ML090840402
| ML090840402 | |
| Person / Time | |
|---|---|
| Site: | Indian Point  |
| Issue date: | 03/04/2009 |
| From: | Advisory Committee on Reactor Safeguards |
| To: | |
| Wen P | |
| References | |
| Download: ML090840402 (392) | |
Text
NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION
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ADVISORY COMMITTEE ON REACTOR SAFEGUARDS
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SUBCOMMITTEE ON PLANT LICENSE RENEWAL
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MEETING + + + + +
WEDNESDAY MARCH 4, 2009
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ROCKVILLE, MD
+ + + + + The Subcommittee convened in Room T2B3 in
the Headquarters of the Nuclear Regulatory Commission, Two White Flint North, 11545 Rockville Pike, Rockville, Maryland, at 8:30 a.m., Mr Otto Maynard, Chair, presiding.
SUBCOMMITTEE MEMBERS PRESENT:
20 21 22 23 24 25 OTTO MAYNARD, Chair JOHN STETKAR MICHAEL CORRADINI CHARLES H. BROWN, JR. HAROLD B. RAY NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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6 7 MICHAEL T. RYAN MARIO V. BONACA WILLIAM J. SHACK DANA A. POWERS J. SAM ARMIJO SANJOY BANERJEE JOHN D. SIEBER NRC STAFF PRESENT:
8 9 10 11 12 13 14 15 BRIAN HOLIAN KIMBERLY GREEN GLENN MEYER STAN GARDOCKI NAEEM IQBAL BARRY ELLIOT SHERWIN TURK ALSO PRESENT:
16 17 18 19 20 21 22 23 24 FRED DACIMO TOM McCAFFREY GARRY YOUNG ALAN COX NELSON AZEVEDO DON MAYER REZA AHRABLI PHILLIP MUSEGAAS NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 T-A-B-L-E O-F C-O-N-T-E-N-T-S Introductory remarks...............................5 Staff introduction Brian Holian...........................8 Entergy -IP Renewal Application Background..................................12 Brian Holian Preparation of application and commitments and plans to implement Garry Young...........................24 Open Items Tom McCaffrey.........................38 Auxiliary feedwater pump fire event Alan Cox..............................44 Structural monitoring programs Rich Drake............................50 Reactor vessel integrity and buried piping aging management program Nelson Azevedo.......................106 1973 feedwater event.......................118 SER Open items.............................133 NRC Staff Presentation Overview Brian Holian.........................184 Scoping and Screening results NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Kim Green............................188 On site inspection results Glenn Meyer..........................207 AMP and AMR results Kim Green............................222 TLAA results Kim Green............................228 Open Items Kim Green............................241 Public Comment Phillip Musegaas, Riverkeeper........275 Subcommittee Discussion..........................291 Closing remarks by staff.........................301 Closing remarks by Entergy.......................303
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 P-R-O-C-E-E-D-I-N-G-S 8:29 a.m. CHAIR MAYNARD: All right. The meeting
will now come to order. This is a meeting of the Plant License
Renewal Subcommittee to review the Indian Point Units
2 and 3 license renewal application. I'm Otto Maynard, Chairman of this
Subcommittee. ACRS members in attendance are Jack
Sieber, Sanjoy Banerjee, Sam Armijo, Dana Powers, Bill
Shack, Mario Bonaca, Michael Ryan, Harold Ray, Charles
Brown and John Stetkar. We're expecting Michael
Corradini to joint us in a little bit. There are some other meetings going on
today so there are occasions that some of the members
may be stepping out and stepping back in. The purpose of this meeting is to review
the license renewal application for the Indian Points
Units 2 and 3, the staff Safety Evaluation Report with
open items and associated documents. We will hear presentations from
representatives of the Office of Nuclear Reactor
Regulation and the applicant, Entergy Nuclear
Operations, Incorporated.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 We also hear comments from Riverkeeper at
the end of the meeting. The Subcommittee will gather information
and analyze relevant issues and facts and formulate
proposed positions and actions as appropriate for
deliberation by the full Committee. There will be no
decisions made as to the ACRS's rejection or
acceptance of any of the applicant or staff's review
today. This can only be done by the full Committee. The rules for participation in today's
meeting were announced as part of the notice of this
meeting previously published Federal Register on February 13, 2009. We have received written comments from Ms.
Deborah Brancato of Riverkeeper who also requested
time to make oral statements regarding today's
meeting. We'll grant Ms. Brancato time at the end of
this meeting to make her statements. A transcript of the meeting is being kept
and will be made available as stated in the Federal Register notice. Therefore, we request the
participants in this meeting use the microphones
located throughout the meeting room, identify
themselves and speak with sufficient clarity and
volume so that they can be readily heard.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 We have several people on the phone bridge
line listening to the discussions today. To preclude
interruption of the meeting, the phone line is placed
in a listen-in mode. It's my understanding that Ms.
Brancato is on one of the phone lines and when it's
time for her comments, we'll open the bridge line so
we'll be able to hear and communicate with her. I'm not going to go over the details of
the plant because I think that's going to be covered
by the applicant and staff in their presentations. I
will say that this review is a little unique in that
these two plants are the same NSSS design and on the
same site, but built and operated by two different
utilities and operated that way for a number of years.
And therefore, that has created some challenges for
me in just reading the document, keeping the plants
straight what's the same, what's the different. And
I'm sure that created a challenge for the staff and
I'm going to be interested in hearing how both the
applicant and the staff handled the differences and
the similarities for the two. We have a lot of material to cover today, so we've scheduled this for a full day rather than a
half day like we have been doing for most of the
applications here lately.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 We'll note also that this one come to us
with a few more open items then what we've seen
recently. I'd like to have the staff discuss that just
a little bit. And to keep from taking up anymore time, I'd like to proceed with the meeting and call on Mr.
Brian Holian of NRR to introduce the speakers and
today's talk. MR. HOLIAN: Good. Thank you. And good
morning, ACRS. My name is Brian Holian. I'm the Division
Director for the Division of License Renewal in NRR. First, I'd like to cover some
introductions and then briefly comment on the schedule
and the application and then turn it over to the
utility. To my right, far right, is Ms. Kimberly
Green. She's been the project manager for Indian Point
throughout. And you'll be hearing in particular from
her later during the staff presentation following the
applicant's presentation. Immediately to my right is Mr. David
Wrona. He's the branch chief responsible for several
plants, including Indian Point. We do have several members of the staff NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 that you'll be hearing from later in the audience, but
in particular I'd like to recognize our regional
representatives here today. To my left Mr. Glenn
Meyer, the senior inspector from the region who you'll be hearing from on a summary and inspection report.
And to his right Mr. Richard Conte, the branch chief
from the Division of Reactor Safety in Region I. Just a couple of comments relating to
Indian Point. It has had an extended schedule, so I'd
like to talk about schedule in particular and as that
relates to the open items, as Mr Maynard had said. I've been back from Region I for about
eight or nine months now, and one of the first actions
I had to do coming back was to extend the Indian Point
schedule by about four months last summer. There are
several reasons for that. (1) As most people know, Indian Point is
in the ASLB hearing process that we have five plants
in license renewal in the hearing process right now.
That results in a number of contentions and a number
of issues which is a good process that provides the
public an opportunity to comment on individual items. The impact on license renewal staff is
each of those items that are contentions in the
hearing process takes staff that are working on our NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 SER and issues there also to support OGC through that
deliberative process. So that's one item that effects
us. The other item that happened probably a
year before the Indian Point application as it was
coming in was the Inspector General did a lengthy
review of the license renewal process at the NRC. And
we had a report both complimentary and critical of
that license renewal process that came out from the
Inspector General. Interestingly, Indian Point the audit
process and the initial SER process was hitting as the
staff was reviewing and looking at the recommendations
from the Inspector General's report. And one of the
areas you'll see I think today is that the staff took
the opportunity to make some improvements in the
operating experience aspect: How well we look at the
operating experience, how well we document that. And
as I reviewed the Indian Point Safety Evaluation
Report I was glad to see a lot more material in there
on operating experience and how that informs our
process and informs our aging management reviews. So
you'll hear more from that later on. On open items in particular that's from
the staff's view, you know, not good and not bad. You NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 know, I've covered both sides of that. We've had a history of a number of open
items on several plants as I look back at the plants
over the last five years or so. As you go back, we
had a plant with up to close to 40 open items. We've
had plants within the range of five to eight over the
several years. Indian Point was centering in around
20 open items. A lot of that is due to schedule. You
know, I mentioned at some point we have to cut off our
Safety Evaluation Report and get the document ready
for publication and out to the committees. So we
continue to work those open items, as we call it, even
after we close the SER with open items and issue it to the Committee. So you'll see some of that today.
You'll see that we've continued over the last several
months working with the applicant on addressing those
open items. Even as we closed this SER out with open
items, we had a response from the applicant addressing
some of those open items. And we had some choices to
make, and that was to either delay the ACRS meeting
further or just continue to work the items. And we
chose that path. So I think as you'll see some of the open
items that we go through, they're routine and aren't NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 necessarily indicative of any application deficiencies, really. I would state it like that.
It's more an aspect of where we are in the review and
when we cut the open items off. So with that, I'd like to turn over to the
Vice President of License Renewal for Entergy, Mr.
Fred Dacimo. MR. DACIMO: Good morning. Thank you, Brian. Good morning, Mr. Maynard. My name is
Fred Dacimo. I'm Vice President for License Renewal. Would you like us to get right into the
presentation this morning? CHAIR MAYNARD: Yes, I would. MR. DACIMO: Okay. Good. Thank you.
Okay. So if we can bring that up. I'm going to introduce the people that we
have Entergy from this morning. Joe Pollock is in the audience. Joe is our
site Vice President. As you mentioned, I am Vice
President of License Renewal, formerly site Vice
President. John McCann is our Director of Licensing
from Corporate Entergy. Don Mayer is our Director of Emergency NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Planning at the site. Richard Burroni is our Manager of Programs
and Components. Garry Young on my left is our Corporate
Manager of License Renewal. Tom McCaffrey is our Manager of Design
Engineering. John Curry is the Project Manager for
Licensing Renewal at Indian Point. Mike Stroud is our Corporate Program
Manager for License Renewal from Corporate Jackson. Alan Cox is our Technical Manager of
License Renewal. Bob Walpole is our Manager of Licensing at
the site. Rich Drake is our Supervisor of
Civil/Structural Engineering. And Nelson Azevedo is our Supervisor of
Code Programs. And we got a discount from Amtrak coming
down here this morning. That's not in scope. This morning on the agenda I would like to
cover a little bit about the background. Because Mr.
Maynard, you mentioned it's an interesting background
with this plant having started with two owners; give NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 you an overview of the operating history. We want to talk a little bit about major
plant improvements and give the ACRS a feel for these
plants from a major component perspective have largely
been rebuilt. Now the list that we're going to go
through I will not by any stretch of the imagination
portray to you that it is a comprehensive list, but
it's just to give you a general feel of the kind of
capital improvements that we've made. We're going to have a scoping discussion.
We'll talk about the application NUREG-1801. We want to give you a feel from the
commitment process that we have, because we feel that
we've got a very robust commitment process. Where we
fall through, we'll narrow things down and we're
watching industry very closely. Obviously, we're going to discuss the
topics of interests, open item and issues that we are
aware of that you would like to discuss. And certainly questions at anytime, with
questions at the end. But that's generally our agenda this
morning. The site, you have two Westinghouse NSSS
plants designed by UE&C, that's United Engineers and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Constructors with WEDCO being the actual construction
entity that built the plants. Indian Point 2 has Westinghouse low
pressure turbines, Siemens high pressure turbine and a
GE generator. Indian Point 3 has ABB low pressure
turbines, Siemens HP turbine and a Westinghouse
generator. Now that immediately brings the question
that you initially rose. It makes for an interesting
operation because the components are not exactly the
same. And we talk a little bit about the background
of the plant you'll see because it was owned by two
different companies, that is why you will see some
component differences between the two units. PWR, large dry containment. Both plants are licensed at 3216 megawatts
electric thermal. 1078 on Unit 2, 1080 on Unit 3. We have once-through cooling from the
Hudson River. The plants do not have cooling towers. We have on Unit 2 dual speed cir water
pumps with the state-of-the-art Ristroph screens that
really minimize impact to the fishery system. As well as Indian Point 3 has variable
speed circulating water pumps with Ristroph screens.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 We have a staff complement of
approximately 1100 people, and that includes security. A little bit on the operating history.
Construction permit on Unit 2 was issued in October of
1966 with the operating license in September of 1973.
You can see it went commercial operation in August of
'74. You can see the three uprates that the
unit went through. Indian Point 3 is similar. We received a
construction permit in August of '69. We received an
operating license in December of '75 with commercial
operation in August of '76. And you can see the three
power uprates. Now here's the interesting history here of
Indian Point. It started out a common owner. Con
Edison owned both Indian Point 1, 2 and 3. Now Indian
Point 1 is currently in a safe-store condition. Fuel
has been off loaded from that facility. The fuel has
been removed from the spent fuel pool and the spent
fuel pool drained, and I'll talk about that a little
later on in the presentation. But there are a couple
of small systems that support the operation of Indian
Point, and we'll talk about during our course of
discussion this morning also.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 But Indian Point 3 was purchased from Con
Edison by the New York Power Authority in December of
1975. So that's when the plant started to -- the
ownership diverged. Indian Point 3 was purchased by Entergy in
November of 2000. So you had a situation where the
plants operated side-by-side with Con Ed operating
Indian Point 2, New York Power Authority operating
Indian Point 3 and then in November of 2000 Entergy
purchased Indian Point 3. In September of 2001 Entergy then went and
purchased Indian Point 2, and 1 came along also. So you went from one owner to two owners
back to one owner. And that is kind of like what the
root cause is of some of the differences that you
obviously see between the two units. We put our license renewal application in
April of 2007. And you can see the expiration dates
for the two units, and '13 and '15 respectively. The intent here of this next slide is just
to give you a feel for the kind of things that have
been done to Unit 2. And this is really truncated
list. You can see we added additional station
batteries, new fan cool unit heat exchangers, new main
generator, titanium condensers. We went to 24 month NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 fuel cycles. Converted to best estimate LOCAs. Went
to sodium hydroid spray additive with TSP baskets in
containment, new low pressure turbines, new hydrogen
recombiners, new steam generators, new feedwater
heaters; a very extensive rebuild on both units to get
the reliability into the units that the region and the
company absolutely demands. And as a matter of fact, in 2008 we completed the installation of a station
blackout Appendix Romeo diesel. MEMBER SHACK: Wait. You replaced the
sodium hydroxide with TSP, right? MR. DACIMO: That's correct. MEMBER SHACK: And do you have calsil
insulation? MR. DACIMO: Yes, we do. Yes. MR. McCAFFREY: Yes, we do. MR. DACIMO: And we did strain of MODs, okay, and we can get into that later on, okay. MR. McCAFFREY: Right. And we've also
upgraded from the TSP to sodium tetraborate. MR. DACIMO: Right. MR. McCAFFREY: And that was a recent
change we made as part of the buffer change up with
the Generic Letter 1-91 issues. MR. DACIMO: So you can get a feel for NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 what we did on Unit 2. On Unit 3, you can see we added a 4th
battery charger/inverter, new fire water tanks
splitting off the fire, had a system for Unit 2, new
SBO/Appendix Romeo diesel in '84. Both plants had the control rooms rebuilt. New main transformer, new titanium
condensers, new steam generators, new feedwater
heaters, new low pressure turbines. Again, implemented a 24 month fuel cycle. New high pressure turbines, new moisture
separator reheaters. So very extensive, again, rebuilt on Unit
- 3. Now we made significant investments in
upgrading the infrastructure at both plants. I'll
also tell we also paid a lot of attention to the site.
And I've a photograph I'm going to show you in a
minute. But in '87 a new training building was built.
We put in a new water treatment facility.
We built the new generation support
facility. We felt it was very important that the
people who work at the plant have very good quarters
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 of. That was very important. We initiated a dry fuel campaign for
Indian Point 1, as I mentioned before. We removed all
fuel from Indian Point 1 from the spent fuel pool in
Indian Point 1 and then we drained the spent fuel
pool. And so that's done. And those assemblies are
on the pad. At Indian Point we have removed 96 fuel
assemblies. Those casks are on the pad and we are in
the process now of getting into the Indian Point 3
spent fuel pool campaign, which is actually ongoing
now from the standpoint of design and beginning
construction later on. In 2008 we installed the new emergency
plant siren system. That is now operable. And we have
planned a new emergency operations facility that will
move into the design, procurement and build of that in
the near future. Current plant status is both units are
operating this morning at 100 percent power. Unit 2
is online for 274 days. Unit 3 is online for 672 days.
Both units are running well with no significant
problems ahead of us. Unit 3 is approaching a refuel outage next
week. And Unit 2 refuels in the spring of 2010.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER SIEBER: Is that a two-year cycle? MR. DACIMO: That's correct, two-year
cycles, Mr. Sieber. Yes. This is a picture facing the river. You
can get a feel in the foreground of the generation
support building. You can Indian Point 1 is in the
middle. That's the pancake type down and the Hudson
River is in the background. Next slide. This is just to give you a feel for the
plant's operating history. The blue is when Entergy
purchased the plants. And so we have made some
significant changes in the reliability of this unit, certainly due to the investment and infrastructure as
well as the people at that facility. With that, that really completes my
presentation and I'm going to turn it over to Garry.
Mr. Young who is our Corporate Manager. MEMBER SIEBER: You had a power uprate to
about 12 percent? MR. DACIMO: Yes. We actually had the
power uprates on both units listed, and you can see
there was 10 percent on Unit 3, a 10 percent uprate in
'78, a 1.4 percent in 2002 and a 4.8 percent in 2005. MEMBER SIEBER: Okay. So that's 14 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 percent? MR. DACIMO: Right. Fifteen or so. MEMBER SIEBER: What major changes did you
make to the plants to accommodate the uprates? MR. DACIMO: New turbines, new MSRs. You
know, obviously, fuel load change. Okay. We also did
-- I'm trying to think of what else. We had no issues with pumps, pumps had
plenty of margin. Okay. Those are the big picture
changes we made to the plant. MEMBER BANERJEE: When did you change your
steam generators? MR. DACIMO: On Unit 2 the steam
generators were changed out, I believe, it was in '99.
And on Unit 3 the steam generators were changed out in
'89. MEMBER SIEBER: I take it you had
condensers problems at one time to the extent that you
had struggled with chemistry control in the steam
generators? MR. DACIMO: The history of steam
generators certainly is typical what you see in the
industry. And that's why a lot of plants went to
titanium condensers. Same with, you know, minimize
cooper intrusion to the steam generators, absolutely.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Right. MEMBER SIEBER: What did you have before? MR. DACIMO: I believe it was a Admiralty
bronze. MEMBER SIEBER: Admiralty? MR. DACIMO: Yes, Admiralty bronze
condensers. MEMBER SIEBER: Yes. Right. Okay. So you
didn't have failures where you were leeching the water
cooper? MR. DACIMO: Right. Right. MEMBER SIEBER: Okay. What experience
have you had with condenser tube leaks currently? MR. DACIMO: The condensers -- MEMBER SIEBER: The Hudson is not perfect
from the standpoint of -- MR. DACIMO: It's brackish water. But I
got to tell you, the condenser reliability has been
very good. And we have plugged very few tubes. We had one defect on Indian Point 3 a few
years ago. It appeared to have been an original
construction defect. But other than that, the
condensers have been very reliable. MEMBER SIEBER: Your chemistry control on
the secondary side is moler chemistry control?
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. DACIMO: When you say "mole" I have-- MEMBER SIEBER: Mole ratio. MR. DACIMO: Mole ratio? MEMBER SIEBER: Is that true or not? MR. DACIMO: I'll have to get an answer to
you. I'll have to get an answer to you. MEMBER SIEBER: Okay. Yes, maybe you
could describe what your chemistry program is? MR. DACIMO: Sure. Be happy to do that. MEMBER SIEBER: Typically people went to
all-volatile -- MR. DACIMO: Other questions? Okay, Garry. MR. YOUNG: Okay. I'm Garry Young. And
I'm the Manager of the Fleet License Renewal for
Entergy. I'm going to talk a little bit about the
application, the preparation of the application and
some background on our commitments and our plans to
implement our comments. First of all, the application itself, this
will be the sixth license renewal application that we
brought to the NRC and to the ACRS for review. We
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 that we've had with our previous projects, this
includes Arkansas Nuclear 1, Unit 1 and 2, Pilgrim, Vermont Yankee and Fitzpatrick. But in addition to
that we also got lessons learned from the industry
through the Nuclear Energy Institute, the experiences
of other utilities. And we factored that into our
application. We then did a peer review of our
application once it was drafted. Again, working with
the Nuclear Energy Institute to have other utilities
look at our application, utilities that were in the process of preparing license renewal applications.
They gave us feedback and comments. We had internal reviews of the application
by our on site and off site Safety Review Committees
and, of course, by our QA. The application was prepared by
essentially the same team that's prepared the other
Entergy applications. It's a combination of our
Corporate Group that has a lot of experience with
doing license renewal applications. But then it was
supplemented heavily by people with experience at
Indian Point so that we got the benefit of the
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 application. We then addressed all the comments
received from all of these sources and incorporated
them into the application. And another item I'd like to comment here
is on the scoping. This was somewhat of a challenge
since we had two Westinghouse units but they were
built at different points in time. And as a result of
that because of some evolving licensing and industry
issues in the 1970s, we wound with up a very different
split of boundaries for systems. And the actual
number of components and the design of the two plants
are in fact very similar, but the designation of
system boundaries is very different. And, for example, Indian Point 2 has about
half as many systems as Indian Point 3 in our
component database. Another example, just to give you an idea
here, is the RHR system between the two units is
almost identical in boundaries and in the description
in the application. But the condensate and feedwater
system is an example where Indian Point 2 has two
systems that form the makeup of condensate and
feedwater and Indian Point 3 has seven systems. So
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 application in the names of the systems and the number
of systems. But in reality if you just look at a
piping diagram, they would look very similar. Okay. The next slide is on the aging
management reviews that were done. We used NEI 95-10, which is the industry guidance document for performing
aging management reviews for the integrated plant
assessment and the time limited aging analyses. The aging management review results were
very consistent with NUREG-1801, the GALL report. And
we calculated that about 90 percent of the aging
management review line items were what we call the
notes A through E, which are the notes that show
consistency with the GALL report, which is typical for
a plant. The other ten percent that did not match
GALL are generally unique material environment
combinations or components that are not addressed in
GALL. And, again, that's typical for plants that are
doing license renewal currently. MEMBER SIEBER: Were you required to take
exceptions because of the references to code years
versus your licensing basis? MR. YOUNG: There were a few cases of
that, yes. Yes. MEMBER SIEBER: Is it a few or a lot, or NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 how many? MR. YOUNG: I've got a later slide that
I'll go into that. But there were actually eight of
our aging management programs that we actually took
exceptions. And some of them were in that category, certainly not all of them. MEMBER SIEBER: Maybe you could tell us
specifically which ones were. MR. YOUNG: Okay. On the next slide we
have 41 aging management programs that we credited for
license renewal. Thirty-one of these programs are
existing programs and 10 are new programs. The 10 new
programs are the ones that you typically see, which
include things like our non-EQ cable inspection
programs, buried piping inspection programs and so on. In the comparison to NUREG-1801, the GALL
report, the breakdown we had is we had eight plant-
specific programs that were not GALL programs. And
then we had 33 programs that were GALL programs. Of
the 33 programs we had eight that had exceptions to
GALL. And some of the examples of the exceptions
-- well, for example, we had the flow-accelerated
corrosion program. We used a later revision of an NSAC
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 exception using a newer edition of that document. In some other cases we substituted some inspections or some criteria; oil analysis program.
We do fuel dilution testing, which is different than
the flash point testing that's in GALL, but it is more
prescriptive. In our fire protection program GALL
recommends a six month interval for inspections and
we're doing it on a fuel cycle basis, 24 months; 18 to
24 months, which again is a typical exception to GALL
that other utilities have taken. All of these exceptions, these eight
exceptions that we took are similar to ones that had
been previously taken by other applicants. And they
are also being provided to the NRC staff as part of
the GALL revision to see if we can incorporate some of
these exceptions into GALL so that in the future we
won't have to take these exceptions because they have
been reviewed and accepted on other applicants as well
as on Indian Point. Does that answer your question? Okay. The next slide, our commitment process.
We have made at this point 38 commitments in our
license renewal application in the review process. We
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 the NRC review of both the audits and inspection
process. So some of these commitments that are in the
application have been revised and modified as a result
of the ongoing review. We're using the Indian Point commitment
management process which is the same sort of
commitment management process we have at our other
Entergy plants. For example right now at Indian Point we
have about 10,000 commitments that are being managed
by this program, so these additional 38 will also be
managed by that same process. This commitment management process is a
well established process and consistent with industry
guidance and standards. Entergy periodically does
inspections and self-assessments of the commitment
management system to ensure that it's working
effectively. And, again, this is the same process
that we used at our other Entergy plants for managing
our commitments. MEMBER ARMIJO: Is the number of
commitment items for the Indian Point plants
consistent with the rest of the Entergy fleet? MR. YOUNG: Yes. MEMBER ARMIJO: Ten thousand is not an NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 unusually high number or anything like that? MR. YOUNG: No. No. It's very similar.
Yes. MEMBER ARMIJO: Thank you. MR. YOUNG: That is a two unit site, so it
has that difference. MEMBER ARMIJO: Right. Right. MR. YOUNG: Yes, but on a per unit basis
it would be. Okay. The next slide is our
implementation activities. WE are taking a fleet
approach to our implementation of these aging
management programs and other commitments. Again, we
have a lot of sites that have committed to many of
these same programs, but each site actually owns the
implementation. And then we have a corporate or fleet
group that helps provide oversight, consistency and
support for each individual site, in this case Indian
Point. We have a fleet manager that's looking
overall for the implementation activities for the
whole fleet. But then we also have a site coordinator
at each site that deals with the specifics. We have a schedule developed for
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 updating and revising that schedule as we develop our
aging management programs. We have several of these programs that are
common to the fleet, such things as the buried piping
inspection program, the non-EG cable inspection
program. We have developed in some cases a fleet
standard and then each site will implement that
incorporating the site specific differences. We are still developing some of these
programs, some of these new programs. They're not all
developed yet, but we have a few that have been
developed. And this will continue as we approach the
period of extended operation. Okay. And that completes that
presentation on the application itself and the
management of commitments and the implementation
plans. The next slide we're going to get into the
SER open items. And as I mentioned, we have a total
of 20 open items in the SER. And we have been
providing information to the NRC staff as requested to
allow them to finish their review. Out of the 20
items at this time we believe there are 13 in which we
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 item. So we put those in the category of ready to
close. So on this here when you see "ready," that
means that we have provided the information to staff.
The staff has indicated that at this time they don't
have anymore questions. So they're in the processing
of closing. It doesn't mean they're closed. MEMBER BANERJEE: So taken an example, maybe, and take us through. MR. YOUNG: Well, for example, we -- MEMBER BANERJEE: Can you take the first
one, perhaps? Was it they were not part of the MR or
something? CHAIR MAYNARD: You're going to go through
each one of these, aren't you? MEMBER BANERJEE: Oh, you are? CHAIR MAYNARD: Yes. MEMBER BANERJEE: You're going to? Go
through each one of these open items? MR. YOUNG: We were planning to focus on
just the ones in which the staff is still continuing
their review. MEMBER BANERJEE: On their review? MR. YOUNG: And the ones that were
resolved, we didn't plan to go through one-by-one. CHAIR MAYNARD: So I think we still may NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 have questions on this. MR. YOUNG: Yes. CHAIR MAYNARD: Because while the staff
may be ready and they can address it -- MR. YOUNG: Yes. CHAIR MAYNARD: We haven't really been
provided that information. MR. YOUNG: Right. CHAIR MAYNARD: So as far as we're
concerned they're still open. MR. YOUNG: Right. CHAIR MAYNARD: And we'll still need some
dialogue on those items. MR. YOUNG: Okay. Okay. MEMBER STETKAR: Otto, when is the
appropriate time to do that? Because I've been
looking forward a little bit and some of the questions
I had we'll get into more details, but some will
pertain to the ones that are tagged on this slide as
ready. So is it appropriate -- CHAIR MAYNARD: Yes. I think what I'd
like to do is to go ahead and let them go through the
presentation. We'll focus on the ones that are still
open and it will come back those they said ready, and
then we'll pick those up.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER STETKAR: Okay. CHAIR MAYNARD: So I do want to save time
for that. MEMBER STETKAR: Okay. CHAIR MAYNARD: Because a number of us
have questions on those. MR. YOUNG: Okay. Certainly, yes. CHAIR MAYNARD: Again, we haven't seen the
staff's resolution or their finals on that. MR. YOUNG: Okay. Okay. And these next
three slides are, again, are just a listing of the 20
open items and the status as we understand it at this
point. Again, there's seven that the NRC staff is
still continuing their review and then 13 which we
think we've provided the information that was needed
to close. MEMBER BANERJEE: So by ready you mean the
staff have closed these items. MR. YOUNG: No. They are not closed. The
staff has asked for -- MEMBER BANERJEE: You've sent down? MR. YOUNG: We've sent the information. MEMBER BANERJEE: Okay. So the staff is
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 they've indicated that that information was what they
needed. MEMBER BANERJEE: And when you mean "NRC
review," you haven't down, is that what it means? MR. YOUNG: No. The -- on the one -- MEMBER BANERJEE: What's the difference
between "ready" and "NRC review." CHAIR MAYNARD: I think they're saying
that out of the 20 open items seven of them I believe
the staff still considers open, 13 I think the staff
is about to close. I think the staff's going to have
to be the one to address that. And I think that's the
way they're putting it in the category is that -- MR. YOUNG: Yes. MR. HOLIAN: That's right. That's a good
summary. MEMBER BROWN: So we should wait to
address questions on those potentially being closed
until we hit the closed ones or -- MR. HOLIAN: Yes. CHAIR MAYNARD: Well, why not just go
ahead and let them go through the presentation, focus
on the seven that are still open. We will come back to
any of them that did not get touched. MR. YOUNG: Okay.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CHAIR MAYNARD: But we'll expect them to
address this stuff. I don't want to just wait until
the staff gets up here and find out they're trying to
address it. MR. YOUNG: Okay. Again, there were three
slides that just listed all of the open items and the
status as we understand at this point. On slide 24 these are the ones, the seven
remaining open items in which the staff is continuing
their review. And we've provided information on all
of these, but there may be additional information
needed by the staff to finish their review is I think
the way to characterize it. And what we'll do is on
each one of these seven items on this slide on the
list that we're calling remaining open items, we're
going to provide a more detailed discussion by the
experts in these areas. And then we've also got three
what we call topics of interest which were topics that
we were requested to provide a presentation on
involving the reactor vessel integrity, buried piping
program and the containment liner event that occurred
in 1973 and the impacts of that. So we'll have a
presentation on each one of these in more detail. MEMBER BANERJEE: That was in OP2 the '73
event?
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. YOUNG: Yes. CHAIR MAYNARD: And again, I won't try to
get through this. We'll control the pace because
it'll probably be more by a number of questions we ask
on these. But we do need to have time to address
questions on the other 13. MR. YOUNG: Yes. Certainly. Okay. And with that, I'll turn it over to
Tom McCaffrey is going to talk about this first open
item on the station blackout scope. MR. McCAFFREY: Thank you. I'm Tom
McCaffrey. I'm the Design Engineer Manager at Indian
Point. For the station blackout scoping we have
complied for Unit 2 and Unit 3 meeting the 10 CFR 50.4 (a)(3) in the scoping. We've complied with the NUREG
guidance of 1800 for the alleged renewal scoping, the
recovery boundary for the station blackout. Right now we're in compliance with the
draft guidelines provided by the NRC as a revision to
the ISG 2008-01. Basically right now both of our station
blackout recovery paths, the primary path which is the
through 138 kV system and the alternate system, the
13.8 are also included in the scoping from The NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Buchanan Substation to the power plant. MEMBER STETKAR: Tom, do you have a
drawing that shows -- as I read through the SER and
various, there seemed to be various concepts of
exactly what paths were included in this evolution. MR. McCAFFREY: Yes. MEMBER STETKAR: Do you have a drawing
that shows what's currently included in your
application? MR. McCAFFREY: Yes, we do. MEMBER STETKAR: Okay. CHAIR MAYNARD: You have to have a
microphone. MR. McCAFFREY: Sorry about that. Okay. So what we have here is the
schematic we provided in the application. We have two
paths of station blackout recovery. One is to our
normal 137 kV feeder from Buchanan Substation down to
the station. On the right side here is our is 13.8 kV
alternate supply down to the nuclear power point. There's two supplies and they're both
contained in the Buchanan Substation, the supplies.
That's the Con Edison Substation that contains the
345, 138 and 13.8 kV systems where we generate and
transit and get power from for the power plant.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER BROWN: So they're physically
located contiguous to each other? MR. McCAFFREY: Yes, they are. They're
about three quarters of a mile away from the power
plant, directly across the street from the entrance to
the -- MEMBER BROWN: But they're both in the
same location? MR. McCAFFREY: Correct. The same yard.
Yes. The same operator who reports to that substation
will be operate the 345, 138 and 13.8 kV systems. MEMBER SIEBER: Is that manned around the
clock? MR. McCAFFREY: That is a manned. The
operator reports there. That's a reporting station but
does not have to be there. Con Edison has the ability
to remotely operate all the breakers from their
normally manned location in New York City. MEMBER SIEBER: Okay. Their dispatch
office? MR. McCAFFREY: Correct. MEMBER STETKAR: Okay. MR. DACIMO: But typically during the week
and most times Saturdays on the day shift there are
people that --
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER SIEBER: But if they aren't there
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, it's -- MR. McCAFFREY: They always report in
there. That's a typical reporting station. So the
operator will report there. If they need his help at
another substation, they might take him out of there.
But that is a critical substation for Con Edison from
just a transition flow. So they always try to keep an
operator in that substation. MEMBER SIEBER: Okay. MEMBER STETKAR: Tom, do you have any
other drawings that actually shows the 137 and 13.8 kV
-- the 3.5, 138 and 13.8 kV switchyard configurations? MR. McCAFFREY: Yes. MEMBER STETKAR: These kind of go off into
there. MR. McCAFFREY: Yes. This does not show
the 345 kV system because that's really -- MEMBER STETKAR: Yes, but you're not
taking credit for that. MR. McCAFFREY: So what we see here is the
highlighted lines are currently what is in scope for
the station blackout recovery. It's the 138 kV
breakers that supply the normal feed into the station
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 13.8 kV supplies into the substation down at the
plant. MEMBER STETKAR: Let me see if I can
digest this for just a second. This shows both paths
from IP2, is that correct? It shows BT3-4 and -- MR. McCAFFREY: I'll walk you through it. MEMBER STETKAR: Yes, if you could. That
would help. MR. McCAFFREY: The unit 2 there, the
power line up in here through this, BT3-4, right? MEMBER STETKAR: Okay. MR. McCAFFREY: And Unit 3 is this one, right. BT5-6 comes in from the side here from IP3. MEMBER STETKAR: Okay. MR. McCAFFREY: That's the 138 kV supplies
into both station. MR. McCAFFREY: Now down here below -- MEMBER STETKAR: That shows the 13.8 down
below. MR. McCAFFREY: -- it's the 13.8 kV
supply. MEMBER STETKAR: Okay. MR. McCAFFREY: Any connections in the
substation there between the 138 kV system and the
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Buchanan Substation, which is across the street from
the power plant. MEMBER SIEBER: Now the equipment in the
Buchanan Substation is not owned by Entergy? MR. McCAFFREY: And that's not true. Part
of the equipment owned by the substation is owned by
Entergy and the station is manned by Con Edison and
they own the majority of the equipment the substation. MEMBER SIEBER: Do you down -- does
Entergy own or does Con Ed own the whiteout path? MR. McCAFFREY: The two breakers that are
associated with the 13.8 kV supply alternate are
Entergy's feeders and breakers. The 138 kV feeders
and breakers are Entergy's breakers and feeders into
the station. MEMBER SIEBER: So the answer is yes? MR. McCAFFREY: Correct. MEMBER SIEBER: That would have been even
better. Okay. In other words, you don't have
anything that you don't own, Entergy doesn't own as
part of your license renewal responsibility to
maintain? MR. McCAFFREY: As is currently -- yes, that's correct. As it's currently in the application, yes.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER SIEBER: Okay. Is it going to stay
that way? MR. DACIMO: There is no plans to sell
anything. MEMBER SIEBER: Okay. MR. McCAFFREY: Right. No plans. MEMBER SIEBER: Yes, but the way you
phrased it -- MR. McCAFFREY: I'd just say there's draft
guidelines out that we believe that we meet compliance
with that based upon what I've shown you here today. MEMBER SIEBER: Okay. MR. McCAFFREY: The draft guidelines will
have to evaluate any of those changes, that change
then we have to see how we comply with the draft
guidelines. CHAIR MAYNARD: I'd like to move on. We
have a number of issues. This is also something, station blackout scoping stuff that's under review by
NRR. There's some more generic items here. And so I
think that's still under review. So I think -- MEMBER STETKAR: This gets to what my
questions were, so that's fine. MR. McCAFFREY: Okay. And I'll turn it
over to Alan Cox.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. COX: The next topic of interest that
we have is the auxiliary feedwater pump room fire
event. And actually what this is talking about is the
aging management approach for systems that are relied
on in the event of a fire integrated in the feedwater
pump room. MEMBER SIEBER: Now, you have two motor
driven and a steam driven and they're all in one room? MR. COX: That's correct. MEMBER SIEBER: So a fire in that room
wipes out that aux feed system and then you have an
alternate means? Okay. MEMBER STETKAR: Alan, before you go into
the specifics for Unit 2 isn't the Unit 3
configuration the same? Don't you have two motor
driven and a turbine driven pump in the same room for
Unit 3? MR. COX: Yes. MEMBER STETKAR: Why is here not a
companion Unit 3 auxiliary feedwater room fire event? MR. COX: Well, the Unit 3 auxiliary
feedwater pump has a fire suppression system installed
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 that count as far as your fire protection program?
