing how unimportant the PRRA aspect
is to this particular uprate, just because I don't
think you will ever get out. Schedule that one just
before the end of time or something like that.
Yes, I thought some of the speakers --
they had very effective slides in showing breadth, and
they don't need to go through it, and then
highlighting perspective by showing that they could
pick out of all that breadth things that were most
important, and then all they needed to add in there is
-- and it doesn't have to be everyone, but occasional
ones to say "and here's an illustration of the depth."
MR. MARSH: We'll do that.
MEMBER POWERS: And I think that would go
a long ways to present.
CHAIRMAN WALLIS: What you want to avoid
is having slides where you had this long list of
things we looked at, all terminating with that the
regulations were satisfied, whatever.
MR. MARSH: Understand.
CHAIRMAN WALLIS: And someone who just
sort of reads that, one suspects, well, if that's all
he's got to show, maybe there isn't much behind it.
But if he could say but this is one where we really
got into it in depth.
MR. MARSH: Where we plumbed the issue and
here's how we plumbed it, and this is what we found.
CHAIRMAN WALLIS: And so departing from
the text helps a great deal to give confidence.
MR. MARSH; I understand.
MEMBER POWERS: Showing a perspective --
showing breadth but then perspective, I thought, was
very effective on one of the presentations,
CHAIRMAN WALLIS: Yes. Okay, are we
though now? Can we take a break?
MEMBER SIEBER: Please.
CHAIRMAN WALLIS: We have to move on to
another one of these.
MR. MARSH: Thank you very much.
CHAIRMAN WALLIS: So we'll take a break.
Thank you all. Until half past three.
MR. BOEHNERT: 3:30.
(Whereupon, the foregoing matter went off
the record at 3:19 p.m. and reconvened at 3:34 p.m.)
CHAIRMAN WALLIS: Please come back into
session. We have a new topic, Clinton Power Station,
Unit 1 Extended Power Uprate. We ought to be able to
make good progress, because this follows the pattern
that we've seen before for other stations.
I'll say up front that some of the
information that will be given is proprietary. Some
of the questions the Committee asks will be answered
by reference to proprietary matters. What we would
like to do is save the proprietary issues for the end
of the day and, if we ask questions which have an
impact on proprietary matters, they will be stored.
Then we'll come back to the answers at the end of the
We do have a continuation of this meeting
MR. WILLIAMS: Yes.
CHAIRMAN WALLIS: We will need to break
for dinner and sleep and all that at an appropriate
time, but we don't want to shortchange you. If we
need the time, we will take it. But I think we have
-- I have an agenda here which says you are going to
break before you discuss ECCS analyses. Is that okay
MR. WILLIAMS: Yes.
CHAIRMAN WALLIS: So let's see how far we
can get then with this plan, and see if we can get out
at a reasonable time today.
MR. WILLIAMS: All right, Dr. Wallis.
CHAIRMAN WALLIS: Please go ahead.
MR. WILLIAMS: Good afternoon. My name
is Joe Williams, Exelon Nuclear. I am the Clinton
Senior Management Sponsor for the extended power
MR. WILLIAMS: I would like to thank the
ACRS in advance for their time. We have brought in a
number of our technical specialists and senior reactor
operators to present the aspects of our power uprate
We will present a summary of the project.
We will discuss plant modifications. We will present
the results of selected analyses and the power uprate
risk evaluations. We will discuss the project
Before we begin the presentations, I would
like to make just a few points.
MR. WILLIAMS: We have submitted a license
amendment request to increase the thermal power output
of Clinton station by 20 percent over our original
licensed thermal power. We have used accepted G.E.
methodology to leverage industry experience and Exelon
Exelon Nuclear has previously uprated
seven G.E. boiling water reactor units. Our analyses
demonstrate that our plant will operate in accordance
with all applicable regulations after uprate, that our
plant operates safely now and will operate safely in
In conjunction with a thermal power
increase, we will also perform plant modifications and
increase the electrical output of Clinton Station.
I would now like to introduce Dale Spencer
who will summarize the uprate project.
MR. SPENCER: Thank you, Joe. Good
afternoon. My name is Dale Spencer, Exelon Nuclear.
I'm the Project Manager for the Clinton Station
extended power uprate.
MR. SPENCER: As an introduction to the
material which we will be presenting to you over the
next few hours, I want to spend just a few minutes and
provide you with a summary of the overall extended
power uprate project, followed by an overview of the
modifications and analyses we've performed.
As Mr. Williams discussed, we are
requesting a license for a 20 percent increase in
reactor power. Our plans are to implement the power
ascension in two steps.
The first step will take place upon start-
up from our eighth refueling outage which is scheduled
to finish in May of this year. The second step of the
power ascension will take place after our ninth
We will be performing modifications to the
plant to facilitate this power ascension, and I'll
cover these in more detail later. These modifications
will be installed between now and early 2004 to
support our schedule for power ascension.
Of the modifications I will describe, we
will show you that we are making relatively few
changes to the operations of safety systems, and that
upon implementation of our uprate, Clinton Power
Station will be limited by balance of plant
CHAIRMAN WALLIS: Which indicates that, if
you change the balance of plant components some more,
you could get even more power out of this reactor?
MR. WILLIAMS: Yes, sir, up to 20 percent.
CHAIRMAN WALLIS: Well, it says following
the uprate it will be balance of plant limited. It
indicates to me you could go for 25 percent, you know,
if you change the balance of plant.
MR. SPENCER: The analyses that we are
limited by now is we performed the analyses to the
G.E. topical, which is a 20 percent plant uprate.
MR. WILLIAMS: That is correct.
CHAIRMAN WALLIS: Yes.
MR. SPENCER: The team we are using to
perform the analysis, preparations and implementation
of this extended power uprate has a wide range of
experience and knowledge. Our on-site core team is
made up of personnel with a broad range of experience
at Clinton, other Exelon and AmerGen plants, as well
as the industry.
We have used the G.E. standard EPU process
as our guide for our analyses and schedule. The G.E.
processes have been used for the performance of
numerous stretch and extended power uprates at boiling
Sargent and Lundy, as the balance of plant
architect/engineer, has served similar roles in
several previous power uprates throughout the country
and is also the original architect/engineer for the
Clinton Power Station.
In addition to the knowledge of the team,
we maintain both a base of lessons learned from the
industry as well as routine contact with other plants
MR. SPENCER: The slide on the screen now
provides a listing of the change in the plant
conditions. In a short summary, our increase in
licensed thermal power will allow us to increase steam
flow to the turbine. The increase in steam flow is
being precipitated by replacement of the high pressure
turbine. Thus, no changes in reactor steam dome
pressure is required for this uprate.
