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Official Transcript of Proceedings NUCLEAR REGULATORY COMMISSION Title: Advisory Committee on Reactor Safeguards Plant License Renewal Subcommitee Prairie Island Nuclear Generating Station Docket Number: (n/a) Location: Rockville, Maryland Date: Tuesday, July 7, 2009 Work Order No.: NRC-2945 Pages 1-138 NEAL R. GROSS AND CO., INC.
Court Reporters and Transcribers 1323 Rhode Island Avenue, N.W.
Washington, D.C. 20005 (202) 234-4433 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 1 UNITED STATES OF AMERICA 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 NUCLEAR REGULATORY COMMISSION
+ + + + + ADVISORY COMMITTEE ON REACTOR SAFEGUARDS
+ + + + + SUBCOMMITTEE ON THE PLANT LICENSE RENEWAL FOR THE PRAIRIE ISLAND NUCLEAR GENERATING STATION
+ + + + +
TUESDAY, JULY 7, 2009
+ + + + + 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., Harold Ray, Chair, presiding.
SUBCOMMITTEE MEMBERS PRESENT:
HAROLD RAY, Chair
MARIO V. BONACA
SAID ABDEL-KHALIK
WILLIAM J. SHACK
JOHN D. SIEBER
J. SAM ARMIJO
DANA A. POWERS
OTTO L. MAYNARD
JOHN T. STETKAR NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 2 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CONSULTANT TO THE SUBCOMMITTEE:
JOHN J. BARTON NRC STAFF PRESENT:
CHRISTOPHER BROWN, Designated Federal Officer
RICK PLASSE
STU SHELDON
ERACH PATEL
ABDUL SHEIKH
ON YEE ALSO PRESENT:
GENE ECKHOLT
MIKE WADLEY
STEVE SKOYEN
JOE RUETHER
PHIL LINDBERG
RICHARD PEARSON
SCOTT McCALL
TOM DOWNING NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 3 MATTHEW McCONNELL 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 TABLE OF CONTENTS Introductions......................................5
Applicant Presentation.............................9
NRC Presentation..................................85
Subcommittee Discussion..........................129 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 4 1 2 3
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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
INTRODUCTIONS CHAIRMAN RAY: The meeting will now come
to order. This is a meeting of the plant license
renewal sub-committee. I'm Harold Ray, chairman of
the Prairie Island Plant License Renewal Sub-
committee.
ACRS members in attendance are Mario
Bonaca, William Shack, Sam Armijo, Dana Powers, Otto
Maynard, John Stetkar, Jack Sieber, Said Abdel-
Khalik, and our consultant, John Barton. I expect
that member Mike Ryan will join us during the course
of the meeting.
The purpose of this meeting is to review
the application for the Prairie Island Plant License
Renewal, the Draft Safety Evaluation Report, and
associated documents. We will hear presentations from
the representatives of the Office of Nuclear Reactor
Regulation and the applicant, Northern States Power, a Minnesota corporation.
The sub-committee will gather
information, analyze relevant issues and facts, and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 5 formulate proposed position and action as appropriate for deliberation by the full committee.
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9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 The rules for participation in today's
meeting were announced as part of the notice of the
meeting, previously published in the Federal Register
on June 16, 2009. We have not received any requests
from members of the public wishing to make oral
statements.
A transcript of the meeting is being kept
and will be made available as stated in the Federal
Register notice, therefore we request that
participants in this meeting use the microphones
located throughout the meeting room when addressing
the sub-committee. Participants should first identify
themselves and speak with sufficient clarity and
volume so that they can be readily heard.
Somewhere I overlooked the fact that our
designated federal official is Mr. Brown, Christopher
Brown.
We will now proceed with the meeting and
I'll call on Brian Holian of the Office of Nuclear
Reactor Regulation to introduce the presenters.
Brian?
MR. HOLIAN: Thank you. Good morning. My
name is Brian Holian. I'm director of the Division of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 6 License Renewal. To my right is Dr. Sam Lee, deputy director of the Division of License Renewal, and to
his right is Mr. Rick Plasse, the project manager for
the Prairie Island review.
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9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 We have several other branch chiefs from
both technical divisions and license renewal in the
audience and we'll hear probably from some of those
later during the NRC presentation. We would like to
highlight two of the staff or one staff and one
contractor that's also with us today.
First is Dr. Stu Sheldon, who is the
senior rafter inspector from region 3. You'll be
hearing from him on inspection results and he's right
here in the first row.
Secondly, we have a contractor here from
Oak Ridge. That's Dr. Naus. He helped the staff with
a site visit and part of our review on some of the
containment structural issues at Prairie Island.
Just a couple other opening items on the
Prairie Island review. One, the staff does have three
open items that you'll be hearing in part of the
presentation today. Progress is being made on all the
open items.
One was a scoping issue related to the
waste gas decay tank. The second item where the staff NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 7 still -- was more of a timing issue. We still needed to just review the PWR vessel internals program that
they submitted, so that's why that's open.
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9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 The third item was some leakage and water
seepage from a refueling cavity. That's been an item, I think, yes, the committee has heard from on Indian
Point a few months back and is an item we're paying
particular attention to on some of the plants that
have had some historical leakage.
The only other item I'd like to mention
really has two parts, and that's just to note that
Prairie Island is a hearing plant. They are on a
hearing schedule.
There were originally seven contentions
that were admitted. Five of those have been closed.
There were four safety contentions and one
environmental contention that have been closed
through the ASLB process. There's just two
contentions remaining and they're both on the
environmental side of the house, environmental
review.
The last item I'd like to recognize is
that on Prairie Island, we did have a unique
memorandum of understanding that we established with
the Prairie Island Indian community and in NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 8 particular, to get their input on environmental issues surrounding the plant.
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9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 So that's been working well and we've
been working with Prairie Island, both on the
inspection and on the review.
With that, I'll turn it over to the site
vice-president, Mr. Mike Wadley.
CHAIRMAN RAY: Mike, before you begin, I
also failed to introduce our consultant to the sub-
committee, Mr. John Barton. Please proceed.
MR. WADLEY: Thank you, Chair. Gene, I was
going to lead us through the introductions here.
MR. ECKHOLT: Yes. My name is Gene
Eckholt. I'm the project manager for the Prairie
Island License Renewal Project.
I want to thank the committee for the
opportunity to discuss license renewal at Prairie
Island and run through some introductions.
At the front table, we've got Mike
Wadley, the site vice-president and we've got Steve
Skoyen, our engineering program manager.
We've also got a number of license
renewal project team members and subject matter
experts with us today.
At the side table are my four engineering NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 9 supervisor leads for the project. Phil Lindberg, the programs lead. Scott Marty, the mechanical lead, Richard Pearson, the civil structural lead, and Joe
Ruether, the electrical lead.
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9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 We also have Scott McCall, the plant
system engineering manager and from the projects
organization, we have Charlie Bomberger, the vice
president of nuclear projects and Ken Albrecht, the
general manager of major nuclear projects.
Sticking to the agenda, we'll start with
some background information on the plant -- the
operating history, brief information on the plant, major improvements. We'll talk some on the license
renewal project and the methodology we used in
developing the licensure application.
We'll talk briefly about implementation
of license renewal at Prairie Island and the status
of that. Then we will talk on specific items of
technical interest, in particular, the three open
items in the SER.
At this point, I'd like to turn it over
to Mike Wadley.
APPLICANT PRESENTATION MR. WADLEY: Thanks, Gene. Chair, committee members, good morning.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 NSP, Northern States Power - Minnesota is
a wholly owned subsidiary of Xcel Energy and is the
owner and operator of the Prairie Island Nuclear
Generating Plant.
The plant is located on the Mississippi
River southeast of Minneapolis and Saint Paul.
Prairie Island is a two-loop Westinghouse pressurized
water reactor with a thermal output of 1600 megawatts
and a gross electrical production of 575 megawatts
electrical.
Pioneer Service and Engineering was the
plant's architect engineer. Prairie Island has a dual
containment consisting of a steel containment
surrounded by a limited leakage concrete shield
building separated by a five foot annular space.
The ultimate heat sink for the units is
the Mississippi River via our clean water system. The
plant's steam cycle cooling is once-through cooling
supplemented by forced draft cooling towers, which
are used on a seasonal basis to support effluent
discharge per metric requirements.
Construction permits were issued in June
of 1968 and operating licenses were later. One was
issued in August of `73 and unit two in October of
1974. We submitted our license renewal application in NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 11 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 April of 2008.
Both units completed their 25th refueling
outage in 2008. Both units operate on an 18-20 month
cycle. Lifetime capacity factors for the station are
84.2 and 86.5 for units 1 and 2, respectively.
Current cycle capacity factors are 96.6
and 98. Refueling outages are scheduled for unit 1
this fall and next spring, for unit 2.
Some major improvements have taken place
at the station since it began operation. In 1983, we
constructed a new intake screen house and re-
configured our intake and discharge canals. That
allowed us to go to seasonal operation with our
In 1986 and 87, we replaced the reactor
vessel and internals as our response to the split-
pin issues the industry had experienced.
In 1993, we added two new diesel
generators on unit 2 and were able to separate the
safety-related electrical systems on unit 1 and unit
2.
At the same time, to improve operational
flexibility, one of our three non-safeguards or
safety-related cooling water pumps was upgraded to
safety related to provide a backup to the two diesel-NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 12 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 driven cooling water pumps used in the safety related
system.
With that, I'll turn it back to Gene.
MR. ECKHOLT: I want to talk a little bit
about the license renewal project, the development of
the license renewal application, get into the various
phases of the project, and wrap up talking about the
commitment that was made in response to license
renewal.
The license renewal project team was
headed up by four engineering supervisors that are
full time NSP employees. They have extensive plant
knowledge and experience.
In addition to that -- I mean, they had a
lot of plant experience, but they didn't have a lot
of background in license renewal, so coming into the
project, at the time the project started in 2005, we
were part of the Nuclear Management Company.
There were three other active license
renewal projects underway in NMC at that time, so we
used the experience of the other members of the fleet
to help train our folks. We utilized their processes
extensively and used that to beef up our knowledge
and program going into the project.
We also utilized a number of contract NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 13 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 support staff members that all had significant
license renewal experience, both within NMC and at
other plants.
Plant staff, plant subject matter experts
were also very actively involved in the project. They
reviewed a number of the LRA input documents during
the development of the LRA.
They also were very actively involved in
support of the license renewal audits and the region
3 inspection in January.
We also remained engaged with the
industry, mainly through the NEI license renewal
taskforce and the associated working groups.
We also observed audits at a number of
plants, NRC audits at a number of plants and
participated in the peer reviews of other plants'
LRA's as we were developing ours.
Again, our project started in 2005, which
is about the time that NEI 95-10 was brought to Rev
6, so our project's process and procedures were based
on Rev 6 of NEI 95-10. The processes we used were
consistent with the guidance of that NEI document. The boundary drawings that we provided highlighted components for all the scoping criteria.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 One other thing to note is that the switchyard
scoping boundary in the Prairie Island LRA does
include breakers at the transmission system voltage.