Usually you talk about barriers with suppression
systems -- MEMBER BANERJEE: These are what, Halon? MR. COX: I believe it's a -- MR. DACIMO: The Unit 3 system is a bottle
system. And I believed it is Halon. MEMBER SIEBER: Or whatever is successful. MR. DACIMO: Right. Yes, because we
haven't replaced that. Okay. MEMBER SIEBER: I'll have to think about
that. MEMBER BANERJEE: I noticed that -- MR. COX: I would point out there's very
little in the way of combustible loading in the room.
So it's very unlikely. Basically in this event a one
hour period is assumed for duration when the room
would be inaccessible to the operators. And for that
a one hour period in this event we're crediting
normally operating secondary plant system to provide
the alternate flow path to get feedwater to the steam
generators. MEMBER STETKAR: And just out of
curiosity, after the one hour time expires what type
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 accessible? MR. COX: Well, after the room becomes
accessible we'd be able to restore the auxiliary
feedwater system from one of the other train in that
room to provide feedwater. MEMBER STETKAR: That presumes that the
fire doesn't effect all of the trains that are in the
same room? MR. COX: Right. So again -- MEMBER SIEBER: I also presume the staff
has accepted this as part -- or as part or is fire
modeling? MR. COX: Right. This is part of the IP2
correlation basis, yes. MEMBER SIEBER: Typically other licenses
have done other things, like put a pump in a different
room with diesel power. MR. COX: Again, for license renewal we
basically worked with the current licensing basis and
this was because this was credited for compliance with
50.48. That's the reason we included these systems in
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 perform their function, the same function during
normal operations as the function that they're
required to perform during event. So that allowed us
an opportunity to take just a unique but still very
effective approach to aging management. And that is
that the normal operation of the system doing its
intended function demonstrates that it will be
available for this one hour period that is required to
respond to this event. I mentioned that this is a unique
approach. That while it is unique for Indian Point, this approach is an approach that's fairly common for
the PWR plants specifically related to the main
condenser where acceptable performance of the main
condenser during normal operation has routinely has
been determined adequate to provide assurance that
that condenser remains operable to performance license
renewal post-accident intended functions. So in essence, for IP2 operation of the
secondary plant system, you know, right up to the
initiation of this event provides the assurance that
those same systems are able to perform essentially
those same functions during an event. That is of
providing an alternate path of feedwater to the steam
generator.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 The staff did ask us for some additional
information. We provided to them, I believe toward the
end of January we gave them some more detailed
component information on the components that are
associated with these systems and also identified
which of the components were covered under other aging
management programs. Specifically since these were in
the turbine building we do have some safety-related
equipment in that turbine building. Most of the
secondary plant fluid field systems are in scope of (a)(2) and are covered under other aging management
programs. MEMBER BANERJEE: Are there passive
components? Of course there are, right? MR. COX: Certainly. Okay. So piping, that sort of thing, would certainly be passive
components that are included in this evaluation. Like I say, a lot of them were included
for (a)(2) and, of course, the steam systems that are
involved in this are part of the -- MEMBER BANERJEE: So how are you, Garry, going to manage the aging, these passive systems? MR. COX: Again, in this case the normal
operation of the plant is putting these systems
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 conditions that they will see for this one hour
period. So that we basically determined there is no
conditional aging management program required for
these components because of that demonstration. MEMBER BANERJEE: And the staff agrees
with that? MR. YOUNG: That is still under review. MEMBER BANERJEE: Okay. Is that still one
of the open items? MR. COX: The concept they've agreed with, again on the BWR side of things, for the main
condenser which is credited for a function of hold up
and plate out -- MEMBER SIEBER: Until they write it down, they don't agree. MEMBER BANERJEE: Okay. That is fine. Go
ahead. MR. YOUNG: Okay. The next subject Rich
Drake will provide the discussion. MR. DRAKE: I am Rich Drake. I'm the
Civil/Structural Engineering Supervisor at Indian
Point. And I'm responsible for the structural
monitoring programs. IP2 reactor cavity structural integrity.
The stainless steel liner leakage occurs -- has NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 started occurring during the outages starting in the
1970s and then mole leaks started to increase more
significantly into 1990s. The refueling cavity is
only flooded approximately two weeks every two years
during the outages. Three areas in 1993 were examined with
core bore samples in several locations and an area of concrete reenforcing was opened up behind the liner.
The evaluation of the concrete samples concluded that
the concrete and rebar behind the cavity liner was
fully capable of meeting its intended design function
for the license renewal period. Minimal effects on
the reenforcing was found. The borated water
penetration was determined to be less than a half inch
into the concrete. And the concrete typically has over
two inches of concrete cover over the reenforcing
steel. MEMBER SIEBER: What impact has the borated water have on the strength of the concrete?
Will it spall off? MR. DRAKE: No. It was determined that it
had very little effect to the concrete. MEMBER SIEBER: And how did you determine
that? MR. DRAKE: We did core bore samples into NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 the concrete behind the liner. MEMBER SIEBER: So you cut holes in the
liner? MR. DRAKE: Cut holes in the liner, took
some core bores and we exposed an area of the
reenforcing steel. MEMBER SIEBER: What does the sampling
program look like? MR. DRAKE: We took several core bores and
we took some breaks and they also did some sampling to
determine the extent that borated water would actually
penetrate into the concrete. And it was much less than
a half inch into the concrete. So it never reached the
reenforcing steel through the normal path. MEMBER SIEBER: So far? So far. MR. DACIMO: Well, we also have extensive
experience from Indian Point 1 where the Indian Point 1 spent fuel pool, which we mentioned, was drained.
That pool did not have a liner at all. MEMBER SIEBER: Yes. It was like shipping
port. MR. DACIMO: Right, exactly. So, you
know, and there were some investigations there that
indicated that indicated wearing issues. MR. DRAKE: We've done other --
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER SIEBER: That wasn't borated, though, was it? MR. DACIMO: At one point in time it was.
Absolutely. MR. DRAKE: Yes. MEMBER SIEBER: Okay. MEMBER BANERJEE: What caused the leakage
to start in the '70s? Do you recall, do you remember? MR. DRAKE: It's through some pinhole
leaks in plug welds or also some porosity in the welds
themselves. The areas that have been identified have
been plug welds and the weld seams. Typically the
leakage occurs midway up on the liner in the weld
area. That's where some of the biggest concerns are.
And then the plug welds. We've taken remedial action. Over the
course of the year we've used ceramalite coatings over
these identified locations. We use an instacoat
strippable coating during the refuel outages. And the
areas that have been coated are varied with different
success levels. MEMBER SIEBER: In other words, it didn't
work? MR. DRAKE: We're still trying to narrow
down all the locations.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER SIEBER: Did you ever consider
rewelding the areas that are bad, and is that
possible? MR. DRAKE: It would be a very dose
concentration area. MEMBER SIEBER: Well, you could -- a lot
of people have put strippable paint on those -- MR. DRAKE: Well, that's what we did. We
did strippable coating and the -- CHAIR MAYNARD: But even with that you
failed to correct? MR. DRAKE: Yes, we've had limited --
we've had some success with that. And then the liner
during the hydrostatic pressure will deflect slightly
in certain locations at the mid height. And that with
the strippable coating when we had the ceramalite
coating, which is very rigid, we actually had like a
knife edge and it cut it and then we started leaking
on that. CHAIR MAYNARD: How are you identifying
the leakage? MR. DRAKE: It drips down into the 46 foot
elevation, which is our bottom elevation normally. And
it's captured within the side crane wall. I have
another slide I could get to and I could show you NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 that. MEMBER STETKAR: Before we get to the flow path, what was your experience in the 2008 outage?
Did you have a leak in 2008 also? MR. DRAKE: We did still have leakage. MEMBER STETKAR: Okay. MEMBER SIEBER: What's troublesome here is
that you have a defective condition that you say today
is okay but you're asking for 28 years more of a
defective condition that can get worse at anytime? MR. DRAKE: Yes, and we know. MEMBER SIEBER: To me that's troublesome. MR. DRAKE: Yes. We are -- presume we are
looking at new processes to go. We are pursuing an
ARVA process which has had success both overseas and
the United States, which is a flexible silicone with a
stainless steel backing to it, which we're going to
apply. We're also looking at Westinghouse
processes which are still in the commercial
development stage. But we are looking at other
processes. MR. DACIMO: But I think to answer your
question directly we don't see that while it is a
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 expectations, it doesn't effect structural integrity
of anything that it impacts -- MEMBER SIEBER: Today? MR. DACIMO: -- both in the short term and
as we extrapolate it out in the long term -- MEMBER SIEBER: I -- MR. DACIMO: Just let me finish. Based on
our experience and investigation, we don't think it's
going to effect the long term structural integrity
either based on our investigation. MR. DRAKE: We've also made a commitment
to do -- MR. DACIMO: Right. MR. DRAKE: -- extra in upcoming outages
to do more core bore samplings and expose another area
of reenforcement to determine that. MR. DACIMO: And we will continue to look
at this on a going forward basis. And we have a
formal commitment to do that while we pursue -- as a
matter of fact it's quite active, a different repair
methodology. MR. DRAKE: Before we do a repair
methodology we're going to examine that area first and
then do the repair. MEMBER SIEBER: The staff has an open item NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 and is considering, right? MR. DRAKE: Yes. MEMBER SIEBER: I'll wait until you make
the decision. MEMBER BANERJEE: You were going to show
us the flow path. MR. COX: This is Alan Cox. I might add that at the time that we do we
have a commitment to do these additional core bore
samples. At that time we will have had over 30 years
of operation with this condition. So we feel like
that's a pretty good indication of what we can expect
going forward. We're going to have a long history of
this condition. We'll be evaluating it at the end of
that 30 year period. MR. DACIMO: And then when you factor in
some of the industry OE there is also a significant
body of experience that's out there upon which we can
draw upon for similar conditions. MEMBER BANERJEE: Could we get copies of
these backup slide that you're showing us now. MR. DRAKE: This one here is the -- MEMBER BANERJEE: Oh, it is in there. MR. DRAKE: This is on the next page. So what I'd like to show here --
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CHAIR MAYNARD: And anything they use as a
backup slide, that gets into the record and we'll get
copies. MR. DRAKE: So our next slide, basically
this is a cross section length wise through the
reactor activity and the refueling -- MEMBER BANERJEE: It's hard to read the
lettering here. MR. DRAKE: Yes, I'm sorry about that.
It's really just for schematics here. So this is here the cavity length of some
of the areas that are leaking in particular, the welds
about midway high up in the cavity. And then most of
it drips down through construction joints or cracks
and it's inside the crane wall. And here is the trench
inside the crane wall that will then take it to the
reactor sumps, containment sumps. There is all coated
with coatings for decon purposes and it capture the
water. The containment liner is way outside and
through several other concrete barriers. And this is
all captured inside the crane wall, that's where the
reactor cavity is. So we capture some here that goes
to the containment sump and there's some down below
the reactor in the reactor cavity sump down here.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CHAIR MAYNARD: Okay. Now you say it only
occurs when you get like above half? MR. DRAKE: That's when we can see that
it'll be about half way up. And then it starts leaking
instantaneously and then we start draining down, when
we get below that point it stops almost
instantaneously. It has -- there must be a small
annulus behind the liner that allows it freely flow. CHAIR MAYNARD: And how much volume? MR. DRAKE: I don't know. It's varied
every year during the sump mod -- CHAIR MAYNARD: Is it -- MR. DACIMO: Well, it's in the area -- in
the area -- when you fully flow we've seen about 4 gpm
is on the outside. MR. DRAKE: Yes, that was the worst case. MEMBER STETKAR: Explain to me a little
bit. This in the cross section is a little bit. But
how is the water getting -- I reckon it comes through
the liner -- MR. DRAKE: Yes. MEMBER STETKAR: -- but does it then seep
into concrete and essentially seep out of concrete
down at the 46 foot levels? MR. DRAKE: Yes. Basically there's NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 construction joints and there's some cracks in the
concrete that will allow it to come through. MEMBER STETKAR: Now I'm curious about the
fact that you said the boric acid is only been -- I
don't remember what you said, a half inch or an inch? MR. DRAKE: A half inch into the concrete. MEMBER STETKAR: Because if the water is
flowing through several feet of concrete, couldn't it
be distributed throughout the entire length of
whatever crack system it's flowing through? MR. DRAKE: It's at -- well, the bottom
portions there. And it pretty much comes straight
down through the -- into the -- inside the crane wall. MEMBER STETKAR: Where is the construction
joint? MR. DRAKE: Well, there's several. You
can't see them on here. But there's cracks that come
through the base underneath the fuel pool. MEMBER BROWN: So it's crack leakage, not
diffusion for the concrete? MR. DRAKE: No, no, no. It comes through
the construction cracks. MR. DACIMO: The space between the liner, the liner butts up against the concrete wall. When
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 and that's where it's flowing down. It flows down
against the outside of that wall to a joint at the
bottom where a horizontal wall meets a vertical wall.
And it ends up in the -- when you go down to the
basement of the vapor containment, you can see it
coming out of those joints. And then it's captured in
a sump that's coated with an epoxy paint. MEMBER STETKAR: You know those are flow
paths -- MR. DACIMO: We have a general -- a very
good understanding of the flow path and then we have a
good capture mechanism and we get a correlation between the makeup related to the pool as well as
the-- MEMBER STETKAR: No. I was just more
interested as long as you know what that flow path
rather than a -- MEMBER SHACK: No, but at 40 gpm you're
certainly going to have that annulus full. And if
there are cracks, it's going to diffuse through. Now
I can believe that it only goes a half an inch through
anyplace that you have integral concrete. But I would
also think that it would follow any crack. MR. DACIMO: Yes. And that's why you see
it coming out of more than one location.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. DRAKE: Yes. And it goes -- it's got a
free path to go straight down. So it -- MEMBER SHACK: Yes, but at 40 gpm -- MEMBER SIEBER: That's a lot of water. MEMBER SHACK: -- you know, it's not as
though it's a drip sort of rolling down that wall. I
mean that annulus is full and it's going to go
whichever way happens to be the easiest way to go. MEMBER BANERJEE: So the surface of these
cracks, would the effect go in from -- let's say you
have a system of cracks, and cracks in this medium, would the effect be felt half an inch from the surface
of the cracks or is it just half an inch from the
surface? MR. DRAKE: Well, we looked at it from the
surface of behind the plate. But, I mean -- MEMBER BANERJEE: But if you look around
the cracks, let's see to the sample around the crack, will you find some permeation or is that not? MR. DRAKE: Well, we've done other
sampling in other places in the plant where we've had
such -- we'll talk about spent fuel pool later, and
we've actually examined those cracks and the rebar
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 even -- MEMBER BANERJEE: So let's say you had a
crack in the concrete, does the water diffuse or
whatever mechanism it is, penetrates on both sides of
the crack to within half an inch or -- MR. DRAKE: It probably could. MEMBER BANERJEE: Could? MR. DRAKE: We evaluated the rebar also
assuming certain thing with that and it still meets
design function. MEMBER BANERJEE: So if the rebar, is
there any cracks which are in the vicinity of rebar, like cracks going through the system or -- MR. DRAKE: Yes. MEMBER BANERJEE: Okay. So the effect
could reach the rebar? MR. DRAKE: Yes. No. And that was
evaluated from that respect also. MEMBER BANERJEE: Right. So even if it
reaches the rebar, nothing happens to the rebar? MR. DRAKE: The rebar still should be in
good shape. And we've had other studies in other
locations in the plant which show where we saw we had
water coming through, we opened up those cracks. And
the rebar was found to be in very good shape.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER BANERJEE: So the rebar was exposed
to the water then? MR. DRAKE: Yes. MEMBER SHACK: But that probably wasn't
borated water? MR. DRAKE: It was borated, too. MEMBER BROWN: And so it's got acid? So
the boric acid doesn't attack the rebar? MR. DRAKE: This is Alan Cox. I've seen numbers quoted where full
leakage borated water has caused corrosion rates on
the order of five mils per year. MR. DRAKE: Yes. MR. COX: It does have some effect, but
it's pretty minimal. MR. DRAKE: And part of the evaluation was
based on industry reports and evaluations from that. MEMBER ARMIJO: I'm trying to understand
this leakage rate and the source. And you mentioned
pinhole leakage in defective welds and maybe some
other defects. But is this liner getting progressively
worse or is it the same leakage but year after year
after year? MR. DRAKE: There have been no -- MEMBER ARMIJO: And do you know where it NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 all is, all those leaks are? MR. DRAKE: There's no aging degradation
effects here. This is all original workmanship. MEMBER ARMIJO: So do you know where these
leak locations are? MR. DACIMO: We do not have each one of
the leaks in the liner. MEMBER SIEBER: That's what we issue tests
on. MR. DRAKE: That's been one of the
problems. That's what we've been trying to do where
we've been trying to seal up certain areas to see if
we could -- MEMBER ARMIJO: See if you can find the
major ones and eventually find them all. MR. DRAKE: Right. And we've coated a
large section of the liner with the pinholes and the
joints and the seams and the corners with the
ceramalite coating and that hadn't solved the problem
from two points. MEMBER ARMIJO: Okay. MR. DRAKE: Mainly because that ceramalite
coating was too rigid and it didn't hold up the way
we'd like to. Water was getting behind it still. MEMBER ARMIJO: But just to make sure I NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 understand. Your intent is as soon as you have a
process for sealing the liner that's reliable-- MR. DRAKE: Yes. MEMBER ARMIJO: -- you're going to do it? MR. DRAKE: We're going to try to correct.
Right. MR. DACIMO: That's correct. And
unfortunately the processes that we have tried have
not been as successful as they need to be. MEMBER ARMIJO: Okay. MR. DRAKE: So we're going to a different
way -- MEMBER ARMIJO: Yes, you're going to try-- MR. DRAKE: -- a better -- which has been
successful in other plants inside and outside the
United States. And we're going to start going that in
certain sections and see if that works better. And
then if that shows promise, we'll start going -- CHAIR MAYNARD: I'm just trying to understand what you're currently committing to.
You're committed to pursuing the modification and some
type of monitoring? I'd like to kind of summarize
what you're -- MR. DRAKE: We have made a commitment to
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 reenforcement steel to determine that the
reenforcement holds up. MEMBER BANERJEE: I just want to
understand the potential for corrosion of the rebar.
What's the typical dimension compared to the corrosion
rate? In other words -- MR. DRAKE: For the size of the rebar? MEMBER BANERJEE: Yes. The cross section. MR. DRAKE: I believe these are a half
inch or more. MEMBER BANERJEE: Okay. So half inch. And
what is your typical corrosion rate in borated water? MR. DRAKE: Five mils. MEMBER BANERJEE: So how many years before
you get significant corrosion? MR. DRAKE: I mean if you go 40/60 years, you would still be marginally attacking that. And we
do have margin in these walls. CHAIR MAYNARD: I'd like to move on. This
is an important topic and it's one that I know we're
going to want to talk about in more detail at the next
meeting and everything. It is an open item. I'm
going to be interested to hear what the staff has to
say also. But since it is an open item, it's still
being reviewed, I'd like to move on.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 It is an important topic and it is
something we're going to be following very closely and
want more information on it. MR. COX: Well, before you go, one last
comment. The safety year that we talked about for
this last time was -- you have to remember that this
is only leaking during refueling outage. So it's
basically a two week period very two years. MR. DRAKE: Right. And then it's very
hard. MR. COX: And then it's pretty hot in this
area, so it's going to tend to dry out any -- MEMBER BANERJEE: Leaving the boron
behind? MR. DRAKE: Boron, from typical reports
and industry events says it has to be a moist -- Boron
only effects -- it corrodes when it's moist. It's got
to be like in a moist pool. A poultice type effect to
really start to do that. This would be a very dry
environment most of the time. MEMBER RYAN: And if you want to defer
until later, Mr. Chairman, that's fine. But I'd like
to hear a little bit more about the groundwater
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 the next topic. MEMBER RYAN: Very well. Very good. MR. DACIMO: This here has no impact on
groundwater. Okay. This is captured within in the
vapor containment and pumped the wa -- MEMBER RYAN: Okay. I am just curious how
you tied in that monitoring that you mention in this
last bullet that's up there now. MR. DACIMO: Okay. MEMBER SIEBER: It's not related. MEMBER BANERJEE: Not related. MR. DACIMO: It's the next topic. MR. DRAKE: Okay. And this is the IP2
spent fuel pool issue of structural integrity. The
spent fuel pool is located in the fuel storage
building which has six foot three inch thick
reenforced concrete walls. The pool liner leakage was first
identified in 1992. The pool liner leakage was
identified on the exterior and was determined from an
18 month's earlier event in 1990 during the reracking
modifications when a worker removed an attachment from
the line. During that event in 1992 several core bore
samples were taken in five separate locations 60
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 examined. Again, we still had over 3000 psi strength
for these samples. In 2005 during excavation of the dry fuel
storage building for the installation of the -- MEMBER SHACK: That repair that you talk
about there, you rewelded? MR. DACIMO: Yes, that's correct. MR. DRAKE: It was repaired in 1992, yes. MEMBER SHACK: This is a thicker liner so
you can do the rewelding successfully? MR. DRAKE: Yes, I believe it's a three
eights inch stainless steel liner. In 2005 during excavation for the dry fuel
storage an exterior concrete shrinkage vac in the
concrete wall was found. It was previously
underground. During extended conditions after that of
the liner we determined a leak was found in the fuel
transfer canal. This is now a normally dry area. No. In 2005 we also took several more
core bores in the area of the crack that showed a
moist spot underneath the crack. And we exposed some
rebar. And, again, that rebar was in excellent
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 inspections. We found a leak in the transfer canal
that was done by extensive UT and visual inspections
in the transfer canal and vacuum box tests on the back
of the transfer canal. And there was a small pinhole
in a plug weld that was also repaired. We found two
very minor indications in welds, these were none
leaks, they passed vacuum box. But they were just
indications in the weld and they were excavated and
repaired also. So to date we've done inspections of all
accessible portions of the spent fuel pool, that
includes 100 percent of the liner above the fuel, 100
percent of the transfer canal and a 100 percent of the
CASS wash pit. The transfer canal extensive inspection
proved that the spent fuel pool liner is sound by both
visual inspections and by UT. There are no aging
degradation related events observed. All structural evaluations have concluded
that the concrete and rebar remain capable of
performing its intended functions. The aging
management inspection programs will continue. We do
spent fuel pool monitoring. We do shiftly inspections
of the pool elevations. And we also are monitoring the
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 the wall. And to date our monitoring program supports
that there is no current leak from the pool. MEMBER STETKAR: I wanted to follow-up on
that last statement you made. I think I read
somewhere that after you discovered the indications on
the exterior you installed some sort of collection
system that would route water back -- MR. DRAKE: Yes. MEMBER STETKAR: -- into the primary
auxiliary building. MR. DRAKE: Yes. What we did was the crack
that was -- MR. DACIMO: This was a shrinkage crack. MR. DRAKE: This was a shrinkage crack, it
was a construction shrinkage crack. Still very tight.
We did some excavations. But this location was going
to be below the new floor that we were installing. So
what we did was we installed a stainless box around
the whole crack. MEMBER STETKAR: Yes. MR. DRAKE: We didn't want to just seal up
the crack; we wanted to be able to monitor it. We
installed a stainless steel box with a line that goes
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 and then be able to be monitored. MEMBER STETKAR: Have you seen any
moisture? MR. DACIMO: It's reduced greatly. Don, I
don't know, you want to address this? MR. MAYER: I can -- MR. DACIMO: Yes, why don't you do that. CHAIR MAYNARD: Can you come up to the
microphone and identify yourself? MR. MAYER: Sure. All right. Hello. I am
Don Mayer, Director of Emergency Planning and also
Special Projects at Indian Point. I was responsible, actually, for the groundwater investigation associated with this leak.
So what I can tell you is that the crack collection
box that Rich talked about at the peak when we first
identified the issue, we had about 1 2 to 2 liters per day that we were collecting for, you know, over the
course of a month or two. Okay. MEMBER STETKAR: And you know it was spent
fuel pool water? MR. MAYER: That's correct. Yes, we knew
that it had been spent fuel pool water, yes. And at the present time, like for instance
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 is anywhere between zero to 50 mLs of water. So it's
very low that enters into the box. MEMBER SIEBER: Per day? MR. DACIMO: Per day. MR. MAYER: Per day. I'm sorry. Yes, per
day. And it was 1 2 to 2 liters per day. MEMBER STETKAR: And the current water is
also the spent fuel pool water? MR. MAYER: The current water is still
indicating elevated levels of tritium. It's about 25
percent of that what's in the pool. So it's
definitely reducing as you would expect, and there's
no indication -- you know, let me put it to you this
way: If there was a leak that was active, okay, we
would expect to see not zero, we'd expect to see some
elevated level with some precipitation related input
going forward, and we don't see that. So we're seeing
about zero to 50 mLs per day. We do see some peaks
which we believe are precipitation related. MEMBER BANERJEE: What do you mean by
precipitation? MR. MAYER: What we see -- we're still
trying to get our arms around this fully. But we've retained a hydrologist on this from the beginning.
And there's an interstitial space -- this liner does NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 not have a tell-tale system. Unit 3 does, this liner
doesn't. And so what we believe has occurred here is
there's an interstitial space between the stainless
steel liner and the concrete that still has a residual
level of tritium that is just being held in that
interstitial space. It's tritiated water, okay? And
what happens is through precipitation events, snow
melt, et cetera, it doesn't take a whole lot of water
to come in and influence zero to 50 mLs per day on
average. And so over time, and we do see a
relationship in the springtime when we'll see elevated
peak that then will tail off. So the explanation that
we have is that it appears to be precipitation and
groundwater run-off based because the pool is above
the groundwater table, okay? MEMBER BANERJEE: So something is getting
in? MR. MAYER: Some small amount has to be
getting in. MEMBER BANERJEE: From somewhere else? MR. MAYER: And causing the concentration
to be lowering over time, which is what you would
expect as this things proceeds. MEMBER BANERJEE: So as the top end it's NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 open to the environment somewhere? MR. MAYER: Well, as we indicated, Rich
better can better describe, but you know shrinkage
cracks in concrete are not uncommon. And so what we
fully expect is that there may be some other shrinkage
crack locations where water can get in as well as get
out. MR. DRAKE: But we have a picture of the
spent fuel pool here. This is the Unit 2 spent fuel
pool building. And basically the 1992 leak that was
observed was up in this area here. And it because of
an attachment that was removed from the wall in this
area here when it was observed and we took core bore
samples there. The 2005 crack was actually below this
floor that is now there. It was below the ground level
in that area here. And that crack now has been sealed
by the stainless steel box and is now monitored. MEMBER RYAN: But the groundwater is
relatively close to the surface, I would guess, for
most of the year, is that right? MR. DRAKE: Do you know the hydrology? MR. MAYER: I don't exactly how deep it
is. It's below the bottom of the pool, I don't know
how many feet.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. DRAKE: Yes. The bottom of the pool is
down here. The crack was still higher than that. Yes.
The crack is still 68 foot or something like that. So
it was higher up, about eight to ten feet up from the
bottom of the pool. MR. MAYER: Yes, and one point, Mike, I
think I know where you may be going or you may be
asking. Is the site is actually elevated. The site at
this location is at the 70 to 80 foot elevation and
then it drops down to the river elevation at about the
five to ten foot elevation. Okay. So the groundwater
itself typically runs down around the 20 foot
elevation as it moves into the river, and this is well
above that. So what happens is the water comes -- MEMBER RYAN: So well above, five feet, two feet, three feet? MR. MAYER: I'm sorry, say again? MEMBER RYAN: Well above is how many feet? MR. MAYER: I'd have to go back and double
check our drawings. It's at least 20 feet above. MEMBER RYAN: The reason I'm asking this
is sometimes, you know in these systems particularly
with wintertime events with snow melt and all the
things you've mentioned, you know you can get water
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 as it's making its way down. And if it's contacting
stuff that's accumulating during a dryer period, you
can have these pulses. MR. MAYER: We do see that. MEMBER RYAN: You do see that? MR. MAYER: We do see that to a certain
degree on some of the welds. MEMBER RYAN: So surface water
infiltration is probably more important to think about
the groundwater level itself? MR. MAYER: For this particular situation, yes. MEMBER RYAN: Okay. MR. MAYER: That's correct. MEMBER SIEBER: You're doing some external
monitoring for tritium, right, weld monitoring? MR. MAYER: Yes, sir, that's correct. MEMBER SIEBER: And you haven't found
anything? MR. MAYER: No, we have found tritium in
the weld water. MEMBER SIEBER: Oh, you have? MR. MAYER: Yes, we have. In fact -- MEMBER SIEBER: That you attribute to the
plant?
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. MAYER: Yes. That's correct. MEMBER SIEBER: Okay. MR. MAYER: That was the principle reason
behind the large investigation that we conducted. We
did identify that this 1992 leak that was referenced
by Rich we believe is the principle source of the
subsurface tritium that we identified. Because it was
a fairly large volume of water over about an 18 month
period that did provide a source term. The pinhole that we identified we also
know we believe did contribute some smaller portion.
That was stopped in 2007. And so, you know, we expect
and we do in fact see a downward trend in treating
concentrations in the pool as a result of those
repairs. MEMBER RYAN: Is that over several cycles
of the seasonal cycles and all that? MR. MAYER: Yes, sir. MEMBER RYAN: So it's a very long term
trend. MR. MAYER: It's very long. MEMBER RYAN: Including the oscillations-- MR. MAYER: That's correct. That's an
excellent point, and I'd just like to elaborate
slightly on that.
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8 The investigation started formally in
October of 2005. Okay. So in hydrologist terms -- MEMBER RYAN: You're just getting started. MR. MAYER: -- that's not a lot of time.
Exactly. But we do have -- you know, we have retained
a good hydrology engineering outfit and we do look at
their data closely. And we do have enough data that
the hydrologist feels comfortable and confident that we are seeing over these least 2 2 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 /3 years a general downward trend in plume concentrations consistent with
what we believe has occurred, which is stopping the
leak. MEMBER RYAN: And I guess I'd assume your
plans that are continuing to do that monitoring to
really develop that trend with a little bit more data
or -- MR. MAYER: Yes, sir. We actually have a
program in place. We call it the long term groundwater
monitoring program. It's essentially codified in our
procedural processes and that's a life-of-plant
commitment. MEMBER BANERJEE: Does it mean that you're
actually making sufficient measurements to map the
plume? MR. MAYER: Yes, it does.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. DACIMO: Which we have done. We
actually have done that. MR. MAYER: We have done that. MEMBER RYAN: That would be helpful for us
to see what other force you have in that area that
could us better understand that. MR. MAYER: Sure. MEMBER SIEBER: Now the drinking water
limits, what 20,000? MR. MAYER: 20,000. MEMBER SIEBER: What's the highest
concentration? It seems to me I read something like
200? MR. DACIMO: Very low. MR. MAYER: No. Actually, what we saw
near the fuel pool we saw levels that were in the
neighborhood of 400 to 500,000 picocuries per liter. MEMBER SIEBER: Okay. MR. MAYER: So we did substantially
elevated in excess of the groundwater concentrations. MEMBER SIEBER: Okay. MR. MAYER: Since that initial situation
was discovered, levels near the pool are down closer
to, you know, 100,000/200,000. So we've seen a
definite drop. Okay. The last datapoint, in fact, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 near the pool is about 95,000. Down by the -- the way the plume -- you
know, if you think about this in terms of macroscopic
flow, because we did -- in answer to your question, we
did a very detailed hydrological study. It's been well
documented. In fact, it's on the public docket. We
provided it to the NRC -- MEMBER BANERJEE: Just the XY dimensions
or you got the Z as well? MR. MAYER: No, it's X,Y and Z. And we
mapped the entire site. We have transducers in
service that give us level and other important
information. We sample it for chemicals. We've got the
whole gamut. Got an excess. We've got 40 wells. Most
of these wells are multilevel wells. So we have -- in
fact, you know, it's not something that I'm
particularly happy about, but the fact of the matter
is we probably have one of the most intensive thorough
groundwater monitoring programs in the United States
as a result of some of the issues we dealt with. Down by the river the concentrations are
significantly less. The wells that are closest to the
river are in the 200 to 100,000 range. Near the
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 and still do see levels in the several thousand up to
maybe 20,000. But it's lower. And, you know, by the
river it's very low. MEMBER SIEBER: Have you found any levels
above 20,000 that are outside the protected area? MR. MAYER: No. MEMBER SIEBER: Or the owner controlled
area? MR. MAYER: Not outside the owner
controlled area, no. MEMBER RYAN: But this big change from, say, the river back up to these protected area wells
that you have makes sense. Because if it's a very
small volume that's leaking and that tritium is going
to distribute very, very rapidly in any hydrogen pool
it sees in water. MR. MAYER: Exactly. MEMBER RYAN: So that further confirms
that the volume leaving, you know, the areas that
you've discussed in the cracks has got to be small. MR. MAYER: Correct. MEMBER BANERJEE: So you've got a point
source of tritium, which is varying with time, let's
say? MR. MAYER: Yes, that's correct.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER BANERJEE: And what this is doing
is it's mixing into the groundwater by some form of
dispersion because it's porous media? MR. MAYER: That's correct. MEMBER BANERJEE: That's what's causing
the diffusion of this? MEMBER SIEBER: Right. MEMBER RYAN: Well, the tritium exchange
very rapidly in any hydrogen pool. MEMBER SIEBER: Yes. It's tritium in
water. MR. MAYER: It turns out that the tritium
as it leaves the reactor is very quickly converted
into water. MEMBER BANERJEE: Well the entrance of
this plume -- MEMBER SIEBER: It's water. It's water, it does what water does. MEMBER BANERJEE: -- which is what is
reaching the river? MR. MAYER: Right. That's correct. MEMBER SIEBER: It doesn't concentrate? MR. MAYER: It does not concentrate. MEMBER SIEBER: So you have -- it can go-- MEMBER RYAN: I think it's independent of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 the flow -- you know, by hydrogen exchange, it will
just uniformly seek the hydrogen pool that is
available. MEMBER SIEBER: Now the way we used to
think of it is -- CHAIR MAYNARD: What you're interested in
his the point characterization? MEMBER BANERJEE: Yes. I think where it
is, what's happening. MEMBER SIEBER: The way for me to think of
it is -- MEMBER BANERJEE: But they don't have it
over time, but they have it now. MEMBER SIEBER: -- the leak is stopped and
you're monitoring for it and continuing the corrective
action. And you have no evidence that you've ever
exceeded the drinking water standard -- MR. MAYER: Yes. Let me characterize it
the way that we characterize it for the Commission. As it turns out, and this is just a
regulatory fact of the business, there are no drinking
water supplies. We take no drinking water from the
site and there are no nearby supplies of drinking
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 have not identified any above that level, but we don't
utilize that regulation in discussions with the NRC
because as it turns out we're regulated to our off
site dose calculation manual level which are dosed, and we're a small percentage of that. MEMBER SIEBER: Well, my perception of it
is more conservative than what you were saying. MR. MAYER: Yes. Yes. MEMBER SIEBER: And to me if you don't
exceed the limit at the site boundary, you're far
better off. Then you don't exceed the limit that
somebody's drinking. MR. MAYER: Absolutely. And we have
confirmed with boundary wells on site as well as off
site monitoring of off site wells, surface waters and
the river. MEMBER RYAN: One of the last questions, it's maybe a forward looking question so forgive me if
you don't have the answer now, and I understand why
you don't because you don't have a lot of data; but if
you continue this program on into the future, at some
point you'll be able say, "Well, some event that
causes this in a nearby well is something we ought to
investigate more fully because it's indicating a
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 leak's getting bigger." Have you thought about what about the
future might be and so forth? MR. MAYER: Yes, we have. Yes, in fact
that was one of the principle design parameters of our
long term monitoring program is what you just
referenced. And so -- MEMBER BANERJEE: So you're going to
continue this program? MR. MAYER: Yes. Life-of-plant. MEMBER BANERJEE: Okay. Very good. MR. MAYER: I'd like to answer Mr. Ryan's
question. The answer is yes. The program was
designed that way. In fact, I focused on Unit 2
because that was the question, but we did provide a
network of wells that are across the entire site.