MR. SPENCER: The next slide I would like
to show is the power to flow map at EPU conditions.
This map graphically shows the approved operating
region for the Clinton Power Station post-uprate.
For clarity, the EPU region has been
highlighted in the upper righthand corner of the map.
One note: Other recent plants have implemented MELLLA
as part of the EPU license submittal. At Clinton, we
have previously been licensed to MELLLA and, thus, the
EPU will be realized by increasing power along the
previously licensed MELLLA boundary.
MR. SPENCER: At this time I would like to
spend a few minutes to review the plant modifications
we will be making, followed by a brief description of
the analyses performed.
MR. SPENCER: As stated in our power
uprate safety analysis report,no safety related
hardware changes will be required to implement the
extended power uprate at Clinton.
Upon issuance of the revised operating
license, we will perform changes to nuclear
instrumentation. This will allow us to increase our
output. These set point changes include the APRM flow
biased Scram and rod blocks, the main steamline high
flow Group 1 isolation, the turbine control valve and
stop valve Scram, and the reset trip bypass, and the
control rod block pattern controller, lower power
setpoints and high power setpoints.
MR. SPENCER: At this time I want to
proceed to a discussion of the mods we will be
performing to the balance of plant systems.
As I stated previously, we will be
implementing our power ascension in two steps. During
the upcoming refueling outage, we will be replacing
the high pressure turbine with a unit capable of
passing higher steam flow.
The main power transformers will be
replaced with units capable of handling the increased
MVA that the power increase will generate. Associated
with the main power transformer replacements are
changes to the isophase bus duct configuration and
The main generator hydrogen coolers will
be replaced, and the hydrogen pressure will be
increased from the current 60 pounds to 75 pounds.
This is to handle the increased heat load in the
The exciter ANO transformer will be
replaced to allow the increased excitation load on the
exciter at uprated conditions, and we will be
upgrading five piping supports on the feedwater
These changes will allow us to achieve the
additional megawatts for the next operating cycle.
CHAIRMAN WALLIS: It's the same feedwater
MR. SPENCER: Yes, sir.
CHAIRMAN WALLIS: But they are pumping
more water, so that --
MR. SPENCER: Yes, they are.
CHAIRMAN WALLIS: -- they run faster or
MR. SPENCER: We have two turbine driven
feed pumps and a motor driven feed pump.
MR. WILLIAMS: The turbine drivers will
run faster. If the motor driven is being used, its
regulating valve will be further open.
MEMBER KRESS: Did you have to do anything
to the recirculation pumps?
MR. SPENCER: No, sir.
MEMBER KRESS: They are okay?
MR. SPENCER: Yes, they are.
CHAIRMAN WALLIS: It's the same core flow.
MR. WILLIAMS: There is the same core
MEMBER SHACK: And why did you add -- or
upgrade the supports on the feedwater piping?
MR. SPENCER: The increases in flow that
we do see are on the feedwater flow and the steam flow
CHAIRMAN WALLIS: This is a flow induced
MEMBER SHACK: The energy in the -- the
higher energy in the line?
MR. WILLIAMS: The higher energy in the
thrust for the faulted conditions, that's correct, not
flow induced vibration.
CHAIRMAN WALLIS: Not flow induced
vibration. Just bigger forces of reaction because of
the higher flow rate? Is that it?
MR. WILLIAMS: Yes, sir, that is correct.
MR. BLANTNER: I'll give you a little bit
more -- My name is Jerry Blantner with Sargent &
Lundy. For the piping analysis, there were five
supports that changed. They were all in the non-
safety, non-seismic portion, and what that was
associated with was there is a feedwater pump trip
which has accelerated.
It came up with larger loads, and this is
associated with the check valve closing. These are --
The support changes are very minor. They were a
baseplate -- Two baseplates had to increase with
stiffeners. Two snubbers went up one size each, and
one piece of auk steel had to change.
MR. SPENCER: To ensure we realize the
full potential from our uprate, we will be performing
additional modifications in the future. These mods
are currently targeted to be installed either online
or during the ninth refueling outage to facilitate
future power increases.
As these mods are only in the conceptual
scoping stage at this time, I just provide an overview
Improvements will be made to allow the
condenser to perform at higher efficiencies.
Improvements will be made to allow the condensate
polishers to operate in a balanced configuration at
the high condensate flows we expect.
Moisture separator reheater chevrons will
be replaced in order to improve the MSR and, thus, the
plant efficiency. Changes will be made to breakers,
conductors and relay schemes associated with the
switchyard to allow the increased megawatts electric
and MBA output of the plant.
Improvements to the exciter are planned
which will allow the plant to run at full capability
of the generator. Also, further improvements in the
cooling capability of the bus ducts are foreseen.
MEMBER SHACK: Dale, are you going to go
to noble metal additions in this cycle or has that
MR. WILLIAMS: We plan to inject noble
metals in the upcoming refueling outage.
MEMBER SHACK: So at the upcoming outage?
MR. WILLIAMS: Yes. That is correct.
MEMBER SHACK: But you don't count that as
a balance of plant, because you would have done that
-- I mean, you don't count that as an uprate mod,
because you would do that anyway?
MR. WILLIAMS: That is correct.
MR. SPENCER: That is correct.
MEMBER SCHROCK: What are the condenser
MR. SPENCER: They are currently targeted
for our next refueling outage a year and a half or so
down the road. The most likely changes are going to
be a continuous online cleaning system or a means of
continuous vacuum improvement for the upper tubes of
the condenser, and these are only in conceptual stages
MEMBER SCHROCK: How do you get 20 percent
more power out of the plant with the existing main
MR. WILLIAMS: The original condenser was
designed with large operating margins. We are
utilizing those margins.
MEMBER SCHROCK: I guess somebody has told
us that before, but I didn't remember it. It was
sufficient to give 20 percent higher power and still
MR. WILLIAMS: That is correct.
MR. SPENCER: I would like to now change
the focus of our presentation to concentration on
several of the analyses and evaluations which have
been performed in support of the EPU.
Listed on the slide are the specific areas
we will present. We will go over each of these right
now, but these areas have been chosen based on
requests from the ACRS as well as select areas covered
in requests for additional information responses to
We have prepared presentation material on
each of these areas, and our experts will be
presenting our findings in each area.