MR. BARTON: Question on your scoping, please.
I noticed you have site lighting as
listed as in scope for license renewal. It's the
first application I've seen with site light. What's
different about your site lighting?
MR. ECKHOLT: Joe, maybe you'd like to
touch on that.
MR. RUETHER: This is Joe Ruether. We took
a bounding approach, so we brought all electrical
components in and dealt with the scoping screen on a
commodity basis.
So it didn't make any difference what the
-- site lighting was basically all the components for
electrical and brought into scope.
MR. BARTON: Okay, thank you.
MR. ECKHOLT: The next slide is a
simplified drawing of our switchyard, showing in red
those components that were brought into scope based
on our CLB.
In blue, is the expanded scope that was
brought in to meet the expectations of the proposed NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 15 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ISG 2008-01 on SBL.
Again, the aging management reviews were
done in accordance with NEI 95-10. We maximized all
consistency to the extent possible. In the end, we
were just a little over 89 percent consistent with
GALL for the AMR line items. That's assuming notes A-
D.
Some plants have gone and used E as well.
We did not do that.
Aging management programs -- there were
43 aging management programs identified in the LRA.
29 are existing at the plant. 14 are new.
Program consistency with the GALL -- 31
are consistent. Of those 31, nine also include
enhancements. 10 programs are consistent with
exceptions. Of those, six also contain enhancements.
There are two plant-specific programs, the nickel alloy nozzles and penetrations program and
the PWR vessel internals program are both plant-
specific.
Of the GALL exceptions, we've tried to
summarize here what we'd call typical GALL
exceptions. They include the use of more recent
revisions of industry standards and the revisions
cited in the GALL, the use of different or additional NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 16 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 industry standards, alternatives to performance
testing specified in the GALL.
Those would be in cases where there
wasn't instrumentation or equipment available to
perform the performance testing specified in the
GALL.
Also, the use of alternative detection
techniques or more recent NRC guidance than GALL
requirements in cases where we used alternates to
inspection test frequencies specified in the GALL.
Time limiting aging analysis was
performed in accordance with NUREG-1800 guidance and
95-10. The TLA's were evaluated in accordance with 10
CFR 54.21(c)(1).
MEMBER SHACK: Question. Are you currently
using a stress-based fatigue monitoring system?
MR. ECKHOLT: No.
MEMBER SHACK: Okay, that's a will.
MR. ECKHOLT: The LRA was submitted with
stress-based, but we completed the ASME code
confirmatory analysis and eliminated the stress-based
fatigue from the LRA.
MEMBER SHACK: And so you can leap the
environmentally enhanced fatigue?
MR. ECKHOLT: Yes.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER SHACK: Are you strictly cycle
counting on all these -- I mean, you've got a list of
components here from 6260, some of which you had
planned to do cycle counting and some of which you
had planned to do --
MR. ECKHOLT: This is Phil. Phil Lindberg, our programs lead. He could maybe give more detail.
MR. LINDBERG: This is Phil Lindberg, Xcel
Energy.
Could you repeat the question again?
You're interested in our cycle counting?
MEMBER SHACK: I'm looking at Appendix B
for the fatigue monitoring and you take the 6260
locations and you've got -- essentially, there's
three different methods.
There's cycle counting. There's stress-
based fatigue usage monitoring, and then there's
cycle based fatigue usage monitoring.
I'm not sure what the differences between
the two are, but then the statement seems to be that
you're not going to use stress-based monitoring
anymore.
MR. LINDBERG: That is correct. We're not
planning to use stress-based fatigue monitoring for
any of those EAF locations. We have section 3 fatigue NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 18 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 analysis of all six new reg 6260 locations.
Initially, as Gene mentioned, the
original submittal went in with SBF numbers for a few
of those locations and given the issues with the
industry with SBF, we redacted that information. We
went ahead and did -- for the hot leg nozzle and the
charging nozzle, we went ahead and did full ASME
section 3 analyses, which used design cycles.
So we have standing section 3 analyses
with applied FEN values that we show acceptance for
60 years. We do intend to continue to count cycles of
those design cycles as part of our metal fatigue
program.
MEMBER SHACK: And there's an update of
the Appendix B that makes that statement?
MR. LINDBERG: Yes. It was submitted via
RAI responses.
MEMBER SHACK: Okay.
MR. LINDBERG: Thank you.
MR. ECKHOLT: There are 36 regulatory
commitments that were identified that currently
exist, with respect to license renewal.
Those commitments are tracked to the
Prairie Island Commitment Tracking Program. They have
been assigned to the station personnel responsible NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 19 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 for implementation prior to the period of extended
operation.
At this point, I'll turn it over to Steve
Skoyen who will talk about the implementation
activities.
MR. SKOYEN: Well, the implementation
impacts all of our plant departments. The
coordination of the implementation itself is the
responsibility of our engineering programs
department.
Because we're going to be implementing a
number of new requirements associated with 10 CFR 54, we are managing that under a changed management plan, which is a formal process at the site.
All of our aging management programs have
assigned owners. Those owners have been involved in
the aging management program reviews as well as the
audits and inspection.
In support of the additional staff
required to implement the license renewal program, we
hired two additional staff earlier this year so that
they can work with a project team who has been
working on the project for the last three or four
years.
They are currently working on planning NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 20 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 and scheduling of new requirements.
MEMBER POWERS: What does it mean that the
programs have planned owners?
MR. SKOYEN: They are assigned program
owners. Two are aging management programs. Some of
those are existing. Some of those are new programs.
There are individuals associated with
those that understand they have that responsibility
going forward for coordinating associated inspections
and requirements.
MEMBER POWERS: I guess I still don't
understand. If I'm a program owner, what is it? What
do I have to do?
MR. SKOYEN: As program owner, you're
responsible for ensuring the requirements of that
program are implemented at the station, whether it's
performance of inspections, evaluations analyses.
MEMBER POWERS: If I get hit by a truck?
MR. SKOYEN: We have back-up program
owners identified for each program. Most of those are
managed in accordance with our program health process
for existing programs.
Going forward, new programs would be
incorporated into that process as well.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER POWERS: This is different how? It
doesn't seem like an unusual management structure at
all on how you would do anything.
MR. SKOYEN: Yes, I don't know that it
isn't that much different.
There are new requirements that we have
to ensure that we implement. That's what the
additional staff will be monitoring and tracking to
ensure that those new commitments we made are
implemented.
MEMBER POWERS: If I'm sitting at my desk
and one day you come in and you say okay, you're in
charge of this program, has anything changed in my
life other than that I now have another job?
MR. SKOYEN: You have additional
responsibility for that program, additional
responsibility for ensuring that those requirements
are implemented. There may be some training
associated, add a qualification.
MR. WADLEY: I think what we were trying
to convey is that we're already starting to integrate the programs into the plant operation. It's not
just sitting in a project group, but we're trying to
bridge that gap between now and a period of extended
operation to make it so it's seamless. That's really NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 22 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 all we're trying to say.
MEMBER POWERS: That's really I was
looking for. You guys now have it.
MR. WADLEY: Yes.
MEMBER POWERS: And presumably, they're
learning what it means because they haven't part of
your project team.
MR. WADLEY: Exactly.
MEMBER POWERS: I mean, if somebody came
in and told them they were in charge of this and they
said what the hell is this, right?
MR. WADLEY: Yes, there would be a glazed
look on their face and they wouldn't move forward.
MEMBER POWERS: Yes.
MR. WADLEY: But that's really what we're
trying to get is that we're starting.
MEMBER POWERS: That's what I was looking
for.
MR. ECKHOLT: And keeping them involved or
getting them involved during the review of the LRA
input documents and the audits helps them understand
so that it isn't dumped on them at the last minute as
our project wrapped up. They've been involved all
along.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. SKOYEN: Any additional questions?
MR. ECKHOLT: Okay, we will move onto what
we're calling specific technical items of interest.
We'll talk about underground medium
voltage cables of Prairie Island. We'll also talk
about the three SER open items under this topic.
CHAIRMAN RAY: Before you do that, I'm
mindful of the fact that we'll go into some areas
that are currently open and have a lot of interest
perhaps.
But I wanted, if this is the right spot
to ask some questions about some issues that aren't
open, but were addressed in your RAIs and had at
least triggered some questions in my mind.
MR. ECKHOLT: Sure.
CHAIRMAN RAY: One of them has to do with
coatings. There was quite a lengthy discussion of
your response to not having an aging management
program for coatings, side containment.
I guess the essence of it is that, to
quote here a sentence here from the response, analysis demonstrated that debris will not prevent a
safety-related component from performing its intended
function. It assumes that all qualified coatings are
within the zone of influence. In the worst case, pipe NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 24 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 break will fail and all unqualified coatings and site
containment fail and become debris along with other
debris that could be generated by a pipe break.
I guess I'm asking myself isn't this true
everywhere? I mean, why is a coatings program called
for at all for anyone given -- is there something
unique, I guess I'm asking, about this pant that
makes it invulnerable to coatings failure as compared
with other plants?
MR. ECKHOLT: We're no different than any
other plant with respect to coatings. The difference
is that when our LRA was initially submitted, we did
not include containment coatings.
However, it was raised as a contention as
part of the hearing process that it wasn't there. So
in an effort to resolve the contention, we went ahead
and brought containment coatings into the license
renewal program. We added containment coatings
program.
Well, actually, we brought the existing
program into license renewal space. That was the
intent of bringing it in -- was to resolve the
concerns raised in the hearing process.
CHAIRMAN RAY: So it is in scope even
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 for monitoring coatings?
Elsewhere here, it says, for example, therefore coatings inside containment do not fall
within the scope of 10 CFR 50.54(a)(2). Since they
are not components, it's fair to prevent satisfactory
accomplishment and so on.
MR. ECKHOLT: Right. We did not bring the
coatings into scope. We did not feel in the initial
application that the coatings performed an intended
function. But again, we brought the program in --
CHAIRMAN RAY: What's the status now? Do
you have a coatings?
MR. ECKHOLT: Yes, we have a coatings
program that meets all the industry and NRC
expectations and standards.
CHAIRMAN RAY: And that's a change, is it?
MR. ECKHOLT: No. No, that was in place.
That was an existing program and basically, we
brought that into scope.
MR. WADLEY: But it's a change from our
original application.
MR. ECKHOLT: It's a change from the
original application.
CHAIRMAN RAY: That's what I was trying to
get at. Right, thank you, because I was really NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 26 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 puzzled by having read this and then listening to
what you said.
MR. BARTON: Let me make sure I
understand. You now have an aging management program
for coatings?
MR. ECKHOLT: Yes.
MR. BARTON: Okay.
CHAIRMAN RAY: All right. That, I think, settles that.