Because we didn't want to be myopic looking at just at
this one situation. So we provided a well field that
covers the whole site. That well field was placed
specifically with our experts and the hydrologist to
evaluate locations that we could then use as back
tracks and sentinels to the potential locations, other
fuel pools, other pipe systems and large tanks. So this long term monitoring program is in
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 quarterly. There are some other wells that are
different frequencies. It's built into our program
and it's designed to determine the effectiveness to
monitor the natural attenuation of the plume that we
do have. It's also designed to help us assess
potential dose implications from that. And then the
third key component of that program is that it is
designed with sentinel wells to help us do exactly
what Mr. Ryan reflected on, which is assess other
leakage points and help us do extended condition. MEMBER SIEBER: I think that answers my
questions. CHAIR MAYNARD: Yes. I would like to move
on again. We'll be interested in what the staff has
to say. And this is an ongoing open item here. So
let's go ahead and move. MEMBER SIEBER: Why don't we move on. MR. DRAKE: Okay. The next area for
discussion is the exterior containment concrete aging
management. The containment structures at Indian
Point have isolated areas that exist at Cadweld joints
of the rebar and at attachment points used for
scaffolding during original construction. These were
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 rule inspections in 1995. MEMBER BANERJEE: So the concrete has
spalled off or -- MR. DRAKE: No. Well, when I say it's
spalled, it's not the traditional spalling of the
concrete itself. These are cosmetic repaired areas
over Cadwelds that were very close to the surface
where scaffold embedded metal pieces that were used
for construction for the scaffolds as they moved up
the dome cylinder were attached to. They came back
later and put a cosmetic coating over these things.
And then during ILRT tests, because the continuing --
that they just popped these right off. MEMBER BROWN: So these are the items are
referred to as "pop-offs" in the inspection? MR. DRAKE: Yes. They're more pop-offs, they're not true spalls of the concrete, though. So
it is due to the lack of -- they're just cosmetic
cover over these embedded items. So it was original. We have not gotten
back and not done more cosmetic repairs over these
things for two reasons: (1) It would not allow us to monitor them
if we -- and would also just pop-off again when we did
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 from these. We've looked at them from structural
impact. The reenforcing steel provides most of the
strength. The observed surface degradation has no
impact for the ability of containment for its intended
function. MEMBER POWERS: What did you get in your
last integrated containment leakage test? MR. DRAKE: I believe they were done in
the last outages for both units. If not the last one, it was the fairly recent one. MR. DACIMO: It was two outages ago -- MR. DRAKE: For Unit 2. MR. DACIMO: Two outages for Unit 2. MR. DRAKE: And then the last outage for
- 3. MR. DACIMO: No. And two outages ago for
Unit 3. MR. DRAKE: But they were within the last
five or six years. MEMBER POWERS: Do we have the data from
those? MR. DRAKE: I gather that we do. MR. DACIMO: The IRLT data? MEMBER POWERS: Yes. Yes. MR. DACIMO: We can get you that. It NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 passed the integrated leak rate test. CHAIR MAYNARD: Okay. Now is the first
time you saw, '95 was when it was first identified? MR. DRAKE: It was when we first observed
and started documenting -- MEMBER SIEBER: That's when they first
wrote it down, correct? MR. DRAKE: Yes. The maintenance rule
inspections rated the structures on site. And the requirement for IWL were first instituted in 1995.
That was our baseline inspections for those programs, and they were documented there. CHAIR MAYNARD: Okay. MR. DRAKE: They were observed further
back. We have in several cases, we have observed
these and they were documented through our normal
corrective action process. And we've had pictures of
them from there going forward to now. And you could
put them on top of each other and just notice no
change. CHAIR MAYNARD: Have you gone back through
your IRLT data to see if there's any step changes at
any point or any significant -- MR. DACIMO: We have looked at the IRLT
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 and there's been no issues with that at all. MEMBER SIEBER: Initially when you do the
initial integrated leak rate test they map cracks. MR. DRAKE: And all the cracks are mapped. MEMBER SIEBER: Have you continued to map
cracks and watch the extent to which they've expanded? MR. DRAKE: We haven't gone back to all of
them, but we've made a commitment going forward. NRC
came in and did an audit of our program. And we made a
commitment to do more detailed mapping of that and
measurement in the future. MEMBER SIEBER: Usually for the first ILRT
you can see where somebody has gone on the outside of
containment to indicate, usually with paint or
something like that, where the cracks are. Because
it's important to monitor. You can tell whether the
rebar is failing or not or stretching by looking at
how far those cracks move or if you have new ones that
you didn't have before. MR. DRAKE: Yes. Most of the tight cracks
are still tight, you know, and seal right back up
after the IRLT. And there has been no measured
staining from any of those cracks. MEMBER SIEBER: You may be able to do that
with some photographic technique because to climb --
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. DRAKE: Yes, that's what we
additionally do. MEMBER SIEBER: -- into containment is not
something -- MR. DRAKE: No, you can't climb in. We
have an opportunity to get up towards above the top of
it with the stack for Unit 1. MEMBER SIEBER: Right. Right. MR. DRAKE: And we use high powered
instruments per the ISI program to get up close
effectively that way and to take pictures. MEMBER SIEBER: Yes. And since you brought
it up, Unit 1 was one with the afterburner on it, right? MR. DRAKE: Yes. MEMBER SIEBER: Okay. And it was a super
heated plant. And that stack is the highest feature
there? MR. DRAKE: Yes. MEMBER SIEBER: What do you do to make
sure that that stack isn't going to fall on some other
portion of the plant? MR. DRAKE: That -- MEMBER SIEBER: Because it's a heavy brick
stack with a steel liner.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. DRAKE: Yes. MEMBER SIEBER: And it's close in. MR. DRAKE: That was analyzed. When Unit 1
was all by itself, the stack was higher. When they
built Unit 2, they actually shortened it so that it
would not contact with the containment building. It
has been inspected in the past. It's going to be
scheduled to be inspected and painted going forward. MEMBER SIEBER: Is that part of your
license renewal program? I didn't see it in there, but -- MR. DRAKE: It's part. MEMBER SIEBER: -- it's a prominent
feature. MR. DRAKE: It's been added to the
structural monitoring program, yes. MEMBER SIEBER: Super. Thanks. CHAIR MAYNARD: Dana, do you have any more
questions on the IRLT or did you just want to see
their data? MEMBER POWERS: I just want to see their
data and the audit report from the NRC on process. MEMBER SIEBER: Sorry to interrupt. MEMBER BROWN: So you're no longer
repairing these pop-off? They just --
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. DRAKE: No. Because if we put the
cosmetic repair on them, we wouldn't be able to
monitor them. Besides, some of them are very
difficult to get to. But if we covered them, then we
wouldn't be able to monitor them. They have surface
rust on them and it hasn't changed. And that seems to
be the best -- MEMBER BROWN: So you do these by photos?
I mean -- MR. DRAKE: We do it photos -- MEMBER BROWN: I mean, there's an issue
with that in the instruction -- MR. DRAKE: Yes. And what we did is made a
commitment that what we're going to do is when we have
the capability to do some direct measurements of
those, even in the remote areas, by using parallel
lasers and to track them. But we have pictures and
you could almost put the pictures side-by-side over
the 10/15 years, and there's no change. MEMBER SIEBER: Well, and you're looking
at the length of the rust streaks, correct? MR. DRAKE: Excuse me? MEMBER SIEBER: You're looking at the
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 streaks -- MEMBER SIEBER: Oh, there aren't? MR. DACIMO: No. The only rust streaks
that are around are from the -- MEMBER SIEBER: No streaks? CHAIR MAYNARD: Rough idea of the size of
one of these pop-offs? MR. DRAKE: The pop-offs, I mean they're
about that size. That's where the embedded thing. And
there's been one where we had years ago, I was able to
-- we could see the scaling section there. We went
out and knocked it off and then we take --
photographed that one 10/15 years later, it hasn't
changed. MEMBER ARMIJO: Are these tens of these or
hundreds of these pop-offs? I can imagine lots of
points when you're building. MR. DRAKE: Yes. At Unit 2 the Cadweld
areas, embedded areas that we have identified, there
are 41 locations in Unit 2 and there's seven in Unit
- 3. MEMBER ARMIJO: These are all -- MR. DRAKE: Seven. They're all on the
cylinder, none on the dome. MEMBER ARMIJO: Okay.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER STETKAR: So there are on the -- MEMBER SIEBER: Well, you didn't the
scaffolding on the dome. MR. DRAKE: There are seven Cadweld
connections and locations. MEMBER STETKAR: And you've seen the pop-
off? When you say "Cadweld connections," the pop-off
locations on Unit 3? MR. DRAKE: Yes. They're either Cadwelds
or from the scaffolding. MEMBER BROWN: Why is there no concern
that there's something underneath the rebar sections
that you can't see and that there was a penetration
into the concrete in containment? Oh, it's not
visible from the surface? MR. DRAKE: No. We know the Cadweld
joints -- MEMBER BROWN: I mean, you've got
environment conditions going all the time if you leave
them open -- MR. DRAKE: Yes. MEMBER BROWN: -- and expansion and water
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 on. MEMBER BROWN: Okay. MR. COX: As Rich indicated, these are on
the side of the building so there's not much for water
getting into and dam -- it's not going to pool in
there. MEMBER BROWN: All right. MEMBER SIEBER: Okay. Thanks. CHAIR MAYNARD: Let's move on. We'll do
one more item and then we'll take a break. MEMBER SIEBER: No question. MR. DRAKE: Okay. The next issue is the
concern for the water-cement ratio. NUREG-1801 for
aging effects for concrete in outdoor air
environments, this recommends that the evaluation
consider water-cement ratio. The water-cement ratio
for Unit 3 was examined and is outside the recommended
requirement. Unit 2 and Unit 3 used ACI 318-63, which
is the original code of record at time of
construction. And this document basically allows two
different methods to determine the required strength
and durability of the concrete. Indian Point used method 2 where we did
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 after the fact and concluded that all our concrete
exceeded the strength requirements of the 3000 psi, our minimum cylinder that we broke was 3600. Almost
all of them were much higher than that. The actual test reports confirmed that.
And there has been no aging effects observed of the
concrete. MEMBER SIEBER: So this is easy to close? MR. DRAKE: We feel so. MEMBER SIEBER: You submitted all the
records and everything to the staff to deal with, right? MR. DRAKE: Yes. Yes. MR. YOUNG: The staff is continuing a
review, and we understand they're making some
additional questions on these records. But -- MEMBER SIEBER: Yes. But what you did is
typical of what the industry has done on that -- MR. YOUNG: Yes. Yes. MEMBER SIEBER: -- construction of
containment. CHAIR MAYNARD: But I don't believe that
this one's one that the staff's ready to close out
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 their review on this. CHAIR MAYNARD: They're still, they're
going back and forth on this on the side. MEMBER SIEBER: Good. We can take a
break. CHAIR MAYNARD: Not yet. Is there any
questions on this one? Okay. Let's take a break. We'll take a
15 minute break. Let's be back at 24 after. (Whereupon, at 10:08 a.m. off the record
until 10:24 a.m. CHAIR MAYNARD: Okay. Let's come back
into session here and go back to the item, I think that's aging management of concrete subject to
elevated temperatures. MR. DRAKE: That is correct. CHAIR MAYNARD: Okay. MR. DRAKE: This stems out of the concern
that IP2 hot piping penetrations are allowed to
operate at temperatures greater than 200 degrees
Fahrenheit. NUREG-1801 allowed local area concrete
temperatures greater than 200 degrees fahrenheit with
plant specific evaluation. So IP2 has done plant specific evaluations for the effects of temperatures up to 200 degree F.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 And basically the engineering evaluations determined
that the maximum 15 percent in strength in concrete
temperatures up to 250 degrees is enveloped by the
concrete structural characteristics that exceeded by
20 percent over the original design strength of 3000
psi. This basically stems the change in the
FSAR which highlights this, stems from a 1994 event
from April to October 1994. Normally the operating temperatures in this area is less than 140 degrees.
But during this period it was noted Unit 2 that
slightly higher temperatures above 150 were observed.
The bulk average temperature was approximately 153
degrees. The highest measured area measurement was
176 with two very isolated temperature readings of 201
to 205 degrees for a short period of time between the
penetrations. So the evaluation was done to determine that this is acceptable for these short durations.
And the FSAR was changed up to 250 degrees. MEMBER SIEBER: What caused that? MR. DRAKE: There were some problem with
the blowers at the time. Normally bulky knits have
four blowers on each unit; two are in normal
operation, two are on standby. Then we have
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 blowers is out of service, the alarm response
procedure immediately notifies the NPOs and start
standby blowers. And since we have annunciator
procedure in effect for temperatures below 150 we
don't see it as it any structural concern. MEMBER STETKAR: Let me ask a question.
You kind of stumbled across this. When you screened
out the hot penetration cooling system from aging
management you -- MR. YOUNG: Yes. MR. COX: Well, let me answer that. That
is correct, the hot penetration cooling system will
essentially assist in maintaining the environment of
the concrete. And typically, you know, that's not one
of the scoping criteria so we haven't included those
types of systems. There are a number of other systems
that also serve a similar function of maintaining an
environment. An example would be containment normal
cooling systems. MEMBER STETKAR: I understand. As I
understand it, I read through the analysis, and the
claim is that the maximum temperature, as you note
here, of the concrete would be 200 degrees Fahrenheit
if there was no cooling flow, meaning I guess the
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 active components and they wouldn't be included under
the AMPs anyway. Did those analyses look at no flow, in
other words blockage of those little cooling channel
paths such that there was no convective heat transfer
from the concrete? Because you're looking at 500
degree plus piping transmitting heat into the concrete
in those adjacent areas. And I was curious how you
came to the conclusion that the maximum temperature of
the concrete and you'd see was 200 degree Fahrenheit, if there was actually no flaw? In other words, if the
cooling channels were blocked? MR. COX: Rich, can you speak at it?
These pipes are isolated, so that is one other factor
there. MEMBER STETKAR: Yes. MR. COX: But Rich is part of the group
that made that analysis. MR. DRAKE: Yes. They're well insulated
and we have the blowers that pass through there. And
in this particular event they were actually taking-- MEMBER STETKAR: But I'm not asking about
the blowers. I'm asking about plugging the little -- I
read about how the little cooling channels are
fabricated with the little ribbed and concentric --
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 you know, sort of a radiator kind of configuration
that the air blows through. If those cooling channels
became plugged, fouled such that you had no air
passage through there or substantially reduced air
passage, regardless of the status of the blowers, would you still reach only a maximum of 200 degrees
Fahrenheit? And where I'm headed, obviously, is an
aging management program to verify that those channels
are open. Because they are a passive flow component. MR. DRAKE: Right. MEMBER ARMIJO: It would take an
inspection of some sort. MEMBER STETKAR: Some sort of inspection
to verify, you know, volume of flow or -- I'm not
going to design a program. It's just a question of
are those -- the same way that you verify whether or
not a water-to-water heat exchanger is plugged or
fouled or whatever. Because these are just air-to-
air-- MEMBER SIEBER: Well, there's two
components to that. You have to calculate to assure
the temperature remains 200 degrees. And then you have
to go out and check to make sure that all the channels
are open.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER STETKAR: Well, the calculation
actually showed that the maximum steady state
temperature was 200 given no convective air flow
through those channels -- MEMBER SIEBER: That it was 205, yes. MEMBER STETKAR: I feel though that -- MR. DACIMO: But we know, though, that
there is no issue at 250, right, Rich? MR. DRAKE: That's correct. MR. DACIMO: Okay. MR. DRAKE: At even higher. Even the ACI
code is under review to revise their standards even
higher. MR. DACIMO: So 250, if you would operate
250, it would not be an issue. MEMBER STETKAR: I understand that. But
the rationale that I read was that it wouldn't 200
degrees if you had no forced flow. And I was curious
what you would exceed if you had no air flow from
there at all. MR. DRAKE: Yes. There was a study to say
that, especially on Unit 3 studies that if you didn't
have anything, temperatures would go to up certain
temperatures over, you know, a 1000 hours0.0116 days <br />0.278 hours <br />0.00165 weeks <br />3.805e-4 months <br />. But --
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 okay? We don't have an answer right now. MEMBER STETKAR: Okay. Thank you. CHAIR MAYNARD: Any other questions on
this item? Okay. Topics of interest. MR. YOUNG: Yes. On the next topics of
interest, Nelson Azevedo will make the presentation on
the next two, the reactor vessel integrity and the
buried piping aging management program. MEMBER SIEBER: I'd just note, are we done
with open items? CHAIR MAYNARD: No. We're going to come
back to these, Jack. We're getting the other ones
here. MEMBER SIEBER: All right. MR. AZEVEDO: Okay. Good morning. My name
is Nelson Azevedo. I'm the Supervisor of Code Programs
at Indian Point. I'll briefly discuss the status of
both reactor vessels at Indian Point 2 and 3 with
respect to upper shelf energy as well as the RT PTS with the thermal shock limits of 10 CFR 50.61. The Unit 2 reactor vessel, similar to Unit
3 was manufactured by Combustion Engineering, both are
Combustion Engineering reactor vessels. With respect to upper shelf energy the
limiting location for Unit 2 is Plate B2002-3, that's NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 an intermediate shell plate. And the upper shelf
energy effective full power years, which is the
expected end of extended operating period accumulated
fluence is 48.3 ft-lbs. Although this is less than
the 10 CFR 50.61 Appendix G screening criteria at 54
ft-lbs, it does exceed the minimum required of 43 ft-
lbs that was the evaluation done by the Westinghouse
Owners Group back in early 1990s were in response to
Generic Letter 29.01 With respect RT PTS , the most limiting location for Indian Point 2 is circumferential weld
34B-009 at 268.4 degrees. Again, that's at 48
effective full power years. And this is less than
screening criteria of 300 degree. 300 degree is the
limit for circumferential welds. Going on to the Unit 3 reactor vessel.
Also manufactured by Combustion Engineering. The
upper shelf energy at the limiting location is Plate
B2803-3 at 49.8 ft.lbs. Again, this is just slightly
less than the Appendix G screening criteria of 54
pounds but it does exceed the 43 ft.lbs required by
the Westinghouse Owners Group analysis done for
Westinghouse. With respect to RT PTS , the limiting locations plate is the same plate, B2803-3, at 279.5 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 degrees. And this does exceed the screening criteria
of 270 degrees. As required by 10 CFR 50.61 Indian Point 3
will submit a plant-specific safety analysis at least
three years prior to reaching the screening criteria. MEMBER SHACK: When are you projected to
do that? MR. AZEVEDO: We're projected to reach the
270 degree limit at approximately 37 effective power
years, which is approximately nine years into the
period of extended operation. And we have implemented both low leakage
scores as well as flux suppressors at Indian Point 3. MEMBER SHACK: But you're taking credit
for that in these projections? MR. AZEVEDO: Yes, we are. MEMBER BROWN: You mean taking credit, the
fact that they'll have a successful -- CHAIR MAYNARD: It means they're going to
have to do something else in addition -- MEMBER BROWN: Yes, in addition. CHAIR MAYNARD: -- in answer to this prior
to that time frame or shutdown. MEMBER BANERJEE: But you're taking credit
for the low leakage score and the flux suppressors?
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. AZEVEDO: Yes, we are. The fluence
calculations for 48 effective full power years do
account for the low low leakage score as well as the
flux suppressors. MEMBER SIEBER: You haven't gone as far as
things like hafnium rods or -- MR. AZEVEDO: No. MEMBER SIEBER: -- in that projection? MR. DACIMO: No, we have not gone as far. MEMBER SIEBER: A change in the PTS rule
will help you? MR. AZEVEDO: Yes. We're following the
revision to 10 CFR 50.61, which is 10 CFR 50.61(a). MEMBER SIEBER: Right. MR. AZEVEDO: Indian Point 3 was one of
the reactor vessels analyzed as part of the rule
change. And if that becomes part of the regulation, that will address this issue to Indian Point 3. MEMBER SIEBER: Okay. But yours isn't the
most severe among the vessels that were examined. MR. AZEVEDO: I know that Indian Point 3
was one of the vessels evaluated. I don't know if it
was the most limiting vessel or not. MEMBER SIEBER: Well, you're down the list
of a few. You're close, but you didn't win.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. AZEVEDO: Okay. CHAIR MAYNARD: Next. MR. AZEVEDO: So next slide I will discuss
the buried piping of aging management program. For
license renewal Indian Point committed to NUREG-1801
program section XI.M34. The program includes
consideration of operating experience, and this
morning I will just briefly discuss some of the recent
operating experiences that we have experience at
Indian Point. We performed an inspection the fall of
2008. We actually dug up two locations. We exposed six
pipe sections. These were two locations where three
pipes ran parallel to one another. The inspections
revealed some coating degradation. There was
approximately five locations that had to be repaired. The pipe wall thickness was measured using
ultrasonics, and these UT results indicated the pipe
remained at full thickness. MEMBER SIEBER: Now you're relying for
your buried pipe corrosion resistance on the outside
coating? MR. AZEVEDO: We are relying on the
outside coating. And we are factoring in operating
experience and making adjustments as we see fit.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER SIEBER: Now operating experience
at some PWRs for cooling water lines shows corrosion
occurring from inside the pipe. And you're relying on
your UT measurements to say that the inside of the
pipe is not corroding? MR. AZEVEDO: Our service water system has
experienced corrosion from the inside. MEMBER SIEBER: What have you done to
repair it or are you just monitoring it? MR. AZEVEDO: We do approximately 40 RT
inspections every outage as well as robotic
inspections, visual inspection from the inside of the
pipe for the larger diameter pipes. So we are
inspecting those pipes. MEMBER SIEBER: Yes. Could you describe
in just a few words what the robotic inspection
consists of? That is pipe's at what, at 36 inch or
something like that? MR. AZEVEDO: They vary in size. I believe
that we individually inspect anything above 14 inches.
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somehow we get into the system. And then we go as far
as we can with a visual crawler and we document the
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 of lots of crud and animals and so forth in there, you
know, crustaceans and -- MR. AZEVEDO: No, we haven't. The
predominant issue with the service water is at weld
joints. Our piping is concrete lined, cement lined.
And if the cement line chips in a certain location, that weld will develop a through-wall leak. That has
been our experience. MR. DACIMO: And we also install the Weko-
seals. MR. AZEVEDO: In some locations that's
correct. MR. DACIMO: In some locations we actually
sent a -- in the joint itself is a seal that you can
snap in place, okay, to protect that joint and
protects service water from migrating through the
joint to the metal. MEMBER SIEBER: Well, operating experience
would tell all of us that we need to pay particular
attention to service water. It has the potential of
picking up chemicals. And since the flow is not high
at all times, the conditions are good for corrosion
and blockage. MR. COX: And a little clarification. This is Alan Cox.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Let me add one clarification. The program
that we're talking about here is really focused on the
outside of the piping. We do have a number of other
programs that we could talk about that deal with the
inside and the service water heavy program is one of
them that Nelson was describing that deals with the
inside of the service water pipe. MEMBER SIEBER: No. I think for the
purpose of license renewal we have to consider both. MR. COX: Right. MEMBER SIEBER: Both the outside
protection and the inside corrosion resistance, plugging and associated things. Operating history
tells us it's important. MR. COX: Right. I just wanted to clarify
that not all of that is going to be under this
particular program that Nelson was discussing. MEMBER SIEBER: All right. MR. COX: It's under a number of programs. MR. AZEVEDO: Okay. So both of these
locations we repaired the coating that had been
degraded and we backfilled the holes. This was done, again, in the fall of 2008. Going on to the next slide. More recently
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 8 inch condensate line. This was due to external
corrosion which led to a through-wall defect. This
location was excavated. The areas of concern were
repaired. One section of the pipe was replaced and the
line was returned to service. A failure analysis is ongoing, has not
been completed yet on the removed section. And we'll
use the results of this failure analysis to establish
both scope and frequency of inspections going forward. MEMBER ARMIJO: Is this a carbon steel
line? MR. AZEVEDO: Yes, it is. MEMBER ARMIJO: Okay. CHAIR MAYNARD: I know you don't like to
speculate until the analysis is done, but do you have
any preliminary conclusions or the cause of this? MR. AZEVEDO: Other than say that the
corrosion is from the outside, I really don't have any
additional information at this time. MEMBER SIEBER: You say that was a
condensate line? MR. AZEVEDO: It was a condensate line, that's right. MEMBER SIEBER: That's under the turbine
room basement?
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. AZEVEDO: This specific location was
under the main feedwater lines and next to the aux
feedwater pump room. MEMBER SIEBER: Okay. And is that buried
piping? MR. AZEVEDO: Yes, it is. MEMBER SIEBER: Okay. MEMBER BANERJEE: How did you find it? MR. AZEVEDO: We had water -- there's a
flow penetration sleeve and the water was coming out
of the sleeve and pooling on the floor. MEMBER SIEBER: Okay. MEMBER BANERJEE: Would that happen in all
cases or is it this particular -- MR. AZEVEDO: Not necessarily. If the leak
had been outside the building, we may not have seen as
quickly as we saw coming out of the sleeve. CHAIR MAYNARD: How did you have to get to
this? Did you have to go through concrete or
anything? MR. AZEVEDO: Yes. We had to cut a hole in
the floor and dig a whole approximately 10 to 15 feet
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 type? MR. AZEVEDO: Bitumestic. It's the black
tar. MEMBER BANERJEE: Now those leaks in other
pipes, what sort of way would you know what would be--
is there a sort of a diagnostic which helps you to
detect them? MR. AZEVEDO: EPRI has been working with
Duke Power and we've been also participating. Some
promising new techniques that the industry is working
on, but right now there is no proven technique other
than just digging holes and visually inspecting pipe.
But we're hopefully that in the near future there
will be some ND techniques that we can use. MR. DACIMO: But it also is dependent upon
the system also. In the case of condensate you would
see, depending on how large the leak would became, your makeup or of you condensate storage tank would
start becoming excessive based upon what your other
system or expected system losses would be. So in
reviewing logs at some point in time you pick up on
that. CHAIR MAYNARD: So a number of it that's
the way -- that's the way it would be picked up is
through performance --
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. DACIMO: Right. That's correct. CHAIR MAYNARD: -- flow test or break-up
rates, things like that. MR. DACIMO: Right. MR. AZEVEDO: Yes, it's a good point that
at least for this ASME section XI class 3 systems we
do flow tests or pressure tests so we would be able to
pick-up through-wall hole defects. MEMBER SIEBER: Yes. This line you usually
-- it operates at a very low pressure and if it leaks, it really doesn't effect safety-related systems. MR. AZEVEDO: Right. MEMBER SIEBER: On the other hand, it can
degrade the foundation of the building, you know, because you're making a cavity under the floor. MEMBER RAY: Fred, is there any difference
between safety function lines, picking up on Jack's
point? MR. DACIMO: What we do is our buried
piping program ranks the systems that we'll look at
based upon safety significance. MEMBER RAY: Okay. MR. DACIMO: So, you know, service water
obviously in condensate storage actually is high. MEMBER RAY: That's right.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. DACIMO: As a matter of fact, condensate the reason it was picked initially to pick
those locations that we looked at was because it
screened out as being -- MEMBER SIEBER: Yes, RWST also. MR. DACIMO: Right. That would be a high
system also. MEMBER SIEBER: Right. CHAIR MAYNARD: Okay. We would like to
move on. MR. YOUNG: Okay. Rich Drake will be
covering the next item on the 1973 feedwater event.
And then following that we can go into the open items
that we didn't talk about earlier. CHAIR MAYNARD: That's right. Yes. MR. YOUNG: Okay. CHAIR MAYNARD: I'm keeping my eye on the
clock. We are going to have time to do that. MR. DRAKE: Okay. This is a question that
was asked about the Unit 2 containment liner 1973
feedwater event. On November 1973 during initial
plant startup from 7 percent power there was a
feedwater hammer which caused a pipe crack inside containment near the containment penetration area.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 containment liner causing a bulge to develop. Subsequent to that piping was repaired.
Other modifications were made to the steam generator
to prevent -- to preclude reoccurrence of this event.
This actually led to the whole industry J tube
modifications. And the deformation restored to the
containment liner with a -- CHAIR MAYNARD: Somebody's got papers on
the speaker there. MEMBER SIEBER: This occurred before you
put J tubes in? MR. DRAKE: This is correct. This is one
of the -- MEMBER SIEBER: So the water hammer came
from the drain -- MR. DRAKE: That's correct. MEMBER SIEBER: -- of the sparger? MR. DACIMO: The J tube model modification
actually came out of this. MEMBER SIEBER: Okay. MR. DACIMO: This was one of the earlier-- MEMBER SIEBER: And you're the guys that
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 guys that were associated with it. So that basically
modify -- MEMBER SIEBER: It was not so artfully
phrased, but you got -- MR. DRAKE: Yes. The piping to the steam
generator modified and the piping itself was repaired. MEMBER SIEBER: Okay. MR. DRAKE: So the area of insulation of
the liner then is expanded to cover a greater area
liner, insulation to prevent reoccurrence of this
also. They performed UTs and a 100 percent mag
particle of the liner itself in the area that the
bulge occurred to make sure that it did not crack. They performed analysis to determine the
as-left condition and also that the liner was good for
continued operation. MEMBER SIEBER: But the liner is not the
support. The support is inside the containment wall.
The liner just happens to be attached to it. MR. DRAKE: That's right. It's just a
pressure -- MEMBER SIEBER: So what do you know about
the inside of the containment wall? How much of that
got ripped apart?
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. DRAKE: What they did is they did UTs
of the embedded studs and determined that there were
several of them that were broken, and that was also
analyzed. MEMBER SIEBER: Yes. But the concrete is
there, too. MR. DRAKE: Yes. But this was a very short
transient effect. So it was just the liner that
bulged. MEMBER SIEBER: Yes. MEMBER ARMIJO: So was it a buckling in?
The liner heated up but buckled -- MEMBER SIEBER: What happens is that pipe
tries to drive itself through to the containment, it
takes the liner -- MR. DRAKE: It's the steam contains the
heat? MEMBER SIEBER: Oh really? MR. DRAKE: Yes. The steam contains the
heat. MEMBER SIEBER: So it's not the water in
the -- MR. DRAKE: No, no, no. No. The water
hammer caused the pipe to crack and that steam pluming
then continues under the liner --
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER SIEBER: The liner, right. MR. DRAKE: -- and then the heat popped it
out. MEMBER SIEBER: Okay. MR. DRAKE: They did mag particles to show
there was no cracking. And then they were able to
restore most of the configuration of the liner back, basically. MEMBER ARMIJO: So you basically just push
it back in? There must have been some plastic
deformation -- MR. DRAKE: Yes. They used an ILRT
basically to restore and push it back into place. It
was measured. MEMBER ARMIJO: Okay. MR. DRAKE: There was sight remaining
plastic deformation that had occurred in certain
locations. MEMBER ARMIJO: But to Jack's point, the
duration of the steam impingement was relatively
short-- MR. DRAKE: That's correct. MEMBER ARMIJO: -- within an hour, half
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 of how long that was. John Curry, he's a Project
Manager for License Renewal. MR. CURRY: As Fred stated, my name is
John Curry. When this incident took place from the
time logs that were taken, the time that the feedwater
actually flowed on where this crack was approximately
a half an hour. So it was a very short time -- MEMBER SIEBER: About the temperature -- MR. CURRY: -- that it impinged on the
containment liner. MEMBER BANERJEE: And what sort of
temperatures were -- MEMBER SIEBER: 400 degrees, probably.
450. MR. CURRY: Yes. The final feedwater
temperature at that particular point in time was
approximately 425 degrees. And the unit was at 7
percent power from the reports. MEMBER SIEBER: Right. MEMBER ARMIJO: So you could calculate
thermal stresses and see if that exceeded some
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 duration for 400 degrees, it wouldn't be a concern. MEMBER CORRADINI: I guess if I were in
your shoes, I would answer the question in a sense
that this was like a sunburn blister. It pulls out and
it insulated itself. MR. DRAKE: That's correct. MEMBER ARMIJO: That helps sort of. MEMBER CORRADINI: It sure does. MEMBER SIEBER: Sort of. MR. DRAKE: Just for the record, is we
have done and we're going to submit the data very
successful ILRTs on a number of occasions since then. MEMBER SIEBER: The last item on that
containment, you probably have done three. MR. DRAKE: Yes. It was last done in -- MR. DACIMO: And in reality after that
event there was a "partial unofficial ILRT" then there
was an official ILRT. So -- MEMBER SIEBER: The unofficial one was to
restore the -- MR. DACIMO: Well, it was 1973 and it's a
little fuzzy, but I think that was the intent. MEMBER BANERJEE: Well, going back to this
blister, can I ask you so you have a pipe which is
cracked. There's a jet of --
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER SIEBER: Steam. MEMBER BANERJEE: -- steam and water or
whatever -- MEMBER SIEBER: Steam. MEMBER BANERJEE: -- coming and hitting
this liner. Why is it bulging outwards? MEMBER ARMIJO: It is expanding. It cane
from behind you, it can't go that way. MEMBER BANERJEE: So it's just a
temperature effect, right? MR. DRAKE: Right. MEMBER BANERJEE: It's not due to any
forces? MR. DRAKE: No. No. CHAIR MAYNARD: It expands, it can't go
out, it's got to come in. MEMBER BANERJEE: So it's a little blister
due to the heat -- MR. DRAKE: Exactly. MEMBER SIEBER: I would have said either
way, but -- MEMBER BANERJEE: -- expansion? MEMBER ARMIJO: You are talking about a
foot in diameter, 20 feet in diameter? MR. DRAKE: It was over a 60 foot arc.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. CURRY: And another unique design
feature of Unit 2 and Unit 3 on the containment liner
all of the plate-to-plate welds that were made in the
field are covered with a channel -- MEMBER SIEBER: Right. MR. CURRY: -- that is welded over them
which we refer to as the weld channel system. And that
is pressurized with 52 pounds of pressurization. And
that air that is fed into that system is monitored.