At this time, I'd like to introduce Bob
Kerestes who will discuss piping analyses used in
support of the EPU.
MR. KERESTES: Good afternoon. Thank you,
Dale. My name is Bob Kerestes. I work for the
AmerGen Corporation, and I'm the Project Engineer for
the extended power uprate project at Clinton Power
MR. KERESTES: I'm here today to present
a number of technical subjects to you. The first of
these will be the piping analysis which we performed
at the Clinton Power Station as part of the extended
power uprate project.
First I would like to point out that the
safety related pipe stress evaluations were performed
in accordance with ELTR1 and ELTR2. The result of
these evaluations are that all safety related pipe
stress levels are within code allowables, and no plant
changes are required.
Secondly, I would like to note that the
safety related pipe support loading evaluations were
performed in accordance with ELTR1 and ELTR2 or it was
qualified based upon more detailed analysis.
MR. KERESTES: On the next slide, please
let me explain further as it relates to the more
The detailed pipe support loading analyses
consisted of the following approach. We applied the
load factors to the individual load components that
were affected by the extended power uprate, i.e., the
thermal and the transient loads.
We also applied the extended power uprate
conditions and performed detailed analysis to update
the plant specific turbine stop valve closure
transient, and also we updated the plant specific
feedwater pump trip transient.
The results of these evaluations is that
all safety related pipe support loadings are within
code allowables, and no plant changes are required.
MR. KERESTES: On the next slide, I would
like to present our conclusions.
All safety related pipe stress and pipe
loading levels are within code allowable limits, and
no modifications are necessary. Our analysis showed
that we have five nonsafety related supports which
require modifications prior to start-up from our April
2002 outage. These supports are located in our
feedwater system outside containment.
All other piping and supports were
acceptable without any changes, and no new pipe break
locations were identified during our analyses.
In conclusion, with the completion of the
modifications planned during our April 2002 refueling
outage, all of our piping systems are acceptable to
support EPU conditions at the Clinton Power Station.
MR. KERESTES: The next subject which I am
going to present to you is the results of the
evaluation we performed on the flow accelerated
corrosion program at the Clinton Power Station as part
of the extended power uprate project.
MR. KERESTES: The provisions of Generic
Letter 89-08, Erosion/Corrosion in Piping, are
implemented at the Clinton Power Station by using the
Electric Power Research Institute generic program
CHECKWORKS. Clinton Power Station's specific
parameters are entered into this program to develop
requirements for monitoring and maintenance of
specific system components.
These requirements are then implemented
through plant procedures. In accordance with the
requirements, the Clinton Power Station flow
accelerated corrosion program was updated for
operation at the extended power uprate conditions.
This update identified several changes to
the predicted wear rates under its complements. We
have incorporated these changes into our program, and
have found that the most significant change is in the
predicted wall thinning rate to the main steamlines
carrying scavenging steam to the high pressure
CHAIRMAN WALLIS: Those wear rates sound
pretty high to me.
MEMBER POWERS: They do.
CHAIRMAN WALLIS: It all goes away so
MR. KERESTES: The wear rate went from 38
mils to 70 mils, which is about 80 percent. This
piping in this area, sir, is about a half-inch thick.
We will certainly continue to monitor this, and if we
find any areas that need replacement, we will take
action and replacement them.
CHAIRMAN WALLIS: Well, half an inch thick
isn't much at 70 mils.
MEMBER SIEBER: It will run a couple of
CHAIRMAN WALLIS: A couple of years,
MEMBER SIEBER: Take a number.
CHAIRMAN WALLIS: Seven years it's gone.
It's gone before then, because it's burst.
MR. CROCKET: Excuse me. I'm Harold
Crocket, and the analysis is made with some
conservative assumptions, and this was a bounding
limitation of this. We recognize that that is
probably a much higher wear rate than we would see,
but we would rather be anticipating wear rates of that
nature rather than go with the easy out.
This way we can monitor it, do our exams,
and feed in the actual measured wear, merge it with
the predicted wear, and get our line correction
factors, and this will refine the analysis.
MEMBER POWERS: You have been doing that
MR. CROCKET: Yes, sir.
MEMBER POWERS: And so -- I mean this
can't be enormously conservative, because it is taking
into account observational data that you have had in
MR. CROCKET: Well, this particular 70
mils is purely predictive. This has not been merged
in with a measured wear at the uprate conditions.
MEMBER POWERS: What's been the measured
wear rate at the un-updated?
MR. CROCKET: Oh, the actual measured wear
rate is much lower, and these particular lines, I'm
going to say, are on the order of 20 mils per year.
But I would have to look at it. It's closer to that.
CHAIRMAN WALLIS: Where does it go?
MR. CROCKET: Excuse me?
CHAIRMAN WALLIS: Where does it go?
There's a sludge somewhere?
MR. CROCKET: In the demineralizers
CHAIRMAN WALLIS: It gets filtered out.
So you can do a kind of conservation measurement in
MR. CROCKET: The other side is, as we see
systems that have significant wear, we upgrade it with
chrome alloy in order to eliminate damage from FAC,
and that's probably what is going to happen, because
we are not going to continue to monitor if we see that
it's apparent that the line needs to be upgraded.
That's ongoing in our long term strategy.
MR. WILLIAMS: We will obtain the actual
measured wear rates on this piping, and we can
communicate those in the morning when we reconvene.
CHAIRMAN WALLIS: Does it wear in a sort
of straightforward way or does it begin to wear and
get sort of -- I don't know what the wear pattern
looks like. If it's got ripples, I could see the
ripples actually increasing the wear rate, because
they stir things up.
MR. CROCKET: Yes, sir. That is correct.
CHAIRMAN WALLIS: Is it ripply wear?
MEMBER SHACK: It varies. There's the
tiger striping, and then there's more -- There's more
CHAIRMAN WALLIS: But it's not just a
smooth wearing. It's --
MR. CROCKET: Sometimes it is smooth.
Sometimes it is the tiger striping.
CHAIRMAN WALLIS: It's the wear which
itself could affect the wear rate, because it affects
the turbulence and so on.
MEMBER POWERS: It should be near and dear
to your heart, because chemistry and turbulence are
intimately connected here.