MEMBER POWERS: How do you tell when a
coating has aged? Is that the indicator or do you
have something that --?
MR. ECKHOLT: Maybe Richard, you can --?
MR. PEARSON: Yes. This is Richard Pearson
from Xcel Energy, Prairie Island.
The coatings program that's in place at
the plant, first of all, you have qualified coatings.
They are monitored, like on a containment vessel
well, by inspection, but the qualified coatings have
been demonstrated really not to degrade.
Then you have the other series of
coatings that total program involves inspection. It
involves how we put new coatings on. It involves
qualification of painters, qualifications of coatings
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ensure the amount of unqualified coatings we have in
containment is still understood and is being able to
be tracked.
MEMBER POWERS: Your indicator of a failed
coating, qualified or not, is it falls off --
blistered, delaminated -- whatever?
MR. PEARSON: That's correct.
MEMBER POWERS: You do not have an
instrumental indication of aging?
MR. PEARSON: No. It's only a visual
inspection.
MEMBER POWERS: I'll tell you an amusing
anecdote. I got interested in coatings on aircraft in
the military. They spend a huge amount of money
trying to design a device to inspect the coatings, to
tell them when to re-paint their airplanes.
So I went over to the Military Airlift
Command to see if they used this and the guy says, we
never used that. We just look at it and when it looks
like it's about to fall off, we re-paint it.
MR. WADLEY: Visual inspections.
MEMBER POWERS: Visual inspections.
MR. PEARSON: This is Richard Pearson
again. If we find degraded coatings, there's some
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 extent of degradation. We'll take measurements, characterize it as best we can.
MR. ECKHOLT: Thanks, Richard.
CHAIRMAN RAY: Okay on coatings?
Another question I had -- similarly, you
have a discussion about flow-accelerated corrosion, correlation methods, and so on, ending up with use of
CHEKworks. But it says Prairie Island does not
experience excessive flow of accelerated corrosion
that was not predicted by CHEKworks. That's good.
Could you just comment on what -- have
you done much replacement of piping for flow-
accelerated corrosion reasons or do you expect to, I
guess?
MR. ECKHOLT: Steve?
MR. SKOYEN: We've not done a great deal
of replacement. Typically, during a re-fueling
outage, we'll replace a couple of typically smaller
lines -- two or three inch, as well as penetrations
into the condenser -- but in terms of large
components, we've not experienced a great deal of
replacement.
MEMBER ARMIJO: When you do these
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MR. SKOYEN: Typically, they're replaced
with the same material, but if in the determination
of the engineer, replacing that with a more resistant
material because of the wear rate in that particular
area is higher than expected, we will replace for
that in materials.
CHAIRMAN RAY: Enough on that. I have only
one or two more in this category.
One of them that caught my attention was
having to do with above-ground steel tanks program.
The response to the RAI on this asserts that
inspection is done of just one of the three storage
tanks because it's representative of the other two
and is sufficient.
Can you say a little bit more about why
you're so confident that you don't need to inspect
all three condensate storage tank bottoms?
MR. ECKHOLT: Phil?
MR. LINDBERG: This is Phil Lindberg, Xcel
Energy.
Basically, we felt we had similar
materials and similar environments such that our
inspection of one condensate storage tank would
reflect all three tanks.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Certainly, if we were to find any
evidence of degradation on that one tank, we would
certainly expand our inspection scope to the
remaining tanks.
MR. WADLEY: Phil, could you talk a little
bit about how we intend to inspect those tanks?
MR. LINDBERG: It is a visual external
inspection. The tanks are insulated, so the
inspection would be of the external insulation
looking for insulation damage or signs of rust or
discoloration coming from the insulation.
We've also stated that we would remove
insulation at lower points or at points that would be
expected that might indicate damage and that we would
physically inspect the exterior tank, the carbon
steel tank surface underneath that insulation on a
periodic basis.
CHAIRMAN RAY: Well, I'm referring to the
ultrasonic inspection of the tank bottom.
MR. LINDBERG: I'm sorry.
CHAIRMAN RAY: And it just says that we're
just going to do one because that will tell us all we
need to know. I'm just curious about why you think
just one UT inspection is representative of all three
tanks. I mean, that's what asserted here, but it's NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 31 1 2 3
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MR. LINDBERG: I guess from the way we
looked at it, it was similar to how the inspections
for, for example, for the one time inspection program
-- were done to confirm the absence of aging on a
sampling approach.
CHAIRMAN RAY: Okay, but you don't have
any other rationale for one is enough?
MR. LINDBERG: I don't have any plant-
specific OE, no.
CHAIRMAN RAY: Okay. And then my
colleagues on the committee here probably can help me
with this last one that has to do with materials
leaching program. It's something I'm not familiar
with.
But basically, your response to the RAI
indicated that a visual inspection was deemed to be
sufficient and adequate. Do you have any other
comment on that or I offer my esteemed colleagues to
question whether that's enough selective leaching of
materials.
It's elevated a status of a program, but
some folks felt that it was sufficient simply to do a
visual inspection, as I read this. I gather you
haven't had any experience with it?
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. WADLEY: No, we haven't. No.
CHAIRMAN RAY: Can you add anything to my
--?
MR. LINDBERG: This is Phil Lindberg. No, actually, our selective leaching program will use
visual inspection in conjunction with either hardness
testing or a mechanical scraping. It's not strictly
visual.
MEMBER ARMIJO: What are the materials in
your leaching program? What materials are you
inspecting?
MR. LINDBERG: Could you repeat the
question?
MEMBER ARMIJO: Yes. What materials are
concerned?
MR. LINDBERG: This would be for cast iron
and for copper alloys containing greater than 15
percent zinc.
MEMBER ARMIJO: Okay, so it's basically
brass and cast iron?
MR. LINDBERG: That's correct. Like I
said, we would be doing visual inspection in addition
to either a mechanical scraping or hardness test or
other available detection technique.
We have an exception to the program that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 33 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 discusses the use of alternate detection techniques
beyond hardness testing.
MEMBER ARMIJO: Have you had to replace
any of these materials?
MR. LINDBERG: We have not done any
inspections to date. This is a new program.
CHAIRMAN RAY: It just caught my attention
that it was an exception, as he indicated. I'm not
familiar enough with it to know whether it's
exception --
MR. LINDBERG: The GALL recommendation is
for a visual inspection in conjunction with hardness
test.
CHAIRMAN RAY: Right.
MR. BARTON: Expand on Mr. Ray's question
on the condensate storage tank, the bottom
inspection.
How are these tanks mounted? What's the
foundation? Tell me how they're installed.
MR. PEARSON: This is Richard Pearson. The
condensate storage tanks sit on a concrete base and
then they actually have some hold-downs on them. The
tank is held down to the concrete base.
I'm not sure what kind of coating was put
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 at them as a concrete base, you see the joint, basically, between the condensate storage tank, the
insulation, the concrete base.
Does that answer the question?
MR. BARTON: Yes, so my next question is, how can you be assured that you don't have moisture
under the tank that you didn't inspect and you do
have some corrosion going on in the tank bottom if
you're only going to do one of three -- what do you
have? Two tanks? Three tanks, okay. Suppose you pick
the wrong tank.
I mean, how are you assured that there's
no leakage getting underneath between the joint in
the bottom of the tank and the concrete foundation?
MR. LINDBERG: This is Phil Lindberg. Part
of that external visual inspection would be of that
joint between the tank and the foundation. So if, again, if we were to find degradation of that joint, that would be an indication of potential intrusion, water intrusion, and we would likely end up doing
some UT inspection on that.
MEMBER STETKAR: That joint is not sealed, am I correct?
MR. LINDBERG: This is a -- I'm not sure
what the material is. There's some type of sealant at NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 35 1 2 3
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MEMBER STETKAR: If the tank would leak, would you see traces of that leakage on the concrete
base and outside the tank?
MR. ECKHOLT: You should, yes.
MR. BARTON: Well, if it's sealed, how
would you see it?
MEMBER ARMIJO: That is the question.
MEMBER MAYNARD: Are you doing the visual
inspection on all three or just on one?
MR. LINDBERG: On all three. The visual is
on all three, MEMBER STETKAR: Yes, you can't visually
inspect the bottom of them.
MEMBER MAYNARD: Right.
CHAIRMAN RAY: Okay on the tank bottoms?
John Stetkar had a question.
MEMBER STETKAR: Two quick ones. Back to
the selective leaching. Do you have any in-scope
systems that have buried cast iron piping?
MR. MCCALL: Hi, this is Scott McCall with
Xcel. Yes, fire protection piping is buried in cast
iron.
MEMBER STETKAR: That's the only one?
MR. MCCALL: Yes.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER STETKAR: The second question I had
-- you had a couple of exceptions on your fuel oil
chemistry program. I think I understand the
rationale.
One of the exceptions you took is you
weren't going to sample for biological activity. I
think, as I understand it, the argument is that you
have very small filters and your normal sampling
program would detect any sludge that might be
generated by any type of biological attack.
Are all your samples taken directly from
the bottom of each of your tanks or are your sample
points elevated above the bottom of the tank so that
you could have a sludge build up without actually
detecting it?
MR. MCCALL: I'm not sure if I have the
answer to that question. I know some of our sampling
is done at top, middle, and bottom locations. The
sampling is coming from some place near the bottom of
the tank.
MR. ECKHOLT: We'll verify that. We can
get an answer for that. We'll verify that.
MEMBER STETKAR: I think in the interest
of time, let's go on to the more interesting topics.
CHAIRMAN RAY: All right, we'll reserve NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 37 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 the -- return to these less interesting ones later.
Go ahead.
MR. ECKHOLT: All right. I'll turn it back
over to Steve to talk about underground medium
voltage cables.
MR. SKOYEN: We did have a failure of a
circulating water pump cable that resulted in a unit
1 trip in May of this year.
That cable was replaced. It was a ground
fault. We are currently in the process of continuing
a cause evaluation and the cable is currently at EPRI
for testing.
We have experienced three other cable
failures. Two of those on 14.8 kilovolt lines and one
on a 41.16.
The two on the 14.8 volts were identified
at the cable terminations. Both of them related to
water intrusion. One actually resulted in a ground
fault. One was taken out of service prior to failure.
Those cables were subsequently replaced in 2005.
We've also had one 41.16 failures, I
mentioned. That was also at a termination. That one
was actually identified during an outage. The cause
of that particular one was manipulation over time
during maintenance that had weakened the insulation.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Going forward, our cable insulation
testing will be part of a new program that's being
implemented called the inaccessible medium voltage
cables. That's subject to 10 CFR 50.49 Environmental
Qualification Requirements Program.
MEMBER BONACA: This is a new program?
MR. SKOYEN: Yes, this is a new program.
That's correct.
MEMBER BONACA: You did not have a program
that responds to the failures you experienced.
MR. SKOYEN: In response to generic letter
2000-701, we have a cable program currently at the
site. We had been MEGR testing cables for a number of
years.