And over the life of the plant and throughout this
whole incident that took place in 1973 no change in
the weld channel flow was indicated. So as the plates
did buckle, the welds also showed that their integrity
was maintained. MEMBER SIEBER: Do you keep that
pressurized all the time? MR. CURRY: Pressurized all the time. MR. DACIMO: Yes, we're one of the few
plants in the country that had that. Connecticut
Yankee being one, Zion being another one. MEMBER SIEBER: Yes. Usually the welds
that would fail is the channel welds as opposed to the
liner welds. MR. DACIMO: Right. Right. MEMBER SIEBER: And most people decided--
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER ARMIJO: Yes. We had an open
question about the site of the buckle. MR. DRAKE: It was over a 60 foot arc. MEMBER ARMIJO: Give me in square feet or
whatever so that -- that's a pretty big -- it's not a
local -- MR. DACIMO: Sixty by ten? MR. DRAKE: It's -- yes, by 10 or
something like that. MR. DACIMO: The deformation though in
inches was what? Was 5/8th of an inch? MR. DRAKE: About an inch and a half -- MR. DACIMO: An inch and a half. MR. DRAKE: -- in the worst case. MEMBER ARMIJO: It was a large area -- MR. DRAKE: Yes. MEMBER ARMIJO: -- with a small -- MR. DRAKE: Yes. Right. MEMBER SIEBER: You say the liner
thickness is an inch and a half? MR. DRAKE: No. No. The worst case, about
an inch and a half. CHAIR MAYNARD: But the liner really isn't
there for structural purposes. It's there for
pressure--
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. DRAKE: Right, just for pressure. CHAIR MAYNARD: -- and you did the ILRT
after that and you'd still be all right. MEMBER SIEBER: It's a membrane. MR. DRAKE: Yes. So we've done ILRTs. We
had the weld channel that's in service, it was
continually pressurized. In this last outage we did a visual
inspection of the as-let condition and confirmed that
the configuration is still in the same point. That
was with the insulation on, though. We have done ILRTs since then to prove
integrity. There is no age degradation observed of
the liner itself. We continue to do ISI/IWE
inspections and we'll continue to do that in the
future. And we made a commitment to perform a one
time behind insulation in those areas inspection to
determine if there's any other degradation going on. MEMBER BONACA: Would you say it again?
Which area? MR. DRAKE: We're going to go with those
areas where there is the permanent deformation and
with the liner buckled that we're going to go --
remove the insulation do a one time visual inspection. MEMBER BONACA: Okay.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER ARMIJO: Remove? You're not going
to cut the liner? MR. DRAKE: No, no. We're going to just
removed the insulation and do a visual inspection
behind the insulation. MEMBER SIEBER: Okay. CHAIR MAYNARD: This would be the
insulation around the pipe, the penetration area? MR. DRAKE: No. This will be of the areas
where the bulge and buckling occurred. MR. COX: This is Alan Cox. There was insulation that was added to the
surface of the liner after this event. MR. DRAKE: And that was done for both
units after this event. CHAIR MAYNARD: Okay. MEMBER RAY: For the -- MR. DRAKE: Up to like the 80 foot
elevation which is almost up -- MEMBER SIEBER: What kind of insulation? MR. DRAKE: -- to the operating floor deck
of the containment. So anything below be now covered. MEMBER SIEBER: What kind of insulation? MR. DRAKE: That --it's a metal jacketed--
I don't know exactly what the size --
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. CURRY: It's a foam glass type of
insulation. MR. DRAKE: Yes. And it's --- MR. CURRY: It's name was FLOAMGLAS. MR. DRAKE: Yes. MR. CURRY: And there's an asbestos
backing paper. So against the liner there's an
asbestos backing it in, there's foam glass insulation
-- MR. DRAKE: Then it's covered with
stainless steel. MR. CURRY: And then covered with a
stainless steel. MR. DRAKE: And this is also outside the
crane wall where you wouldn't get any immediate jet
impingement except if you had a pipe break or
something like. MEMBER SIEBER: Except for the pipe, that
reason why you put it there. MR. DRAKE: But it wouldn't be -- MEMBER SIEBER: Would it go to the sump?
Would it go the sump if you washed it off the wall. MEMBER BANERJEE: So how high is this?
Eighty feet? MEMBER SIEBER: It's high.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. DRAKE: It goes up to our 80 foot
elevation from a 40 foot -- from a 46 -- MR. DACIMO: It's a band, right? It's a
band at how many feet high? MR. CURRY: Well, it's from the 46 foot
elevation-- MR. DRAKE: Almost to the 80th. MR. CURRY: -- to the 80 foot elevation. MR. DRAKE: All the way around. MR. CURRY: And the full area of
containment. And it extends above in the hot piping
penetration areas. So it was extended at the time of
the incident and then carried over to Unit 3. MEMBER SIEBER: When you GSI-191
calculation for debris is that included? MR. DRAKE: This was all -- that was
considered. Oh, yes, that was considered. Absolutely. MEMBER SIEBER: Because that's -- MR. DRAKE: And it's also outside the
crane wall. MEMBER BANERJEE: And it is jacketed? MR. DRAKE: It's got -- it's covered with
the steel. I said "jacketed," that was probably a
misnomer. It's covered with the same metal. MR. COX: It's still the same thing.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER SIEBER: Sheet metal? MEMBER BANERJEE: Well, it's not fibrous
or anything like that, right? MEMBER SIEBER: Yes, it is. MEMBER SHACK: It's all glass. MEMBER BANERJEE: Is it fiberglass? MEMBER SHACK: Yes. MR. CURRY: Well, it's a rigid -- it's a
rigid piece of insulation. It's a -- MEMBER SIEBER: You can break it up in
your hand. MR. CURRY: -- made of-- basically it's
molten glass with air pockets in it, foam -- MEMBER BANERJEE: Okay. It crumbles into
what? Particles? MR. CURRY: Yes, well it's not fibrous. MEMBER BANERJEE: But not fibrous? MR. CURRY: But not fibrous. CHAIR MAYNARD: I'd like to move on. I
think this topic would be of interest during a GSI-191
discussion. MEMBER BANERJEE: I'm sure they're thought
about it. CHAIR MAYNARD: But for license renewal, I'd like to go ahead and move on.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 What I'd like to do now is go back to page
- 21. Just step through the ones that are marked "Ready" and give the members a chance to ask questions
or to dig into these a little bit deeper. You don't
have to go into great detail, maybe just discuss it.
We'll get you into you into the great detail. MR. YOUNG: Okay. Alan Cox is going to
walk through each item and give a little summary of
what the item is and what response. All of these
items we've provided responses in a letter that went
in toward the end of January, if I remember right. MEMBER SIEBER: Yes, we have the letter. MR. YOUNG: So that's what all these items
are. They're part of that January 26th letter. CHAIR MAYNARD: Yes, I understand. We
briefly want to pursue these a little bit. And the
other items we've been talking about that are still
open issues, there's going to be information going
back and forth and these we'll get an opportunity to
review new information. You know, this is one we're probably not
going to see any information on and that's what we've
got to see if there's areas that we want to ask for or
need more information on. So that's why we need to
step these.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. YOUNG: Yes. Okay.
Alan? MR. COX: Okay. The first item is on the
-- I think the title is yard hose houses and chamber
housings. These are ruptures in the fire protection
system. The yard hose houses, but essentially it's a
storage cabinet to contain tools and nozzles and -- MEMBER BANERJEE: So how do you determine
that there's no degradation of these, you inspect
them? MEMBER SIEBER: It doesn't make any
difference even if there is. MR. COX: It doesn't make any difference.
You could run over them with a truck and the fire
systems would still perform its function. It's a
convenience item for storage. MEMBER SIEBER: The only thing you have to
worry about is the configuration of the hose that you
store in there. And you test those regularly anyway. MR. COX: The hoses are tested
continually. MEMBER BANERJEE: And you are testing
them, yes? MR. YOUNG: Yes. The staff question was
why aren't they in scope. And then we provided the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 answer that they didn't provide an intended function
that met the criteria. And that was the answer we
provided in the January letter. MEMBER SIEBER: And in most plants they're
just sheet metal shacks with a door on it. MR. COX: The chamber housings, again, it's a surge chamber that's intended to prevent false
alarms due to pressure surges in the fire water system. They have no license renewal function.
They've got an orifice coming in and an orifice going
out, so there's not really a pressure boundary for the
fire water system. MEMBER STETKAR: When you talk about "chamber," this one is filled with valves, right? MR. COX: Right. MEMBER SIEBER: Right. MR. COX: The next one is the main
feedwater system stop valves. MEMBER SIEBER: Scoping. MR. COX: It's a scoping question about
whether those were included within scope. I believe we
have some of the valves that are safety-related that
are used for main feedwater isolation. These
particular valves are used as backup feedwater
isolation. And they were included in scope as (a)(2).
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Since they weren't safety-related, they didn't really
fit under the (a)(1) category. So we did include them
for (a)(2) and they evaluated in the maintenance
tables for the (a)(2) components. MEMBER SIEBER: I think the units are
different. You've got different scoping depending on
what years you're talking about. MR. COX: Yes. I think the -- it alludes
to the BFD-90 valves on one unit are credited and not
on the other unit. MEMBER SIEBER: Okay. MEMBER STETKAR: I had a question: Why is
that? MEMBER SIEBER: Original license basis. MEMBER STETKAR: What? Because the lines
are physically precisely the same size on each unit.
The valves perform the same function on each unit. So
I was curious why on Unit 2 the BDF-90 valves are
excluded as they're explicitly included on Unit 3? MR. COX: Well, I think the answer goes
back to the different ownership of the plant. At the
time -- MEMBER STETKAR: Okay. That's the answer.
History. MEMBER SIEBER: It's the license basis.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. COX: Let me finish. It's the license
-- the analysis. And it had to do with two different
people doing the analysis and the assumptions under
one analysis was that these valves operated and the
assumption on the other was they didn't. And both
results -- both analyses provided acceptable results. MEMBER STETKAR: This might be more a
question for the staff then -- MEMBER SIEBER: It's a legal issue. MEMBER STETKAR: -- because it's not at
all clear functionally. MEMBER SIEBER: All right. Move on. MR. COX: Okay. What's next? MR. YOUNG: Inaccessible fire barrier. MR. COX: The inaccessible fire barrier
penetration seals, it's probably one of the process
for doing evaluations to justify if you do have any
fire accessible fire barrier seals to justify not
doing the inspection. You know, you look at the fire
hazards and that sort of thing. And you have to have
a documented evaluation for those cases. So the question here was do we have any
evaluations and in looking through -- again, the
process requires it for inaccessible seals, but we
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 we had to have that evaluation. So the simple answer was we don't have any
inaccessible seals, we don't have any evaluations. CHAIR MAYNARD: Well, I think you skipped
one, the IP2 auxiliary feedwater pump room fire -- MR. COX: Okay. I'm sorry. You talked
about that earlier from the aging management
perspective. The question on scoping was to identify
the systems we relied on, the secondary systems that
we relied on in that event and to identify
specifically what parts of the systems that we relied
on and whether those systems were covered under the AT
scoping. And we provided that information in the
response. MEMBER SIEBER: Right. MEMBER STETKAR: I had a question about it
doesn't have -- I asked earlier about the fire event.
But I had a related question to auxiliary feedwater
pump. And I notice that you have screened out the HVAC
systems, heating/ventilation systems for the Indian
Point 2 auxiliary feedwater room. I think based on a
rationale that operators could locally open doors and
provide alternate cooling for that room, if I
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 issue. I don't know if we have that -- MEMBER STETKAR: Okay. I have a two part
question. One is the basis for screening out the Unit
2 HVAC completely and the other is that I didn't see
anything to address the HVAC for the Unit 3 auxiliary
feedwater pump room, which as best as I can tell, is
the same type of configuration. MR. COX: We can look at that and get back
to you later. MR. DACIMO: Well, we have Tom McCaffrey. MR. McCAFFREY: Tom McCaffrey, the Design
Engineering Manager. We do have an analysis, the high energy
line break analysis that credits the operator action
to open up the roll-up doors for 30 minutes. It's a
procedure to control for both units and for the
operators to take those actions. They have set points
associated with that to give them indication that they
need to take that action. MEMBER STETKAR: Do you have analyses to
show that the cooling that you can provide is
effective since the steam and feedwater lines go
through there and it can get pretty hot pretty fast? MR. McCAFFREY: Correct. Correct. And we
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 believe the number is 250 degrees approximately. I
don't know the number off the top of my head. It's in
that ballpark. The operators will have plenty of time
when they get the alarm to go out there, roll open the
roll-up door to provide cooling to that room MEMBER STETKAR: This room is full of now
hot pressurized steam when he opens up the door. MR. McCAFFREY: Yes. The roll-up doors
would be a garage door type of -- MR. DACIMO: They're very large doors, like a garage door. MR. McCAFFREY: The room is not -- it's
smaller than this room here. So the room that they're
opening is not a -- in relationship, it's probably
half of this room size where the garage door is
probably bigger than the entrance way here. MEMBER STETKAR: The same rationale
applies for Unit 3? MR. McCAFFREY: Correct. MEMBER SIEBER: It is 200 pounds of steam.
That's to feed to the turbine driven steam pump. MEMBER STETKAR: The main steam lines go
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 not go through aux pump room. MR. McCAFFREY: In the other room. This
is purely going to be the aux feed line break from the
steam going to the aux steam pump, aux door feedwater
steam driven pump in the room. And that's the line
break you're going to have in this room. MEMBER SIEBER: Yes. It is either the
steam supplied to the turbine or the aux feedwater, which -- MR. DACIMO: Those are the two highest
pressure lines in that room. MEMBER SIEBER: That's right. MR. McCAFFREY: Correct. MEMBER SIEBER: And they're sort of
intermediate, as I see it, as far as energy is
concerned. MEMBER STETKAR: And that analysis that
you mentioned as part of the current licensing basis
for not requiring operability of those ventilation
systems for that room, is that -- I'm not familiar
with the current licensing basis. MR. McCAFFREY: I'm not really sure of the
question. The current licensing basis we do credit an
operator action to open up the roll-up doors to help
mitigate the high-energy line break. And the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 operators, we have timed this with the operation to be
sure they can get there, you know during a scenario
they can get there and open up the roll-up door within
30 minutes. MEMBER STETKAR: Okay. So essentially I
guess what I'm asking you is the current licensing
basis doesn't require operability of those ventilation
systems to support the auxiliary feedwater system, is
that correct? MR. McCAFFREY: I'd not -- I don't know
that answer. MR. DACIMO: John Curry, do you have that? MR. CURRY: I don't know the answer
directly, no. MR. DACIMO: Okay. MEMBER STETKAR: Okay. And this other, the current tech specs, do they require operability of
those ventilation systems to support the auxiliary
feedwater system? MR. McCAFFREY: No. MEMBER STETKAR: Okay. Thanks. MEMBER BROWN: I missed something on
something on the fire protection seals. MEMBER SIEBER: Yes, I got a question or
two.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER BROWN: When I looked into the
responses there was still a response you all gave
back, I guess, to the staff. But it looked like your
position was that it's still going to come down to if
you couldn't get to a fire barrier protect penetration
seal, you didn't have to inspect it. Is that -- MR. DACIMO: Well, I didn't hear your
comment a moment ago. CHAIR MAYNARD: Let me go back over the
comment then. MR. YOUNG: Yes. The question on this one
was in our on site documentation we show that if there
is an inaccessible seal that we can't inspect, we have
to do an analysis to document that and the basis for
not inspecting. In the follow-up to that procedural
requirement we found there were no inaccessible fire
barrier seals so there were no calculations. If in the future we do have a change in
which one of these seals becomes inaccessible, then we
will have to follow the procedural requirements that
the staff had reviewed. But at this time we have no
inaccessible seals. MEMBER BROWN: Okay. MEMBER SIEBER: But the reasoning is not
too great behind excluding them had you had some, in NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 my opinion. MEMBER BROWN: No, that was my concern.
Was that because inaccessibility it wouldn't have
passed inspection -- MEMBER SIEBER: If you don't have them, it's not an issue. On the other hand if you had
similar seal failures in accessible areas, I would
certainly look at inaccessible -- MR. YOUNG: Well, absolutely. That would
be part corrective action program, yes. Right. MEMBER SIEBER: Well, that wasn't in your
submittal, the -- MR. YOUNG: No. But we haven't had any, you know, any -- MEMBER SIEBER: Yes, I got that. MR. YOUNG: Okay. MEMBER BROWN: Thanks. CHAIR MAYNARD: Okay. The heat exchanger
monitoring. MR. COX: The heat exchanger monitoring
was a question that we received on provide more
details on the inspection criteria. And we provided an
answer to discuss the qualifications -- we got a
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 things that he would be looking for in terms of
surface roughness caused by corrosion, erosion
pitting, whatever it might be. And, of course, any
unacceptable signs of degradation would be evaluated
through the corrective action process. And, again, this would all be done by an engineer that's got a
qualification for that particular function. Any questions on that? CHAIR MAYNARD: ISI Lubrite sliding
supports? MR. COX: Lubrite sliding supports was
similar to that. We were asked, you know what exactly
are you going to look at as part of inspection that
we've committed to. These are inspected as part of the
overall inspection of the support, as part of the
Section XI IWF program. And basically inspection will
involve looking at the -- you know, you can't see a
lot of the Lubrite because it's supporting the component. And, you know, you can't see the edges.
You can see signs of scoring and scratching on the
surfaces that are supposed to slide. And, you know, basically you're looking for gouges or binding that
would effect the performance of that support. MEMBER SIEBER: Well, are you actually --
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 not moving. Because every time you heat the plant up, every time you start and stop a pump and check valve
slams shut, those surfaces slide. MR. DACIMO: We do an inspection at the
end of every outage where you go do and do a visual
part to look at it. MEMBER SIEBER: To look at it? Yes. I
mean, this is -- it's not it's hidden and it's not
like it never gets exercise because there's a lot of
plant maneuvers in view that actually cause these
things to function. MR. COX: Again, it's all part of the IWF
program for looking at those supports. We'll be using the same IWF frequency and maybe looking for signs
of-- MEMBER SIEBER: If you look as far as
seismic analysis concerned and also the bending of
structural components. And so it has an importance, but it's not impossible to visually observe. MR. COX: Anything else on Lubrite? The next item was a question we had on
Code Section XI. We had in our Section XI ISI program
we had talked about corrective actions and the staff
had asked for a clarification if that meant that we
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 specific sections of the code. That would be
Subsections IW A, B, C, and D and F that were
applicable to that component class. And the answer was
yes, that is what that meant. So it was basically
just a clarification of our intent. The next one was -- excuse e. MEMBER SHACK: I am just -- go on to the
next one. MR. COX: Okay. The next one is periodic
surveillance preventative maintenance program. Again, it's a clarification or a request for additional
details on the specifics of that program. MR. YOUNG: Alan, this is a nickel -- CHAIR MAYNARD: We have to go by our list
so we can keep track. MR. COX: That's fine. MEMBER SIEBER: My question on nickel
alloy is you had over the years about a 14 percent
increase in power, licensed power output which obviously has moved TH up and up and up, right?
What's your TH right now at a 100 percent power? MR. COX: Nelson, have you got any
information on that? MR. AZEVEDO: Yes. My name is Nelson
Azevedo.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 I don't have the exact number. It's
around 600. MEMBER SIEBER: 600? That's pretty low.
Okay. I was going to say the sensitivity change
in the color is around 610. But you're probably below
that. MR. AZEVEDO: Yes. Unit 2 we -- MEMBER SIEBER: That's my benchmark, Bill. MR. AZEVEDO: Unit 2, reactor -- both the
reactor vessel heads are T-hot so they don't have the
bypass cooling. And the Unit 2 ran historically in
the 580s. And after the power uprates they went up to
around 600. I don't have the exact number. I could
get that for you, but it's around 600. MEMBER SIEBER: Okay. MEMBER BANERJEE: And Unit 3? MR. AZEVEDO: Unit 3 is roughly the same
within a couple of degrees. And again, I can get the
exact numbers. I don't have -- MEMBER BANERJEE: It would be useful to
have the exact numbers. MEMBER SIEBER: I think there's only two
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 numbers. MEMBER SIEBER: Okay. CHAIR MAYNARD: And those are low compared
to what some of the PWRs are still operating at. MEMBER SIEBER: Okay. Go ahead. MR. COX: Yes. The basic of this question
was to provide some clarification on exactly where we
had nickel alloy components and welds. And we provided
that information in response to that. MEMBER SIEBER: Are you sure they replaced
where you say you have thermal sleeves? MR. COX: I would give that question to
Nelson. MR. AZEVEDO: I'm sorry. What was the
question again? MEMBER SIEBER: Are you sure that you have
thermal sleeves everyplace that your design drawing
showed? MR. AZEVEDO: Well, we had one thermal
sleeve that dislodged from its location and we found
the pieces in the reactor vessel and -- MEMBER SIEBER: Have you analyzed that? MR. AZEVEDO: Yes, we did that analysis
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 replace it, right? MR. AZEVEDO: We did not replace it. But
we have seen no other indications that any of the
other thermal sleeves have dislodged from their
locations. CHAIR MAYNARD: With their age of plant, their design probably does identify them all. In the
'80s there was a design change made that drawings for
some plants that it'd show a thermal sleeve there, but
that changed in the construction and it was removed. MEMBER SIEBER: They didn't put it in. CHAIR MAYNARD: Yes. So but your age of
plant, I'm not aware of any design changes on thermal
sleeves that were current at that point. MR. AZEVEDO: Yes. I believe that changed
occurred in the mid-1980s. CHAIR MAYNARD: Yes. MR. AZEVEDO: But by that point both units
were already operating. CHAIR MAYNARD: Yes. MEMBER SIEBER: Well, you're right. In
some plans there's some confusion as to whether they
exist or not. CHAIR MAYNARD: Right. Because there's a
fuel change after the original design.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER SIEBER: After the drawings were
made the analysis was done. Okay. Thanks on that. MR. COX: I guess the second part of that
particular item dealt with the bottom head
penetrations on the vessel. MEMBER SIEBER: Right. MR. COX: And I think we had used the term
in one of our audit question responses bottom head
drain safe ends. And we don't actually have any
bottom head drains. So we clarified that that was the
safe ends on the bottom head were the safe ends that
were used to connect to the in-core instrumentation.
The bottom mounted instrumentation to the -- MEMBER SIEBER: You have about 50 of
those? MR. COX: Fifty? MR. AZEVEDO: We have 58. MEMBER SIEBER: Fifty-eight. Okay. MEMBER BANERJEE: With the upper head you
have inspections show nothing around CRDMs or
anything? MR. DACIMO: We'll let Nelson answer that
question. MR. AZEVEDO: Yes. We've been doing NDE of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 the upper head. By the way, for Unit 2 we have 97
penetrations and Unit 3 we have 78 penetrations. And
we have not found any indications. MEMBER SIEBER: You're doing a visual on
the outside? MR. AZEVEDO: We do both visual of the
outside surface of the head as well as NDE from the
inside on both units. MEMBER SIEBER: Right. MEMBER BANERJEE: No cracks, nothing? MR. AZEVEDO: We have not found any
indications, any rejectable indications. MEMBER SIEBER: You have the susceptible
material in penetration nozzle? There is a class of
penetrations that were more susceptible than others. MR. AZEVEDO: You're talking about the
upper head penetrations? MEMBER SIEBER: Yes. MR. AZEVEDO: Our penetrations were
Huntington alloy penetrations. They're not the B&W
material. MEMBER SIEBER: Okay. Thanks. MEMBER ARMIJO: Also are any of them like
spares or basically where it's a dead space error? MR. AZEVEDO: Yes. We have spares and we NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 also run the instrumentation through some of those as
well as active control rod drives. CHAIR MAYNARD: Okay. And do you know, do
you guys do a vacuum filled for filling up.? MR. COX: Yes, we do. CHAIR MAYNARD: Okay. MEMBER BANERJEE: And you inspect the
welds as well of the -- MR. AZEVEDO: Yes. We use the Westinghouse
approach which is a dual probe eddy NUT, which we do
inspect approximately 10 percent of the weld material
as well as the entire base metal, MEMBER SIEBER: Great. CHAIR MAYNARD: Okay. MEMBER SIEBER: CASS components. MR. COX: Okay. The question on the CASS
components. There were two parts of the question.
Part A basically questioning whether we were relying
on UT examinations for CASS components. And our
response was that because the ultrasonic testing is
not reliable for those type of materials, we did not
rely on that as part of our program. MEMBER ARMIJO: What do you rely on? MEMBER SIEBER: What do you rely on? MEMBER ARMIJO: He's setting us up, I'm NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 sure. MR. COX: We would usually rely on
basically the visual inspections and surface
examinations. MEMBER SIEBER: Do you UT -- I recognize
that it's very difficult to find flaws in CASS
stainless, but -- MEMBER ARMIJO: No, this is limited to
like CASS piping as opposed to bell bodies where you
know the chemistry of the alloy -- MEMBER SIEBER: Well, the centrifugally
cast has some unique features of its own. MEMBER ARMIJO: Yes. Yes. But the alloy
chemistry effects whether it's going to embrittled or
not. MEMBER SIEBER: Well, let me ask this
question: Most plants that have CASS piping of the
era of Indian Point Unit 2 and 3 have augmented tech
specs for inspections. Do you have augmented tech
specs for the inspection of the reactor vessel for
piping worlds where they require additional
inspections over and above what has later been
required? MR. AZEVEDO: No, I'm not aware of any
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 IWB requirements. MEMBER ARMIJO: What are your largest CASS
components, not valve bodies but let's say piping? MEMBER SIEBER: The piping, 36 inch -- MEMBER ARMIJO: But you large diameter
CASS piping? MEMBER SIEBER: Yes. Oh, yes. The whole
cooling system. MEMBER ARMIJO: Well, that's -- CHAIR MAYNARD: We'll let them answer
that. MR. AZEVEDO: I believe the only CASS materials that we have are the Finnies, the elbows.
So I have to verify as far as the piping goes. MEMBER ARMIJO: Okay. So it's very
limited? You don't have your big piping -- MEMBER SIEBER: It's the important stuff, though. MEMBER ARMIJO: -- system isn't CASS
stainless? MR. DACIMO: When you say piping, you
talking about RCS piping? MR. AZEVEDO: Yes, I'll have to verify on
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 material. MR. DACIMO: We have to get back to you on
that. MEMBER ARMIJO: Okay. MEMBER BANERJEE: What is the concern you
have? MEMBER ARMIJO: Well, they're very
difficult because they're very thick walled, the way
they're made the microstructure makes it almost
impossible to do ET exams. And there's concerns about
embrittlement. MEMBER SIEBER: Yes, there's a lot of past
issues. CHAIR MAYNARD: They need to verify their
material. I believe it was a little bit later when
many of the RCS systems related to the spun CASS
stainless steel. So they may not have that. MEMBER ARMIJO: If it's forged, we're
wasting time. MEMBER SIEBER: But before we leave these
kinds of components and go off into the service water
system, have you replaced baffle bolts in these
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 jetting, any evidence of it? MR. AZEVEDO: We have not seen the
evidence of that, although we do have the 347
material. MEMBER SIEBER: Okay. Have you replaced
split pins? MR. AZEVEDO: Yes, we have replaced split
pins. In fact, we're replacing split spins again on
Unit 3 this coming outage starting next week. MEMBER SIEBER: You mean the ones -- the
first replacements? MR. AZEVEDO: That's right. This is the
second time for Unit 3. CHAIR MAYNARD: You were probably in with
the first batch and they actually made improvements in
the split pins after the first ones had been
installed. So be my guest. MEMBER SIEBER: Yes. Okay. Thank you. MR. COX: Anything else on the CASS
components? MEMBER SIEBER: Service water? MR. COX: Let me find the right page of my
notes here. CHAIR MAYNARD: Yes, the service water
system.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. COX: Here we go. The service water
question that dealt with some differences in aging
effects for titanium materials in two different
locations. And it turns out that in one location we
actually knew the particular grade of titanium, and it
was a grade that was not susceptible to this
particular aging effect. The other location we didn't
have the specific information on the type of titanium.
So we took the conservative approach and called out
that aging effect for that component. MEMBER BANERJEE: So your main system is
titanium where the river water is going through? MR. COX: We have some titanium in the
service water. I won't say the whole system is, but
there is some titanium. MEMBER BANERJEE: So the heat exchangers, are they, the water there are they titanium? Tubes
or-- MR. COX: The shell for this heat
exchanger is titanium. It's a question about -- MEMBER BANERJEE: Well, I'm talking about
the heat exchangers with the river water, correct? MEMBER SIEBER: The main condenser type? MR. DACIMO: The main condenser is
titanium. But you're asking circulating water?
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER BANERJEE: Yes. Anything which
river water is coming into contact with. MR. COX: Well, there's a whole series of
heat exchangers. MEMBER BANERJEE: Now they're all titanium
or they're -- MR. DACIMO: Every heat exchanger is not
titanium. MEMBER BANERJEE: Okay. So there's some-- MR. COX: Some of them are. I mean, we
had to put that material in the table because we did
have some titanium heat exchangers. Like Fred's
saying, there's others that are other materials. MEMBER BANERJEE: Okay. CHAIR MAYNARD: But the bottom line of
this one was where you could not identify the specific
type of titanium, you have included it in an aging
management program? MR. COX: Right. But I think we probably
included both of them in an aging management program, but we included it for this specific aging effect in
this case because we can't say it wasn't susceptible
to that. CHAIR MAYNARD: Okay. MEMBER BANERJEE: So do you monitor the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 thickness of the titanium tubes and things like that? MR. COX: Well, we do eddy current
testing. We do visual inspections on the inside of --
you know, the areas that are accessible for visual
inspections. Different techniques are employed
depending on the location. MEMBER BANERJEE: And do you have to clean
them out often, all sorts of vegetation? MR. DACIMO: We have a prevent -- well, it's chlorinated, okay, so that minimizes the amount
of cleaning that you have to do. But additionally
there is a preventative maintenance program where you
open up heat exchangers on a relatively reasonable
periodicity to clean them out and check them out. MEMBER BANERJEE: So you don't have
systems like these little balls and things which-- MR. DACIMO: No, we do not have a Amertap
system. CHAIR MAYNARD: That's usually just for
the main condenser. MR. DACIMO: The main condenser, that's
correct. We do not have Amertap in each one of those. MEMBER SIEBER: No. You only do that on
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 the periodic inspections and if we see that the need
for frequent cleaning based on those inspections, we
would do that. But, I mean, we got a pretty long
history with the program, so I think we -- MEMBER SIEBER: I presume you do heat
balances on these exchangers, too? MR. DACIMO: We monitor inlet and outlet
temperatures, absolutely. Absolutely. MEMBER SIEBER: And you can judge from
that. MR. DACIMO: Particularly for the diesel, absolutely. MEMBER SIEBER: Yes. Okay. CHAIR MAYNARD: Periodic surveillance and
preventive maintenance, program elements? MR. COX: Yes. PM was a question, again, where we had to provide -- that's the one I started to
talk about while ago. We had to provide more detail in
terms of what specific components -- I guess we had
included those in the general description of the
program already, but not under the scope section. So
we basically pointed out where that information could
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 depending on the aging effect that we were monitoring.
And basically we could have credited the techniques
that are recommended in the GALL report. Under the
one-time inspection program there's a table that says
for a particular aging effect here's the acceptable
inspection technique for that effect. And that's what
we provided in response to this question. Components supports, a question was on the
concrete around the anchors where the component
supports. And, again, this was primarily a
clarification to say that that concrete around those
anchors, concrete anchors and supports was included in
the structures monitoring program that was looking at
the floor or the wall that that support was attached
to. MEMBER SIEBER: This is mainly Hilti bolts
and things of that nature? MR. COX: Right. MR. DACIMO: There's Hiltis and embedded
anchors depending on the location. There's embedded
anchors also. MEMBER SIEBER: Oh, okay. MR. COX: It was just a clarification that
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 the support. MEMBER SIEBER: Now you can visually
inspect a Hilti bolt location and not be able to tell
whether it's going to stay in there or not. MR. COX: Right. Right. MEMBER SIEBER: So I presume you tug on
them every once in a while? MR. COX: I'm not familiar with the
details. MR. DRAKE: Actually, as part of the scrub
program, the resolution of that issue, we did do tug
tests on many components. We also did some
retorquing checking on some of those, too. MEMBER SIEBER: Now the classification B1
to B5 was different between the units, was it not? MR. COX: I'm not aware -- MEMBER SIEBER: I got the feeling that
there was some differences between which ones were in
each one of the categories. MR. COX: I wasn't aware of any
differences in that. MEMBER SIEBER: Okay. MR. COX: Do you know specifically? Reza
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 probably clarify that. MR. DACIMO: Would you state your position
also? MR. AHRABLI: I'm the Service Lead for the
License Renewal for Entergy. As Alan pointed out, I think that question
rise from the fact that as we are rolling on the
application it almost imply that they be used on
either IBF ISR program for monitoring for inspecting
the concrete surrounding the anchors. That wasn't
really intended to be implied that way because the
stress monitoring program looks like the concrete
surrounding the anchor bolts and IBF looks at the
anchors. So the clarification as Alan pointed out, that is correct. And back to your question as to B1 through
B5, that's really categorization as provided by the
NUREG-1801, by the GALL. MEMBER SIEBER: Right. MR. AHRABLI: So B1 applied to the
containment structure and B2 through B5 is different
than the containment. So clarification was there was, you know, background on that question that the staff asked us.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER SIEBER: Thank you. MR. COX: Again, I'm not aware of any
differences, but if you've got some specifics on that
we can certainly dig into it. MEMBER SIEBER: Well, it's not important. MR. COX: Okay. CHAIR MAYNARD: Class 1 fatigue? MR. COX: Class 1 fatigue, this was a
question on the number of heatups and cool down
transients. I believe when we put the application
together we had a period of time when we didn't have
data readily available, so we made our projections on
the number of heatups and cool downs based on a -- MEMBER SIEBER: On a shorter period. MR. COX: -- shorter period. And during
the audits we had an opportunity to go back and get
the additional data and provided the revised numbers. MEMBER SIEBER: Do you have complete data
now? You only took about a ten year period and said
well this period is like all the others. MR. COX: Well, we actually took the -- MEMBER SIEBER: But you do have the data
because you have operator logs. MR. COX: We actually had a -- it was I
think longer than a ten year period. More like a 20 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 year period, but it didn't include the last ten years, I believe. MEMBER SIEBER: Ten years? Yes. MR. COX: And we went back and added that
data. MEMBER SIEBER: Yes. CHAIR MAYNARD: As I recall, wasn't this
an area where you -- the available data for IP2 and
IP3 were a little different and you may not have used
the same periods of time. MR. COX: That's right. Because they were
operated by different people, the programs had evolved
a little bit differently. And actually have some
commitments going forward to go back and revisit those
projections for -- I think we had already gone and
kind of reconstituted that history on one of the units
and we've got a commitment to do that for the other
unit. MR. DACIMO: Unit 3. MEMBER SIEBER: The fatigue analysis here
is usually for large components and major heatups and
cool downs as opposed to high frequency cyclic changes
that you find in small air lines, correct? MR. YOUNG: Yes. MR. COX: That's correct.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Is that the last one? MEMBER SIEBER: I think that's it, right? MR. YOUNG: And that covers all of the-- CHAIR MAYNARD: You may think you're done, but I've got a few other questions. One, and I think we'll be hearing about
this this afternoon a little bit, it's on the water in
the manholes and some of the cables. And I don't want
to get into the whole generic issue of what's being
looked at right now. I just want to get a good
understanding what cables that you guys have. Do you
have any statement? MR. DACIMO: We're going to ask Tom
McCaffrey, our Design Engineering Manager to discuss
that. MR. McCAFFREY: I'm Tom McCaffrey, the
Design Engineering Manager. We have approximately six cables, 13.7 kV
coming down from Buchanan Substation to the station
and one 6.9 kV tie between the two stations that would
be the license renewal underground medium voltage
cables. They have manholes that they run through, and
that would be the scope of what would be in the
license renewal program, the medium voltage cables and
manholes.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER SIEBER: Well, let me ask a couple
of questions. One of them is what's the structure
from one manhole to another? Is it duct work, conduit, piping, concrete boxes? And when the manhole
is full of water, is that interconnection full of
water also? MR. McCAFFREY: So in some of the
situations it's a direct buried cable between
manholes. MEMBER SIEBER: Okay. MR. McCAFFREY: In other situations it's
conduit. So there is a variety of connections between
the manholes and the manhole for each cable section. MEMBER SIEBER: Can I assume then that if
there's water in the manhole, there's water in the
conduit? MR. McCAFFREY: As we kind of talked
before, the plant is kind of built on a hill. MEMBER SIEBER: Yes, I got that. MR. McCAFFREY: So what you're going to
get is -- MEMBER SIEBER: Yes, it goes downhill. MR. McCAFFREY: -- any water is going to
flow downhill. So you're going to get some type of
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 manhole, that's going to eventually flow out of the
manhole and down towards the river. MEMBER SIEBER: Right. Now the power
supply to things like service water pumps, service
water pumps in your screen house. Service water pumps
are safety-related? You immediate voltage cable
connects from there to the plant, and that's usually
underground, right? MR. McCAFFREY: Our service water cables
are 480 volt AC cables. MEMBER SIEBER: 480? MR. McCAFFREY: All of our safeguard
motors and loads are 480 volt loads. MEMBER SIEBER: Are any of your submerged
cables qualified to operate in a submerged condition?