CHAIRMAN WALLIS: I'm just trying to get
the idea, how rapidly it develops once it begins to
get significant geometrical changes. Does it start to
wear more rapidly when it gets these significant
MR. CROCKET: You know, if we're looking
at, for example, a 16 inch diameter pipe, it's got
maybe a half-inch of wall, and we see at our exam at
R-4 that it's lost 50 mils and then we come back four
cycles later and it's lost another 60 or 80 mils, then
we're going to make a conservative assumption at that
point and probably replace it and upgrade the material
The systems that have significant wear, we
have a population expansion program. So if we see
degraded conditions, we continue to do examinations to
make sure that it has not gotten worse at other
similar trains or upstream/downstream locations.
It's not in our best interest to leave
pipe in place that continues to wear. When we see it
wearing, our first response is to try and upgrade the
MEMBER SCHROCK: Does your inspection
technique allow you to pretty much map the corrosion
MR. CROCKET: When you say map, are you
speaking along the run of the piping system or very
MEMBER SCHROCK: You were talking about it
being nonuniform, and you're concerned, I suppose,
with the thinnest place. How do you know that you
observed the thinnest?
MR. WILLIAMS: Describe our gridding.
MR. CROCKET: Yes, exactly. The gridding
-- we use EPRI recommended grid spacing, and at the
point we see low readings, we refine the grid and go
to a smaller mesh until we have ascertained where the
wear is going on.
MEMBER SCHROCK: Thank you.
MR. KERESTES: We will continue to monitor
and inspect our piping systems, again in accordance
with this latest update, to ensure plant and personnel
So in conclusion, flow accelerated
corrosion effects are acceptable at the extended
MR. KERESTES: The next subject I would
like to present to you is the feedwater nozzle fatigue
MR. KERESTES: First I would like to
provide you with some background. In our extended
power uprate submittal, we noted that the analyzed
fatigue usage factors for all components except the
feedwater nozzle were within the American Society of
Mechanical Engineers Section III allowable criteria of
CHAIRMAN WALLIS: They are within for how
long? For a long time in the future?
MR. WILLIAMS: Forty years.
CHAIRMAN WALLIS: Forty years? For the
life of the plant?
MR. WILLIAMS: That is correct, Dr.
Wallis. We analyzed for 40 years, including pre-
uprate and post-uprate operating conditions.
MR. KERESTES: Specifically, we noted that
the safe end on the feedwater nozzle exceeded the
fatigue usage factor of 1.0 and we would perform
evaluations in accordance with the American Society of
Mechanical Engineers code Section XI, Appendix L.
Further review indicated an alternate
analysis approach to attempting to lower the fatigue
usage factor. I would like to present to you that
ultimate analysis approach.
MR. KERESTES: This ultimate analysis
approach consisted of two areas. We used more refined
methods of analysis as allowed by the Code. These
include applying the scaling factors to the applicable
thermal stress terms, removing conservatism from the
flow scaling factor, and establishing pre-EPU and
post-EPU usage contributions.
We also utilized more accurate estimates
of plant operational cycles. These cycles are
verified by an ongoing fatigue monitoring program at
the Clinton Power Station which monitors the usage of
the feedwater nozzle during the life of the plant.
If we find ourselves getting close to 1.0,
we can perform fracture mechanics and additional
In conclusion --
CHAIRMAN WALLIS: Why is there fatigue in
the feedwater nozzle?
MEMBER SIEBER: Thermal.
CHAIRMAN WALLIS: Is there a lot of
fluctuation in temperature?
MR. WILLIAMS: Yes, as a result of
CHAIRMAN WALLIS: It's transients, but you
don't have many transients.
MR. WILLIAMS: Included in the plant
analysis are -- and contributions toward the analyzed
fatigue are thermal transients which the feedwater
nozzles are sensitive to. For example, loss of
feedwater heaters or other components of --
CHAIRMAN WALLIS: But these are sort of a
few dozen in the lifetime of the plant or something,
MR. WILLIAMS: That is correct.
MEMBER SIEBER: Hopefully.
CHAIRMAN WALLIS: It's not as if there's
some kind of a fluctuation in temperature which is
beating this thing all the time, is it? Very unusual
-- relatively unusual event, but you still have to
take account of it.
MR. WILLIAMS: That is correct.
CHAIRMAN WALLIS: Heat it up and cool
down, heat it up and cool down.
MEMBER SHACK: So this is basically a
Section III analysis with a fatigue curve that has no
environmental contribution versus a Section XI where
you would have had a K environment term.
MR. WILLIAMS: Sam, can you get to the
MR. RANGANATH: My name is Sam Ranganath.
I'm with G.E. Nuclear Energy.
The fatigue analysis is that using the
Section XI fatigue curves.
MEMBER SHACK: Section III or Section --
MR. RANGANATH: Section III fatigue
curves. There is some debate on how much
environmental effects are included in these fatigue
curves, and that's going on with the ASME code, but at
this point the --
MEMBER SHACK: Did you do an alternate
analysis with Section XI, Appendix L, to see what
difference it made?
MR. RANGANATH: One can do -- postulate a
crack and do a crack growth analysis to --
MEMBER SHACK: Appendix L wouldn't
postulate a crack, right? That would just be a smooth
-- with a K effective.
MR. RANGANATH: There are several ways --
options that are available to do the Appendix L
analysis. One is to include an environmental
correction factor, but I believe that much of the
conservatism in the correct analysis comes from we
assume step changes, for example.
This is an idealized thermal cycle diagram
that was developed when the plant was designed, and we
have found over time through fatigue monitoring that
these step changes and so on are extremely
So I think we probably have more than
enough conservatism to account for even any postulated
MEMBER SHACK: What is your usage factor
now with the new analysis?
MR. KERESTES: Right now that number is
MEMBER SHACK: Not a lot of margin left
MEMBER POWERS: Approximately, right?
MR. RANGANATH: The feedwater nozzle with
the double -- triple sleeve has been a very effective
system, and we have not -- in the last 15 years
there's been no issues relative to fatigue.
MEMBER SHACK: I mean a design to reduce
thermal stresses, you would think, would show up in
MR. RANGANATH: Actually --
MEMBER SHACK: It's still .873.
MR. RANGANATH: -- the bulk of the fatigue
contribution comes from what's known as the low cycle
end of it. The high cycle end of it is the one that
gives you the rapid cycling, which has been the focus
The triple sleeves farger has pretty much
caused out the high cycle fatigue aspect of it. So we
are tinkering with probably a very conservative
analysis for the low cycle fatigue, and wherever we
have seen actual fatigue monitoring, we find that the
step changes are not anywhere near what we have
assumed in the analysis.
So I really believe that this is over many
plants when we looked at actual fatigue monitoring.