MR. BARTON: In that letter, you said you
would have a program in place by the end of the 2007.
When the inspection team was out there in
September 2008, they said you didn't have a program
in place, although it was in the commitment tracking
system. Yet, the SER says you had a program in place
in March 2008.
What's the story? Is there a cable
maintenance program in place at the site at this
time?
MR. SKOYEN: There currently is a cable NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 39 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 program in place, as you mentioned, that we had
intended to implement that program by the end of
2007. That implementation was delayed. That program
has now been implemented.
MR. BARTON: Is that because somebody
missed it in the commitment tracking system or did
you change the date in the commitment tracking system?
MR. ECKHOLT: That was never entered -- it
was not identified as a formal commitment.
MR. BARTON: It was not?
MR. ECKHOLT: It was not. It was not in
the commitment tracking system. It was basically a
statement of our intent to implement the program by a
certain date.
MR. BARTON: So your answer to the generic
letter was you intended to have it, but you didn't
put any commitment? You didn't cite commitment on it?
MR. ECKHOLT: It was not identified as a
formal commitment.
MR. BARTON: Okay.
MEMBER STETKAR: To what extent do you
have water intrusion in underground medium voltage
cable ductwork?
MR. SKOYEN: Joe?
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. RUETHER: This is Joe Ruether. I
didn't hear the question.
MEMBER STETKAR: To what extent have you
found water intrusion in underground medium voltage
cable ductwork or other conduits and holes?
MR. RUETHER: The two examples in the
13.8, we've seen water in those cables and replaced
that, as we referred to earlier.
And then, also, in this recent May, cable
-- a motor pump cable for unit one that looks like it
may have water involved in that as well. The root
cause is not complete, so it's --
MEMBER STETKAR: Do you pull manholes or
other types of covers to inspect? If you do, how
often do you do it? Which ones do you do?
MR. RUETHER: We have, as far as in scope
of license renewal, medium voltage. We have one
manhole involved there.
When we replaced the 13.8 kV cable, we
put in a whole new ditch, a whole new routing. We put
a new manhole at that time in 2005.
We've looked at water level -- opened up
the cover several times, have not seen water or any
indication of water, looking on the sides to see if
any water has been in there.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER STETKAR: Do you have a procedure
to periodically pull the manhole covers to inspect
the water?
MR. RUETHER: Yes, we do.
MEMBER STETKAR: Is that on occasion?
MR. RUETHER: No -- yes, we do. It's in
the PM program.
MEMBER STETKAR: How often?
MR. RUETHER: We initially looked at
quarterly and then it was determined that we didn't
see evidence. That was subsequently changed to every
four years.
Based on the experience from license
renewal, we'll be committed to doing that inspection
every two years. MEMBER STETKAR: That's a long time. If I were to look at a site clock plan, where's the
manhole where you have seen water or where you
inspect? Is it the one out at the screenhouse? 13 kV
and all?
MR. ECKHOLT: It's actually located -- I
have a site plan. I'll pull it up.
MR. RUETHER: This is Joe Ruether again.
The 13.8 manhole is actually away from the river from NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 42 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 the plant. You got the river and then you have the
physical plant and then going in is where the manhole
is. It used to be the middle parking lot.
MR. ECKHOLT: The manhole is in this
location right here. It's an old parking lot that's
no longer used now.
One other thing to note with the manhole, the bottom of the manhole is sand, so should any
water enter --
MEMBER STETKAR: It's an opportunity for
water to come in.
MR. ECKHOLT: But it also drains out very
readily both ways.
MEMBER STETKAR: If you say so. MEMBER MAYNARD: I'm not sure that once every two years -- I'd have to see the program to
know whether -- I mean, it could be getting wet deep
down and if you're just looking at it at a time it
may be down, but I also consider this probably more
of a current operating issue as much as a license
renewal issue that should get resolved as part of
this. The two year cycle doesn't really excite me as
far as an adequate inspection.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER STETKAR: Yes, and that is sort of
the reason why I brought it up because it is a
current operating issue.
On the other hand, there are a lot of
plants out there that have water in manholes that
don't have cable failures.
For this purpose, I would disregard
termination failures because it's obviously not an
environmental thing. It's a work process issue.
But I think inspections every four years, every two years are scant. I'm also surprised you
only have one manhole that carries medium voltage, important to safety cables. I have to do a little
research on that.
CHAIRMAN RAY: Okay?
MEMBER ABDEL-KHALIK: This program -- when
do you expect them to be completed?
MR. SKOYEN: The actual development of the
program?
MEMBER ABDEL-KHALIK: The actual testing.
MR. SKOYEN: Implementation of our
existing program -- you're referring to generic
letter program?
MEMBER ABDEL-KHALIK: You have a cable
testing program in place.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. SKOYEN: Correct.
MEMBER ABDEL-KHALIK: When do you expect
testing to be completed of all medium voltage cables?
MR. SKOYEN: Of all medium voltage cables?
The testing that's required by the program requires
that we determinate the cable at both ends, so those
will take place over a series of outages over the
next few years.
In terms of a -- pardon me?
MEMBER BONACA: Somewhere around four
years?
MEMBER ABDEL-KHALIK: It said four
outages, which carries you through the period of
extended operation. I'm just trying to find out why
that is acceptable. MR. SKOYEN: I believe that would be two outages on each unit.
MEMBER ABDEL-KHALIK: So when would that
end?
MR. SKOYEN: That would end approximately
four years or the less of four years --
MEMBER ABDEL-KHALIK: Which is right
before the period of extended operation.
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MEMBER ABDEL-KHALIK: Okay, thank you.
MR. ECKHOLT: The commitment for the
license renewal aspect of this program is to be
completed by the PEO. Anything more on --?
CHAIRMAN RAY: No thanks.
MR. ECKHOLT: Okay, moving on to the SER
open items. We'll talk first about the PWR vessel
internals program.
The GALL anticipates a future program. It
anticipates that the program under development by
EPRI and MRP will be reviewed and approved by the NRC
and put in place.
Our original LRA was submitted with the
associated GALL statement submitting to implement the
program as approved by the NRC. As part of the
hearing process, a contention was raised on the
adequacy of just providing a commitment rather than a
detailed discussion of an internals program.
So in order to resolve that contention, we've submitted a plant-specific vessel internals
program back in mid-May that was based on the EPRI
MRP-227 Rev 0 document that was submitted for NRC
review.
We did retain the commitment to update NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 46 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 the program based on whatever is finally approved by
the NRC.
Subsequent to us adding that to our LRA, all the parties involved in the contention process
agreed that it resolved the issue and agreed to
dismiss the contention. The ASLB subsequently
dismissed the contention.
And then, as Brian noted, the NRC staff
review is still in progress on the submittal we made.
MEMBER SHACK: And this is basically an
inspection plan?
MR. ECKHOLT: Yes. Any other questions?
The second open item relates to scoping of the waste
gas decay tanks. SSCs are in-scope per part 54 in
part if they prevent or mitigate the consequences of
an accident which could result in off-site exposures
comparable to those referred to in 10 CFR 100.
The Prairie Island waste gas decay tanks
are classified as safety-related. However, we did not
initially bring them into scope because the off-site
exposure potential was not considered comparable. It
was not what we consider -- it didn't reach a 10
percent threshold.
The NRC reviewers took issue with that
interpretation and in the end, we agreed to re-NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 47 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 classify the waste gas decay tanks as in-scope and we
made a submittal that went in in early June bringing
those tanks into scope. Again, the NRC staff is
currently reviewing that submittal.
Then the third SER open item relates to
reviewing cavity leakage. Just a little bit of
background on the NRC review of this issue. The NRC
was briefed on this issue during the aging management
audit in the fall of 2008.
We also held a public meeting with the
NRC staff to give them more detailed information on
the issue and the actions we were taking. There were
a number of REIs that we responded to and there was
an NRC team that came on-site to do an audit of some
of our documentation as well. We have responded to all the REIs. The last response went in on June 24th of this year.
Again, the NRC review is still in progress.
We'll also provide some more detailed
information. Steve Skoyen will give us a little
background on the leakage, our containment
configuration, the leak locations, the leak paths, our inspection results to date, the corrective
actions we're taking, and what we're looking at for NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 48 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 long term aging management as well as an evaluation
we've done on potential degradation. So with that, I'll turn it over to Steve.
MR. SKOYEN: Thank you, Gene. Prairie
Island has experienced intermittent leakage
indications in both units since the late 1980's.
Approximately 1987 was the first documentation of a
problem.
The cumulative leak rate that we see from
the refueling cavity is approximately one to two
gallons per hour. It's most commonly seen in the ECCS
sump and then in the regenerative heat exchanger
room.
Sources has been determined to be
refueling cavity water, based upon the chemistry of
the water that accumulates in those two locations, and the fact that the leakage indications typically
begin two to four days after the refueling cavity has
been flooded. They end approximately three days after
the cavity has been drained.
We've been successful with sealing
activities, either application of a strippable liner
or caulking, but our success has been inconsistent.
MR. BARTON: Let me ask a question. I've
seen that you've taken some corrective actions, but NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 49 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 this subsequent -- I assume when you do a strippable
coating prior to a refueling outage, do you do the
same spots all the time, but yet when you fill up for
that outage, do you still have leakage, which means
that you've got -- that the coating either failed or
you've still got leakage in other parts of the pool
that you haven't found.
MR. SKOYEN: We had some success with a
coating when it was applied properly and when we were
able to apply it to all areas, we were successful.
We were unsuccessful when it was applied
improperly. We saw the coating delaminating in the
application to the location that we believe are
leaking is not done properly, so we didn't -- the
process wasn't applied.
MR. BARTON: Were you ever successful in
an outage of sealing and not having any leakage in
that outage of did you always have leakage?
MR. SKOYEN: We were successful with the
application of the strippable coating approximately
50 percent of the time.
We were also successful when we caught
around the base plates and underneath the support
stand nuts approximately 50 percent of the time.
MR. WADLEY: Sufficiency of application is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 50 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 --
MR. BARTON: You think it's an
application, but if you had applied it properly you
think you would have stopped it?
MR. WADLEY: Yes.
MR. BARTON: So you think you know where
the leaks are?
MR. WADLEY: Correct, yes.
MR. ECKHOLT: We'll get into that here.
MR. BARTON: Okay.
MR. WADLEY: We demonstrated a correlation
during a --
MR. BARTON: I just wondered whether we
were chasing a ghost here or whether we're just
having a problem fixing what's there. Okay.
MEMBER STETKAR: Well, you know if you've
been successful part of the time and unsuccessful
other parts of the time, you may want to consider
another sealing method or do additional work and make
sure the sealing method you use actually performs its
function.
MR. ECKHOLT: We'll get into --
MR. SKOYEN: Well get into the action we
plan to take.
Following the most recent refueling NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 51 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 outage in which our sealing method was not
successful, we determined that we needed to perform a
root cause evaluation on this issue. So that was
performed earlier this year.