Are they qualified? MR. McCAFFREY: Our cables are designed to
be underground, they're not designed to be submerged
cables. MEMBER SIEBER: That's not what I asked. MR. DACIMO: So well the answer to your
question is no. CHAIR MAYNARD: No. He said no. MEMBER SIEBER: Now, do you have splices
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 manholes? MR. McCAFFREY: We typically have splices
in the manholes. MEMBER SIEBER: Right. That's where you
pull the cable from? MR. McCAFFREY: We do not do -- correct. MEMBER SIEBER: Now splices are harder to
qualify than undisturbed cable because they're
handmade. What tests do you run to determine that the
insulation and how often do you run them? MR. McCAFFREY: Well, going forward we are
going to be implementing a new -- as a corporation
we've decided to go off and start testing using the
EPRI guidelines for medium voltage testing. We're
going to be doing a Tan Delta or partial discharge
testing on our cables. We're currently evaluating
which is the better method for us to use for our
medium voltage cables going forward here. MEMBER SIEBER: But you haven't done that
yet, right? MR. McCAFFREY: We've done some section
high pots and Meggers of the cables, but as you know
that is not a true indication of the cable insulation
testing. MEMBER SIEBER: That's right.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. McCAFFREY: And you know the industry
has recently come out with that guidance and we're
currently evaluating what's the proper use of us at
Indian Point. MEMBER SIEBER: In your operating history
have you had cable failures of these cables? MR. McCAFFREY: Well, we've had cable
failures. They've been related to workmanship. They
have not been age-related failures. MEMBER SIEBER: At splices or in the
pulling process? MR. McCAFFREY: Very close -- either in
the splice or very close to the entrance to the
manhole, which would be basically your cable pulling
failure. MEMBER SIEBER: Okay. CHAIR MAYNARD: John? MEMBER STETKAR: I just wanted to clarify.
You said that in going forward you're going to do
whatever the EPRI recommended testing was for your -- MR. McCAFFREY: Yes. MEMBER STETKAR: -- medium voltage cables.
But that -- are you going to apply that same testing
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 and see how that works. The cables are different style cables, the shielded cable versus nonshielded.
So that's going to get into some issues with how we
test their cables. I don't know if I answered your question
completely. But there is -- MEMBER STETKAR: No, you didn't. I guess
my simple question is are you going to be doing more
in depth testing of the insulation on the 480 volt
cables? MR. McCAFFREY: We're going to evaluate
how to use -- right now EPRI is really focused more on
the medium voltage and the shielded. MEMBER STETKAR: I know that, and I'm
trying to find out whether you're drawing the line at
the six cables, 6.9 Kv and above or extending it down
below? MR. McCAFFREY: Well, I think the best way
right now is right now, yes, we're going to see how it
works on the 6.9 and the higher voltage and see if we
can apply it to the lower voltage. But I can't say
it's going to work perfectly as a trendable tool on
the lower voltage cables. CHAIR MAYNARD: I really don't want to get
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 the current license regime right now. I want to stick
to what's it mean for license renewal. And I think
understanding what you have in scope that is
potentially subjected to this is important. MEMBER STETKAR: Well my question is key
of that because there's a grey area between 480 volt
and higher voltage cables right now. And because all
of their safety-related equipment at this plant
happens to be 480 volt, that grey area becomes
relatively more important at this plant for license renewal than other plants that have 4 kV pumps.
That's the only reason I'm interested in that. MR. McCAFFREY: Right. And we do it for
the safeguard, the 480 volt motors, we do Megger
testing, we do online motor testing from the
switchgear to the motor. So we test the whole cable
of motor cables from the switchgear to the motor
itself. And we use that to trend what's going on and
pick up if we have any dead areas in the cables we'll
pick it up and address it there. And I was kind of hedging my words about
the new technologies. I do not know how it's going to
work on the lower voltage cables. MEMBER STETKAR: Yes, that's right. MR. McCAFFREY: And what we do right now NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 as part of our current preventative maintenance
program for our safeguards and 400 volt equipment, we
test it, we measure it, we use like a Baker testing or
PBMA technology to trend our commission of cables and
orders. MEMBER STETKAR: Thanks. MEMBER SIEBER: Well, I agree with Otto
that it's not a license renewal issue. It's a current
issue. And it's one that needs to be addressed. And
whatever the resolution in the current time frame it
will extend to the period of extended operation. MEMBER BROWN: Yes. The inspection report
that was issued, the staff noted that I guess one of
the manholes with the 6.9 kV cables and the splices
were submerged. MEMBER SIEBER: Yes. They had water. MEMBER BROWN: And the assessment was that
the cable and the splices were satisfactory but there was no basis for saying hey how did we assess that.
Was it just a visual, did you run some electrical
tests, was it -- they just look nice and pristine, you
just brushed the water off and a little bit of the
dirt that's accumulated and -- MR. McCAFFREY: Basically what has been
done is a visual inspection. There is no -- you know, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 as you know, a high pod or a Megger test at that
level, it's a destructive test and there's really no
good technology to say, hey -- MEMBER BROWN: Well, high pod is
destructive. A Megger test is not necessarily
destructive. MR. McCAFFREY: But a Megger is not
necessarily looking at a 1300 volt or, you know, even
a 6900 volt level, which is really a 15 volt cable.
It's going to pick up a degradation of the insulation
that you'd get from water intrusion that -- you know, with the degradation of the insulation. There's new technology with a partial
discharge and 10 delta are really going to help you
understand if you have that insulation breakdown, which a Megger, you know unless you have a short round
with that cable voltage, of the voltage class of
insulation you're not going to be able to detect that. MEMBER BROWN: Well, I'll preserve my
judgement on it. MR. McCAFFREY: Okay. MEMBER BROWN: Megger is not as bad as you
say. MEMBER STETKAR: Let me ask you, this is
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 license renewal. It's somewhat related to existing, though I can't really -- right now the commitment for
the license renewal program says that you're going to
inspect the manholes for water accumulation once every
two years, I believe, is the commitment for the
license renewal. MR. McCAFFREY: Right. MEMBER STETKAR: Don't your currently
inspect them once every quarter? MR. McCAFFREY: Yes. And that's really
more of a -- MEMBER STETKAR: And you say you're going
to use plant experience as the basis for your license
renewal inspection frequency. So I'm curious about
why you inspect them every quarter now which must be
driven by some plant experience. MR. McCAFFREY: The quarterly inspections
is the really the root water. We do not do the
complete visual inspection, get down there and go out
there and inspect all of the supports and the back
arms for the cables. It's not the full 100 percent
inspection. That's what the two year inspection will
include when we do the entire visual inspection along
with pumping down the manholes, which we do quarterly. MEMBER STETKAR: So the current is just a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 quarterly open up the manhole and pump it down. Okay.
Thanks. MR. DACIMO: It just appears with us to
be, well it is, good operating practice if the manhole
is strong. CHAIR MAYNARD: And I agree. I think this
is going to, again, be resolved as part of the current
licensing issue. First, I don't find once every two
years and these manholes being useful for much at all.
I mean, if you find water, you pump it down. I don't
know. But anyway, I think it's going to be dealt with
in the current licensing -- MEMBER STETKAR: I was more concerned
about how they're using current -- you know, use
operating experience to be into a new license renewal, you know, inspection frequencies and things like that. CHAIR MAYNARD: I wanted to discuss this a
little bit because I know it's going to come up later
and we might as well discuss some of it while you were
here in front of us here to talk about it. Fred, I believe that you had some answer
to some of the previous. MR. DACIMO: Yes. We want to bring up
three issues. One, address the issue on the type of
chemistry we were doing. Second, the spent fuel pool.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 And third there's a question about the use of hafnium.
We do use hafnium on Unit 3, okay. And have been
since '95. Okay. So that addresses that. And I've asked Don Mayer to come up on the
-- John Curry? Okay. John is our Project Manager for
License Renewal. MR. CURRY: There was a question that you
had asked, Mr. Sieber, on the type of chemistry
control that we used. Right now both plants use the
volatile chemistry treatment, AVT. MEMBER SIEBER: Right. MR. CURRY: Unit 2 had started out its
life with phosphate control. And that was taken out
during hot functional testing or right after. They
both went commercial with AVT and we use ethanol, adamine and hydrozine are the additions. MEMBER SIEBER: Okay. Okay. MR. CURRY: And in addition to that your
question on the moler control. We maintain a very
high pH, 9.6. And so with that high pH, and as Mr.
Dacimo had mentioned earlier, we have a new factor
factory. So we have very good water that's added, and
that's so between the good water and the pH control, the corrosion products are kept up. MEMBER SIEBER: You probably haven't had NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 much of an insult from your early use of TSP? MR. CURRY: No, and actually -- MR. DACIMO: We've got new steam
generators. MR. CURRY: -- we have new steam
generators. MEMBER SIEBER: Well, good luck on your
current steam generators. (Several speaking simultaneously.) MEMBER SHACK: -- corrosion of the -- MR. CURRY: Yes. MEMBER SHACK: So you have no cooper
anywhere in the system? MR. CURRY: Very low corrosion rates in
the secondary plant, that's correct. MEMBER BANERJEE: I have a general
question, Otto, if I may ask them. I don't know if
it's within the scope of the review or not. There's always been concern in this area
about warm water going into the Hudson and there's
lots of discussion about this. Now what is the long
term implication, say, 20 years more operation? Is
this going to have some deleterious effect or any
effect that can be identified which is different? MR. DACIMO: You mean as it relates to the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 environmental impact statement and with the
environment? MEMBER BANERJEE: Yes. I'm just asking as
a general interest. It is out of scope, probably. CHAIR MAYNARD: This is truly out of scope
for this review. The environmental report is included
as an attachment. It has its own process that that
goes through. MEMBER BANERJEE: It doesn't come to us? CHAIR MAYNARD: We get a copy of it. But
there's a process for handling the -- MEMBER BANERJEE: But we don't have to
comment on it? CHAIR MAYNARD: Right. Okay. MEMBER BANERJEE: Well, then it's out of
scope. MR. DACIMO: I will say the fishing has
never been better of the Point. CHAIR MAYNARD: They do have to answer
that question and I know that there were several
public meeting and the staff. But that is a separate
process for that. MR. DACIMO: We have one more issue on the
spent fuel pool I'd like Mr. Mayer address. MR. MAYER: Hello again. Don Mayer.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Fred had asked to me just provide a couple
of additional comments and clarify a couple of things. First of all, I'd like to just make it a
little clearer that the data that we have in front of
us right now indicates that the Unit 2 spent fuel pool
is not leaking. I did discuss that during the course
of the meeting, but Fred just wanted me to make that a
little clearer. The pool concentrations downstream, et
cetera, are indicative of no active leak. We continue
to monitor that as part of our quarterly monitoring
process. And the second part of what I was asked to
comment on is I mentioned the long term monitoring
program. A key, and in fact one of the principle
components of that program is to act as an indicator
of a potential new leak. And in fact, we believe the
sensitivity for leak detection at the Unit 2 pool in
particular is quite good. We have welds that are very
close to the pool, in fact several feet from it. So we
do have the capability to detect new potential leakage
should it occur. Thank you. MR. DACIMO: And just by way of background
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 around it. CHAIR MAYNARD: Okay. Fred, did you have
anything else? MR. DACIMO: That really completes our
prepared statement. CHAIR MAYNARD: All right. Appreciate your
time. And obviously stick around because as we hear
from the staff, we may be asking you some more
questions and stuff. At the end of the day we will go around
the room and identify what we believe the members are
going to need more information on, especially at the
next meeting. And I know that some of these
containment issues and the cavity leak and the stuff, there are some important issues that we're going to
need to dig into much further. We'll kind of go
around the room at the end of the day and identify for
our next meeting those things. MEMBER ARMIJO: Yes. Otto, some of us are
going to have to be in another meeting. Could we
bring up some issues now? MR. DACIMO: If you want, I might suggest
I can just go through the list of things that I have. CHAIR MAYNARD: No, we'll go around the
room.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. DACIMO: Okay. MEMBER SIEBER: Yes. Let me ask how many
people are going to the PTS meeting? MEMBER BANERJEE: In and out, I would say. MEMBER SIEBER: Yes, I'm going. CHAIR MAYNARD: Bill and Jack. We do have a few minutes here. So since
you're not going to be here this afternoon, you'll be
in the PTS meeting. So say some things right now you
want. MEMBER ARMIJO: Yes. When we were talking
about this buckling of this liner, the only thing I
didn't hear enough on is how you concluded that there
was no significant damage to the concrete behind that
liner when that event occurred? And I'd just like to
hear a little bit more it later. MR. DACIMO: Okay. CHAIR MAYNARD: Okay. Jack? MEMBER SIEBER: Well, I made a list of
questions before I got here. And I think they've been
satisfactorily answered. On the other hand, there's a
lot of open items and more than I've seen in recent
times. And my final opinion was on how you closed the
open items that you have and how the staff decides
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 find anything on the material in the license renewal
application or the safety evaluation that would
preclude at this time, pending resolution of these
outstanding items, my acceptance of the LRA. CHAIR MAYNARD: Bill, did you have
anything you want -- MEMBER SHACK: No issues we haven't
discussed. CHAIR MAYNARD: Okay. And again, at this
point the key is more in what do we want to make sure
that we address later. Because we can all have our
individual opinions right now, but it doesn't really
mean anything until the full Committee meets until we
see how the NRC actually resolves some of these
things. And there are several of these items that are
going to get discussed, but I'd like to get it
narrowed down to key items of interest for us. And we
will do that. Either at the end of the day, we'll go
around on it afterwards. But we'll also have some
things for the staff that we will be providing to
them, too. So with that I'd like to go ahead and take
lunch break. We'll be back at 1:00. And at that time
we'll start with the staff's presentation. So thank you.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 (Whereupon, at 11:51 a.m. the meeting was
adjourned, to reconvene this same day at 12:59 p.m.)
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 A-F-T-E-R-N-O-O-N S-E-S-S-I-O-N 12:59 p.m. CHAIR MAYNARD: Okay. Like to bring the
meeting back into session. And we'll start with the
staff's presentation. I'll turn it to Brian Holian. MR. HOLIAN: Good. Good afternoon. I just
had a couple of items before I turn it over to Kim
Green, the Project Manager. A couple from this morning
and one I forgot. One, I'd like to remind the staff is they
support the Project Manager and the region up there to
identify yourself to go to the microphone. There are a couple of introductions I also
wanted to make. Also up at the front table you'll see
Maurice Health. He's previously been the Project
Manager for Sharon Harris and has Duane Arnold, which
is later on in the cue. But he's up assisting Kim with
slides. One other introduction. Often times
license renewal has contractors that work with us as part of the SER process and the audit process.
Sometimes I don't acknowledge them. But today I
wanted to acknowledge Brookhaven National Lab worked
on the Indian Point application with this. And Rich
Morante, Mr. Rich Morante is with us today also. And NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 he was also responsible looking back at the operating
experience with our staff, in particular on the
concrete items that you heard discussed this morning. Two other items I wanted to just touch on.
A lot of it came up on one question this morning about
environmental reviews in particular. And I did want
to mention really that side of the staff that's also
working on Indian Point on our environmental reviews, that is a separate process and goes through the draft
SEIS. And then the final SEIS. And just to remind
the Committee that we did issue the draft SEIS a few
months ago and held a couple of public meetings up in
the Indian Point area in February. And those were
widely attended. So over 300 people at each of those
meetings, the daytime meeting and the evening meeting.
And covered a wide variety of potential impacts that
were disclosed in the environmental impact statement. And the staff, you know, got a lot of
interest on the environmental aspects up there. I
think a normal plant on a scoping process we get 300
comments on environmental scoping. On Indian Point
the staff received over 3700 comments. And now the
draft SEIS is out and that comment period, I believe, ends in March time frame. So we'll be responding to
those comments and that'll be a separate track.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 The last item I wanted to mention came up
a little bit this morning, and I'm sure we'll cover it
again, is the groundwater monitoring that's ongoing on
the site. And one item that I wanted to mention
there, as the utility I think covered very well, I
wanted to mention an inspection report that was sent
out, and I'll get to the ACRS Committee, in May of
2008 from Region I. We did not bring that part if the
Division of Reactor Safety with us today, but the
inspection report speaks well to the issues of
groundwater and monitoring for what they've done in
the last year, year and a half. The accession number, just to read it into the record, is ML081340425. And the region did conclude in the
inspection report that public health safety has not
been nor likely will be adversely effected. And they
went into the split sampling that gets done between
the NRC and the utility. So I wanted to mention that. With that, I'll turn it over to -- oh, one
other item on that. In the reactor oversight process
we have had an open deviation, which is in the reactor
oversight process one method that we could use to add
inspection resources to a plant. And Indian Point has
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 has been one. I think the siren system was another one
that did receive additional inspection resources up
and above what we normally do under the ROP. That's it. With that, I'll turn it over
Kim Green. MS. GREEN: Good afternoon. As Brian
mentioned, my name is Kim Green and I am the Safety PM
for the Indian Point license renewal application. And
as you've already met Brian, he's the Division
Director for License Renewal, he's joining me. As
well as Dave Wrona, who is my branch chief. And also
in the audience I'm joined by members of the technical
staff who participated in the review or in the audits
that took place at the applicant's facility. I'll begin my presentation by providing an
overview of the license renewal application. Next I'll discuss the staff's review as
its documented in Section 2 of the Safety Evaluation
Report. And then Mr. Glenn Meyer, who was the lead
renewal inspection team leader, will discuss the
license renewal inspection and what took place in the
findings of that inspection. And then I will come back and discuss the
staff's review as documented in Sections 3 and 4 of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 the Safety Evaluation Report. And lastly, I'll go over the open items.
Mainly I was going to focus on the seven open items
that are still under staff review, but I do have in my
slides the open items that the staff has information
for which they feel they can close the open items. And
I will discuss those as you see fit. The license renewal application was
submitted by the applicant by letter, dated April 23, 2007. As they've mentioned, they are both Westinghouse
4-loop power pressurized water reactors. They're each
rated at 3216 megawatts thermals and they have an
electric output of about 1080 megawatts each. And they have already mentioned that the
operating license for Unit 2 expires at midnight on
September 28, 2013 and for Unit 3 it expires on
December 12, 2015. As they already mentioned, the plant is
located about 25 miles north of the North York City
limits. On January 15, 2009 the staff issued its
Safety Evaluation Report. In that report we identified
20 items. The staff issued 121 requests for
additional information. And during the audits we asked
272 audit questions. The applicant docketed its NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 responses to those questions in letters dated December
18, 2007 and in March 24, 2008. The applicant made a total of 38 license
renewal commitments. And the number of RAIs that we
asked in the audit questions and the commitments is
fairly typical of a plant going through license
renewal. This next slide just enumerates the audits
and regional inspections that occurred during the
course of the review. As previously mentioned, the SER was
issued with 20 open items. At the time of the issuance
the staff requested additional information by formal
letter, dated December 30. 2008. So it was pretty
present. Or we actually requested additional
information within the SER itself for some of the open
items. For the remaining six open items that we
did not request additional information, the staff at
the time was still reviewing information we had from
the applicant. Some of that was submitted in early
November of 2008. I just wanted to point out that last week
the staff did issue a draft request for additional
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 a phone call with the applicant on those. And as soon
as the staff looks at a few things, we'll finalize
those RAIs and issue those formally to the applicant
so they can respond. By letter dated January 27. 2009 the
applicant submitted additional information for 14 of
the open items. The staff has reviewed that
information and based on the information contained in
that letter we feel that we will be able to close 13
of the 14 open items. And as I proceed through this
presentation I'll note the status of the open items. Section 2.1 of the SER documents the
staff's review of the applicant's scoping and
screening methodology. Based on its audit and review
the staff was able to conclude that the applicant's
methodology is consistent with the requirements of 10
CFR 54.4 and 10 CFR 54.21(a)(1). Section 2.2 of the SER documents the
staff's review of the applicant's plant-level scoping
results. The staff determined that the applicant
initially omitted the IP2 chlorination and the IP3 hydrogen systems from the scope of license renewal.
Therefore, we issued a request for additional
information. And the applicant subsequently included
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 within the scope of license renewal. MEMBER STETKAR: Can I ask just a quick
one on that? I notice they did add the IP3 hydrogen
system. Is the IP2 hydrogen system included in the
scope? I couldn't find it, but it's a big document. MS. GREEN: I don't know that off
the top of my head. But Stan Gardocki, who performed
the review might be able to answer that question. MR. GARDOCKI: This is Stan Gardocki. I think it was included, and we noticed
that it was included on a unit, and that's why we
asked the questions and we had them it include it on
the other one. We were specifically looking at the
attached pipe into the BCT whether it was safety-
related -- MEMBER STETKAR: I understand. MR. GARDOCKI: That's what brought our
attention to it. So I know if it wasn't included, it
would have brought it to my attention. So it was
brought up in IP3 that hydrogen was not -- it was in
the table of attached -- there's an attached that says
not in scope. So it was particularly called out
there. MEMBER STETKAR: Right.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. GARDOCKI: But IP2 is included under
the gas systems. So under nitrogen and hydrogen it
was included in there. MEMBER STETKAR: Perhaps. MR. GARDOCKI: Yes. MEMBER STETKAR: The big discussion on IP2
is intended to focus on nitrogen. There was a lot of
discussion about nitrogen. And hydrogen was just
mentioned as another gas system. Anyway, could you confirm whether it's
included? MR. GARDOCKI: Yes. MEMBER STETKAR: Thanks. MS. GREEN: So the applicant, like they
said, they included these two systems within the scope
of license renewal. And with these inclusions the
staff concluded that the applicant did identify the
systems and structures within the scope of license
renewal in accordance with 10 CFR 54.4(a). Section 2.3 of the SER documents the
staff's review of the applicant's scoping and
screening results for mechanical systems. In the
license renewal application the applicant identified
59 mechanical systems within the scope of license
renewal for IP2 and 87 for IP3. And I think the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 applicant explained adequately this morning why the
difference exist in the number of systems. And as they
explained, they were basically owned by two different
utilities for numerous years. And that resulted in how
they named and identified their system boundaries. And
so that resulted in a difference of the number of
systems identified. For the balance of plant systems, those
being the auxiliary and steam and power conversion
systems, the staff employed a two tier approach. For the tier 1 systems the staff reviews
the application and the UFSAR if there is a discussion
of the UFSAR for that system. For the tier 2 systems the staff reviews
the application, the UFSAR and the license renewal
drawings that are provided by the applicant. The staff did perform a 100 percent review
of the mechanical systems identified by the applicant
as within the scope of license renewal. The staff identified the omissions of some
nonsafety-related components from the scope of the IP2
containment spray system. Since staff requested the
applicant to do an extended condition review and as a
result the applicant identified three other systems
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 the scope of license renewal. These are the IP2 and
IP3 closed cooling water systems and the IP3 folding
vent sampling system. The applicant amended the application and
added the nonsafety-related components to the scope of
license renewal in accordance with 10 CFR 54.4(a)(2). Section 2.3 of the SER staff identified
three open items. At this point I should point out
that the A in the numbering scheme identifies an issue
particular to Unit 2 and a B would identify an issue
particular to Unit 3. So for the first open item 2.3A.3.11.1
that was the open item that questioned the aging
management review results for the yard hose houses and
chamber housings. And the applicant covered that. Do you have any -- CHAIR MAYNARD: You say that's only for 2.
Am I missing something? Why wasn't that applicable
to 3 also, just the same question? MS. GREEN: Well, I think at the time we
asked the question, the applicant had mentioned --
when the staff reviewed the license renewal
application we were under the impression that for
these particular components they were within the scope
of license renewal. Because the applicant scopes at a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 system level. So if they identify that a system meets
one of the intended functions in 54.4, they will put
the entire system. They'll say the entire system is
in scope. But then when they do an aging management
review they determine which portions of the system
actually support an intended function and need to be
subject to an aging management review. And so when the staff asked the question
we asked it only of Unit 2, I think. And they
identified these as being within the scope of license
renewal. And since they are passive and long-lived
components, if they're in scope we would expect them
to be subject to an aging management review. But
after they provided information in the letter dated
January 27th they indicated that they're not in scope.
They don't meet any of the intended functions.
Therefore, they wouldn't be in scope. So that
clarified that for us. But I don't think we asked that particular
question for Unit 3. But if I wanted to know for sure, I'd have to ask Naeem Iqbal to come to the mic and to
answer your question. CHAIR MAYNARD: Okay. We should ask, because it sounds reasonable but there are some other
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 conclusion for 2 applicable to 3 in this case? MS. GREEN: I'll let Naeem answer. MR. IQBAL: Okay. We'll answer this
question. Naeem Iqbal from NRR. Yes, we asked this question. I asked this
question specifically because in their application
they specify for the Unit 2. So we asked this
question. CHAIR MAYNARD: Okay. This question was
asked for IP2. MR. IQBAL: Right. CHAIR MAYNARD: Why wasn't it asked for
IP3? MR. IQBAL: Because in the chapter 2 they
only identify for Unit 2. So that's why. CHAIR MAYNARD: Okay. Why wasn't it
identified for 3 then? Why is 3 absent from this? MR. IQBAL: Maybe they don't have that.
Those components. Because these plants are two
different plants. Different so maybe the plant
configuration may be a little different. CHAIR MAYNARD: I understand that. And if
somebody said that 3 doesn't have them, that all of
them that are there are really associated with 2, then
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 that. I've heard speculation, but I don't know -- MS. GREEN: We would have to get back to
you on that. CHAIR MAYNARD: Okay. MS. GREEN: The next open item is 2.3.4.2-
- 1. That questioned the exclusion of a certain
feedwater isolation valves, or the apparent exclusion.
We had asked the applicants to clarify if the valves
that we were questioning, the BFD5s at Unit 2. And I
think the BFD5s and BFD90s at Unit 3. They're
mentioned in the UFSAR as providing backup feedwater
isolation during main steamline break, I think. And
it wasn't clear. Because the applicant does not
highlight on their drawings the components that are in
scope for -- nonsafety-related components that were in
scope for (a)(2). So it's not always clear to the
staff whether the components are subject to aging
management review and if they're in scope. So we asked and the applicant provided
information and clarified that the valves that we were
questioning are in fact in scope for the purposes of
54.4(a)(2). So with that information, we think we'll
be able to close this open item. CHAIR MAYNARD: John? MEMBER STETKAR: And I asked the applicant NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 this morning, I'm not sure I got a satisfactory
answer, could you explain to me why the BFD90 valves
are not mentioned at all for Unit 2, but they are in
scope for Unit 3 when they're precisely the same
valves performing precisely the same function? MS. GREEN: We did ask that as part of our
RAI for the applicant to explain if the condition
exists for Unit 2. But Stan Gardocki was the
reviewer, so I'll have him answer your question. MR. GARDOCKI: This is Stan Gardocki, Balance of Plant Branch. The BFD90s are motor operated valves that
close as a redundant isolation to the safety-related
fuel reg valves. So on one drawing on one drawing, on
the station drawing it shows an SI signal to those
valves. And it also shows on that valve drawing that
the signal going to the feedwater bypass valves. So
that's why I included two valves on one unit and just
the one valves on the other unit. MEMBER STETKAR: Let me ask Entergy then.
On Unit 2 do the BFD90s, the feedwater bypass reg
valves, the small lines, do they receive an SI signal
to close also, the motor operated isolation valves on
Unit 2? MR. DACIMO: Yes, they do.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER STETKAR: Thank you. Hence, my
question. CHAIR MAYNARD: Identify yourself. MR. DACIMO: Fred Dacimo, Vice President
License Renewal. MEMBER STETKAR: Hence my question. The
DFD90 values on Unit 2 will also receive a safety
injection signal, then why didn't the staff question
their inclusion? MR. GARDOCKI: We did, and that was part
of the RAI. We asked them similar to the other unit
should these also be effected on that unit. Not
questioning the licensing basis, but we asked them
under extended conditions in that RAI should they be
included. And basically what the staff is looking for
whether these valves should be included as an (a)(1)
component versus an (a)(2) component if they had a
specific related function. And they weren't included
on the drawings as within the boundary flags
identified as (a)(1) components. So our specific
question said should they have been included within
the boundary flags as a safety-related component
providing a safety-related function. CHAIR MAYNARD: Well, I think John's
question is really about --
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER STETKAR: I understood the question
about the drawings and whether things were
highlighted. My question is that on Unit 2 the normal
feed reg control valve, isolation valves, are designed
BFD5. And the feed reg bypass valve, isolation valves, are designed BFD90. And that's the same designation
on Unit 3. The valves are designated the same. You raised the question apparently on Unit
3 because you saw both sets of motor operated valves, 90s and the 5s, receiving a safety injection signal, is that correct? MR. GARDOCKI: Correct. MEMBER STETKAR: And we just confirmed
that indeed both sets of valves on Unit 2 also receive
a safety injection signal, but the open item in all of
the questions that I see pertain only to the number 5
valves on Unit 2. MR. GARDOCKI: And the reason why they
were specifically addressed to that was is it
specifically states in the UFSAR for one unit that
they are credited. And the other unit it specifically
states they are not credited for closing on low power
operations. That's why the bypass valves were not
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 that's where our confusion was. So we asked that
under extended condition should they have been. But
their design basis document that we looked at, the
UFSAR specifically say in low power operations they
don't have to close the feedwater reg bypass valves.
So that's why we didn't ask specifically that valve
for (a)(1). It wasn't credited. MEMBER STETKAR: For Unit 2 you didn't ask
it? MR. GARDOCKI: Correct. MEMBER STETKAR: You did ask it for Unit 3
because Unit 3 -- MR. GARDOCKI: Say in their UFSAR they do
credit. So there was a difference in their design
basis documents between the two units. CHAIR MAYNARD: Well, I don't think we're
going to get an answer here. MEMBER STETKAR: No. CHAIR MAYNARD: I think it's something we
make a note of and we need more information on for the
next time we meet. MEMBER STETKAR: No, that's fine. I just
wanted a clarification. CHAIR MAYNARD: I think we need to have, you know, why are they different. And I understand NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 that one may have a different licensing basis, but I
think we also need to understand why do they have a
different -- MEMBER STETKAR: That's one issue. I'm
just trying to find out some of the things that I was
concerned as I went through this is there are real
physical differences between the two units and there
are some differences that are more paper differences
between the two units. And I wanted to understand if
there are differences in the SER or the license
renewal application between the two units, what the
basis for those differences are. Real physical
differences are obvious. MR. GARDOCKI: But the answer it came down
to was they were nonsafety-related valves and they can
use nonsafety-related valves as a redundant isolation.
So the question of whether they should have been
safety-related was dropped. So -- MEMBER STETKAR: Yes. And this issue has
come up on many license renewal applications. This is
not a new threshold issue for us at all. The question
is why the difference between Indian Point Unit 2 and
Indian Point Unit 3 for valves that are precisely the
same size performing precisely the same physical
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 UFSAR. And valves that also need safety injection
signals. MR. COX: This is Alan Cox. Let me add one point of clarification. As
far as the LRA and licensing goes the valves are not
treated any differently. Again, their question was on
whether they should be classified as (a)(1). The
bottom line is they're both -- both unit the same
valves that we're talking about here are in scope and
subject to aging management review for (a)(2). MEMBER STETKAR: (a)(2)? They are? MR. COX: Yes. MEMBER STETKAR: Okay. Good. Thanks. CHAIR MAYNARD: Okay. MEMBER STETKAR: That helps a lot. As
long as the staff agrees that none of them are under
scope for (a)(1), none of -- however many of them are, eight, sixteen. As long as none of them are in scope
for (a)(1), then that's a valid conclusion. And if
you say all of them are in scope for (a)(2) regardless
of whether they're the 90s or 5s, that's good. MR. COX: All right. MEMBER STETKAR: Thanks. MEMBER RAY: Mr. Chairman, as long as
we've got this here.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CHAIR MAYNARD: Sure. MEMBER RAY: On the RAIs that are yet
going out do we understand how we will have the
benefit of the responses for our deliberations? CHAIR MAYNARD: Yes, we will get copies of
those, anything that we want and that's responsive. When we meet again, then all of those
should be resolved in some manner or not, and we will
have that to review ourselves and see if we agree or
disagree or have additional questions on them. MEMBER RAY: I just wanted to be sure. CHAIR MAYNARD: Yes. MR. GARDOCKI: If I can follow up on your
earlier question with the hydrogen system, I did find
it in the LRA under Section 2.3.3.5 for Unit 2. It
describes the nitrogen system. And it not only
includes the nitrogen system, it includes the carbon
dioxide system and hydrogen. MEMBER STETKAR: So it does include
hydrogen? Thanks. MR. GARDOCKI: And it describes to the
VCT. MEMBER STETKAR: Thank you. MS. GREEN: Okay. The third item on this
slide is 2.3A.4.5-1, which is the IP2 aux feedwater NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 pump room fire event. Basically for that issue the
applicant provided information just describing the
systems that were needed to provide flow to the steam
generators during the one hour fire event. But the
staff didn't feel that it had enough information at
the time to make a determination that they had
provided adequate information for those components
that are subject to aging management review since
that's what's required by the rule. So we asked the question and the applicant
did provide that information to us in a letter, dated
January 27, 2009. So with the information that they
provided they fulfilled the requirement of the rule
identifying those components that are subject to aging
management review. So we feel with that information we
can close out this open item. In Section 2.4 of the SER the staff
concluded that there were no omissions of structures
or structural components from the scope of license
renewal in accordance with 10 CFR 54.4(a). And there
were no omissions from an aging management review in
accordance with 10 CFR 54.21(a)(1). Section 2.5 of the SER document, the
staff's review of the scoping and screening results
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 system, the staff identified one open item in this area which deals with the station blackout scoping.
That's open item 2.5-1. The staff is still evaluating
the applicant's scoping boundary for that. I will
cover that in a little more detail and we've heard a
little bit about it this morning from the applicant. But with the exception of the station
blackouts open item, the staff concluded that there
were no omissions of electrical and instrumentation
and controls systems components from the scope of
license renewal. And there was no omissions from an
aging management review in accordance in 10 CFR
54.21(a)(1). At the end of Chapter 2 our conclusion in
the SER was that the applicant's scoping and screening
methodology is consistent with the requirements of 10
CFR 54.4(a) and with the 10 CFR 54.21(a)(1). And the staff also concluded that with the
exception of the open items there were no omissions
from the scope of license renewal. And there were no
omissions from the aging management review. So at this time I'd like to turn the
presentation over to Glenn Meyer. MR. MEYER: Good afternoon, Chairman
Maynard and ACRS members. I'd like to briefly discuss NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 the results of the regional inspection. The inspection has basically two primary
objectives. We take a look at the scoping of nonsafety
systems structures and components to make sure that in
the field there is no potential interaction that could
effect the safety systems. And we also take a sample
of the aging management programs to look at what
exists on site in terms of program support, prior
history, plans to implement the programs. There is a secondary objective wherein we
pick a few systems to look at the condition of the
system, to look at how the aging management programs
cover them and also the operating experience by the
system. And in this case we looked at auxiliary
feedwater on both units and we also looked at the Unit
2 station blackout diesel generator. MEMBER STETKAR: Can I ask a question?
And this might not be relevant for you, but your
inspections tend to look at operating experience. MR. MEYER: Yes. MEMBER STETKAR: I had a general question.
We've had at least one other applicant that I can
think of who used a rather narrow interpretation of
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 for the use of operating experience and the
documentation of that operating experience as being
relevant only to "existing programs" rather than new
programs. Was that same distinction made here or are
you confident that the operating experience that you
looked at in your inspections and that's documented in
the application applies across the board both to new
programs and to existing programs? Because I'm
thinking of this other applicant who actually had to
go back in and finish up that experience for the new
programs because it is relevant. MR. MEYER: Let me clarify. The previous
applicant, could that be Beaver Valley. MEMBER STETKAR: I don't -- MR. MEYER: Okay. Was it a month ago that
you had the meeting? MEMBER STETKAR: There's at least one
other applicant. MR. MEYER: Okay. Well we had in Region
I, it turns out that Beaver Valley's application is
later, but the report was issued before Indian Point.