The thermal cycles are a lot less severe than what we
MEMBER SHACK: What did your more refined
method of analysis do for you here?
MR. RANGANATH: What we have done is we
have done scaling factors of the original assumptions.
So the thermal -- for example, the flow rate are
higher. So you account for the heat transfer effect.
We also look at actual number of cycles
versus postulated numbers. So that's what was done to
refine the fatigue analysis. But the fact remains
that the original fatigue analysis probably was very
CHAIRMAN WALLIS: This is irrelevant,
because thermal fatigue has caused pipe failures, I
believe. It's not something unheard of.
MR. RANGANATH: Yes. That has happened,
and the triple sleeves farger was intended to
eliminate the leakage that you get, and that's why the
high cycle or rapid cycling that caused the original
fatigue cracks in the feedwater nozzle is pretty much
eliminated, and it's been a very successful
MR. WILLIAMS: Dr. Wallis, I should
supplement the discussion we had on operational
transient contributions. In addition to operational
transients due to equipment problems, the normal
start-up and cool-down cycle of the reactor also
MR. KERESTES: So in conclusion, in the
analysis we are now completing we will demonstrate
that the feedwater nozzle safe end cumulative usage
factor will remain less than 1.0 over the 40 year life
of the Clinton Power Station.
I would now like to --
CHAIRMAN WALLIS: You will demonstrate, as
far as that it's a "will"? You will do an analysis.
It says "will demonstrate." That's a statement of
MR. KERESTES: No. As I noted, right now
we have the final draft report form General Electric.
We are reviewing that report on site, and going to
approve it shortly.
CHAIRMAN WALLIS: So the analysis has been
done, and it does show this?
MR. KERESTES: Yes, it does show this.
CHAIRMAN WALLIS: It's just a question of
recording it and mailing it?
MR. KERESTES: Thank you. We do have the
report. It does show this, and we are in the process
of approval on site right now.
Any further question? I would now like to
introduce Mr. Keith Moser of Exelon Corporation, who
will present the topic of reactor and internals.
MR. MOSER: I'm Keith Moser. I'm the
Reactor Internals Program Manager, and I've got Sam
Ranganath. He's my counterpart with G.E. Nuclear.
You know, a couple of months ago we were
here talking about Dresden and Quad power uprate and
how we do an asset management strategy, go component
by component. One of the nice things about a BWR-6 of
Clinton's vintage is you don't have a lot of the
material issues, that we've got the improved heat
treat beams for the X750. We've got low carbon --
Yes, we replaced those out in 1994.
We've got the low carbon stainless steel,
and when we walk through all the different components,
you know, you basically get to the same place we were
with Dresden and Quad. There's two issues that you
are really thinking about.
You have, obviously, accounted for the
delta P, increased delta P in your fall handbook. So
that's covered. But the two areas that you are
thinking about is what am I going to do with the
Now for the pressure vessel, what we did
back in the summer of 2000, we wanted to incorporate
the two code cases so we would get some benefit from
lower hydrostatic test pressures. When we did that,
we said we know we are going to power uprate. So
let's see what we can do with the fluence estimations
at that time, and we scaled it up so we wouldn't have
to repeat the calculation.
Well, in hindsight that wouldn't have been
necessary, because the improved methodology that just
got NRC topical approval essentially says we were
already conservative, even with EPU conditions.
The next thing that we are looking at is
we are going to be doing the shroud inspections. The
shroud inspections are coming up this spring. What we
are doing is we are doing a fluence profile, again
with the same neutron transport calculation, making
sure that we account for where we have high fluence
welds, what the fluence profile is through-wall and
Then when we get the inspection results,
hopefully, we won't have anything but we will be able
to better characterize how to do the flaw evaluations.
That kind of takes care of where we're at
on the increased fluence that you would expect with
the power uprate. The other area is also the
increased steam flow that you are going to get.
MR. MOSER: Most of the places that would
show up with would be your dryer. For this dryer, you
know, we've done the analysis. It says that we won't
have any problems, but just like at Dresden and Quad,
we've gone back and said historically have we seen --
Just the last outage we went and looked at some of the
dryer components and the separate components.
Then this cycle when we come down in the
spring, we are going to again look at the dryer so we
get a real good benchmark. Then after power uprate,
we are going to go back and look again, just to make
sure we didn't miss anything.
When you do that, you know, essentially
what we've concluded is that our reactor internal
systems and our pressure vessel -- we've pretty much
conservatively bounded all the effects that power
uprate are going to have, and believe that they are
acceptable for EPU conditions.
Are there any questions?
CHAIRMAN WALLIS: These fatigue cracks in
the steam dryer, they were actually observed at
Clinton or somewhere else?
MR. MOSER: You know, we have some small
amount of cracking at Clinton. We're not sure if it's
IGSEC or not, because it's pretty much stopped. The
place, if you remember, is Peach Bottom. We had some
fatigue cracks there.
What we are doing is we're coming up and
getting the metallurgical samples done to see if we
can't see the beach marks and striations. Again, Sam
Ranganath and his team are taking some of the
information we've got from other places and seeing if
we can't refine our finite element model to better
predict when you may run into these things for our
MEMBER SHACK: Are these stainless steel
MR. MOSER: Yes, absolutely.
MEMBER SHACK: Is your shroud 304L?
MR. MOSER: It's an L grade, yes. But
again, 218 vessel, a little more compact than the
Dresden models we talked about before. Therefore, you
are going to get to those fluence levels a little bit
earlier in life.
MEMBER SHACK: What is your fluence level
in your shroud welds now?
MR. MOSER: You know, it's above 5 x 1020,
slightly above that right now.
MEMBER SHACK: Slightly above it?
MR. MOSER: It's about 80, if I remember
right, and we've just gotten a neutron transport
calculation. Before we go in the outage, we are going
to do a full blown fluence profile, like I said. So
I could better answer that question a little bit
later. But as you know, that's only for certain
Then we will be factoring in the new VIP
documents, VIP 99, I believe, and VIP 100 on fracture
toughness and crack growth rates, if there is any
cracking to be observed.
Any other questions?
MEMBER SCHROCK: I guess these things are
all plant specific that you are talking about here?
MR. MOSER: Yes, sir.
MR. SCHROCK; It seems almost generic, in
MR. MOSER: Well, the concepts, the
approach is fairly generic, how we go through each one
of these different asset management strategies or
component by component look. But we always use the
plant specific values. Thank you.