As a result of that root cause
evaluation, we determined the sources of leakage to
be the embedment plates for the reactor internal
stands which are in the lower cavity and then the rod
control cluster change fixture supports which are in
the transport.
We determined that based upon the
correlation between when we are successful in
mitigating a leakage and when we were not, when we
could relate that back to problems during application
of the coating or application of the caulking.
Some background on our containment vessel
because it may be different from others you've seen -
- bring up the drawing.
Actually, if you turn to the last slide
in your presentation -- we did include a figure so we
can look at that. The containment pressure vessel
itself has an inch and a half thick bottom head, an
inch and a half thick shell, and the top head is 3/4
of an inch thick.
At the ECCS sump location, as well as NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 52 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 other penetrations, the thickness of the shell is 3/4
of an inch for reinforcement.
Material is an SA 51670 low temperature
carbon steel.
The lower head, as you can see in the
drawing, is fully encased in concrete on both sides.
The remainder of the containment pressure vessel --
and there's a five foot annular gap between the
containment vessel itself and the one in the leakage
-- reinforce the concrete shield building. That
allows us access to the vast majority of the
containment pressure vessel itself.
I'd also like to point out on this slide, because we'll be talking about this later, the
regenerative heat exchanger room. That lies right
below our lower cavity and we have seen evidence of
leakage there.
The fuel transfer tube and canal, as well
as the upper refueling cavity. This is the reactor
head.
At this time, I would also like to point
out our sump charley, which is below the reactor
vessel. We'll also be referring to that later. At
that particular point, the thickness of the concrete
is approximately 16 to 18 inches.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER ABDEL-KHALIK: So how would a leak
make its way all the way to the sump there?
MR. SKOYEN: Actually, that is not the
sump where we typically see the leak. We'll get to
that in the next section.
MEMBER ABDEL-KHALIK: Okay.
MR. SKOYEN: Okay, the top view, you'll
notice our ECCS sump -- that's at an elevation of
693.7. 693 and 7 inches. We didn't see that in the
prior view because it was in a different plane.
That's typically where the leakage would show up, in
that particular location.
MEMBER STETKAR: So that's 693.7, so
that's --
MR. ECKHOLT: We've just got another --
MEMBER STETKAR: Do you have another
elevation that shows that?
MR. ECKHOLT: It's down in this location.
The refueling cavity bottom is up here.
MR. SKOYEN: Can we go back to the cut-
away drawing again, the elevation drawing. It may b
easier to see here.
Although it's not shown on this picture
relative to the other elevations, you can get an idea
of approximately where that is located.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. ECKHOLT: That's basically down --
MR. SKOYEN: 693 elevation.
MEMBER MAYNARD: That's at the bottom of
that thing over on the right.
MEMBER ARMIJO: You have a slide 51, page
51, that's shows the ECCS sump. Is that one of those
locations that where you're finding the water?
MR. SKOYEN: That's correct. That's the
location that we're referring to on this particular
slide, in the center -- the cut-away drawing in that
particular location.
And you'll note that the grout between
the containment pressure vessel itself and the sump
is relatively thin in that particular area.
MR. ECKHOLT: This area here.
MEMBER ARMIJO: This looks thicker there
also, for some reason.
MR. SKOYEN: Correct. That's a penetration
so it has some reinforcements. That's approximately
three and a half inches. Next slide, Gene.
The actual leak locations themselves, the
typical reactor vessel internals support stand is in
the left and the typical RCC change fixture support
stand is on the right. There are eight internal
support stands and we have three NRCC change fixture NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 55 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 supports.
The leakage, we believe to be flowing the
threads down past the nut. Once past the nut, there's
a seal weld -- this is the RCC change fixture -- seal
weld that was installed when this was originally put
in.
That ground flush, we believe that
there's a leakage path to that location that's
allowing the refueling cavity water then to pass
completely through the stud and then come out
underneath the embedment plate.
Similar arrangement on the internal
support stands. MR. ECKHOLT: Maybe you can describe the caulking we've done on these in the past?
MR. SKOYEN: Yes. Past actions that we've
taken, most recently was caulking and we would remove
the nuts from the top of the base plate, underneath
those nuts to prevent the leakage from going past the
threads. Then between the base plate and the
embedment plate, we would try to caulk there.
If you look at this and go back to the
prior slide, Gene, that orange material that you see
there is the caulking. That is applied and removed NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 56 1 2 3
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MEMBER STETKAR: Is that borated water?
MR. SKOYEN: That's correct.
MEMBER STETKAR: What are the materials
for the nuts, the studs, face plates?
MR. SKOYEN: It's all like a pore
stainless.
MEMBER STETKAR: Okay. Have you seen
corrosion of any sort that is significant that would
change the strength of the structure?
MR. SKOYEN: In the refueling cavity
itself?
MEMBER STETKAR: Of these supports.
MR. SKOYEN: No, we have not. No corrosion
and no reports of any deficiencies related to the
integrity of the supports for the studs.
Okay, next slide, Gene. Do you want to go
to the cut-away drawing? We are referring to slide
number 33 when we talk about the path the leakage
takes.
Once the leakage is underneath the
refueling cavity and liner -- or seeped through -- it
will travel through construction joints between the
floor of the transfer pit and the wall behind the
transfer tube. Once it's behind the wall in the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 57 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 transfer tube, it can travel horizontally and
circumferentially around the containment, which is
between that space between the concrete and the
shell.
Once it gets into the lower elevation of
containment, we see that come through the ECCS sump.
As we mentioned earlier, grout is relatively thin in
that area and that's why we believe it shows up in
that particular location.
The leak rate that we see in this
particular location is approximately one gallon per
hour -- up to one gallon per hour. It has been the
last -- depending on our success with mitigation. We have also seen evidence of leakage in our regenerative heat exchanger room, which is
directly below the lower refueling cavity. That
particular leakage will travel and once it's
underneath the liner. It can follow hairline cracks
in the concrete and then seep through the sealing in
the walls in that particular room.
MEMBER ARMIJO: Do you have some sort of a
sump pump in that area, that 851 -- slide 851.
MR. SKOYEN: In the ECCS sump? Yes, there
is not an existing pump in there, but during NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 58 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 refueling outages, we will pump that occasionally if
that particular outage has some leakage.
MEMBER STETKAR: A portable pump?
MR. SKOYEN: Yes, correct.
MEMBER SHACK: I thought you said before
you didn't see leakage into sump C.
MR. SKOYEN: Sump Charley is underneath
the reactor vessel. What we're talking about here is
MEMBER SHACK: Do you see leakage in both
of the sumps?
MR. SKOYEN: No. We see the -- commonly, we see the leakage in the ECCS sump. Sump Charley, if
there's leakage in that particular area, it is more
than likely due to leakage through the cavity seal.
CHAIRMAN RAY: I was going to say how the
heck are you going to separate that?
MEMBER STETKAR: Well, you can tell just
be -- well, you have insulation on the reactor vessel
so you can't see.
MR. SKOYEN: Correct.
MEMBER STETKAR: The pathway is going to
be between the vessel.
MR. DOWNING: I would like just to add one
clarification if I may, My name is Tom Downing. I'm NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 59 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 at Prairie Island site.
There is evidence of leakage in the sump
under the reactor vessel only in that there's a stain
in the wall that originates from a construction joint
and comes down the wall. Actual leakage has never
been witnessed because that sump is not accessible
when the pool is flooded.
You can also see on the diagram there
that the one horizontal line coming over to the sump
directly under the reactor vessel is just to indicate
that there is a stain on the wall there.
MR. SKOYEN: Any additional questions
regarding leakage?
CHAIRMAN RAY: Well, you demonstrated or
illustrated I should say a hypothetical path. It's
one that I assume could exist. It's not a unique path
from the site of the leakage to the sump of interest.
MR. SKOYEN: Correct. Regarding
inspections that we've done related to the leakage, we have poured ultrasonic examinations and visual
examinations of the containment vessel.
In particular, in the ECCS sump, we have
removed the grout at that location more than once and
performed inspections there.
All readings have been above nominal. All NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 60 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 readings have been consistent, which should indicate
no corrosion in that particular area. The visual
inspection confirmed that as well.
The annulus area, we have also inspected
there because as we've mentioned, once the refueling
cavity leakage would get past underneath the liner, once it gets to the transfer tube, it can go down
along the wall. So we have inspected from the annulus
from external to the pressure vessel looking back in
to determine if there's been any corrosion on the
interior side. We've seen none on the exterior.
At that location, we have not identified
any corrosion either. Again, all of our wall
thickness measurements are above nominal in that
location and they're also consistent.
MEMBER STETKAR: Now, I take it every
place where leakage ends up is in some kind of a
concrete vault with the liner, metallic liner?
MR. SKOYEN: No, that's not correct.
MEMBER STETKAR: What's not correct about
it? No liner?
MR. SKOYEN: No liner.
MEMBER STETKAR: Okay, so you're flat up
against the concrete?
MR. SKOYEN: Correct.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. ECKHOLT: Yes. There's no steel liner
on the surface --
MEMBER STETKAR: Have you found any
deterioration of the concrete or the coating or do
you usually have some kind of a coating here?
MR. SKOYEN: No. We see the leakage
seeping through the coating. We have not seen that
the coating has deteriorated in that location and we
have no evidence of concrete degradation either.
MEMBER STETKAR: Have you inspected the
areas for cracks that would take you far enough into
it rebar?
MR. SKOYEN: We have looked at cracks. The
cracks that we have looked at as part of our
structures monitoring program could be characterized
as hairline cracks. We have no significant cracking.
MEMBER STETKAR: You have no way of really
determining what condition of rebars?
MR. SKOYEN: Not directly, that's correct.
CHAIRMAN RAY: Well, now, aren't you
planning to excavate --
MR. SKOYEN: Yes.
CHAIRMAN RAY: Let me hear you out. Tell
me about -- what's the plan?
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. SKOYEN: Yes, we'll be covering that a
little bit later.
CHAIRMAN RAY: All right.
MEMBER ABDEL-KHALIK: Now, when you say
the leak rate is one to two gallons per hour, this is
your measured leak, right?
MR. SKOYEN: That's correct.
MEMBER ABDEL-KHALIK: Do you have any idea
what your actual leak rate is? How would you go about
estimating that?
MR. SKOYEN: That is probably the most
direct way to measure it. Tom, if you have something
to add?
MR. DOWNING: Yes. My name is Tom Downing.
When you first -- well, I shouldn't say
when you first start experiencing -- back in `98, `99
time-frame when we experienced leakage, we hung
plastic sheeting up in the leak areas and drained it
into a bucket, five gallon bucket, and timed it.
At that time, the leakage in the region
room was estimated at 1.25 gallons per hour.
Similarly, we estimated the amount of leakage into
the ECCS sump at .5 gallons per hour.