But it's become clear that on new programs this does
tend to be an across the board approach that they
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 industry operating experience. And the applicants rely
on that and don't do an in depth look at their own
experience thinking that when the new program is
implemented prior to the period of extended operation, at that point they'll review their own operating
experience. So in my experience from recent
inspections Indian Point would tend to be similar to
the others where they don't pursue operating
experience for a new program and instead rely on the
industry experience that has been taken credit for in
the GALL report. MEMBER STETKAR: But if I understand that, let me make sure that I understand it. That what
you're saying is that they will consider their own
plant operating experience, but not until that program
is implemented? MR. MEYER: You know, basically design
constructed and implemented, right. They have the
basics of the new program and their commitment to the
GALL exists now, but the operating experience part of
it will go into depth later. So in fact, in the Beaver Valley case when
I inspected there and found that they were aware of
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 outside the industry, that they still felt that they
were going to deal with that later and had not really
dealt with the issue. MEMBER STETKAR: But you were at least
aware of that operating experience; that's my point.
At this time are we aware of the -- MR. MEYER: It came out during the
inspection. Our issue was that even though they were
aware of it, it was cast iron pipes that were failing. MEMBER STETKAR: Yes. MR. MEYER: And even though they were
aware of it, they had not adjusted aging management
program to address that. They were still taking
credit for a one time inspection, which is to confirm
that the conditions are not -- MEMBER STETKAR: That's a specific concern
at Beaver Valley. But I think my point is that -- MR. MEYER: But I would say that their
approach would be consistent -- we should ask Entergy, but I believe their new programs, there is a
distinction between existing programs and new
programs. And I believe their new programs are based
on the industry experience that's taken credit for the
GALL report. So -- CHAIR MAYNARD: Well, I think it would far NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 to ask Entergy. I think what you're asking is in
developing these new programs did they take any of
their own operating experience into account? MEMBER STETKAR: That's correct. Making
commitments for the frequency of inspections or the
type of inspection or additional testing to be
performing those new programs? MR. YOUNG: Yes. This is Garry Young. In the operating experience review we
actually have two parts to it. One is to look at the
adequacy of the aging management program through
operating experience and the other is to look at aging
effects through operating experience. So the first part, the part where we look
for aging effects we do look at all operating
experience to determine if we have aging effects that
are different or somehow beyond the scope of what's
already covered in the GALL report or 95-10 or other
industry guidance. So that operating experience we
look at everything. The operating experience to look at the
effectiveness of an aging management program we do
focus primarily on existing programs. For example, since the cable inspection program doesn't exist, then
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 of that program other than what's already been
documented in the GALL report. So, but we do have two parts to it. We
look at all operating experience on aging effects to
see if we captured all the aging effects and then
separately we look at the operating experience on the
adequacy of the program. And that is focused on
existing programs and not new programs that don't
exist. CHAIR MAYNARD: I think what I understand
you said was that in developing the programs, the
frequency, the types of examinations that you may do, you do consider all your operating experience that you
have available. MR. YOUNG: Yes. CHAIR MAYNARD: What you don't consider
for the new programs is the effectiveness of those
programs -- MR. YOUNG: Yes. CHAIR MAYNARD: -- because you haven't had
anything to compare the effectiveness to. MR. YOUNG: That's correct. So, yes, there's two parts to the operating experience. And
that's right. So, yes, if we --
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER STETKAR: I see the rationale.
Yes. Thanks. CHAIR MAYNARD: And I think the important
part is getting it factored into the initial -- MEMBER STETKAR: That's right. And my
primary concern was has that type of review been
performed and is it available for the staff to make a
conclusion that the elements of the programs that
you're committing to, you know, accurately account for
that experience. MR. YOUNG: Yes. I think, I mean -- and
again, the example you gave where there was operating
experience that an aging effect that previously had
not been identified is requiring aging management and therefore could be subject to one time inspection.
That is exactly the kind of experience we're looking
for to see if we can in fact credit that program. MEMBER STETKAR: Thank you. CHAIR MAYNARD: Go ahead. MR. MEYER: I think we talked about two
the system that we looked at. Turning to scoping. The inspection
concluded that Entergy's scoping of nonsafety system
structures and components was generally accurate and
their method acceptable. In our review we looked at NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 both the structural and spatial interaction parts to
reach that conclusion. I do want to note that during aging
management program we found two errors in scoping, and I'll address those shortly. So turning to aging management programs.
When looking at the service water integrity program
our inspector found that were components, specifically
baffles under the service water pumps, that were not
included in scope. Entergy agreed that it was
appropriate and concluded that the structural
monitoring program was the place to put that so the
license renewal application was amended to address
that their program documents are planned to be updated
to address that. In a similar fashion when we looked at the
lubricating oil analysis program the reactor coolant
pumps have motors with heat exchangers for cooling.
Entergy was under the impression that the cooler when
the motors are refurbished are replaced. So as such, they wouldn't need an aging management program. Our
inspectors found that wasn't accurate, that they were
actually refurbished and reused. And so they were
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 renewal application. We also had some concerns in the diesel
fuel monitoring program, specifically the Indian Point
3 fuel oil storage tanks. Our plan to have wall
thickness measurements, but the existing procedure and
acceptance criteria for that. So they changed the LRA
in that respect. Also, Unit 2 has a fuel oil tank truck
that in an emergency would be used to transfer fuel.
And their procedure for doing that was deficient
regarding sampling, process and location. So they
adjusted their procedures and amended the application. And also the Unit 2 security diesel
generator, the fuel tank for that had been omitted
from the program for diesel fuel oil. And they did add
that and amended the application. In the water chemistry program there were
disparities regarding pH and glycol concentration
testing. And also including the security generator for
the sampling on those processes. They did amend the
application and planned to address the program. In the metal enclosed bus inspection
program, their existing procedure didn't specify an
appropriate acceptance criteria regarding basically
the possibility for dirt and dirt to effect the bus.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 And so they did amend the application in that regard
and are addressing that in the procedures. Next slide. Also, the next two are new programs. In
the selective leaching program the application stated
there would be a selected set, but wasn't specific as
to how that set would be determined. And they agreed
that a 90 percent confidence that 90 percent of the
components did not have degradation, would be a
suitable sampling approach and amended the application
to include that. In the non-EQ bolted cable connections
monitoring program there was a disparity between what
the application had and interim staff guidance
regarding methods to monitor the bolted connections.
And they agreed that they would make certain that the
final guidance would be what they met. And they
adjusted -- they amended the application to address
that. Also during the inspection we addressed
the exposed rebar that you heard about this morning.
We looked at the records and their evaluations of the
existing conditions and felt that they were
appropriate, but their plans were to continue to
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 belief that to truly monitor and trend the condition
would involve some quantitative measures. And they
did subsequently provide Commitment 37 to describe
those additional quantitative inspections. There were other issues that we did
address on site and didn't involve application
changes. One was operating experience on the metal-
enclosed bus program. It's an existing program. The
inspection determined that there was 2004 example
where a bus had been inoperable and yet their
operating experience review and program basis
documents didn't include that. And we felt it should
be part of the record, although it didn't
substantively change the metal-enclosed bus program.
And they agreed they would change their operating
experience review report to include that sample. In the heat exchanger monitoring program
we did have the opportunity to look at instrument air
closed cooling heat exchanger that were open during
the inspection. And following up on that there was a
disparity between the units where one unit included
the instrument air closed cooling heat exchangers in
the program and the other did not. So they agreed that
they both should be in and would adjust the program to
do that.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 We looked in the electrical area Indian
Point Unit 2 has a material that they use for
electrical cable separation. It's not a fire
protection purpose. And one of our inspectors had
looked in that are previously and noted that transite, a material that's specifically for this electrical
cable separation, hadn't been addressed in their aging
management review. They agreed that they had looked at
all the fire protection materials. And so they did
take a look at transite and concluded there were no
aging effects, but they would adjust their aging
management review documents to note that. And lastly, there were in walking down
various systems in the plant, there were a few
isolated incidents where inspectors noted degraded
conditions. And in following up, found that they
hadn't yet been entered into the corrective action
system in the structural monitoring, boric acid
corrosion and fire protection areas. And Entergy
agreed that that was appropriate and they did put
these conditions into the corrective action program. We did return after the main inspection to
do a few additional inspections. One was the Unit 2
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Entergy's items, these condition reports for isolated
degradation entered into your corrective action
program, I'm sure you entered the condition. Did you
also enter or take a look at why these hadn't been
identified before or did you just put the condition in
and -- MR. MEYER: In fairness I should note that
in a lot of these program areas they do periodic
inspections. And we may have identified evidence of
boric acid that subsequent inspection would have
identified but, you know, it hadn't yet occurred. But
regardless -- CHAIR MAYNARD: I understand that. And
it's usually pretty obvious whether something has been
there a short time or a long time. And I'm just
wondering -- MR. DACIMO: But our corrective action
program requires you do that on a generic basis. Why
aren't your own people identifying some of these
issues? Right. And we looked at that. CHAIR MAYNARD: Okay. Good. MR. MEYER: We returned. The SBO diesel
generator was declared operational on April 30th, so
we returned following that both to look at the scoping
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 management programs are going to address this new
system. And we felt that they had done an acceptable
job of including it within the application. We did return to look at the electrical
cable vault or manhole as it's been described, to
observe that. And that is documented in the report.
And I think we've addressed the fact that there was
some water. Some splices were under water and they
drained that vault. So I think that's been discussed. And lastly, we returned during the Unit 2
refueling outage because we did note that there had
some corrosion on a part of the containment liner. I
don't believe this is the same as the containment
liner problem that's had extension discussion. So
this one was accessible. We had inspectors return and
take a look at the conditions. Found them to be
similar to what was described in their documents and
it didn't seem to be a problem in that respect. So based on our inspections we concluded
that scoping of nonsafety system structures and
components and the sampled aging management programs
are acceptable. And our inspection results support a
conclusion of reasonable assurance that aging effects
will be managed and intended functions maintained
during the period of extended operation.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 I'd also like to briefly address current
performance. Both units are in the licensee response
column of the action matrix. That's the lowest level
of regulatory oversight. As Brian mentioned, there
are what we refer to as deviation memos that permit us
to do more inspections in areas that are suitable for
more inspection. And that has been the alert
notification system and also the ground water issue. Over the past 12 months all of the
findings that we've had, the inspection findings have been green, the lowest level of safety significance.
And all the current performance indicators and over
the last 12 months are green and have been. And that
indicates that their performance is suitable. That concludes my presentation. If there
are no questions, we'll -- CHAIR MAYNARD: It doesn't mean there
won't be some later. MR. MEYER: I'll remember that. CHAIR MAYNARD: John, you looked like you
were going to -- MEMBER STETKAR: No, I'll wait. MS. GREEN: Okay. I'm going to start with
section 3 now. Section 3 of the Safety Evaluation
Report consists of the staff's review of the aging NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 management programs and aging management review
results. I won't go over each of the subsections. I'll
just touch on those and have an open item or item of
interest. Section 3.0.3 contains the staff's review
of the applicant's aging management programs. In the
LRA the applicant identified 41 aging management
programs; 10 were identified as new programs, 31 were
identified as existing programs. Fifteen of them were reported to be or
identified as consistent with the GALL report. And 10
were identified as consistent with the GALL report
with enhancements. Eight were identified to have exceptions.
And eight were identified as plant specific programs. So in this section of the SER the staff
identified eight open items. And by letter, dated
January 27, the applicant submitted additional
information that will enable the staff to close the
five open items that are listed here. Would you like me to cover each one or do
you have any particulars? The applicant covered them
this morning. CHAIR MAYNARD: I would just ask if any of
the members for these from the previous discussion NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 this morning have any questions for the staff right
now on these? MEMBER RYAN: No. CHAIR MAYNARD: We can go on then. MS. GREEN: Okay. The following three
open items are still under review by the staff. And
I'm going to cover those in detail later toward the
end of the presentation. Section 3.1 of the SER documents the
staff's review of the aging management review results
for the reactor vessel, internals and the reactor
coolant system. There were two open items identified
in this section of the SER. We've received
information from the applicant by a letter dated
January 27th. And we should be able to close these two
open items out. Any questions on these two for the staff?
Okay. Section 3.3 of the SER the staff's review
of the aging management review results for the
auxiliary systems is documented. There is one open
item in this section, and that's about the titanium
heat exchanger components. We've received the
information and the clarification we needed from the
applicant in the letter dated January 27th. So we NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 should be able to close this particular item out. Section 3.4 of the SER documents the
staff's review of the aging management review results
for the steam and power conversion systems. There was
one open item in this section, and that's the IP2 aux
feedwater pump room, the fire event. And I'm going to
cover this a little bit more later. Because this item
is still under review by the staff. And Section 3.5 of the SER we document the
staff's review of the aging management review results for the structures and the structural components.
There were three open items identified in this section
of the SER. Two of them are still under staff review, and I'm going to address those later in the
presentation. The third open item was about the
concrete, the aging management program that would be
used to manage the effects of aging for the concrete
and surrounding B1 supports. The applicant clarified
which they are using, so we'll be able to close out
that open item.
Questions? MEMBER STETKAR: I have a question about
under the structures. There was an RAI that was
raised regarding parts of the service water intake
structures, the bar racks and the screens and some of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 those things. Not necessarily the physical concrete
parts of the structure, but structural elements in the
intake structure. And as I read the resolution of that RAI it seemed to focus on Unit 3 specific line features.
As I understand it. Correct me if I'm wrong, if I
remember the plans correctly. Unit 3 has an intake
structure with the six normal service water pumps and
then it has a set of three backup service water pumps
to take suction from the discharge canal. But Unit
only has the single intake structure with the six
service water pumps with no backup pumps, is that
right? MR. McCAFFREY: This is Tom McCaffrey from
Entergy. That's correct for Unit 2. Unit 2 in
addition has a river water system which can supply
like a third operation for service water to the
station. It's a separate intake function from Unit 1. MEMBER STETKAR: That might be the answer
to my question. MR. McCAFFREY: Okay. MEMBER STETKAR: Those river water pumps
are not located in the same intakes? Are they located
in the same intake structure?
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. McCAFFREY: No, they're a separate
intake structure. MEMBER STETKAR: Thanks. I'll stop. MS. GREEN: Okay. Section 3.6 of the
Safety Evaluation Report documents the staff's review
of the aging management review results for the
electrical systems and instrument control system. In
the LRA the applicant identified a 138 kV high voltage
cable associated with station blackout as within the
scope of the license renewal and subject to aging
management review. However, the applicant stated that
at that time that there were no aging effects
requiring management. And that for the material
environment aging effect combination that neither the
component, being the cable, or the material or
environment were evaluated in the GALL report. The applicant also stated at the time that
the cable was designed for continuous wetted
conditions. So the staff questioned the applicant's
conclusion regarding that cable and issued a request
for additional information. Ultimately the applicant
amended the LRA and added that high voltage cable to
the scope of the periodic surveillance and preventive
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 to be acceptable. For Chapter 3 the staff concluded that
with the exception of the open items the applicant has
demonstrated that the aging effects will be adequately
managed during the period of extended operation in
accordance with 10 CFR 54.21(a)(3). Section 4 of the SER documents the staff's
review of the applicant's time-limited aging analyses.
Again, I'm not going to go over each of the
subsections, but we'll touch on those that have open
items or matters of interest. Section 4.2 of the SER we document the
staff's review of the applicant's reactor vessel
neutron embrittlement TLAAs. It was mentioned earlier
today, for the IP2 the limiting beltline material is
lower shell Plate B2002-3. And since the irradiated
Charpy V notice upper shelf energy value is projected
to be less than the acceptance criteria of 50 foot-
pounds,, the applicant has provided an equivalent
margins analysis that demonstrates that the reactor
vessel will have margins of safety against fracture
equivalent to those required by Appendix G to Section
XI of the ASME code and will satisfy the requirements
of Section 4(a)(1)(a) of Appendix G to 10 CFR Part 50
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Unit 2. MEMBER BROWN: Can I ask a question on
that? MS. GREEN: Sure. MEMBER BROWN: The other document that we
had indicated that this 48.3 value was less than the acceptance criteria of 50, Entergy presented that.
But they also noted that it was greater than the
Westinghouse Owners Group equivalent margin to -- I've forgotten what the rest of the words were -- of 43.
And so I guess I've got a disconnect right now between
50 -- MS. GREEN: Okay. MEMBER BROWN: -- which is the criterion, 54 which says, hey, you out to have margin to the 50
but the analyses are saying we don't need any margin
to the 50 and it's right up against. So they do
another analysis to some other criteria which is not
stated. What is this criteria and why is okay to be
greater than -- why is it -- let me phrase this
properly. Why is okay to be significantly above this
43 value which was previously understood to be the
margin that you ought to have. MS. GREEN: Okay. Barry Elliot is just-- MR. ELLIOT: I couldn't hear the question.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 I'm sorry. MEMBER BROWN: That's all right. I'm not
even sure it was clear. Where are you? MR. ELLIOT: I'm right here. I had see
you. I can't hear. MEMBER BROWN: Okay. Well, that's all
right. I can't see without my glasses. CHAIR MAYNARD: This is going to be an
interesting discussion. MEMBER BROWN: Entergy presented when
they presented their paper they said the Westinghouse
Owners Group value for -- and I can get it back out, the equivalent margin from the 50 was 43. MR. ELLIOT: Right. MEMBER BROWN: They were going to be at
49, whatever the number is in here. 48.3 at the end
of the extended period of operation, which was less
than 50. MR. ELLIOT: Right. MEMBER BROWN: And I guess my question
what good is 43 if that's where you're supposed to be
margin purposes, but yet it's okay to be up to the
acceptance criteria for 50. MR. ELLIOT: Okay.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER BROWN: And then Kim brought up
this other issue about well because they're up real
close, they do this other analysis for the code and
found that it met some criteria, but which she didn't
state. MR. ELLIOT: Okay. MEMBER BROWN: So I guess I just wanted to
understand why it's okay to be so close to the margin. MR. ELLIOT: Okay. MEMBER BROWN: Excuse me. Above whatever
the margin was we had before we'd eaten it all up or
close to it. MR. ELLIOT: Okay. Okay. Let me explain
to you, first off, they're meeting the regulation and
why they're meeting the regulations. My name is Barry Elliot. I'm surprised. The only people I thought
would ask the question aren't here. But that's very
good. That's a very good question. And let me just explain and give you a
little background on the regulation. The 50 foot-
pound criteria is established at if you're above that
energy level for the reactor vessel materials, we're
sure that you have adequate fracture toughness to
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 basis events. So the purpose of the evaluation of upper
shelf is to determine whether or not you're below 50
foot-pounds. MEMBER BROWN: Yes. MR. ELLIOT: Once you demonstrate that
you're below 50 foot-pounds, which is what they have
demonstrated here, we have another part of the
regulations which says you have to reach Appendix G criteria. The way that is satisfied is two ways.
There are two documents that we use to satisfy that
criteria. One is Appendix K of the ASME code which
gives criteria and methodology by which you can
demonstrate that you have adequate fracture toughness. MEMBER BROWN: Even though you're below
the 50 -- MR. ELLIOT: Even though you're below the
50 foot-pounds. The second criteria is we have a
Regulatory Guide, which is Regulatory Guide 1.161
which gives guidance on how to use the ASME code. Now what happened here is the licensee
evaluated their vessel to something that was done in
the '90s. It was 1993 or '94 document that the NRC NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 reviewed and it reviewed it to the documentation that
was appropriate at that time. So as part of this
review I requested that they update it to the current
regulations, which was the current ASME code and the
current Regulatory Guide. And it compared the two. And the comparison determined that the
guidance in the past and the requirements in the past, there was only difference. And that was the
equivalent margin analysis. There was one difference
and it was more conservative in the past than it is
today. So that they have demonstrated that they could
meet the guidance today. And the guidance today that
they meet would be applicable to 43 foot-pounds. And
as long as the vessel has more than 43 foot-pounds
they are meeting today's regulatory requirements. MEMBER BROWN: Okay. So I guess there was
an industry accepted basis for saying we can make it
less conservative than it used to be? MR. ELLIOT: Yes. Industry methodology, the ASME code criteria, which we have endorsed. The
NRC has endorsed it. MEMBER BROWN: I know that you have
endorsed that. MR. ELLIOT: And now we've asked them to
update it, and they made the comparison. And they NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 meet those requirements today. CHAIR MAYNARD: As I recall, it's not just
changing acceptance criteria. If you meet the 50, then you don't have to do have to do anymore. If
you're below that, there's additional evaluation and
analysis that have to be done before you can take
advantage of the lower acceptance criteria. MR. ELLIOT: Right. Yes. And that's what
they've done. They've done it through a generic
analysis and now they've demonstrated that the generic
analysis is applicable today. And they've also
demonstrated that it's applicable to their plant. And
that's the reason it's acceptable. MEMBER BROWN: Okay. I think. CHAIR MAYNARD: Go ahead. MS. GREEN: So similarly at Indian Point 3
they have a limiting beltline material, and that's
shell Plate 2803-3. And again they provided since
their value is going to be less than the acceptance
criteria of 50 foot-pounds, they provided a margin now
that demonstrates that their reactor vessel will have
margins of safety against fracture toughness
equivalent to those required by the ASME code and also
by Section 4(a)(1)(a) of Appendix G to 10 CFR 50
through the period of extended operation.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER BROWN: Same -- MS. GREEN: Same answer. MEMBER BROWN: Same answer, so I'm not
going to say anything on this one. MS. GREEN: Ditto on that one. At Indian Point 3 with regard to
pressurized thermal shock, the applicant calculated
the referenced temperature for PTSIU for the limiting
plate. That's the 2803-3 plate. In accordance with the
current PTS rule and position 2.1 of Regulatory Guide
1.199 Rev. 2. The staff requested that the applicant
estimate when the screening criterion would be
exceeded. And the applicant estimated that it would be
exceeded approximately nine years into the period of
extended operation. That's what they told us and
that's what they said this morning. So that would be
2024. And at that time -- MEMBER BROWN: Is it where? The reason I
ask that is that they said it would occur at 37
effective full power years. Somebody made that
statement this morning. MS. GREEN: Yes. MEMBER BROWN: Yes. And the extension was
- 38. When they go to 60 years they'll have 48
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 made that statement. Correct me if I'm wrong. And
based on they said they would meet -- they would get
there -- no. They were going to their limit at 37
effective full power years. So I just did a ratio
roughly and said it would about 2021, 2024. So I'll
allow some error there. So that means what do you have in place?
I mean, I just kind of look at this, okay, you're
going to get well ahead of you finishing your extended
period. And you have to figure out what you're going
to do or shut down. Do you wait until the eleventh
hour and fifty-ninth minute? This is kind of a-- MR. AZEVEDO: No, you don't. MEMBER BROWN: -- theoretical question, I
guess. And, Otto, if I'm stepping. CHAIR MAYNARD: Well, you're not. We've
addressed this for a number of other plants, though. MEMBER BROWN: Okay. CHAIR MAYNARD: And we can have them
address it here or talk about it a little bit. But
the bottom line is you have to have a program in place
that identifies before they exceed any limits. MEMBER BROWN: No, I understand that. CHAIR MAYNARD: Before they meet that they NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 have to do something to either reduce it -- MEMBER BROWN: Do they reduce power to do
that to change that, is that what you mean? CHAIR MAYNARD: Or if they can't, they
reach that point, they shut down. The license renewal, getting a license for
operating an extended period of time does not give you
the right to violate any of the rules or regulations. MEMBER BROWN: I understand. CHAIR MAYNARD: So if you've reached that
point, you have to shut down. The applicant's not
required to have in place what they're going to do at
this point. They just have to have it done before
they-- MEMBER BROWN: Now is that by rule also? CHAIR MAYNARD: Now let me have them go
ahead it here. MEMBER BROWN: Okay. I don't want an
announcement. I mean, we go on I mean if that's the
case. CHAIR MAYNARD: Well, let them go ahead. MEMBER BROWN: All right. MR. AZEVEDO: Yes. The short answer is, in
fact, and some of the other members of the ACRS in a
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 10 CFR 50.61 does provide an alternative way to
demonstrate that we have the adequate fracture
toughness. And if that gets approved, that will
resolve our issue. There are other things that we can do -- MEMBER BROWN: Is that analytic or a test
basis? I'm not in that meeting, so -- MR. AZEVEDO: Well, it's different
screening criteria that we would have to do different
calculations to demonstrate that we meet the
alternative requirements. MEMBER BROWN: All right. That's enough.
I won't beat that one to death anymore. I'll stop. CHAIR MAYNARD: Well it is an important
issue. But within the concept of license renewal
we're looking at programs to be able to detect and
identify and manage these -- MEMBER BROWN: Yes. And my past experience
in our programs, this is a number we paid a lot of
attention to. That's all. CHAIR MAYNARD: Yes. MEMBER BROWN: So I was just interested in
the thought process as to where they were. CHAIR MAYNARD: And there are discussions
going on right now and other alternatives and stuff.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 But the bottom line is for license renewal we're
looking at what do they have in place -- the staff, what do we have in place from a regulatory standpoint
to ensure that this issue either gets addressed before
any limits are exceeded. And if not, the plant shuts
down. MEMBER BROWN: Okay. CHAIR MAYNARD: Go ahead. MS. GREEN: And because the applicant has
predicated that they'll exceed the PTS screening
criterion, it included Commitment 32 which states that
as required by 10 CFR 50.61 before IP 3 will submit a
plant specific safety analysis for Plate B-2903-3 to
the NRC three years prior to reaching the screening
criterion. They also added in that commitment that
alternatively the site may choose to implement the
revised PTS rule when approved. Obviously if they
don't approve the rule, that goes away. But if they do
the staff just points out that the rule is -- the
revised rule is draft at this time. MEMBER BROWN: And they've seen that, I
take it? They said that would solve their concerns, is that correct? Okay. I thought I heard you say
that.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CHAIR MAYNARD: Yes, this has been worked
on for some time. MEMBER BROWN: That's fine. No, I am
aware of that based on the last meeting we had on it.
I just didn't know how extensive it was. MS. GREEN: Section 4.3 of the SER
document is the staff's review of the applicant's
metal fatigue analyses. Sixty year fatigue analyses
were performed for all NUREG/CR-6260 locations with
the exception of two locations at Indian Point 2 and
three locations at Indian Point 3. And that's because
Indian Point 2 and Indian Point 3 are ANSI B331.1
plants and therefore they do not have cumulative usage
factors for the these particular locations. But they
have made a commitment to manage aging under their
fatigue monitoring program for all new NUREG/CR-6260
locations in accordance with 10 CFR 54.21(c)(1)(iii).
And that's identified as license renewal Commitment
- 33. There was one open item in this section.
There was open item 4.3-1. And the staff asked the
applicant to provide the actual number of heatup and
cool downs for IP3. In the LRA did not have that
information. I guess at the time they submitted the
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 issuing the SER with open items I didn't realize that
they previously provided that information to us in
response to an audit question. And they pointed that
out kindly to me. And they also provided the
information again in a letter dated January 27th. So
now that we have information, it can be closed. CHAIR MAYNARD: I'm surprised that you
didn't remember everything. MS. GREEN: I know. It's a little
overwhelming after a while. That should not have been. If I had
realized at the time, that would not have been
identified as an open item. CHAIR MAYNARD: Better to have it this way
than to -- so that's fine. MS. GREEN: Okay. Well, I'm going to try
to over the open items that are still under staff
review at this time. As I stated in the beginning, the SER was issued with 20 open items. And since
before the issuance of the SER the staff has been
working with the applicant to obtain the information
that we need to complete our view. So by letter dated December 30th, 2008 we
did issue a request for additional information for
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 additional information for five more of the open
items. That left six that were under the staff review
at the time. We had information for some of them. I
think five if I recall in a letter that the applicant
sent to us in the beginning of November. And the time
we were issuing the SER, the staff hadn't completed
its review of that information. So we weren't able to
ask the applicant for additional information at that
time. So they had nothing to provide to us. By letter dated January 27th the applicant
did submit additional information for the 14 open
items for which we requested additional information.
And based on our review of that information, the staff
has informed me that 13 of the open items can be
closed. We don't expect to ask for any additional at
this point in time. We feel we have enough information
to close 13 of those open items. And we informed the
applicant of that information. So we still have seven open at this time.
And they're listed on this slide. And I'm going to
try to cover them, what the staff's thinking is the
these particular items. You heard from the applicant
what their view is. Now I'm going to try to cover the
staff's.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 So for station blackout, as you know it's
basically a generic issue that the staff has been
evaluating. At Indian Point -- when we were reviewing
their application the diagrams that they had in the LRA did not identify two independent recovery paths.
So we asked them a question. And when they responded
to us, they revised the figures. But at the time they
revised the figures, they changed the boundary from a
circuit breaker to a motor operated disconnect, which
kind of threw us because the staff believes that the
boundary should end at a circuit breaker. That's what
our guidance suggests. So then by letter dated March 24th the
applicant revised it's LRA response to end the
boundary at a circuit breaker. And then by the letter
dated August 14th, 2008 the applicant clarified that
the recovery paths did include the structural
foundations needed. So the staff is still reviewing the
applicant's boundary and the information that we've received. And at this time it's still an open item.
Okay. CHAIR MAYNARD: Go ahead, John. MEMBER STETKAR: I don't know if it's fair
to ask and you can say no it's not fair.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CHAIR MAYNARD: We don't have to be fair, John. MEMBER STETKAR: You can make a pretense. Since this is not one of these kind of a
track, 13 or 14 that are well underway to being
resolved, could I ask what particular concerns the
staff still has related to the scope? I got confused
as I went through the timeline also. And when Entergy
showed me the drawing this morning that showed the
whole switchyards with the circuit breakers and
pathways highlighted, it seemed pretty
straightforward. MS. GREEN: Right. I'm going to let my-- MEMBER STETKAR: I want to say I don't
want to say don't want to -- MR. HOLIAN: I take this. MEMBER STETKAR: -- fairly straightforward
in terms of acceptance, at least I could clearly see
where the boundaries are. MS. GREEN: Well, I'm going to let Brian-- MR. HOLIAN: Yes. This Brian Holian, Division Director. And I'll cover this one. And we also had a simplified drawing that
we were preparing also to try to make it a little more
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 cover it in a couple of sentences here. One, you know, this station blackout issue
has been around for a couple of years, the generic
aspect of it. As much as different plants have feed
reg valve differences on whether that's in their COB
or not. At this point you're looking at how far out
does the plant boundary go for license renewal. And
that's what it really gets at. And the basis behind
some of the questions. And even how clear that is
from plant-to-plant on their COB is a question. So
it's an appropriate area for the regulatory and the
plant to be discussing in license renewal, and it has
been. We do have existing guidance out there
now. And it's generally worded. It talks about the
path that's required. Typically includes the
switchyard circuit breakers. And so that's general
guidance. Typically is an issue for interpretation
from plant-to-plant. And I think as we look back at
the history it was written that way because it was to
be based on what they were licensed to, even as they
came in with their electrical diagrams on that. So
it's the first item I wanted to mention. The second item we put out, the staff put
out, to try to clarify that existing guidance a year NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ago, more detailed guidance that basically said, and
it's still in draft and it's out and it's been
commented on, that we'd like you to detail this a
little bit further to make it consistent across all
the plants. And you will take it out plants to
transmission system voltage. I'm paraphrasing, but
that's one of the items in the revised guidance. And
it gets it way into the switchyard. And what you saw at Indian Point, Kim
described earlier an area where they beefed it up, I'll say, to meet our first guidance, our existing
guidance. So they quickly -- just the existing
guidance. Typically where do you go and, as she
mentioned, pass the disconnects to a circuit breaker that is typically met. So I think from the utility's
viewpoint they meet the existing guidance. This transmission-system voltage what you
saw in their drawing was they have one line that comes
down from 138 kV, the second line that goes out it
stops at the 13.8, 6.9 transformer. That's still in
the switchyard, at the edge of the switchyard. Our
electrical staff would basically say take it out on
that second path, the redundant path, to the next
circuit breaker set that are still right there in the
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 So that's the area of delta; how far out
do you go into the transmission. A little criticism from the industry that, hey, how far out do you want us to go, you know, the
next transformer pass that or not? So that's the area
of disagreement. I will just touch on it now. We do have
guidance, and even NEI has weighed in on this in the
last year on the draft guidance, that even the station
blackout rule itself might not have been written to go
to that aspect of the rule. And staff, their
criticism of the staff, which I brought up to the
Subcommittee here during our general briefing on
license renewal issues a few months back, was that you
should go after this in clarifying the station
blackout rule vice an interim staff guidance in the
license renewal aspect. And that's a good criticism, I think. And the electrical branch might be
choosing to go at it that way to clarify the boundary
for the station blackout event vice, you know, a
plant-by-plant issue as we come into license renewal. So to summarize, and this is still being
decided upon by the staff, but you might see us
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 that says -- MEMBER STETKAR: The transmission voltage? MR. HOLIAN: That transmission-system
voltage. And if that's so, it will clarify this open
item and it'll be closed. But that discussion is still
ongoing. MEMBER STETKAR: Thanks. That helps me an
awful lot. Because I hadn't appreciated the subtly of
the transmission voltage criteria, let's say. Thanks. MS. GREEN: Okay. The next open item that
you heard about earlier from the applicant about the
Indian Point 2 refueling cavity leakage. During the on
site audits the staff identified that IP2 refueling
cavity leaks when flooded during refueling operations.
And as the applicant mentioned, that usually lasts
about two weeks out of a 24 month refueling cycle. The staff questioned the applicant about
what corrective actions have been taken to repair the
leak. And as you heard, the applicant's made several
attempts to repair the leaks, but they haven't proven
successful yet. And the applicant mentioned that it has an
action plan to permanently remedy the issue. But when
they told us about it, they did not make it a license
renewal commitment.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 And as they also mentioned, they had
previously taken bore samples in the region of the
leak to determine the extent, if any, of degradation
to the concrete. And as they also mentioned, the
sample showed that none has yet occurred. So the staff asked the applicant what they
had planed to do for the period of extended operation.
And the applicant committed to perform a one time
inspection in this region. I think they plan to take
another bore sample in the region to confirm the
absence of concrete and rebar degradation. And that
was provided as license renewal Commitment 36. And as I mentioned earlier, last week we
sent them a draft request for additional information
to seek information on their plans to monitor
degradation in this region during the period of
extended operation. I can add a little bit more to this. The
information that they gave us for their permanent fix
I think is going to take three refueling outages, which would be after their current license expires.
If a renewed licensed were to be issued, they wouldn't
know whether or not the permanent fix that they might
implement would be successful. And so not knowing
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 to do to monitor it during the period of extended
operation to confirm that no degradation is occurring.
So that's where the staff is at this point. CHAIR MAYNARD: Well, I think we talked
about this one a lot with the applicant. And this was
the one that for me I'm having probably the biggest
struggle getting my arms around it as to what the
overall confidence level in, you know what degradation
if any has been done. You know the overall safety
significance of this. And I don't know, for me it's
probably not worth talking about it anymore at this
point. But I know the next meeting for me we're going
to have more discussion and I need to see some more
information on that. That's something I'll cover
later. But we can wait also and see how the staff
resolves this and stuff, too.
John? MEMBER STETKAR: Yes. Can I ask a question that I didn't think of it until right now.
It's really a question for Entergy. Just to help me
file some things away, if nothing else. Is there -- I don't want to call it
annular, but an interspatial space between the
refueling cavity liner and the concrete? We talked a
little bit about that with respect to the fuel pool NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 this morning and that, you know, there might be water
there. Is there a similar space that water might be
permanently residing? Or do you feel that if there is
a space, that water has such a free path that it
drains away? MR. DACIMO: Yes. We feel fairly strongly
that there is no trapped water in this area. MEMBER STETKAR: Okay. That any water
that enters basically winds up down on the -- MR. DACIMO: And we can see that via
starts and stops when you flood and when you -- lower
levels, okay. When you flood the cavity up and also
on your lower levels, start and stop. Additionally, we had done some mass balances previously when we had
done our containment sump strainer modifications. And
we could see the make up rate is really equivalent to
the train rate. So that gives us a feel for what's
going in is going out. Okay. Additionally if you look at the geometry
we feel pretty confident that the geometry, the way
the vertical walls are, that you're getting good
drainage. There's nothing that's going to pool under
there. And particularly you can kind of look up in the
basement of the vapor containment and kind of see
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 that in itself gives us a fairly confident that is all
drained. Last but not least is we also feel on top
of all of that, okay, it is only wetted two weeks per
two years. So the amount of time if we were to assume
-- let's assume that we're incorrect. If we are
incorrect, we really feel that the impact on the
structure itself would not be significant. And we'll -- I assume this is going to be
a discussion next time. So we'll bring -- MEMBER STETKAR: Yes. Yes. MR. DACIMO: -- those issues to the table. CHAIR MAYNARD: And I think for me it
would help, go ahead and talk about it, maybe some
better pictures and stuff to go into what you think
the path is. Just a little bit better detail than what
the pictures that we had there. MR. DACIMO: We will be prepared to do
that next time. Now, all of that notwithstanding, I don't want to imply that again that we're happy with this.