MR. WILLIAMS: We would now like to
discuss core and fuel with Fran Bolger of General
MR. BOLGER: I'm Fran Bolger from General
Electric. I'm going to discuss the core and fuel
design that was done for the power uprate. Next
MR. BOLGER: As part of the power uprate
process, an equilibrium core was developed. The
equilibrium core was 18 month cycle design with GE 14
fuel. In this equilibrium core design it was
demonstrated that the core had sufficient shutdown
margin, MCPR margin and LHGR margin, if operated at
Recently, we have also completed the
reload analysis for the next cycle 9 core which is
implementing EPU, and I would like to show some of the
details of the cycle 9 core. Next slide, please.
MR. BOLGER: This slide is a summary of
the cycle 9 core. IF you look over on the left side,
there is a core map picture. The color bundles, the
shaded green and the gray bundles are the fresh fuel
to be loaded in cycle 9.
If you look in the slide, you will notice
in the center of the box there's a value. In some
cases you see a zero. That's indicating it's at zero
exposures. Some of the other bundles -- for example,
you will see the bundles out on the periphery are at
a higher exposure, on the order of 30,000.
The lower value on the box is the bundle
type. The bundle type corresponds to the column
labeled IAT on the bottom of the chart. This chart
shows the fuel which will be resident in cycle 9.
There is a two times operated batch of GE 10 fuel.
There's a once burned batch of GE 14 fuel and a large
fresh batch of GS 14 fuel. The batch is 268 bundles.
I'd like to describe some of the margins
that were calculated for cycle 9. Let me say first
that this core was designed for not -- Yes, question?
CHAIRMAN WALLIS: This is an eighth of a
MR. BOLGER: It's a quarter core.
CHAIRMAN WALLIS: You would think an
eighth of a core would be good enough. But then it's
not quite -- I notice the numbers aren't quite
symmetrical, I notice.
MR. BOLGER: It's close to octein
CHAIRMAN WALLIS: Pretty close, but you
would expect them to be.
MR. BOLGER: There is some small variation
in there. If yo look at the reflected quadrants, you
will see some small differences as well.
CHAIRMAN WALLIS: Is that because of the
way in which the calculation was run, so that if you
saw them one way and you run across something --
MR. BOLGER: Well, one of the main reasons
is when the rod patterns change throughout the cycle,
they are varied as a function of the cycle, and
different rods are inserted. For example, you see
this group of rods inserted. This happens to be a
symmetric pattern, but later in the cycle you do a
sequence exchange, and you may insert this rod here in
So there's a natural tendency to shift
the power away from octein symmetry, and then what you
will do later in the cycle is set another pattern that
will shift it back. So it will tend to achieve octein
symmetry throughout, although there will be a small
amount of variability.
These columns are some of the margins for
the cycle 9 design. This lefthand column is the cycle
exposure in megawatt days per short ton.
The next column is the Eigen value. The
predicted Eigen value for this cycle -- This was
predicted based on a previous cycle operation in the
expected performance of the GE 14 reload.
You will notice the core flow goes below
the minimum on the power flow map, which was 99
percent. This is because this core and these results
are shown at about 90 percent EPU power, because it's
a transition to the next cycle, which will be at full
This next column is the ratio of the MCPR
operating limit to the calculated MCPR. In the case
of the MCPR, the core was designed for a maximum ratio
of MCPR of .93. So you will see in this example that
the maximum through the cycle MCPR ratio is only .88.
So it had about five percent margin to the design
The next column is the MLHGR ratio, which
is the ratio of the calculated LHGR to the LHGR limit.
In the case of the LHGR, this was designed to a design
target of .91, and you can see that the actual design
had about two percent margin to the design target.
The last column is -- The second to last
column is a ratio of the average planar LHGR to the
average planar LHGR limit, and it's similar to the
LHGR, had about a .9 relative to the design target of
The last column shows the axial power
shape through the cycle. This is a core average axial
power shape. The value is presented, and then in
parentheses is the axial node.
So you notice that the core tends to burn
toward the bottom as you operate through the cycle.
Then as you get toward the end of the cycle, the power
shape will move toward the middle of the core.
In summary, the core provides the desired
energy, has adequate MCPR margin and LHGR margin, as
required by the reload process. Next slide, please.
MR. BOLGER: As is done for full power
uprates, the thermal limits monitoring power level is
scaled down. In the case of Clinton, it is scaled
from a value of 25 percent to a value of 21.6 percent
of the EPU power. Next slide, please.
MR. BOLGER: A conclusion: Adequate
margins have been demonstrated in equilibrium design
as well in the cycle 9 core design.
CHAIRMAN WALLIS: Are you putting in any
kind of new fuel? I forget now.
MR. BOLGER: No. This is the same fuel
type that was loaded in the previous cycle.
MEMBER SIEBER: I presume that you believe
that future cycles will also be able to take full
advantage of the EPU rating?
MR. BOLGER: Yes. There was a equilibrium
core analysis that was performed which did show
adequate margins in a "when operated at full EPU."
MEMBER SIEBER: Okay.
MR. BOLGER: The next presenter is Kent
Scott from AmerGen.
MR. BYAM: My name is Tim Byam. I'm with
AmerGen. Dr. Wallis, we have reached the portion of
our presentation which is proprietary. It contains
General Electric proprietary information.
MR. BOEHNERT: Well, then we need to ask
people who are not approved to hear G.E. proprietary
material to leave the room. How long do you think the
session is going to take?
MR. BYAM: Approximately 30 minutes maybe.
MR. BOEHNERT: Thirty minutes? Okay.
Well, if you gentlemen want to go over into the next
room and then come back in about 30 minutes, we would
let you back in the room.
So we don't have any problem with anybody
here? Okay, continue.
Transcriber, we will go into closed
session, closed session transcript.
(Whereupon, the foregoing open session
went off the record for closed session at 4:19 p.m.
and went back on the record at 5:02 p.m.)
CHAIRMAN WALLIS: Are we going to keep
MR. SCHWEITZER: Keep going. Next I would
like to present the Clinton Mark III containment
MR. SCHWEITZER: To evaluate the
containment for EPU, we followed the established
method for the containment analysis in ELTR1. The
limiting events that were analyzed were the main
steamline break, the recirculation suction line break,
and the alternate shutdown cooling.
MR. SCHWEITZER: The next slide shows a
summary of the results. This table shows the drywell
and containment pressures and temperatures and the
suppression pool temperature following the analyzed
The first column of values on the left are
the original analysis in the Clinton updated safety
analysis report. The second column of values are the
comparison benchmark cases which use the EPU methods
with the original licensed power.