So the sum of total leakage and
containment generally ranges between one and two NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 63 1 2 3
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MEMBER ABDEL-KHALIK: Well, but my
question was aimed at finding out are there any other
locations where water could actually be accumulating?
MR. DOWNING: It's a potential that water
is accumulating on the bottom head of the reactor
vessel itself. There's really no way to know for sure
exactly where the water travels or where water
resides.
I would expect that the leakage either
comes through the construction joint or follows the
transfer tube directly, comes down the wall, comes
around containment, and could potentially fill the
interface between the interior concrete in the inside
diameter of the reactor vessel bottom head.
MEMBER ABDEL-KHALIK: If that were the
case, what would be the consequences?
MR. SKOYEN: Of the actual water at that
location?
MEMBER ABDEL-KHALIK: Right.
MR. SKOYEN: We'll also be getting into
that as part of the presentation a little bit later
when we talk about evaluation of potential
degradation.
MEMBER ABDEL-KHALIK: Okay.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CHAIRMAN RAY: We can run a little over, but we've got 20 minutes.
MR. SKOYEN: All right. We plan to prepare
to permanently eliminate the leakage during our next
refueling outage on each unit.
MR. BARTON: Let me ask you. This thing
has gone on for so long. Why now do you decide you're
going to fix it?
MR. SKOYEN: Well, we had, as I mentioned
earlier, we had tried a number of sealing methods.
Given the inconsistency of performance, we determined
that we could no longer rely on that to eliminate
this leakage.
We were successful during our unit 1
outage in the spring of 2008, the sealing on that
unit.
We had less success in the fall. We
didn't see leakage for approximately 10 days, but
after 10 days, we did see leakage into our ECCS.
MR. ECKHOLT: We had some difficulty. We
couldn't remove the nuts and get the caulking under
them for that outage so --
MR. SKOYEN: That is a concern as well
because that's a stainless to stainless interface.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 and installation in that area.
What we're performing now is a permanent
repair so that we don't have to do that anymore.
MR. WADLEY: It's not acceptable to
continue to have this leak. Too many unknowns.
CHAIRMAN RAY: Mike, I must say that that
was hard to figure out from a lot of the rhetoric
that was submitted here -- that it wasn't acceptable.
I'm glad to hear you say that.
MR. BARTON: Yes, thank you.
MR. SKOYEN: The repair method that we're
going to employ is shown on this particular slide. As
you can see, on the right hand side of the slide is
the existing configuration with an open nut.
We will be installing blind nuts, as
noted on the lefthand side in the particular
locations where it's attainable to surface area and
the thread engagement.
Then putting a seal weld all the way
around the location, that will eliminate the leak
path that could occur there.
We'll also be putting a seal weld between
the base plate and the embedment plate to eliminate
that leak path.
We believe that by doing this, we will NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 66 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 permanently eliminate the leakage that occurs from
both the internal stands and the RCC change fixture
support stands.
MEMBER ARMIJO: There was no seal weld
there initially?
MR. BARTON: There was initially. They
said down here, they think that -- MEMBER ARMIJO: Yes, just around the threads.
MR. SKOYEN: Yes. Just around the threads.
So we believe this to be a much more
robust design than was the original. It also allows
us to inspect these welds going forward and identify
any concerns with those in repair.
It also, from a dose consideration, perspective, is we receive far less dose employing
this method of repair than going back to the original
drawing.
So for a number of reasons, we believe
this is the correct method for repair.
CHAIRMAN RAY: I take for granted that
there aren't any leak chases on the seams of the
cavity and so on.
MR. SKOYEN: That's correct, right.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER ABDEL-KHALIK: Have you done a
simple calculation to -- if you have a certain water
level in the refuelings, storage, how big a crack in
terms of equivalent diameter would you have to have
to have to give you water flow of one to two gallons
per hour all the way from that location to that sump?
MR. SKOYEN: I don't know that -- we
haven't done a calculation on a crack size. We do
know that it would be somewhere between 165 and 350
drips per minute.
MEMBER ABDEL-KHALIK: No, I mean, size of
the hole.
MR. SKOYEN: I don't believe we've done
that. Tom?
MR. DOWNING: Yes. Again, my name is Tom
Downing. We've never actually calculated what size
hole would be needed to generate a one to two gallon
per hour leak, but intuitively it would seem that it
would be pretty small.
MEMBER ABDEL-KHALIK: It has to travel a
very, very long distance.
MR. DOWNING: Yes, it does travel a
torturous path. Again, leakage manifests itself in
ECCS sump anywhere from three to ten days after the
pool is flooded to a level of -- is pool at 35 feet, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 68 1 2 3
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MEMBER ABDEL-KHALIK: But that would be a
relatively simple calculation to do just to get an
idea how big a hole is that.
MR. WADLEY: We'll take a look at that.
We'll get back to you.
CHAIRMAN RAY: You guys are persuaded that
you know where the leakage is coming from. I would
just observe the seam leakage in these liners is not
uncommon.
MR. SKOYEN: We have inspected for seam
leakage in the past, both through vacuum box testing, POINT testing. We will be doing some additional seam
leakage testing this upcoming outage.
MEMBER SHACK: Well, I think that was the
point of Said's thing is to see whether that hole
size is really consistent with what you think is the
mechanism, a small crack in that seal weld or a
bigger hole which might indicate --
MR. SKOYEN: We have other problems. Okay, thank you.
CHAIRMAN RAY: But the fact is you do know
that these things are leaking? There's no doubt about
that.
MR. SKOYEN: 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 ARMIJO: And you had good success
when you seal them, although it's unreliable when you
seal them with coatings or caulking or whatever.
MR. SKOYEN: That's correct.
MEMBER ARMIJO: So there may be other
leaks, but these you know for sure.
MR. WADLEY: We have high confidence that
this is the most probable location of the leak. The
repairs that we'll perform then will validate whether
or not those -- our assumptions and our confidence
was truly supported in this location.
CHAIRMAN RAY: What's your experience on
the spent fuel pool?
MR. WADLEY: No leakage at all that I can
recall. Does anyone else have a --?
CHAIRMAN RAY: We may return to that if we
have time, but you're focused on this now so lets
continue.
MR. WADLEY: Yes.
MR. SKOYEN: Okay, we're going to enhance
our monitoring of the tank pressure vessel by
removing concrete from our sump Charley, which we
referred to before. That's the sump below the reactor
vessel. It's a relatively --
CHAIRMAN RAY: Jack, this is the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 70 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 excavation I was talking about that he's referring to
here.
MR. SKOYEN: We'll be removing concrete at
that location because it's the lowest -- as close as
we get to the lowest point in containment.
With respect to the head, there was
stagnant water there. That would be the most probable
location.
Again, that's 16 to 18 inches of concrete
we'll have to remove. Once that's removed, we'll be
performing both a visual examination and an
ultrasonic examination to assess the containment
pressure vessel.
If there's any water observed in that
particular area, that will be removed. We'll be doing
this in the outages following the repair locations.
MEMBER STETKAR: I take it you don't
expect to find any water in there, right?
MR. SKOYEN: I don't know if I'd make that
statement. We'll talk about that a little bit later
as well.
We'll also be performing some additional
assessments. We will be performing a margin
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rebar, as well as evaluating the structural NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 71 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 requirements potential degradation around the fuel
transfer tube.
Long term aging management -- we are
going to be monitoring areas that previously
exhibited leakage for the next two outages after the
repairs. That is in our corrective action program.
We'll continue general monitoring for new
leakage using the structures monitoring program per
ASME section 11 IWE program for the remainder of the
plant life.
For any new issues that are identified, we will be utilizing the corrective action program
for evaluation and application of additional
corrective actions.
We have performed evaluations of
potential degradation for the steel containment
vessel, the concrete, and the rebar.
With respect to the steel containment
vessel, as previously mentioned, we have not
identified any corrosion, nor have we identified any
wall thickness concerns. All of the readings we've
taken for wall thickness have been at or above
nominal. The water that would be done in that lower
elevation of containment would be essentially
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 continued corrosion.
The alkalinity from the concrete -- we've
demonstrated that that would elevate to a pH
sufficient to inhibit corrosion in those areas.
The containment vessel corrosion behind
the concrete in the areas wetted by the cavity
leakage, we would expect to be no more than 10 mils.
MEMBER ABDEL-KHALIK: Based on what?
MR. SKOYEN: That was based on evaluation
and the different factors that the time that the
refueling cavity actually leaks. It's very limited.
It's only during outages for approximately 15 days --
the buffering effect that you get from the concrete
and elevated pH.
MEMBER ARMIJO: This is 10 mils over the
whole life of this leakage?
MR. SKOYEN: That's correct.
MR. BARTON: How many years has this been
going on?
MR. SKOYEN: In performing our evaluation, we assume the entire plant life, although there
wasn't evidence of it prior to 1987.
With respect to the concrete, long term
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Dissolving the calcium hydroxide
neutralizes the acid if it's not refreshed, so if
it's not continually refreshed, that reaction would
stop.
The refueling cavity liner -- our
evaluation has concluded that there would be
negligible effect on the refueling cavity walls and
floor because those are all fortified feet thick with
the exception of one location which is adjacent to
the transfer tube. That evaluation of that area is
still ongoing.
At the containment vessel inside surface, the water would essentially be stagnant so the acid
would be neutralized by the alkalinity in the
concrete, again having minimal effect. It's not
refreshed other than during refueling outages.
Cracks in the concrete -- essentially the
same situation. The water would be stagnant so the
acid would be neutralized by the alkaline in the
concrete there as well.
MR. BARTON: How long after refueling
outage do you think that the containment vessel
remains wet? That that area remains wet?
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MR. BARTON: What do you think, yes, after
refueling outage and leakage stops, how long do you
think that area remains wet?
MR. SKOYEN: At the lowest elevation of
the containment vessel, potentially it could remain
wet indefinitely.
MEMBER SHACK: Is that how you calculated
your 10 mils? That indefinitely at some pH that you
assume from the concrete?
MR. SKOYEN: That's correct.
MEMBER SHACK: Okay.
MR. SKOYEN: With respect to the rebar, there is some potential for the refueling cavity
leakage to reach re-bar in the cracks. Corrosion of
the wetted rebar would be inhibited, again, by the
alkalinity in the concrete promoting a protective
layer.
Qualitative assessment concluded that
there had been no significant signs of corrosion.
We've not seen any spalling, concrete cracking at
these locations. We've only had minor rustings that
have come through hairline cracks.
So the conclusion is that the corrosion
of the rebar, whether wetted periodically or NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 75 1 2 3
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CHAIRMAN RAY: Well, that's the rhetoric
that I was referring to. We don't need to go into it, I don't think, if we're committed to stop the
leakage.
The main conclusion one draws from this
is it's not an alarming condition.
MR. SKOYEN: Right, correct.
CHAIRMAN RAY: But if we stop it, then we
don't need to draw the ultimate conclusions that
you're presenting here.