Okay? We're going to live with this but on the other
hand, though, don't think it really presents a long
term challenge for this facility if it remains
uncorrected.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MS. GREEN: Okay. The next open item is the one that addresses the IP2 spent fuel pool leak.
As the applicant mentioned, and has already been
established, that the Indian Point 2 spent fuel pool
has experienced leakage. And as the applicant
mentioned, the spent fuel pool does not have leak
chase channels which makes it more difficult to detect
and quantify leakage. So to assess for potential indications
this spent fuel pool leakage, the applicant did commit
to test the groundwater outside the IP2 spent fuel
pool for the presence of tritium from examples taken from adjacent monitoring walls every three months.
And they've identified this as license renewal
Commitment 25. Entergy in the application and in their
program they didn't state that they plan to perform
augmented inspections of the spent fuel pool structure
during the period of extended operation. So the staff
requested some additional information on the condition
of the concrete and rebar in the area where the
leakage had been detected. And the applicant did
provide this information including information about
their bore samples that they had taken. But at the
time of the issuance of this SER the staff was still NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 evaluating the information. But they did that in the
November 6th letter. But since that time, like I said, last week we did send a draft request for additional
information to ask the applicant how the AMP or the
aging management program will determine if a degraded
condition exists during the period of extended
operation or explain how the AMP will adequately
manage the potential aging of concrete due to borated
water during the period of extended operation. CHAIR MAYNARD: And again, I think this is
another important item that we certainly want to
discuss next time. I'm not sure there's need to
discuss anymore here. I don't know it might -- MEMBER RYAN: Just to reiterate what we
said earlier, you know, a better understanding, a
little more depth on the geohydrologic program and how
it relates to the engineering conditions. And I think
it would be particularly helpful to give your insights
from the monitoring you've done as to what you think it means relative to how the defect is behaving.
That's particularly useful. Because I'm sure you've
got a record of monitoring now over some period of
time. So gaining your insight into what that tells
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 share the conclusions that we've had -- you know, all
this stuff is on the public record. We'll bring that
in and we will share that everyone. MEMBER RYAN: Good. One thing you didn't
mention we talked a lot about tritium, because that's
the indicator. And any other radionuclides that are
detected and what your interpretation of those
positive that you've got, if any, would be helpful as
well. MR. DACIMO: We'll be prepared to do that. MEMBER RYAN: Thank you. CHAIR MAYNARD: I'd like to take a break
right now. Let's come back at 15 'til and we'll go
ahead and finish. (Whereupon, at 2:27 p.m. off the record
until 2:44 p.m.) CHAIR MAYNARD: Okay. Let's come back
into session. And, Kim, go ahead with the next item
here. MS. GREEN: Okay. The next open item
that's under staff review is the one that addresses
spalling of the exterior concrete containment
structure. During the on site audit staff reviewed
some operating experience relative to the concrete
spalling and asked a lot of questions. The applicant NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 provided information about the areas and the reasons
for the spalling. As they mentioned earlier, it
occurs primarily where the Cadweld sleeves have
insufficient concrete coverage and also where they
have applied some concrete over the anchor embeddments
that were used for erection of scaffolding during
initial construction. The applicant also mentioned that they did
evaluate the structural margins for the IP
containments and concluded that at the locations where
the rebar is exposed there is sufficient design margin
to ensure structural integrity. And they also said
that this condition is being monitored under their
containment inservice inspection program. In response to the staff's request about
this issue, the applicant committed to enhance the
containment inservice inspection program during the
period of extended operation. As Glenn also
mentioned, they covered that during the inspection.
And the applicant said that they would perform
enhanced characterization of the degradation. I think
they're going to quantify it using some camera that is
able to record measurements. And that will allow them
to perform effective trending of the degradation. And
that was identified as license renewal Commitment 37.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 And this is another item that we recently
submitted a draft RAI on, and we're just trying to
find out how the applicant will use the enhanced
inspection results and the design margin calculations
to ensure that there's no loss of intended function
during the period of extended operation. Open item 3.4-1 addresses the aging
management review results for those components needed
to support a fire event in the IP2 aux feedwater pump
room. In the application the applicant stated that
the systems needed to supply feedwater to the steam
generators during the fire event are continuously in
operation and are monitored. They also stated that
significant degradation that could threaten the
performance of the intended functions of the
components will be apparent in the period immediate
preceding the event and corrective action will be
required to sustain continued operations. And for the
minimal one hour period that the systems would be
required to provide makeup to the steam generators
that further aging degradation that would not have
been apparent prior to the event is negligible. So
therefore the applicant did not identify any aging
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 intended functions to provide feedwater to steam
generators is assured. Therefore, they did not
identify a specific an aging management program would
be required. Because these systems contain passive and
long-lived components, the rule states that the
applicant should demonstrate that the effects of aging
will be adequately managed during the period of
extended operation such that the intended functions
will be maintained consistent with the current
licensing basis for the period of extended operation.
And based upon the information LRA that we had, the
staff did not believe it had sufficient information to
make this determination. So by letter dated December 30, 2008 the
staff asked Entergy to provide details of the AMR
results for those systems credited for providing flow to the steam generators during the fire event. They
provided that information in a letter dated January
27th. And the staff is still evaluating the response
at this time. CHAIR MAYNARD: I'm still trying to get my
hands around this one. The aux feed is so important
that I'm still -- like I don't know that I've got a
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 nervousness here that I've got to do some more
reviewing on my own for this situation and really what
the effect is on aux feed and everything here. So, John, you look like you have -- MEMBER STETKAR: Yes, Kim, I kind of share
Otto's uneasiness, and I'm not quite sure if I can get
my hands around exactly why. Because in some cases
I'm not intimately familiar with kind of the rules of
defining these fires. From what I heard you just say is I
noticed on the second item on the slide there says
that applicant stated that aging related degradation
occurs during one hour is negligible. And what I
heard you say is that you aren't particularly
considering that one hour time window in your
evaluation, is that correct? You're more concerned
with the availability of the normal systems to provide
flow regardless of whether it's one hour after the
fire or a couple of hours, is that correct? MS. GREEN: Correct. That's correct. MEMBER STETKAR: Okay. So the one hour
doesn't really enter into your evaluation, is that
correct? MS. GREEN: Yes. That's correct. There are some systems that are used NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 during this event that are already in scope for other
reasons. MEMBER STETKAR: Right. Right. MS. GREEN: And then there are some
systems that are only -- I think the only reason
they're in scope is because of this fire event. MEMBER STETKAR: Right. MS. GREEN: And the applicant is making a
statement that because these systems are in continuous
operation they'll always be monitored and therefore
they would identify if there was a problem with the
system prior to the fire event ever occurring. And
they've cited some precedents in other applications, as they mentioned, where the staff has for the BWRs in
particular I think, accepted the justification that
for condensers in particular that they're in
continuous operation and the post accident intended
function would be maintained based on continuous
operation. I think the staff is still evaluating this
because we haven't seen this yet for a PWR. MEMBER STETKAR: Okay. MS. GREEN: And so the staff is still
trying to come to terms with whether or not there are
some passive long-lived components that would have NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 known degradation, not necessarily at this plant but
in GALL, the components of particular material would
experience some aging related degradation. And whether
or not it's one hour the staff doesn't -- MEMBER STETKAR: Doesn't care how long
after T 0 the thing -- MS. GREEN: Right. Correct. MEMBER STETKAR: Thanks. That helps me a
little bit with the one hour. And I'll ask it again just to make sure I
understand that the staff agrees that because of the
Halon protection system in the IP3 auxiliary feedwater
room this is a nonconsideration for IP3, is that
correct? And there isn't a corresponding IP3
auxiliary feedwater room at the -- MS. GREEN: That is my understanding. I think in this particular zone for the
aux feedwater pump room at IP2 there is an exemption
that they have for fire protection, but it's due to
the fact that they don't have -- well, I went back and
tried to dig up the history on this. And this is one
of those areas that doesn't have adequate suppression, so therefore they have to take credit for providing
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 clear this morning. MS. GREEN: Right. MEMBER STETKAR: That IP2 doesn't have
adequate protection. But it's concluded that IP3 does
have adequate protection? MS. GREEN: That is my understanding. CHAIR MAYNARD: I would think that's
something that we would want to get clarified at the
next meeting. MEMBER STETKAR: I mean, it sounds like
it's part of the current licensing basis. It may be a
physical difference between the two plants because of
the existence of the protection systems, the
differences in those systems. I just want to make sure
that -- MS. GREEN: We can find that out and make
sure that we understand that; that it is not an issue
for IP3. MEMBER STETKAR: I mean, I was just
curious because in the SER there's a section heading
that says IP3 auxiliary feedwater room fire event and
it just simply says not applicable -- MS. GREEN: Right. MEMBER STETKAR: -- without any further
discussion about why that is or --
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MS. GREEN: Well, that was my genius. MEMBER STETKAR: I'm sorry. MS. GREEN: They identified in Section
2.3.4-5 in their LRA. And if I had put in 2.3.4-5 as
their condensate system for IP3, it would leave a --
you know, in the numbering. And so I put it in and
just said it's not applicable. MEMBER STETKAR: And so it was easy for me
to find the section to go look, because it was there. MS. GREEN: So by doing so, I guess I've
caused some confusion. But we will definitely find
out for certain. CHAIR MAYNARD: Okay. We're easily
confused, but that's all right. MEMBER STETKAR: We're easily confused. CHAIR MAYNARD: Harold, were you -- MEMBER RAY: Yes. I mean, I guess the
issue comes down to whether or not there are in fact
systems relied upon in this event that are in service
all the time prior to the event, correct? MS. GREEN: That's what they tell us, yes. MEMBER RAY: Well, but I mean that's the
question in your mind? MS. GREEN: Yes. MEMBER RAY: Are you all confirming that?
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CHAIR MAYNARD: We need to make sure that
the staff has looked at that and agrees with that. MEMBER RAY: Yes. MS. GREEN: That was one of the questions
we had asked. If they are going to take -- in scoping
-- this issue is kind of divided. It has two parts.
The scoping and screening aspect of it which we had an
open item on, which they provided the information and
we can close based on the information they provided. And then there's the aging management
review results which are a little bit different which
the staff is still evaluating. One of the questions we did ask and the
staff caught this, was if you're going to take credit
for continuous operation of systems they found some
systems that the applicant had credited which are
continuously operated. They are only operated
intermittently. And when we asked them about that, they went ahead and added that particular system to
scope and said "Okay, this is in scope and it's
subject to aging management review because it's not in
continuous operation." But we did, we did question about the
systems that were continuously operated versus the
ones that were intermittently operated.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER RAY: Okay. But that's a long way
of saying, I think, that the unresolved issue hinges
on the question of whether or not there are or are not
systems relied on in this scenario that are in
continuous operation. It sounds like. MS. GREEN: Yes. MEMBER RAY: Okay. CHAIR MAYNARD: Again, I think it's
important for the next meeting for us to know what the
staff's final review and position on that. MEMBER RAY: Well, yes. And what the
basis of it is. I mean, someone tell us what the
systems are that are in dispute here, if there's a
dispute at the end of the day. MS. GREEN: The next open item is 3.5-1
and it addresses the water-cement ratios that were
cited in the license renewal application for IP
concrete. In the LRA the applicant had identified
water-cement ratios to support its claim that certain
aging effects identified in the GALL report that
required further evaluation are not applicable to the
concrete. The staff noted that the applicant
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 entrainment and water-cement ratios per American
Concrete Institute Standard 318-63 and asked the
applicant to clarify the correct water-cement ratio
value that it used. So by letter, dated November 6, 2008, the
applicant stated that the ACI Standard 318-63 provides
two methods for determination of concrete properties.
And it further stated that the concrete mixture at IP
was established based on tests of concrete mixtures
with varying water to cement ratios per method 2 of
the standard. The applicant stated that the actual test
for containment concrete showed compressive strengths
above the required 3000 psi. The staff recently issued a draft RAI to
ask the applicant to define the water to cement ratios
and provide results of original concrete strength
tests or alternatively the applicant may identify
applicable aging effects and describe how they will be
managed during the period of extended operation. I think this is my last open item to
cover. It's 3.5-2, and that addresses the reduction of
strength and modulus of concrete due to elevated
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 applicant stated that the concrete surrounding the IP@
penetrations can reach temperatures of up to 250
degree Fahrenheit. The GALL report recommends further
evaluation to manage the reduction of strength and
modulus of concrete structures due to elevated
temperatures greater than 200 degrees Fahrenheit. The applicant concluded that the reduction
of strength and modulus is not an aging effect
requiring management. So the staff questioned the
applicant's conclusion and asked the applicant to
evaluate the effects on the properties of concrete
exposed to the elevated temperatures. The applicant
determined that there is a reduction in strength of
approximately 15 percent from elevated temperatures
but found this to be acceptable because compressive
strength tests showed that the actual strength is 15
percent higher than the design strength of 3000 psi. And this is another one where we recently
issued a request for additional information to ask how
the strength of margin was determined and if reduction
in modulus of elasticity was considered in the
evaluation. CHAIR MAYNARD: For me on this one if
they're using what the actual strength versus the
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 this is part of the staff's question to them is in
showing how they know that, how did they determine
that? You know, if you take one sample and say it's
applicable to everything, that's probably not enough.
So what was used and how do they know what the actual
strength is? It would be important to me once we see
how this gets ultimately resolved, if it does. MS. GREEN: Right. So we've asked them for
that information. So hopefully, when they provide the
information we've requested, we'll be able to close
out. As they mentioned earlier, the temperature
-- and we found this out during a phone. There was
some question about 250 degrees; was that during
normal operating conditions or was it post accident
conditions. And they had said that the temperatures
really are more around 150 degrees during normal
operating conditions. So with that information, too, that was helpful to know to get that clarification. So
they're going to provide that to us in writing. MEMBER STETKAR: That 150 degree
temperature, though, is based on operation of that air
cooling system, is that correct? MS. GREEN: That's my understanding. CHAIR MAYNARD: And you'd ask questions--
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER STETKAR: I had asked questions
about that this morning. CHAIR MAYNARD: There's another one that
would need to be addressed when we meet again on this. MEMBER STETKAR: Yes the basis for the
fact that it basically can't become higher than 250
degrees. CHAIR MAYNARD: Okay. MS. GREEN: I think that concludes my
presentation. CHAIR MAYNARD: Okay. Any other questions
for the staff here? Charlie? MEMBER BROWN: Okay. I just had a
question on the audit report. This is the one I
talked to you about earlier. This is your alls audit
report. Under the flow-accelerated corrosion section, pate 13. You all noticed event chamber drain piping
and high pressure turbine drain piping and another --
a two inch line and then a three-quarter inch line.
And you all -- they did wall thickness checks. And I
guess on one of them, the event chamber drain piping, I guess the minimum acceptable thickness is 123 mils and the actual measured was 52 mils. And
there's some required thickness for two more years of
135 mils, which obviously they don't meet.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Then there were two other ones. One of
them was almost identifiable. They were kind of right
on, very, very close. And I guess my question came out as there
went on to be an explanation. There was a response
that said hey you go -- if you encounter these things, there's certain things. You take more samples and you
test those, and you do a bunch of stuff for similar
sized pipes. One thing I didn't see in the program for
doing that, this is Entergy's response to that, is you
found a situation where your inspection process did
not identify a minimum that was unacceptable before it
actually occurred. And typically you would like to do
that. Now I'm not sure this is a safety system.
but the principle is kind of the same in that the
whole corrective action process doesn't address
changing the frequency of inspections for certain
particular elbows or, you know, flow redirections or
what have you in order to ensure you have a process
that does identify that you're getting close. That you
don't surprised. And this was fairly big. A big
number difference. It's like almost a third of the
required.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 So that was my question is that the
process they didn't give a specific program, I guess
maybe it's your alls' program because it talks about
their fact program. So my question is why isn't
frequency a factor once you find your inspection
doesn't identify a problem before it actually becomes
a big program or it's significantly below wall
thickness? Is Entergy to -- MR. DACIMO: We can comment on that. CHAIR MAYNARD: Okay. Go ahead. MR. AZEVEDO: Yes. My name's Nelson
Azevedo. The FAC program and in point follows the
NSAC 2020, just to give you a standard, as well as the
EPRI guidelines. I can't comment on the point that you're
bringing up, but I can tell you in general terms just
because you exceed the required thickness does not
mean that section is no longer acceptable. There's a
localized wall thinning evaluation that we can do.
And, again, just because you exceeded the minimum 360
requirement doesn't mean that that section was
unacceptable. But more going to the other point as what
do we expand. We add additional locations that we do NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 inspections -- MEMBER BROWN: Well, that's locations. I
understand the locations part. MR. AZEVEDO: Right. MEMBER BROWN: It was frequency that I was
addressing. MR. AZEVEDO: Well, what we do is we
calculate the erosion rate and based on that rate we
extrapolate to when we need to additional inspections
at this or other locations before we exceed whatever
the minimum required is. So that is part of the
program. MEMBER BROWN: Okay. But this one didn't
work? MR. AZEVEDO: Again, I have to get the
details of this one here. Just because it was below
the minimum thickness does not mean it was
unacceptable. CHAIR MAYNARD: I think what you're
getting at here did they make adjustment to their
frequency when they found this? MEMBER BROWN: Exactly. Thank you.
Exactly. That would have been my reaction. Here I
found a circumstances where I did not identify it
before it really became a problem. And with whatever NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 other process you did do, would you have adjusted your
frequency to try to ensure and look at other
circumstances to see if hey, is my approach really
giving me a frequency in which I can find these
before? MR. AZEVEDO: The answer is yes. MEMBER BROWN: But it's not stated in the
response. When I looked at page -- I'll find it here
in a minute. I think it's page 70. MR. DACIMO: We'd have to review. We'd
have to look at that document. But the program
requires that. MEMBER BROWN: Okay. Now, did you all ask
that question or not? MS. GREEN: I can't tell you whether we
asked the question or not. The individual reviewer is
not at this meeting. I could find out and get back to
you on it. CHAIR MAYNARD: What I would suggest that
we do is have Entergy take a look at the audit report
and the staff do. And our next meeting -- MEMBER BROWN: That's fine with me. CHAIR MAYNARD: -- address what-- MEMBER BROWN: Yes, that's fine. CHAIR MAYNARD: -- they did and what the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 program required. MEMBER BROWN: That's fine. CHAIR MAYNARD: Yes, I think that would be
good. Any other questions for the staff? MEMBER BROWN: Hold on. Hold on. No. CHAIR MAYNARD: What I'd like to do now
is, Theron, if you could bring on, let's see, Ms.
Deborah Brancato and we'll hear comments that she
prepared. We also received documents from her. Ms. Brancato, are you on? MR. MUSEGAAS: Actually, this is Phil
Musegaas, Judge. Or, you're not a judge, I guess. Mr.
Maynard, is that who I'm speaking to. CHAIR MAYNARD: That's correct, yes. MR. MUSEGAAS: Okay, sir. My name is
Phillip Musegaas. I'm the lead counsel for Riverkeeper
on the Indian Point proceeding. So there was a little
mix up because Deborah submitted the comments, but
I'll be giving the statement today. Would you like me to spell my name for the
record? CHAIR MAYNARD: Yes. If you would, please. MR. MUSEGAAS: Okay. P-H-I-L-L-I-P and
last name is M-U-S-E-G-A-A-S.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 And I just have a statement that will
probably just take a few minutes. And you have our
written submissions as well, which go into more
detail. I just want to thank the ACRS for giving
us the opportunity to provide comments today and to
make a statement today. We appreciate it. To begin with, Riverkeeper is a not for
profit organization dedicated to protecting the Hudson
River and its tributaries from pollution. Since our
inception in 1966 Riverkeeper has used litigation, science, advocacy and public education to raise and
address concerns relating to the Indian Point Nuclear
Power Plant. Our predecessor organization, actually, which the Hudson River Fisherman's Association
actually was an active party opposing the original
licensing of the plant. Riverkeeper's offices are located 22 miles
from Indian Point. And we have numerous members that
reside within at least 50 miles of the plant, and many
of them within 15 miles. Over the years Riverkeeper has been
actively involved in raising safety concerns
associated with the plant's operation. In November of 2007 Riverkeeper filed a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 petition to intervene challenging Entergy's license
renewal application. We were subsequently admitted as
a party and granted a hearing. Three of our five
contentions were admitted for adjudication. What I'd like to do today is just very
briefly highlight two of our admitted contentions
which bear directly on the information in the
application, of course, and in the staff's draft SER.
And then also mention some concerns we have relating
to a contention which was not admitted, but which we
feel we should bring to the ACRS Subcommittee's
attention. So I'd like to talk just briefly. I'm
going to talk about metal fatigue, flow-accelerated
corrosion and then severe accident mitigation
alternative analysis. So to being with metal fatigue. The NRC
regulations require that license renewal applicants
evaluate the time limited aging analyses for covered
components effected by metal fatigue and demonstrate
that such analyses remain valid for the extended
licensing term or that they have been projected to the
end of the period of extended operation. This is
pursuant to 10 CFR 50.21(c)(1)(i) and (ii). If the applicant is unable to do so, it NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 must submit an aging management plan demonstrating
that the effects of aging on the intended functions
will be adequately managed for the extended period of
operation. Entergy's license renewal application
fails to demonstrate the TLAAs remain valid for the
period of extended operation, or that they have been
projected to the end of the period of extended
operation. And there's, I think, three points I'd
like to make here. First, the TLAAs and the LRA for selected
representative components show that the
environmentally adjusted cumulative usage factors, which are the CUFs or C-U-Fs, for a number of
components will exceed one, which is the unity, during
the license renewal term. Second, Entergy's list of components with
CUFs of less than one in Tables 4.3-13 and 4.3-14 is
inaccurate because: (a) Based on data in NUREG/CR-6909
Entergy used an unrealistically low environmental
correction factor, which is referred to as a FEN; Second, Entergy did not project the
analysis to 60 years but rather used the CUF of
record, which is the current CUF accounting for the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 original 40 year license term, and; Third, Entergy did not calculate several
limiting locations since data was unavailable. Had Entergy employed proper methods and
assumptions, the number of components with CUFs
greater than one would be much larger than depicted in
the LRA in these tables. And I neglected to mention at the outset, but the technical contentions that we filed
challenging the metal fatigue and the flow-accelerated
corrosion are supported by technical expert Dr. Joram
Hopenfeld. So we have expert support for these
contentions. I'm not an attorney. I'm not an engineer.
S if you do have specific technical questions related
to this, we can happily have our expert to respond to
those. I certainly wouldn't be able to. So going on. Our third main point on
metal fatigue. Entergy's assessment of TLAAs is
incomplete because having identified components that
exceed unity, Entergy was required to expand the scope
of the TLAAs in which it considers exacerbating
effects of environment conditions on the fatigue of
metal components. This is according to NUREG-1801, which is the GALL report.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 And had Entergy applied the FENs to
reflect the fact that these listed components operate
in a very harsh environment, not just in the vacuum
and in the air environment that's being modeled but in
the environment of water and stream that are known to
reduce fatigue life, many of the CUFs would have far
exceeded unity. An aging management program must provide
sufficient detail to demonstrate that the applicant
will adequately manage aging of equipment. And it is
not sufficient to merely "summarize options for future
plans." And I'd like to emphasize the point because
while this may be more of a legal matter than a
technical matter at this stage of the proceeding, Riverkeeper is particularly concerned about this. In its application Entergy basically has
put out several options for addressing metal fatigue
during the extended period of operation. They made
some adjustments to their plan following Riverkeeper's
petition and New York State's petition to intervene, which also metal fatigue concerns. However, the
current state of Entergy's application, Entergy's has
stated that they will choose among three options to
address metal fatigue: (1) Refine the fatigue analysis to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 determine CUFs less than one when accounting for the
effects of reactor water environment; (2) Manage the effects of aging by an
inspection program, or; (3) Repair or replace the effected
locations before exceeding a CUF of 1.0. Unfortunately, none of these options
satisfy the NRC's safety regulation. To demonstrate that aging will be managed
effectively, Entergy must provide an actual
description of its monitoring program that includes a
clear definition of the type and frequency of its
inspection in order to ensure that components are
replaced or repaired in a timely manner. An
acceptable aging management program must also specify
criteria for repair or replacement. It is not
sufficient to merely presume that these things will
happen based on a vague commitment to comply with the
regulations in the future. Riverkeeper feels, and we believe the
regulations require, that Entergy should be required
to demonstrate that they comply with the regulations
and provide the analysis prior to approval of license
renewal. However, the staff's SER finds that Entergy's
TLAA assessment is entire acceptable, as I believe NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Kimberly Green explained. The SER concludes that the
effects of aging on the intended functions of relevant
plant components will be adequately managed for the
period of extended operation. I will continue with flow-acceleration
related corrosion. And I know I have limited time,so
I'll try to be concise here. NRC regulations require license renewal
applicants to have a program to effectively manage
wall thinning due to FAC. Detection of FAC should
occur before there is a loss of the structure and the
component's intended function. So again, this is
supported by NUREG-1800. The wall thinning must be monitored or
inspected to ensure that the structure and component's
intended function will be adequately maintained over
the extended operation term. Entergy's program is inadequate to ensure
that the effects of FAC on relevant plant components
will be properly managed. First, Entergy's reliance
on the CHECWORKS computer program is misplaced because
it has not adequately re-benchmarked the program to
account for changes in plant operating parameters. And
this refers to the latest power uprates that were
granted to Indian Point 2 and 3. Respectively, Indian NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Point 2's uprate was in October 2004, an increase of
3.26 percent. And Indian Point 3, the uprate was
granted in March 2005 and that was a power increase of
4.85 percent. Such power changes effect velocities, temperatures, coolant chemistry and steam moisture, especially on the secondary side of the plant where
the steam flow and feed flow increases are approximately proportional to the power increase.
Accordingly, CHECWORKS must now be properly updated. And in more detail we change the way in
which Entergy used CHECWORKS in their application. Since CHECWORKS cannot be property relied
upon to monitor and detect thinning from FAC, Entergy
must provide detailed information regarding the method
and frequency of component inspection and its criteria
for component repair or replacements. This, again, according to NUREG-1800. The program should include a methodology
for analyzing the results against applicable
acceptance criteria. And we don't believe Entergy has
either used CHECWORKS accurately or provided detailed
information, as I've said, regarding their
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 replace components. Next I would like to briefly talk about
severe accident mitigation analysis, alternative
analysis. Entergy's LRA seriously underestimates the
potential containment bypass during a core damage
accident. In light of current knowledge about severe
reactor accidents it is prudent to assume that: (1) Any high, dry accident sequence, i.e., those in which the secondary side dries out due
to the unavailability of feedwater and the reactor
coolant system pressure remains high, all primary
coolant is lost and the core uncovered would involve
induced failure of steam generator tubes and that
would result in one or more of the secondary side's
safety valves, downstream of the effected stream
generators would remain open after tube failure. Taking these assumptions into account, Riverkeeper believes the conditional probability of
atmospheric release categories in the event of core
damage due to this type of accident is over 50
percent. In the context of the SAMA analysis
Entergy has not properly considered the contribution
to severe accident costs made by severe accidents
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 induced failure of the SG tubes. Because it does not
account for the above mentioned functions, Entergy's
estimates of conditional probabilities of atmospheric
release categories are incorrectly low.
Correspondingly the value Entergy assigns to the cost
risk associated with atmospheric releases is
mistakenly low. And again, in the interest of time we've
given you detailed information on support for these
concerns. A second issue relating to the SAMA
analysis, Entergy's LRA does not adequately take into
account the safety risks of spent fuel pool fires.
While initially it was assumed that the storage spent
fuel generally did not pose significant risks, with
the introduction of high-density closed form storage
racks into spent fuel pools beginning in the 1970s, this understanding is no longer valid. The closed
form configuration of high-density racks can create a
major problem when water is lost from a spent fuel
pool including, of course, significant pool fire. And we have in support of our petition we
have included an expert report that supports this
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Entergy has not considered the contribution to severe
accident cost that would be caused by fire in either
of the spent fuel pools in Indian Point 2 or 3. If the
cost of pool fires were considered, the value of
SAMA's would be significant. And just to note, Riverkeeper is well
aware that SAMA analysis has traditionally been
applied only to reactor accident and then any spent
fuel storage or spent fuel issues are generally
considered category 1 by the NRC and are exempt from
license renewal review. However, we think it is
important to raise this issue before the ACRS. Finally, Entergy's license renewal
application does not adequately take into account the
safety risks of intentional attacks on Indian Point 2
or 3 or their spent fuel pool. These attacks are
reasonably foreseeable and indeed, have been addressed
to some degree by the NRC. One final point and then I have a quick
comment and I'll wrap up here. Entergy grossly miscalculates the
radiological consequences in performing its SAMA
analysis. Specifically, Entergy significantly
underestimated off site costs resulting from a severe
accident at Indian Point in three ways:
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 (1) They used a source term that resulted
in unusually mean off site accident consequences in
comparison to results obtained with source terms
vetted by independent experts and actually recommended
for use by the NRC, and; (2) Failing to adequately consider the --
in its consequence calculations resulting from
meteorological variations, and; (3) Inappropriately using the $2000 per
person rem dose conversion factor. Due to such underestimation, Entergy has
significantly under estimated the off site cost of
severe accidents. Entergy's erroneously low cost
estimate has therefore led it to underestimate the
benefits of SAMAs that mitigate or avoid the
environmental impact of severe accidents. And this particular aspect of our SAMA
challenge is supported an additional expert report. And that concludes most of my
presentation. I just want to make a couple of
comments based on some things I heard this morning on
the phone. First, in the discussion of the spent fuel
pool Indian Point 2's spent fuel pool leak. I just
would like to note for the Board's attention that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 there were actually two large plumes of contaminated
ground water that are now on the site. One is
primarily a tritium plume, I believe, originating from
the Indian Point 2 pool. It underlies a large portion
of the site between the IP2 pool and the Hudson River.
And actually this contaminated water is presumed to
be leeching into the Hudson. In addition, there is a large plume of
groundwater contaminated with strontium-90, cesium-137
and nickel-63 and other radionuclides that originated
from the Indian Point 1 pool. That pool, as Don Mayer
explained to you, has been drained the source of that
leak presumably has been eliminated. However, the
residual contamination remains in the groundwater and
remains on the site. Just so you have a full picture
of extent of contamination there. And that plume is
additionally leaking into the Hudson River through the
groundwater and up into the water table. Riverkeeper would list to ask the Board
respectively that if and when Entergy submits revised
calculations regarding the CUF calculations for metal
fatigue, we would like the opportunity to present our
critique or our response to that calculation to the
ACRS. And we would have our expert do that, of course.
So we would just like to lodge that request with the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ACRS at this time. That concludes my comments. Thank you very
much. CHAIR MAYNARD: Okay. I'd like to thank
you for your comments. And we were and have been
taking notes on what you said. We did copies of the
documentation that you had provided to us. And relative to future meetings or future
consideration we have of this or any of the other
items, you'll certainly have an opportunity to provide
your comment before we make any final decisions. Our
meetings will all be public meetings. So you will have
an opportunity if you choose to to comment on
information relevant to license renewal at that time. MR. MUSEGAAS: Okay. Thank you. Can I ask you a quick question just
procedurally? If you don't mind, I'll be very quick. Are you -- CHAIR MAYNARD: One of the advantages that
we have is that we don't have -- MR. MUSEGAAS: --going to have additional
Subcommittee meetings or are you going to a full
Committee at the next stage? CHAIR MAYNARD: I'm sorry. I can't answer
that right now.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. MUSEGAAS: Okay. CHAIR MAYNARD: We will have further
discussion with the full Committee and we'll decide
what our next actions are. No matter what we decide
to do before there is another meeting or any other
activity, there would be public notice and the
knowledge of that would be made public well in advance
of it there. So I can't answer what our next step will
be because that will have to be a full Committee
decision. So can't answer that right now. MR. MUSEGAAS: I see. Thank you. CHAIR MAYNARD: And one of the advantages
we have is we gather information. At this point we
don't have to answer any. MR. MUSEGAAS: That puts in a good
position then? CHAIR MAYNARD: Okay. Well, thank you
very much for your comments. MR. MUSEGAAS: Sure. CHAIR MAYNARD: And again, you will have
an opportunity when we meet on this again to provide
comments relative to this issue. So again, thank you
very much. MR. MUSEGAAS: Thank you, Mr. Maynard.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CHAIR MAYNARD: Okay. What I'd like to do
now is to go around the room. I think the focus needs
to be we've talked about these individually, one more
time what items before we meet again, whether it be
another subcommittee meeting, full Committee meeting, whatever, as to what additional items -- you know what
things do we need to see some information and stuff
on. We've talked about some of these. I'll kind of go over my list from what I
heard. Charlie, you had asked for some information on
the FAC program and what they did, maybe specifically
for this items in the audit report there. MEMBER BROWN: Yes. CHAIR MAYNARD: Sam Armijo had asked about
the buckling and the condition of the concrete
underneath it and how that was determined. MEMBER BROWN: That's the feed break. CHAIR MAYNARD: Where you had the feed
break there. John, you'd asked about the temperature
analysis, what if those bits were plugged on that
cooling system there. You asked for plume data from the spent
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 for the integrated leak rate testing. And three of the key issues that we talked
about here that need a little more discussion in the
record: Cavity leakage both from the applicant and
the staff. I know that's an ongoing review and stuff, but I think that's something that several of us felt
nervous that we would need to see more information, more specific information relative to that; Spent fuel pool for IP2. More information
on that and where the plume data and stuff comes into
play, and; That the aux feed pump room fire, you
know, different between 2 and 3 and does the fire
suppression system, is that enough to qualify for not
having to have the aging effects in there. Let me go around and see if there's
anything else that the members -- John, I'll start
with you. Are there any others? MEMBER STETKAR: No, I don't, Otto. I'm
quickly looking at my notes here. And I think that -- CHAIR MAYNARD: This doesn't have to be
your last chance. Because if we think of something
later, we'll get it to you, Kimberly. And I'll also
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 able to stay for this portion and see if there's some
other items to focus on. MEMBER BROWN: The aux feed system thing, continuous use you didn't mention. MEMBER RAY: Yes, he did mention that. MEMBER BROWN: He did that. Okay. MEMBER RAY: He mentioned it in the
context of fire protection. MEMBER BROWN: Okay. All right. MEMBER STETKAR: Just to make sure, and
this is a question to you, Otto, or perhaps Peter, or
I'm not sure. With respect to what we just heard about
the SAMA concerns, we typically as a Subcommittee
don't review -- that's all part of the environmental
impact report submittal and that's not within our
scope of review, is that correct? CHAIR MAYNARD: Right. We get that
information to look at it, but -- MEMBER STETKAR: But it's simply
information. The only reason I was concerned about
that is because of my PRA background. A lot of the
contentions that are raised, kind of go over into the
risk assessment area. And we don't normally comment or
question about those issues for the license renewal
process.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CHAIR MAYNARD: That has its own process
there that it goes through there. MEMBER STETKAR: Okay. I just wanted to
make sure of that because that's something that I
looked at. CHAIR MAYNARD: And as an individual if
you have comments or input on that, you can certainly
provide that to the staff for their consideration. MEMBER BROWN: Well, you covered my items.