The third column of values are the EPU
results, and the last column shows the design basis.
Comparing the first and second columns
shows the change in methodology. Comparing the second
and third column shows the effective of EPU, which is
relatively minor with a no vessel pressure change.
And comparing the third and fourth column shows the
margins to the limits.
I'd like to point out that all remain
below the design limit with the exception of the
drywell temperature. This value is above the design
temperature of 330 degrees for less than .5 seconds.
This has been evaluated as acceptable, because there
is insufficient time to heat up the structure.
MR. SCHWEITZER: The conclusion of these
results is that Clinton performance of the containment
is acceptable at EPU conditions.
CHAIRMAN WALLIS: The peak temperature
doesn't really impose some load by itself, does it?
It has to heat something else up. Peak pressure would
immediately stress whatever is around it.
MR. SCHWEITZER: Correct.
CHAIRMAN WALLIS: The temperature takes
some time, particularly with all these masses of
MR. SCHWEITZER: And this is a temperature
MEMBER KRESS: And time is a relevant
parameter to have in your limit? Why do they have --
They don't specify a time for it. Why do you feel
that time is an appropriate way to accommodate being
above the limit?
MR. SCHWEITZER: Well, the temperature is
a structural design limit, and with the atmosphere
changing for such a short spike, the structures don't
change in temperature.
CHAIRMAN WALLIS: So it really should be
a design -- a structural limit on temperature, not a
MR. PAPPONE: This is Dan Pappone. It's
showing the 330 degree temperature limit. It really
is a structural limit. It also factors into the
equipment environmental qualifications, and both of
those do have a time element in them.
So in this case, we are talking about a
very brief transient right at the beginning. We are
picking up a little bit of the compressive heating
effect as we are squeezing it before we clear the
vents, and it drops right down.
If we looked at the actual temperatures
that the structure would see and the equipment in
there would see, there's a time lag, and they wouldn't
be coming up near the 330.
CHAIRMAN WALLIS: I think all you need to
do is show by back of envelope or something that the
time concept of these things is much longer than the
actual time for which it's subjected to this
MR. PAPPONE: That's right.
MEMBER POWERS: I guess I'm missing
something. My intuition is bad here. You increase
the amount of energy that you are putting into the
drywell and eventually into the containment by roughly
20 percent. Well, where does it go? I mean, all
these numbers go down or marginally move up. Where's
the energy go?
MR. PAPPONE: The energy is really showing
up in the peak suppression pool temperature, and
that's the long term part. That's where you are going
to see the higher decay heat from the core showing up
in the pool, and you've got to get up to a higher
delta T across the higher temperature difference
across the heat exchangers in order to be able to
remove that energy with the fixed service water side
conditions that you have.
The short term part as far as peak
temperatures and peak pressures, those are driven
almost exclusively by the pressure in the vessel. We
are keeping that constant, so when we break the pipe
and it comes rushing out, we've got the same driving
MEMBER POWERS: So if looked at a time
plot on these things, I would find that if I
integrated that, I would get my 20 percent back?
MR. PAPPONE: Yes. The 20 percent would
show up in the pool temperature, and I believe that is
what the results are showing.
MR. SCHWEITZER: You can see that between
the comparison of column 2 and 3.
MR. PAPPONE: Right. The ten degree
increase in the pool temperature due to the power
uprate is that piece that's due to the core power
CHAIRMAN WALLIS: Why is it limited to 185
degrees Fahrenheit? What are you concerned about, if
it goes above 185?
MR. PAPPONE: The concern there is the
partial pressure in the air space in the containment
part. Well, the containment is a large structure. So
it's not like the earlier containment, Mark1/Mark2
containments that had a 56 to 62 psi design pressure.
This has a much smaller one.
CHAIRMAN WALLIS: So it's the effects of
this temperature on the pressure that you are
MR. PAPPONE: That's right.
CHAIRMAN WALLIS: Really, the bottom lien
is the pressure, isn't it?
MR. PAPPONE: That's right.
CHAIRMAN WALLIS: And you are not taking
this water and pumping it somewhere else. It's not a
question of --
MEMBER KRESS: It's a big pool.
CHAIRMAN WALLIS: It's a big pool.
MR. PAPPONE: They've got the big pool in
there, and we're cooling that pool remote, if you
CHAIRMAN WALLIS: Do you have a picture of
this containment somewhere?
MR. PAPPONE: Do we have one?
CHAIRMAN WALLIS: I'm just trying to
MR. PAPPONE: I could draw a sketch for
you real quick, if you like.
MR. SCHWEITZER: Would you like a sketch?
CHAIRMAN WALLIS: Well, maybe you can make
a sketch. We can go on. You can hand it to me in ten
minutes or something. Are we done for the day now?
MR. WILLIAMS: Dr. Wallis.
CHAIRMAN WALLIS: Okay, make the sketch.
Please make the sketch then.
MR. WILLIAMS: Dr. Wallis, while he's
making the sketch, we are prepared to clarify the
issue on the core flow.
CHAIRMAN WALLIS: Yes.
MR. WILLIAMS: If you would give us a few
CHAIRMAN WALLIS: Sure.
MR. WILLIAMS: We would like to
reintroduce Kent Scott to discuss it.
MR. SCOTT: Thanks, Joe. Again I'm Kent
Scott from AmerGen. Did a little bit of research with
respect to the differences between the core flows on
the two power to flow maps, the existing one and the
new power to flow map, the 105 percent vice 107
What I found was that the -- So the
licensed value for core flow is 107 percent of the
original rating or 90.4 millions pound mass per hour.
That's what is shown on the original power to flow
CHAIRMAN WALLIS: That's what we see here.
MR. BOEHNERT: Right.
CHAIRMAN WALLIS: It's not quite the same
as the one that we saw on the handout.
MR. SCOTT: That's right. Well, a little
bit of history. After implementation of the increased
core flow licensing change, we found that the plant
was only able to achieve 102.5 percent core flow.
With this in mind, the cycle 9 reload
design used a limiting value of 105 percent for core
flow. This was done to provide additional operating
margin from thermal limits. So when they did the
reload design for cycle 9, they looked at it and said,
well, we're not going to be able to get to the 107
percent licensed limit; let's use 105 percent, and
that will give us additional operating margin to
So that was the basis for the difference
between the two. Thanks.
MR. WILLIAMS: Thank you.