This is an awkward context for us to
address fundamental issues like you're dealing with
here. We'll talk to the staff about that later.
MR. SKOYEN: Right, I understand.
MEMBER ABDEL-KHALIK: But the statement
has been made that leakage is unacceptable.
MR. WADLEY: Yes, that's true. Correct.
MEMBER ABDEL-KHALIK: Yet this has been
going on for more than 20 years. Is this sort of a
new management attitude?
MR. WADLEY: Well, we've tried a number of
different methods to solve the problem. Performing
the root cause evaluation provided some additional
insights that we didn't -- we tried to do a fix, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 76 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 quick fix, with caulk and strippable material.
This approach is a more rigorous approach
to a deeper understanding of what we're dealing with
so I think we have a better solution.
It's never been acceptable, but we've
never spent the time and the effort to get to the
details. We didn't come up with a proper solution.
MEMBER ARMIJO: I just had a quick
question. When you excavate under that sump C, now
that won't be the lowest point on your containment
vessel. Is that a concern, you know, that you're
going to look for evidence of water or corrosion
damage, but that's still -- I don't know -- maybe a
foot or two higher than the bottom. I don't know. The
low point of the vessel seems to be -- you won't ever
see that.
MR. SKOYEN: Tom, do you know the
difference between exact elevation?
MR. DOWNING: Yes. If I'm understanding
your -- again, my name is Tom Downing from Prairie
Island.
If I understand your question, you're
asking about the location of the excavation and it's
not bottom, dead center.
MEMBER ARMIJO: Yes.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. DOWNING: That's true and I would
agree that in an ideal world, it would be nice to be
able to excavate bottom, dead center because if water
had pooled there, that you would expect it to be.
It's just not really physically possible
in that the concrete is so thick there. It gets three
to four feet thick and even trying to excavate
through 16 to 18 inches of concrete with a mat of
steel at the top and then a double mat towards the
bottom would be very difficult.
MEMBER ARMIJO: No. I'm just -- I agree
with that and I wouldn't expect a pool of water
there. I just -- if it's spreading out and it's
wetted, I just wondered how many inches difference
there is between the dead center bottom and where
you're excavating.
MR. DOWNING: My recollection, from
looking at past drawings and trying to determine how
thick that concrete is, is that it's approximately
eight feet from bottom, dead center where we're going
to be excavating.
MR. ECKHOLT: What's the difference in
elevation, Tom?
MR. DOWNING: Yes, the difference in
elevation -- again, this is just pure -- my NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 78 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 recollection. I think it was in the realm of about a
foot and a half.
It's the 105 foot containment and then it
comes up as an ellipse so if you assume it's a
perfect ellipse, you can kind of figure that out.
MEMBER ABDEL-KHALIK: And the purpose of
this is to confirm that your 10 mil calculation is
correct?
MR. SKOYEN: That's correct. To assess at
that particular location, ensure that our centers are
correct, as well as provides us an opportunity that
if any water has pooled there, to evacuate that
water.
MEMBER ABDEL-KHALIK: Do you know the
thickness of the containment anywhere to within 10
mil accuracy?
MR. SKOYEN: We have performed containment
vessel inspections as we mentioned previously, both
from the annulus in the transfer tube area and at the
ECCS sump. Within 10 mils of accuracy is what you're
referring to?
MEMBER ABDEL-KHALIK: Right. Anywhere.
MR. SKOYEN: We know the nominal plate
thickness that was delivered so we have a fairly
strong understanding of what the thickness will be.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. ECKHOLT: I think the UT measurements
have been pretty uniform.
MR. SKOYEN: They've been fairly
consistent uniform.
CHAIRMAN RAY: Well, the excavationisn't
intended to verify the 10 mils, I don't think.
MEMBER SHACK: But you don't want to see
significant corrosion there because then it raises
Sam's question. Exactly how much corrosion is
significant may be argued but --
MEMBER ABDEL-KHALIK: But the presentation
earlier indicated that this analysis led you to the
10 mil estimate was done in a very conservative way.
MR. SKOYEN: That's correct.
MEMBER ABDEL-KHALIK: So in a sense, by
doing this, you're trying to confirm that your
analysis was indeed conservative, that indeed that
reduction and thickness, if any, does not exceed the
10 mil. The question is, how can you tell?
MR. SKOYEN: We would have a pretty good -
- from the surface examination, we would also have an
idea if there had been any reduction, evidence of any
corrosion.
MEMBER ABDEL-KHALIK: Okay.
CHAIRMAN RAY: You also had some NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 80 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 experiments done by your consultants, I believe, and
those ideal experiments showed it was very low. I
just think 10 mils is a very small number. I would
have put more windage on that.
MR. WADLEY: And I appreciate the question
and the comment.
MEMBER MAYNARD: I understand that the
conclusion on the significance here. I'm just not
sure how long that's valid. The concrete kind of
neutralizing the boric acid -- you do have a chemical
process going on and I don't know how long that can
go on without starting to degrade the concrete or the
rebar.
At some point, you lose the ability to
continue to neutralize it. I don't know if that's
1000 years or if's that's five years. I don't have a
feel for that, but I'm kind of curious as to how long
those conclusions are good for.
MR. DOWNING: Hi. This is Tom Downing
again. The 10 mils was based on 36 years of operation
to date. Again, we have not see any corrosion.
We do not believe there's any corrosion, but we would expect a similar evaluation for 36 years
forward so that a total over 72 years is potentially
20 mils.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CHAIRMAN RAY: That's what I was referring
to, Otto, and I mentioned this is an awkward place to
try and deal with fundamental physics of something
like what's the threat of borated water in the wrong
place for a long time, which is not to say that we
shouldn't have some way of dealing with that.
It's just that I'm not sure that all the
work the applicant has done here, we can conclude is persuasive. The inspection of the
containment itself by this excavation was what I felt
was most valuable and the commitment now heard to
arrest the continued leakage. Go ahead.
MR. SKOYEN: Okay. Just in conclusion, the
expected containment vessel corrosion behind the
concrete in the wetted areas, we would expect to be
minimal, as we've been discussing.
We would also expect the concrete
degradation and any associated rebar corrosion not to
have had a significant effect on the reinforced
concrete that has been wetted in a leakage.
CHAIRMAN RAY: Okay, we're almost on time.
MR. ECKHOLT: Almost, just a final
summary.
The LRA was developed by an experienced
team. It conforms to the regulatory requirements and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 82 1 2 3
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Prairie Island will be prepared to manage
aging during the period of extended operation.
CHAIRMAN RAY: Would you put up your back-
up slide 49, please? I want to make sure that members
still have the list here. We've read about many of
the items that are accepted here.
I don't recall reading about the steam
generator tube integrity program exception. Can you
comment on that?
MR. ECKHOLT: Phil, can you touch base on
that?
MR. LINDBERG: Excuse me. This is Phil
Lindberg, Xcel.
The exception to the steam generator tube
integrity program falls in the category of using a
later revision of an industry standard then what's
recommended in GALL.
I believe it's NEI 97-06 standard. I
believe we used Rev 2 where GALL recommends Rev 1, so
that's the exception.
CHAIRMAN RAY: That's why I didn't read
about it, I guess. All right, other questions of the
applicant.
MR. BARTON: I got -- there's a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 83 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 description in the LRA on the stem generator system.
You mentioned unit 1 steam generators have flow-
limiting devices, steam nozzle for main steam line
break limits steam flow, but on the second unit, you
don't mention anything about the flow limiting
devices in the case of a main steamline break. You do
have them?
MR. ECKHOLT: Yes, they're intervaled in
the main steam line. Richard, can you --?
MR. PEARSON: This is Richard Pearson. The
flow limiting devices in the steam nozzle exist only
on the unit 1 replacement steam generators.
For unit 2, there is no flow limiting
orifice, so the break at the top of the steam
generator sees the full opening of the steam outlet
nozzle.
MR. BARTON: So limiting the flow limiting
device is somewhere in the steam line through that?
MR. PEARSON: Yes, just downstream of the
elbow at the top -- well, there is a flow-limiting
device. It's the flow orifice and that does limit
flow for the breaks downstream of the flow element.
MR. BARTON: Okay, I was just wondering
why you described the unit 1 was and unit 2, you
didn't --
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. PEARSON: Because it's part of the new
MR. BARTON: I got you, thank you.
CHAIRMAN RAY: Speaking of steam
generators, you said unit 2 replacement is planned, Mike.
MR. WADLEY: 2013.
CHAIRMAN RAY: 2013. Any other questions?
We will take a 15 minute break and return at 10:25.
(Whereupon, the hearing went off the
record at 10:07 a.m. and resumed at 10:23 a.m.)
NRC PRESENTATION CHAIRMAN RAY: Back to order, please. We
will now hear the NRC staff presentation on Prairie
Island. Mr. Plasse?
MR. PLASSE: Yes, good morning. My name is
Rick Plasse. I am the project manager for Prairie
Island's license renewal application.
For today's presentation, we'll be
discussing the results of the staff safety review of
the application.
With me, to my right is the lead
inspector from region 3, Dr. Stuart Sheldon. He led
and conducted the regional inspection in January.
Stuart will be presenting the results of that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 85 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 inspection.
Seated in the audience are various
members of the NRC staff that participated in the
reviews. Results are contained in the SER with open
items. They're here to assist and answer any
questions that may arise.
For today's presentation, we'll start
with a brief overview of the application and then a
discussion on section 2, scoping and screening
results.
Then I'll turn it over to Stu to address
the regional inspection, followed by a review of
section 3, aging management program and aging
management review results, and then section 4, TLAA
discussion.
The applicant discussed the open items in
detail. Brian had mentioned staff is continuing to
make progress on the open items. Some of it was due
to timing of some of the recent information provided
by the applicant.
I will provide a snapshot of the status
of those items at the applicable portions and
sections where we have a discussion on those items.
Next slide overview, I think the
applicant pretty much touched upon this. I don't want NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 86 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 to go back and rehash it unless someone wants me to.
I'll go to the next slide.
Overview -- the SER with open items was
issued June 4. There were the three open items as
discussed in detail, which we'll touch upon.
There were 168 REIs that were issued as
the staff went through its review process. There's 36
commitments to each unit. There's no unit-specific
commitments. They're all pretty much applicable to
both units.
As you probably noticed, I believe
there's more numbers. In the actual commitment list, there was a couple of items which were updated that
were in use and there were several environmental
commitments that are in the record, in the commitment
list. But as far as the safety review, there's 36
commitments for each unit.
This slide just gives a list of the
activities that the staff and the region undertook
going through the review. We have the scoping and
screening methodology, which was in August of `08. We
have the aging management program documents, which
was September of `08. The regional inspection was in
January of `09. They had a formal exit in February of
`09.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Then we had a follow up audit on the
topic that we had and the technical discussion
earlier on reactive cavity leakage -- a one day audit
included one of our contractors and some of the NRC
tech staff.