I had one other, I guess, enquiry or thought relative
to the ground monitoring. Do they provide one of those
little, you know, boundary plots to show where the
tritium. You hear all the words and everything, but a
little plat picture that shows a line going around
that says what the concentrations are. I don't know-- MEMBER RYAN: I think we got agreement
that we're going to get some additional information. (Whereupon, simultaneous discussions.) MEMBER RYAN: I was just trying to get a
better understanding pictorially for my visually
oriented mind growing up in the television age. CHAIR MAYNARD: One other question for
you, Charlie. I think that the staff has offered
this, you know, put a little information together on
the embrittlement and the Charpy V test, the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 requirements and stuff there -- MEMBER BROWN: Okay. CHAIR MAYNARD: -- and the program for
that. MEMBER BROWN: Yes. As long as it's not
5,000 pages. If it's kind of crisp summary, a page and
half. I don't know. Something that's reasonably
readable in my lifetime. CHAIR MAYNARD: Okay. Harold? MEMBER RAY: I'm not -- I wouldn't express
the issue as leakage, but I think what you're
intending I agree with, which is any challenge to
structural adequacy arising as a result of the
leakage. MEMBER BROWN: Right. MEMBER RAY: That issue, the sufficiency
of the sampling that's been done to establish that
that's not a problem, is it even possible to eliminate
it as an issue merely by sampling, perhaps analysis
would be more fruitful. And then I guess you and John had an
exchange there about the issues that were raised by
the gentleman on the phone link right now. I guess I
need some tutorial on that subject matter. I mean, I
can't imagine us duplicating a process that's already NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 underway at the SLB, for example. But on the other
hand, I'm not sure how we process it. And the
business about well it's not something that we take
into account may well be correct excerpt as input that
we receive. But I guess I'm just feeling at this
point, Otto, that I need a little more education about
how we deal with the number of things that were
brought to our attention there as concerns. This I don't think is the right time or
place to do it. Maybe the full Committee discussion is
the right place. I'm not sure. CHAIR MAYNARD: Okay. MEMBER RAY: But that's the thing I would
add to what's been said so far. I just need more
education about how do we process that input. CHAIR MAYNARD: Yes. And I think the full
Committee would be a good place we can kind of talk
about that a little bit. And the bottom line by any
input that we get from the public gets considered, we'll take a look at what is within our scope.
Anything else, you know, the staff has heard this and
we can always refer things to the staff instead of -- MEMBER RAY: Exactly. CHAIR MAYNARD: It's not that there's a
box here and anything outside of that gets ignored.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 It's just a matter of what we consider versus what's
considered through another process. MEMBER RAY: Well, it would take quite a
bit for us to step through that again. And I just
wanted to put that on your list of to-dos. Because I
do feel that we do need to digest it and discuss it to
see what we should be doing. CHAIR MAYNARD: Okay. MR. TURK: At the risk of volunteering, sir. CHAIR MAYNARD: Come to a microphone. MR. TURK: I'll probably follow the advice
or I'll fail to follow the advice of never volunteer. CHAIR MAYNARD: Could you give your name. MR. TURK: My name is Sherwin Turk. I'm a
lawyer in the Office of General Counsel, and I'm
working with the staff on the Indian Point license
renewal review. Matters that were raised by Riverkeeper
before the licensing board were looked at by the
Board. They reached a decision on whether the issue
should be admitted or not. Their decision is subject
to appeal and review by the Commission directly. At the same time, any comments that
Riverkeeper has on the draft EIS, the draft NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 supplemental EIS which the staff issued, would be
looked at by the staff before issuing the final EIS.
They'll be addressed in the final EIS. And, again, the
EIS itself will be part of the record that the
Commission considers it reaches a decision on
licensing. So there is this twofold process for
considering environmental concerns. MEMBER RAY: But I don't know that that
answers the question what cognizance should we take
it. I mean, that's hopeful but not dispositive, I
don't think. MR. TURK: Yes. I'd have to leave that up
to ACRS' own counsel. MEMBER RAY: Right. CHAIR MAYNARD: And again, I think you're
talking from discussion of the full Committee meeting
there. So, yes. Okay.
Mike? MEMBER RYAN: I think the issue of the
groundwater we've touched on enough. And to me it's
one where there might be some insights developed and
gained by looking at the data in terms of what the
behavior of a leakage is rather than any other
environmental assessment beyond that.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 So I think from the plant renewal
standpoint it's useful for us to hearing more about
that with regard to the renewal questions more than, you know, some of the other questions that we were
raising on the forum. So I'm happy we'll take a look
at that. CHAIR MAYNARD: One other item. I think
when I was reading the introductory remarks, I think I
left a sentence out. I think I failed to identify that
Peter Wen wa the Designated Federal Official for the
meeting here. So get that on the record. We did have
one. Okay. I'd like to thank everyone for
their presentations, the applicant, the stuff. I
appreciate the public comments from Riverkeeper. We will take all these comments and items
and factor those into our further review. And have
discussions at the full Committee meeting to determine
what our next step for us would be. But I think we've
provided you with some of the key things that we think
we certainly need to focus on. And that doesn't mean
that there might be other issues that will come up and
or when come time for another meeting, that we have
different questions. But at least these are things
that I think are the top of our minds right now.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 So, with that, I don't know, Brian, did
you have any closing remarks? MR. HOLIAN: No. I just have a couple of
comments and it's just quickly just a couple of
process takeaways that I took from some of the
questions. And I just wanted to mention that I had
one comment about the reactor cavity leakage that's
applicable. One, on the question of RAIs or requests
for additional information on feed reg valves. I take
that as a process issue that we've been looking at in
license renewal for when we ask a specific question
about one plant, say IP2 or 3, that we also are open
ended enough to ask the utility to address, you know, the difference in the COB on that. So I do understand
that. And we would expect the utility if there was an
issue related to the application, to pick that up
also. But I take that as a process improvement for us. The second item was a discussion on
operating experience and the issue of what you look at
now vice what you look at for a program to be and to
come. I do just mention that we do have a couple of
plants this year entering the extended period. And
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 into account. So I think the question was more of
whether they're doing it now or whether they're saving
up their operating experience to apply it to the
program at the right time. But that will be an item
that we'll check on in our process for ensuring they
do that. The last comment I had was just briefly on
reactor cavity leakage. We will get a bigger
discussion of that both from the staff and the
applicant. But I will mention that the ACRS will
probably hear Prairie Island. I don't know when that
Subcommittee meeting is, but we had a public meeting
with them just Monday of this week on reactor cavity
leakage similar to what you heard discussed here today
at the Prairie Island plant. So more to come on that
one. CHAIR MAYNARD: And Harold reminded me we
do need to emphasize, like on the leakage, it's not so
much the leakage as what's the safety significance of
that and what's -- MR. HOLIAN: That's exactly right. And a
last plug for some of the some of this operating
experience that was looked at at Indian Point. You
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 for not including enough operating experience. And we
are looking to make sure that the GALL items, especially in the concrete items that you heard about
today, whether we have the applicable items in there
for aging effects. So that we look at that as a
success story as the staff's been pulsing some of
those areas. CHAIR MAYNARD: Fred, did you have any
closing? MR. DACIMO: Yes. Fred Dacimo. One technical item that we'd like to
address before we just wrap it up. MR. AZEVEDO: Again, my name is Nelson
Azevedo. Some question this morning as to what the
temperature was for the reactor vessel heads at both
units. The temperature is 592 degrees for both units. MR. DACIMO: We appreciated this
opportunity to speak to the ACRS this morning and this afternoon. I think the questions were insightful.
And we will certainly address all the issues at
however the ACRS decides what venue they want to have
this meeting the next time. And we're looking forward
to that. That's all I've got.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CHAIR MAYNARD: All right. If nobody has
anything, we will adjourn the meeting. Thank you very much. (Whereupon, at 3:42 p.m. the meeting was
adjourned.)
1 Indian Point Energy Center Indian Point Energy Center ACRS License Renewal Subcommittee March 4, 2009 2 Joe PollockVice President, Site -IPFred DacimoVice President, License Renewal -IP John McCannDirector, Licensing Don MayerDirector, Emergency Planning Rich BurroniManager, Programs and ComponentsGarry YoungManager, License RenewalTom McCaffreyManager, Design Engineering John CurryProject Manager, License Renewal -IPMike StroudProject Manager, License Renewal Alan CoxTechnical Manager, License RenewalBob WalpoleManager, LicensingRich DrakeSupervisor, Civil/Structural Engineering Nelson AzevedoSupervisor, Code Programs Indian Point Energy Center Indian Point Energy Center Personnel in Attendance Personnel in Attendance 3*Background*Operating History*Major Plant Improvements*Scoping Discussion*Application of NUREG-1801*Commitment Process*Topics of Interest*Questions Agenda 4 IPEC Site Description*Westinghouse NSSS UE&C (AE) -WEDCO (Constructor)*IP2 -Westinghouse low pressure turbines, Siemens HP turbine, GE generator*IP3 -ABB low pressure turbines, Siemens HP turbine, Westinghouse generator*PWR, large dry containment*3216 MW thermal power1078 MWe-IP2, 1080 MWe-IP3*Once-through cooling from Hudson River*IP2 dual speed circulating water pumps with Ristrophscreens*IP3 variable speed circulating water pumps with Ristroph screens*Staff complement: approximately 1100 5 Indian Point Unit 2*Construction permit October 14, 1966*Operating license September 28, 1973*Commercial operation August 1, 1974*Upratedpower licenses 11.4% (3071 MWt) March 7, 1990 1.4% (3114 MWt)
May 22, 20033.26% (3216 MWt)October 28, 2004 IPEC Operating History 6 Indian Point Unit 3*Construction permit August 13, 1969*Operating license December 12, 1975*Commercial operation August 30, 1976*Upratedpower licenses10.0% (3025 MWt) August 18, 1978 1.4% (3067 MWt)
November 26, 20024.85% (3216 MWt) March 24, 2005 IPEC Operating History IPEC Operating History 7 IPEC Operating History IPEC Operating History License Transfers*IP3 Con Edison to NYPADecember 24, 1975
- IP3 NYPA to EntergyNovember 21, 2000*IP2 Con Edison to EntergySeptember 6, 2001*LR application (IP2 & IP3)April 23, 2007*Operating license expires -IP2 September 28, 2013-IP3 December 12, 2015 8 Major Improvements Major Improvements Indian Point Unit 21978One additional station battery and inverter1981Fan cooler unit heat exchangers One additional station battery and inverter1982Rebuilt control room with human factors and new computers1985Dual speed circ pumps & Ristrophscreens 1990 Main generator 1995 Titanium condenser1996Implemented 24 month fuel cycle1997Converted to best estimate LOCA analysisReplaced NaOHspray additive with TSP baskets in containment 9 Major Improvements Major Improvements Indian Point Unit 2 (cont) 1998 Low pressure turbines1999Autocatalytic hydrogen recombiners 2000 Steam generatorsFeedwaterheaters Converted to alternate source term 2004 High pressure turbine Moisture separator reheaters 2006 Main transformers Containment sump improvements 2008 SBO / Appendix R diesel generator 10 Major Improvements Major Improvements Indian Point Unit 319814 th battery charger / inverter1982Two new fire water tanks and pumps1983Fan cooler unit heat exchangers1984SBO / Appendix R diesel generator1985Variable speed circulating water pumps1986Rebuilt control room with new computers and human factors One main transformer 1987 Titanium condensers 1989 Steam generators Condensate polishing system and blowdown recoveryFeedwaterheaters 11 Major Improvements Major Improvements Indian Point Unit 3 (cont) 1993 Low pressure turbines1995Implemented 24 month fuel cycle 1997 Thermal hydrogen recombiners2003Converted to best estimate LOCA analysis 2005 High pressure turbine Moisture separator reheaters Converted to alternate source term 2007 Second main transformer Containment sump improvements 2008Sodium tetraboratebaskets 12 Major Improvements Major Improvements Site1987 Training building1997 Water treatment facility2005 Generation support building2007 Dry fuel storage IP1 -160 fuel assembliesIP2 -96 fuel assemblies2008 E-plan siren systemPlanned Emergency operations facility 13 IPEC Plant Status IPEC Plant Status Current Plant Status*Both units on-line at full power-IP2 continuous days on line -274-IP3 continuous days on line -672*Next outages -Spring 2009 (IP3)-Spring 2010 (IP2) 14 Indian Point Energy Center 15 IPEC Generation 16 LRA Development*Incorporated lessons learned from previous applications*Peer review conducted -NEI and other utilities*LRA internal reviews (Safety Review Committees and QA)*LRA prepared by experienced, multi-discipline Entergy team (utilized corporate and on-site resources)*All comments resolved prior to submittal IPEC License Renewal Project IPEC License Renewal Project 17 Application of NUREG-1801 Aging Management Reviews*Aging management reviews consistent with guidance in NEI 95-10*Aging management review results achieved good consistency with NUREG-1801*90% of AMR line items used notes A -E (consistent with NUREG-1801, Rev 1) 18 Application of NUREG-1801 Aging Management Programs*41 aging management programs-31 existing programs-10 new programs*NUREG-1801 / plant-specific breakdown-8 plant-specific programs -33 NUREG-1801 programs*8 with exceptions to NUREG-1801 19*License renewal commitments (38)-Refined during audit / inspection process-IP commitment management process*Commitment management process established consistent with industry guidance*Entergy periodically inspects commitment management process Commitment Process 20 Fleet Approach*Employing fleet approach to implementation for Entergy plants that have submitted an LRA*License renewal implementation fleet manager and site coordinator in place*Develop schedule for Entergy plants as renewed licenses approved*Several common fleet implementing procedures are being developed for Entergy plants Implementation 21 SER Open Items SER Open Items Item StatusIP2 Fire Protection -yard hose houses and chamber housings ReadyIP2 & IP3 Main FeedwaterSystem -stop valves ReadyIP2 Auxiliary FeedwaterPump Room Fire Event ScopingReady Electrical and Instrumentation & Control Systems -SBO scopingNRC reviewFire Protection Program -inaccessible fire barrier penetration sealsReady Structures Monitoring Program -
IP2 reactor cavity NRC review Structures Monitoring Program -
IP2 spent fuel poolNRC review 22 SER Open Items SER Open Items Item StatusContainment InserviceInspection -
containment concrete aging mgmtNRC reviewHeat Exchanger Monitoring -visual inspection criteria ReadyInserviceInspection Program -Lubrite sliding supportsReady InserviceInspection Program -
ASME Code Section XI ReadyNickel Alloy Program -program clarificationReadyInserviceInspection Program -
CASS componentsReadyService Water System -material / environment clarificationReady 23 SER Open Items SER Open Items Item StatusPeriodic Surveillance and Preventive Maintenance -program elementsReadyAuxiliary FeedwaterPump Room Fire Event -aging management NRC review Containment Structures -
water-cement ratios NRC reviewConcrete Structures -Aging management of concrete subject to elevated temperaturesNRC review Structures and Component Supports -Groups B1 -B5 supports ReadyClass 1 Fatigue -IP3 heatupand cooldowntransientsReady 24*Remaining Open Items-OI 2.5.1SBO scoping-OI 3.4-1AMR results for systems used during auxiliary feedwaterpump room fire-OI 3.0.3.2.15-1IP2 reactor refueling cavity structure-OI 3.0.3.2.15-2IP2 spent fuel pool structure-OI 3.0.3.3.2-1Exterior c ontainment concrete aging management-OI 3.5-1Water-cement ratio for concrete-OI 3.5-2Aging management of concrete subject to elevated temperatures
- Other Topics of Interest-Reactor vessel integrity-Buried piping aging management program-IP2 containment liner -1973 feedwaterevent Topics of Interest 25 SBO ScopingOI 2.5-1SBO Scoping*SBO scoping for IP2 and IP3 meets the requirements of 10 CFR 54.4(a)(3)*The LR SBO recovery boundary is in accordance with the NRC guidance (NUREG-1800, Section 2.1.3.1.3 and 2.5.2.1.1)*The LR SBO recovery boundary is also in accordance with the proposed NRC guidance in LR-ISG-2008-01 (Draft issued 3/5/2008)*Both primary and alternate sources of offsite power are included for SBO re covery for IP2 and IP3 26IP2 Auxiliary FeedwaterPump Room Fire EventOI 3.4-1Component Aging Management*Secondary systems credited for alternate flow path to steam generators for a period of one hour in the unlikely event of fire in the room*Normal plant operation directly demonstrates ongoing ability of the identified systems to perform license
renewal intended function*RAI requested additional detail on component types credited and aging management*Provided requested information in letter dated January 27, 2009 27 Structures Monitoring ProgramOI 3.0.3.2.15-1IP2 Reactor Refueling Cavity Structural Integrity*Stainless steel liner leakage occurs only during refueling outages since late 1970s. Corrective actions implemented with mixed results *Evaluation of concrete samples concluded concrete and rebar behind the cavity lining remain capable of
performing license renewal intended function*New processes being researched to repair leaks in the reactor refueling cavity liner*Aging management includes SMP inspections, core bore sample of concrete and inspection of rebar 28 Structures Monitoring Program 29 Structures Monitoring ProgramOI 3.0.3.2.15-2IP2 Spent Fuel Pool*Pool liner leakage first identified and repaired in 1992*2005 during excavation for dry fuel storage, an exterior shrinkage crack in concrete wall was found*2007 liner leak found and repaired in transfer canal*Structural evaluations concluded that the concrete and rebar remain capable of performing license renewal intended function *Aging management includes SMP inspections, SFP level monitoring and monitoring of groundwater near SFP exterior wall 30 Structures Monitoring Program IP2 Spent Fuel Pool 31 Structures Monitoring ProgramOI 3.0.3.3.2-1Exterior Containment Concrete Aging Management *Isolated areas at Cadweldjoints of rebar and at attachment points used for scaffolding during construction-First documented during the initial IWL inspection in 1995*Evaluation of structural impact -reinforcing steel provides most of the strength, observed surface degradation has no impact on ability of containment to perform its intended function*Areas are monitored by Structures Monitoring Program *Commitment for program enhancement to better characterize observed degradation through the use of optical aids for improving trending capabilities 32 Structures Monitoring ProgramOI 3.5-1Water-Cement Ratio for concrete*NUREG-1801 identifies aging effects for concrete in outdoor air environment *Recommends evaluation considering water-cement ratio*IPEC water-cement ratios for concrete are outside NUREG-1801 recommended range*ACI 318-63, original design spec for IPEC, provides two methods to determine the required concrete strength*IPEC used method 2 for testing of concrete mixtures for containment concrete*IPEC actual test reports conf irm the compressive strength of concrete was above the required 3000 psi of ACI 318-63 33 Structures Monitoring ProgramOI 3.5-2Aging management of concrete subject to elevated temperatures*Concern that IP2 hot piping pen etrations are allowed to operate at temperatures greater than 200 o F*NUREG-1801 allows local area concrete temperature greater than 200 oF with a plant specific evaluation*IP2 plant specific evaluation fo r the effects of temperatures up to 250 o F was performed*Engineering evaluations determined that a maximum of 15% reduction in the strength of concrete for temperatures up to 250 o F*Concrete tests showed actual strengths more than 20% above design strength of 3000 psi 34 Topic of Interest IP2 Reactor Vessel Integrity*Vessel was manufactured by Combustion Engineering*Limiting Upper Shelf Energy (USE) location is Plate B2002-3 at 48.3 ft-lbs. Although less than the Appendix G screening criteria of 50 ft-lbs, it exceeds th e 43 ft-lbs required by the WOG equivalent margin analysis. *Limiting RT PTS location is circ weld 34B009 at 269.4 o F which is less than the screening criteria of 300 o F.
35 Topic of Interest IP3 Reactor Vessel Integrity*Vessel was manufactured by Combustion Engineering*Limiting Upper Shelf Energy (USE) location is Plate B2803-3 at 49.8 ft-lbs. Although this is less than the Appendix G screening criteria of 50 ft-lbs, it exceeds the 43 ft-lbs required by the WOG equivalent margin analysis. *Limiting RT PTS location is plate B2803-3 at 279.5 o F which exceeds the screening criteria of 270 o F.*As required by 10CFR50.61, IP3 will submit a plant-specific safety analysis at least three years prior to exceeding the screening criterion 36 Topic of Interest Buried Piping Aging Management*For license renewal, IP is committed to NUREG-1801 program Section XI.M34*Program includes consideration of operating experience*An inspection in Fall of 2008 examined six pipe sections (i.e. three sections at each of two locations)*Inspections revealed some coating degradation. Pipe wall thickness was measured with UT*UT indicated that the piping remains at full thickness.*The coating was repaired and the holes were backfilled.
37 Topic of Interest Buried Piping Aging Management*Recent underground leakage in an 8"condensate line due to external corrosion which led to a through-wall defect.*The location was excavated, the areas of concern were repaired or replaced and the line was
returned to service.*A failure analysis is on-going on the removed section of piping to establish additional inspection
scope as well as future re-inspection frequency.*This operating experience is being reviewed to establish the scope and frequency of future buried
pipe inspections.
38 Topic of Interest IP2 Containment Liner1973 FeedwaterEvent*November 1973 -plant trip from 7% power*Flashing steam impinged on the containment liner causing a bulge to develop*Piping was repaired, other modifications made, and liner deformation restored leaving a slight permanent deformation*During last outage, 2008, visual inspection confirmed liner still in "as-left"configuration*Continuous weld channel pressurization and ILRTsconfirm liner integrity*Commitment made to perform a one-time visualinspection prior to entering the period of extended operation 39 Comments and Questions Advisory Committee on Reactor Safeguards License Renewal Subcommittee Indian Point Nuclear Generating Unit Nos. 2 and 3 Safety Evaluation Report with Open Items March 4, 2009 Kimberly Green, Project Manager Office of Nuclear Reactor Regulation 2 Introduction*Overview*Section 2: Scoping and Screening Review*License Renewal Inspections*Section 3: Aging Management Program and Review Results*Section 4: Time-Limited Aging Analyses (TLAAs)*Open Items 3*LRA Submitted by letter dated April 23, 2007*Westinghouse 4-Loop*3216 MWth, 1080 MWe*Operating license DPR-26 (IP2) expires September 28, 2013*Operating license DPR-64 (IP3) expires December 12, 2015*Located approximately 25 miles north of NYC limits Overview 4*Safety Evaluation Report with Open Items was issued January 15, 2009*20 Open items*121 RAI'sIssued*272 Audit Questions*38 Commitments Overview 5*Scoping and Screening Methodology Audit-October 8, 2007 -October 12, 2007*Aging Management Programs (AMP) Audit-August 27, 2007 -August 31, 2007*Aging Management Review (AMR) & Time-Limited Aging Analysis (TLAA) Audit-October 22, 2007 -October 26, 2007-November 27, 2007 -November 29, 2007-February 19, 2008 -February 21, 2008*Regional License Renewal Inspections-January 28, 2008 -February 1, 2008-February 11, 2008 -February 14, 2008-March 31, 2008 -April 2, 2008-June 2, 2008 -June 6, 2008, and June 18, 2008 Overview 6*SER issued with 20 open items-14 with requests for additional information-6 are still under review by staff*Applicant submitted additional information dated January 27, 2009*Staff can close out 13 Open Items Open Items 7Section 2.1 -Scoping and Screening Methodology*Based on audit and review staff concluded that the applicant's methodology is consistent with the requirements of 10 CFR 54.4 and 54.21(a)(1)Section 2.2 -Plant-Level Scoping Results*IP2 chlorination and IP3 H 2 systems initially omitted from scope*Staff concluded applicant identified mechanical systems and structures within the scope of license renewal per
Section 2: Structures and Components Subject to Aging Management Review 8Section 2.3 -Scoping and Screening Results:
Mechanical Systems*Mechanical Systems: 59 (IP2 ) and 87 (IP3)*Two Tier Review of Balance of Plant systems: -Tier 1 Review: Review LRA and UFSAR-Tier 2 Review: Detailed review of LRA, UFSAR, and license renewal drawings*100% of mechanical systems identified by applicant as within the scope of license renewal were reviewed 9Section 2.3 -Scoping and Screening Results:
Mechanical Systems*Staff identified omission of nonsafety-related components from scope for IP2 containment spray system*Applicant re-evaluated and identified 3 other systems (IP2 CCW, IP3 CCW, and IP3 BVS)*Amended LRA and added components to scope 10Section 2.3 -Scoping and Screening Results Mechanical Systems*Three Open Items-OI 2.3A.3.11-1 -yard hose houses and chamber housings-OI 2.3.4.2-1 -feedwaterisolation valves-OI 2.3A.4.5-1 -auxiliary feedwaterpump room fire event systems*These OIscan be closed 11Section 2.4 -Scoping and Screening Results:
Structures*Staff concluded that there were no omissions of structures or structural components from scope of license renewal in accordance with 10 CFR
54.4(a), and no omissions from AMR in accordance with 10 CFR 54.21(a)(1).
12Section 2.5 -Scoping and Screening Results:
Electrical and Instrumentation and Control Systems*OI 2.5-1 -Station blackout scoping*Issue is under staff evaluation*With exception of SBO OI scoping, staff concluded no omissions of electrical and
instrumentation and control system components
from the scope of license renewal in accordance
with 10 CFR 54.4(a), and no omissions from
AMR in accordance with 10 CFR 54.21(a)(1) 13Section 2.6 -Conclusion for Scoping and Screening*The applicant's scoping and screening methodology is consistent with the requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1)*With exception of open items, the applicant adequately identified those SSCswithin the
scope of license renewal in accordance with 10 CFR 54.4(a), and those SCssubject to an AMR
in accordance with 10 CFR 54.21(a)(1).
License Renewal Inspections Glenn Meyer Region I Inspection Team Leader 15 Inspection Objectives*Scoping of Non-safety SSCs*28 Aging Management Programs (AMPs)*2 Systems: Auxiliary Feedwater; IP2 SBO diesel generator (DG)*Followup: IP2 SBO DG, electrical cable vault, and containment liner 16 Scoping*Scoping of non-safety SSCs-generally accurate and acceptable*Structural and spatial interactions reviewed*AMP reviews found 2 component scoping errors 17 Aging Management Program Review Resolved by LRA Amendment 3:*Structural Monitoring*Oil Analysis*Diesel Fuel Monitoring*Water Chemistry*Metal-Enclosed Bus Inspection 18 Aging Management Program Review Resolved by LRA Amendment:*Selective Leaching*Non-EQ Bolted Cable Connections Resolved by LRA Commitment 37:*Exposed rebar on containment exterior 19 Aging Management Program Review Resolved Onsite:*Metal-Enclosed Bus Operating Experience *Instrument air heat exchangers*AMR for transitematerial*Condition Reports on isolated degradation 20 Follow Up Inspections*IP2 SBO diesel -scoping and system review when operational*Electrical cable vault -when accessible*Unit 2 containment liner -when accessible 21 Inspection Conclusions*Non-safety SSC scoping and aging management programs are acceptable.*Inspection results support a conclusion of reasonable assurance that aging effects will be managed and intended functions will be maintained 22 Current Performance*Both units -Licensee Response Column*All Findings -Green*All Performance Indicators (PIs) -Green 23 Section 3: Aging Management Review Results*Section 3.0.3 -Aging Management Programs*Section 3.1 -Reactor Vessel & Internals*Section 3.2 -Engineered Safety Features*Section 3.3 -Auxiliary Systems*Section 3.4 -Steam and Power Conversion System*Section 3.5 -Containments, Structures and Component Supports*Section 3.6 -Electrical and Instrumentation and Controls System 24Section 3.0.3 -Aging Management Programs (AMPs)*41 AMPs-10 New Programs-31 Existing Programs*15 consistent with GALL Report*10 consistent with GALL Report with enhancements*8 with exceptions to GALL Report*8 plant-specific 25Section 3.0.3 -AMPs*8 Open Items*The following 5 OIscan be closed-OI 3.0.3.2.7-1 -fire penetration seals-OI 3.0.3.3.3-1 -acceptance crit eria for visual examinations-OI 3.0.3.3.4-1 -inspection methods, etc. for lubritesliding supports-OI 3.0.3.3.4-2 -corrective actions for ISI-OI 3.0.3.3.7-1 -Periodic Surveillance and Preventive Maintenance Program 26Section 3.0.3 -AMPs*The following 3 OIsare still under review-OI 3.0.3.2.15-1 -IP2 reactor refueling cavity leakage-OI 3.0.3.2.15-2 -IP2 spent fuel pool leak-OI 3.0.3.3.2-1 -Exterior containment concrete degradation 27Section 3.1 -Aging Management of Reactor Vessel, Internals, and RCS*2 Open Items-OI 3.1.2-1 -Nickel alloy components-OI 3.1.2.2.7-1 -Inspection of CASSThese 2 OIscan be closed 28Section 3.3 -Aging Management of Auxiliary Systems*One Open Item-OI 3.3-1 -Clarification of material/environment/aging effect for titanium components This OI can be closed 29Section 3.4 -Aging Management of Steam and Power Conversion Systems*One Open Item-OI 3.4-1 -AMR results for components needed during a fire in IP2 auxiliary feedwaterpump room This OI is still under staff review 30Section 3.5 -Aging Management of Containments, Structures and Component Supports*3 Open Items*The following 2 OIsare still under staff review-OI 3.5-1 -Water-cement ratio for IP concrete-OI 3.5-2 -Reduction of strength and modulus of concrete due to elevated temperatures 31 Section 3.5 -
Aging Management of Containments, Structures and Component Supports*The following OI can be closed-OI 3.5-3 -Aging management of concrete surrounding B1 supports 32 Section 3.6 -
Aging Management of Electrical and I&C Systems*LRA identified no aging effects for IP2 138-kV high-voltage cable*Staff issued RAI*Applicant amended LRA to add cable to Periodic Surveillance and Preventive Maintenance Program 33Section 3.7 -Conclusion With the exception of the Open Items, the applicant has demonstrated that aging
effects will be adequately managed during
the period of extended operation in
accordance with 10 CFR 54.21(a)(3) 34*4.1 Identification of Time Limited Aging Analyses (TLAAs)*4.2 Reactor Vessel Neutron Embrittlement*4.3 Metal Fatigue*4.4 Environmental Qualification of Electrical Equipment*4.5 Concrete Containment Tendon Prestress*4.6 Containment Liner Plate and Penetration Fatigue*4.7 Other Plant-Specific TLAAs Section 4: Time-Limited Aging Analyses 35% CU48 EFPY Fluence (E>1 MeV) at 1/4T 10 19 (n/cm 2)Initial Charpy V notch USE Value (ft-lb)Irradiated Charpy V notch USE Value at 48 EFPY (ft-lb)
Acceptance Criterion per 10 CFR 50, App. G (ft-lb)0.251.1367448.3>
50 Section 4.2: Reactor Vessel Neutron Embrittlement -Upper Shelf Energy Limiting Beltline Material-Lower Shell Plate (B2002-3)
Unit 2*Equivalent margins analysis submit ted which meets Appendix G of ASME Section XI and 10 CFR Part 50, Appendix G 36% CU48 EFPY Fluence (E>1 MeV) at 1/4T 10 19 (n/cm 2)Initial Charpy V notch USE Value (ft-lb)Irradiated Charpy V notch USE Value at 48 EFPY (ft-lb)
Acceptance Criterion per 10 CFR 50, App. G (ft-lb)0.240.92986849.8>
50 Section 4.2: Reactor Vessel Neutron Embrittlement -Upper Shelf Energy Limiting Beltline Material-Lower Shell Plate (B2803-3)
Unit 3*Equivalent margins analysis submit ted which meets Appendix G of ASME Section XI and 10 CFR Part 50, Appendix G 37%CU%Ni 48 EFPY Fluence (E>1 MeV)(@clad/steel interface) 10 19 (n/cm 2)Initial Charpy RTNDT 0 F RTPTS 0 F Acceptance Criterion per 10 CFR 50.61 0 F 0.24 0.52 1.56 74279.5<270 o F Section 4.2: Reference Temperature for Pressurized Thermal Shock (PTS) ValuesLimiting Beltline Material-Lower Shell Plate(B2803-3)
Unit 3Commitment 32: As required by 10 CFR 50.61(b)(4), IP3 will submit a plant-specific safety analysis for plate B2803-3 to the NRC three years prior to reaching the RT PTS screening criterion. Alternativ ely, the site may choose to implement the revised PTS rule when approved.
38*60-year fatigue analyses were performed for all NUREG/CR-6260 locations, except 2 locations (IP2) and 3 locations (IP3)*Entergy will manage aging for NUREG/CR-6260 locations in accordance with 10 CFR 54.21(c)(1)(iii) (Commitment 33)Section 4.3: Metal Fatigue Analyses 39 Section 4.3 -
Class 1 Fatigue*One Open Item-OI 4.3-1 -Number of IP3 plant heatups and cooldowns This OI can be closed Section 4.3: Metal Fatigue Analyses 40 Open Items Still Under Staff Review*OI 2.5-1 -SBO scoping*OI 3.0.3.2.15-1 -IP2 reactor refueling cavity leakage
- OI 3.0.3.2.15-2 -IP2 spent fuel pool leak
- OI 3.0.3.3.2-1 -Exterior containment concrete degradation*OI 3.4-1 -AMR results for the auxiliary feedwaterpump room event*OI 3.5-1 -Water-cement ratio for IP concrete
- OI 3.5-2 -Reduction of strength and modulus of concrete due to elevated temperatures 41*OI 2.5-1 -SBO scoping-Applicant revised LRA Figures 2.5-2 and 2.5-3, the "Offsite Power Scoping Diagram(s)"for IP2 and IP3 for primary and secondary offsite power paths -By letters dated March 24, 2008 and August 14, 2008, the applicant revised and clarified its response -The staff is completing its review of the applicant's information on the SBO scoping boundary and will
document its conclusion in the final SER 42*OI 3.0.3.2.15-1 -IP2 reactor refueling cavity leakage-IP2 refueling cavity leaks at the upper elevations of the stainless steel cavity liner when flooded during refueling outages-Attempts have been made to mitigate this condition-An action plan is being developed for permanent fix
-Applicant has committed to perform one-time inspection prior to entering period of extended oper ation to confirm absence of degradation (Commitment 36)-Applicant has not identified augm ented inspections for period of extended operation-Staff sent draft RAI to request how the AMP will monitor condition during period of extended operation 43*OI 3.0.3.2.15-2 -IP2 spent fuel pool leak-IP2 spent fuel pool (SFP) has experienced leakage-IP2 SFP does not have leak chase channels
-Applicant committed to test the groundwater outside IP2 SFP every 3 months (Commitment 25)-Applicant does not plan to perform augmented inspections of SFP during the period of extended operation.-Staff sent draft RAI to request how the AMP will monitor this condition during period of extended
operation 44*OI 3.0.3.3.2-1 -Exterior containment concrete degradation-External surfaces of IP2 and IP 3 containments have locations of concrete spalling-Applicant explained that areas of spallingoccur at cadweld sleeves and scaffolding anchor locations-Applicant concluded there is sufficient design margin for exposed rebar-Applicant committed to perform enhanced inspections of containment (Commitment 37)-Staff sent draft RAI requesting information on how the applicantwill use the above within its Containment InserviceInspection Program 45*OI 3.4-1 -AMR results for the IP2 auxiliary feedwater pump room fire event-Applicant stated that systems are continuously in operation and monitored-Applicant stated aging related degradation that occurs during 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> is negligible-Applicant concluded that there are no aging effects; therefore no AMPsare necessary-Applicant provided additional information on January 27, 2009-Staff is still evaluat ing applicant's response 46*OI 3.5-1 -Water-cement ratio for IP concrete-LRA identified the water-ceme nt ratios for IP concrete -Staff identified a discrepancy and asked for clarification-Applicant stated it used Method 2 in ACI 318-63 standard to determine concrete strength-Applicant stated that comp ressive strength > 3,000 psi -Staff sent draft RAI to define water-cement ratios and provide results of original concrete st rength tests. Alternatively, the applicant may identify applicable aging effects and how they will be managed 47*OI 3.5-2 -Reduction of strength and modulus of concrete due to elevated temperatures-LRA stated concrete surroundi ng IP2 penetrations can reach 250 °F-GALL Report recommends further evaluation to manage reduction of strength and modulus of concrete structures due to elevated temperature (>200 °F)-Applicant concluded that reduction of strength and modulus is not an aging effect requiring management-Applicant determined a reduction in strength of 15% from elevated temperatures which is acceptable-Staff sent draft RAI about how strength margin was determined and if reduction in modulus of elasticity was considered. Alternatively, the
applicant may explain how the aging effect will be managed 48 Questions?
SBO RecoveryIP2 Offsite Power Scoping Diagram48 SBO Scoping Buchanan Substation50