MR. BYAM: I believe we've reached --
CHAIRMAN WALLIS: We're just waiting for
Dan to draw us a sketch to go home.
MR. BYAM: We're waiting for our artist to
MEMBER SIEBER: It looks a lot like the
CHAIRMAN WALLIS: Do the Subcommittee have
any other questions to raise while we are waiting for
the picture? Any observations?
MR. BOEHNERT: There it is.
MR. PAPPONE: This is a quick sketch of
the Mark 3 containment where we've got the reactor
vessel sitting inside of a cylindrical concrete shell.
We've got a large, large steel building, another
All of the refueling stuff is inside of
the containment up here above the drywell, and got the
suppression pool in here. We've got a weir wall with
a set of three horizontal vents.
Now where do we want to go with this?
MR. SCOTT: Talk about the various design
pressures and temperatures?
MR. PAPPONE: Right. I guess the biggest
difference when you are looking back at the --
comparing this to the earlier containments is you've
got this big, big containment air space volume.
CHAIRMAN WALLIS: Drywell and wetwells are
MR. PAPPONE: This is the drywell region
CHAIRMAN WALLIS: I could never figure out
why it was dry, but I guess that's the drywell.
MR. PAPPONE: Because we've got the big
pool of water here, and that's the wetwell. In the
earlier containments, the Mark 1, the Mark 2
containments, the drywell volume and the wetwell
volume were about the same.
CHAIRMAN WALLIS: This is the one where
you have the vent clearing of the three, and you have
a big bubble that comes through and all that stuff.
MR. PAPPONE: All of them have some form
of vent clearing. All of them have some form of big
bubble. But in here, the key difference is that we've
got this big, big full reactor building structure and,
because that structure is so big, it's not designed
for the 60 psi loads, pressure loads, inside.
That's where the concern was. We heat
this up to 185 degrees. We get a partial pressure of
water up here that gets close to that design pressure
CHAIRMAN WALLIS: This is still very low
compared with the design structural limit of 15 psi.
MR. PAPPONE: Right. The structural limit
here is a 15 psi compared to the 60-ish. The
structure here is still the same 60-ish psi.
MEMBER SIEBER: But you never achieved
MR. BOEHNERT: Jack, we can't hear you.
MEMBER SIEBER: Oh. You never get close
to 60 psi in the drywell in any accident. Is that not
MR. PAPPONE: For those other -- For any
of these, no. The earlier containments, we get fairly
close to it. The Mark 1s we get up there, not all the
way. The 62 psi, as I say, is a transient
MEMBER SIEBER: Then you have automatic
relief through the suppression.
MR. PAPPONE: Right. The whole
suppression -- pressure suppression containment
relieves that pressure through here with the idea that
we are going to condense that steam here and not
subject the rest of the building to that pressure.
MR. BOEHNERT: So the wetwell air space
load is for controlling over the hydraulic loading at
MR. PAPPONE: At 185 that's where we're
looking at the pressure loading across this part of
MR. BOEHNERT: That was controlling?
MR. PAPPONE: The structural load here is
feeding back into the air space pressure here that
then feeds back into the pool temperature limit.
CHAIRMAN WALLIS: Okay. thank you. Do we
look ahead to tomorrow or have we got something else
to do today?
MR. BYAM: We are prepared to continue, if
you would like, or we can break at this point.
CHAIRMAN WALLIS: No, I think you can
break at this point. We don't seem to have that much
to do tomorrow.
MR. BYAM: No. I think that --
CHAIRMAN WALLIS: The bulk of it concerns
Bill Burchill's risk analysis. Is that the bulk of
MR. BYAM: Yes, as well as project
CHAIRMAN WALLIS: And we should be able to
do that, say, in about an hour?
MR. BYAM: I would say an hour and a half,
MEMBER POWERS: Do we have somebody on the
committee to play Steve Rosen?
CHAIRMAN WALLIS: Any volunteers?
MEMBER POWERS: Well, I am noticing that
they are going to discuss large transient testing.
CHAIRMAN WALLIS: That's right.
MEMBER POWERS: And I peeked ahead,
perhaps illegitimately. I noticed that they are not
in favor of large transient testing. I was shocked to
CHAIRMAN WALLIS: It's the same arguments
we had before.
MEMBER POWERS: And as you will recall,
the bulk of the ACRS thought that was fine, but we had
one strong dissenting opinion. Are we going to be
able to reproduce his arguments? I can't.
MEMBER KRESS: No, but we can give him a
chance during the full Committee meeting.
MEMBER POWERS: Well, I was hoping we
could avoid that.
CHAIRMAN WALLIS: He essentially takes the
view that, no matter how much you believe that you've
got it all under control and you can calculate things,
you never really know until you test it.
MEMBER SHACK: He's a structuralist,
despite being a PRA man.
CHAIRMAN WALLIS: Yes. He's a doubter.
I guess he has enough experience behind him.
MEMBER POWERS: Why don't you just put
that on your Vu-Graph, that only a structuralist would
endorse doing these tests.
CHAIRMAN WALLIS: Well, I wish we would
get away from this labeling people as one thing or
another, as if there were some sort of religion
involved here. We can all be rational without being
called rationalists, I hope.
MEMBER SHACK: I would hope that I didn't
-- Scratch a rationalist hard enough, and he becomes
MEMBER POWERS: As we found out.
CHAIRMAN WALLIS: We could turn you into
a conservative, too.
MEMBER POWERS: I don't think so.
CHAIRMAN WALLIS: I think we're through
MR. BYAM: Would the committee like a more
formal drawing of the containment? Would that be
CHAIRMAN WALLIS: Sure. It would be very
nice to have a picture in the morning.
MEMBER POWERS: I think we've got one.
CHAIRMAN WALLIS: I remember this sort of
thing. Yes, that's fine.
MEMBER POWERS: I don't think I would
knock myself out on that. I'm sure we can find one.
MR. BYAM: Thank you.
CHAIRMAN WALLIS: Anything else the
committee would like before we break? We are going to
recess. Is that the word?
MR. BOEHNERT: Recess.
CHAIRMAN WALLIS: Recess until tomorrow
morning at 8:30, and then we will finish your
presentations in a little over an hour, we hope, and
then we need to hear from the staff. That should take
us until lunchtime tomorrow.
MR. BYAM: Thank you.
CHAIRMAN WALLIS: And if there is no
impediment to that, I will close the meeting today.
Thank you all very much for your
(Whereupon, the foregoing matter went off
the record at 5:18 p.m.)