A couple things I just wanted to note. As
the staff completed its review, had completed its
audit, we had a couple issues that we still needed
follow up. We had follow up REI's.
Also, we asked Stu, as part of his
review, to do some reviews in the field in January
and give a couple of examples of those. We talked in
detail about the medium voltage cables and the
manhole, the 13.8 kV safety related manhole.
When we did the audit in September, we
had the applicant open that manhole for our audit
team to inspect, so we inspected that in September.
We did not see any evidence of any water intrusion.
Also, in January, when the region was
there, they opened it again in the cold of the winter
of Minnesota and I believe they didn't see any
evidence also.
And one point I'd like to make, the
applicant mentioned in their slide on the medium
voltage cables, the recent failure they had with the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 88 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 circ water. That is a non-safety related circ water
pump.
They are doing a root cause and there
will be an LAR and any extended condition, they'll
address in that LAR. It did result with a plant trip, so that LAR is not due till 60 days following the
event. I believe the event was mid-May -- May 18 or
so.
With that, I'll go to the next slide.
MEMBER ABDEL-KHALIK: I know it was kind
of facetious, talking about the mid-winter in
Minnesota, but are there any submerged cables at all
on site? If they go through the winter and they go
through a freezing, thawing process, is that more
damaging than wetting and drying cycle?
MR. PLASSE: Anyone on the staff like to
respond to that one?
MR. LI: My name is Rui Li. I'm an
electrical engineer for the division of license
renewal.
I went to Prairie Island for an audit.
The cables in Prairie Island are direct buried, so
most of the cables are underground so you wouldn't be
able to see them.
Unlike most of the other plants that we NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 89 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 visited previously, there is only one manhole in this
plant.
MEMBER ABDEL-KHALIK: But my question
pertains to whether or not going through a freezing, thawing process would be more damaging than wetting
and drying cycles?
MR. LI: I can get back to you on that, but the point I'm trying to make is because these
cables at Prairie Island are on direct bury, it's
hard to observe that phenomenon in this place -- to
see if there's actually any ice underneath close to
the cables.
MEMBER ABDEL-KHALIK: Okay, thank you.
MR. MCCONNELL: This is Matthew McConnell
with the electrical engineering branch. I was
involved with the review of the Prairie Island
To answer your question, the answer is I
don't know. I mean, it may be, It depends on the
chemical make up of the cables, the insulation and
type, and how long the cables would be exposed to
such condition.
My understanding is there's no evidence
of that type of activity going on at Prairie Island, specifically with safety-related cables, so that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 90 1 2 3
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I'm aware.
MEMBER MAYNARD: I would suspect that most
of the cable would be below the freezing level there, but there may be areas where --
MEMBER STETKAR: Yes.
MEMBER ABDEL-KHALIK: I mean, if they have
an inspection frequency of once every two years, it
is conceivable that you can accumulate enough water
in a pool box without detecting it. That water would
go through the water, freeze, and you would have a
cable that would undergo that kind of cycle.
MR. HOLIAN: This is Brian Holian. Just a
reminder for the committee, they did start off with a
quarterly inspection program and hopefully, taken
that through several quarters to check that very
theory.
But we were talking about the regional
aspects too on how well they follow through on their
commitments in that aspect and what those commitments
are based on. So I'm sure Dr. Sheldon will be able to
monitor. Hopefully, we've historically looked at did
they do enough to base their current inspection
frequency on.
I don't know if the region can talk to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 91 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 that, but that is one time the staff will continue to
follow.
MEMBER ABDEL-KHALIK: Thank you.
MR. PLASSE: Okay, to go on to section 2
of the application. The applicant had mentioned that
they have now placed the radwaste decay tank in
scope.
By letter dated June 5, the applicant
included the waste gas decay tank within the scope of
license renewal. I said I'd give a status of the
ongoing activities.
The staff has completed its review of the
information provided by the applicant in the June 5
letter. I have been told by the staff that this item
can be closed and it will be documented in the final
SER.
With that, for section 2.1, the staff's
audit and review has been concluded that the
applicant's methodology is consistent with 54.4 for
in scope and 54.21(a)(1) for components subject to an
AMR.
Section 2.2, the staff found no omissions
of plant-level scoping systems and structures within
the scope of license renewal.
Section 2.3, mechanical systems -- the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 92 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 staff completed a review of all systems. As
documented in the LRA, there were 37 mechanical
systems. 29 of the systems were a balance of plant
auxiliary and steam and power conversion systems.
I've got a sampling of some of the things
that were added to scope based on RAIs, plant floor
drains, flex connections, fire dampers, the waste
gasket K-tank. There were several stainless steel
flex connections in the heating system, diesel
generator and support systems.
Also, several boundary drawings were
noted where in-scope components were inadvertently
shown as out of scope on the drawings.
The components, however, typically were
already addressed in the LRA tables and therefore, there were no LRA changes required. But the staff did
do a 100 percent and those RAIs are documented in the
SER where these applicable things were addressed.
Section 2.4 and 2.5, there were no
omissions of components within a scope of license
renewal. However, just as a note, during the
acceptance review, a discussion was made with the
applicant to understand the station black-out, which
the applicant kind of discussed in their
presentation, so there were some additional scope NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 93 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 adds in the switchyard, which the applicant addressed
with the blue coloring in his slide, slide number 13.
With that, with the one open item, which
the staff has since determined should be able to be
closed, there were no omissions from the scope of
license renewal in chapter 2.
At this time, I will turn the
presentation over to Dr. Stuart Sheldon to discuss
the regional inspection.
MR. BARTON: Rick, before you do that, I
have a question. What's the current staff position on
fuse holders? Has there been a change to GALL or
something that I missed?
Since day one, I always thought fuse
holders ought to be in scope for aging management
programs. I keep beating a dead horse and was told to
get off of it, and now I notice that in the
applications I've been reviewing in the past year, people are now starting to have aging management
programs for fuse holders. I don't understand what's
going on.
MR. NGUYEN: This is Duc Nguyen from
license renewal. Right now, we don't intend to change
the GALL. It can sit with the regulation if the fuse
folder at the assembly, then this is our scope of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 94 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 aging management review and depending on the plant-
specific, if the fuse holder will determine that they
have no aging effect, then they are not required in
the aging management program. This is a plant-
specific review.
MR. HOLIAN: This is Brian Holian. Just to
add on to that, I think you've seen some, maybe a
consistency over the years.
MR. BARTON: Yes.
MR. HOLIAN: Just as a reminder, that
plant lighting issue was a similar item in here.
License renewal, if the applicant puts it in scope, we'll take it.
So that's a short answer. If they go
ahead and add it and it's part of their program and
they do it for simplicity or however they're
organized on site by discipline, we'll keep it in
scope. So that's what you're seeing here.
We are going through a GALL update now.
People are giving us comments. I know fuse holders is
one of those areas where historically it's been
thought should it be in scope, generically or not.
I think you heard from a reviewer that
our initial thought is that it still would not be
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ferret that out this year as we finish our reviews of
that.
MR. BARTON: Thank you.
MR. SHELDON: Okay. I'm Stu Sheldon. I led
the license renewal inspection for the region at the
end of January of this year.
We had five experienced inspectors and
one newly qualified inspector as an observer on this
inspection.
We conduct the inspection under
inspection procedures 71002. Our focus is on scoping
and screening in aging management. We focus on (a)(2)
non-safety affecting safety systems. Our primary
means are physical walkdowns of systems to verify
their proper scoping and material condition.
We didn't identify any issues within the
scoping aspect of this. They're very conservative in
their scoping aspects. We did identify a few minor
material condition issues that they entered in their
corrective action program some corrosion that they
had not identified previously, some very small fuel
oil leaks, that type of thing.
We reviewed 24 of the 43 aging management
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 of the existing programs -- that they have an
existing program.
We also conducted walk downs of any
applicable systems -- if the program has an
applicable system, we conduct walkdowns then. We also
had the opportunity to accompany a unit 1 containment
entry. During this inspection, one of our -- ISI
inspector -- would have to go within the unit 1
containment and in the annulus area surrounding the -
-
MR. BARTON: What did you think of the
material condition inside containment?
MR. SHELDON: My report is that it's very
good. He did identify a leaking valve while he was in
there. I don't remember how many drops per minute it
was. It was a very small leak on a valve that --
that's what they were in there looking for.
CHAIRMAN RAY: Are you talking about a
MR. SHELDON: Right, packing leak.
MR. BARTON: That seems to be an issue. I
think you pointed out in your inspection report that
there have been historically a lot of packing leaks
and boric acid leaks, etcetera. Is that still an
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MR. SHELDON: I don't remember --
MR. BARTON: That was in the audit report.
MR. SHELDON: Okay, I don't remember
making that kind of statement.
MR. BARTON: As far as, during your
inspection, did you look at that? Was that an issue?
MR. SHELDON: The ISI programs, we did
look at. We didn't find any issues with what they
were doing on their ISI.
MR. BARTON: I was just wondering whether
it was a training issue or whether it was still
ongoing.
It was in the audit report. It wasn't --
you guys probably -- you didn't point that out. Do
you know, Rick? MR. PLASSE: Maybe some of the staff can help me out. There were several RAIs and also
subsequent follow-up RAIs on the boric acid program.
MR. SHELDON: We did have some questions
associated with it on whether they were meeting the
code and leaving the boric acid on the components.
The results of that is no, they are not.
They are cleaning it off -- not necessarily during NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 98 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 that containment entry, but when the problem is
corrected, then the boric acid is cleaned off. There
were questions concerning that.
MR. PLASSE: My recollection is -- and the
applicant can, if I misrepresent something, they can
correct me -- is that they don't intend to leave
boric acid residue. They intend to clean it up as
soon as they can.
In some cases, there may be a dose case
or something where they make a decision to not get it
at that point and time, but they evaluate those
specific cases. Erach did those RAI's. He can
probably --
MR. PATEL: Hi. I'm Erach Patel. I'm with
the boric acid corrosion program.
Yes, you're right. They did have a
significant temporal valve packaging -- packing their
leakages on. They took a generic evaluation of that
and they reviewed live load packings and they
replaced a whole bunch of packings and they're trying
to make sure that they're going into the source of
the leakage itself to make sure that they prevent
those leakages.
So the corrective action program does
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MR. BARTON: Thank you.
MR. SHELDON: As part of our review, we
also interviewed plant personnel, specifically the
program owners who are going to be responsible for
implementing these programs to verify that they
understand what the program is and are involved with
the development.
Our operating experience review consisted
of reviewing system health reports, program results
from sampling programs, and we had access to the
corrective action program and did searches on our own
to look for anything that might be inconsistent with
what they said in their application. We did not
identify anything there.
One unique aspect of this is we had an
observer from the Prairie Island Indian community. On
our inspection, the tribal counsel president of the
Prairie Island Indian community came and observed as
we did our inspection.
Of the aging management programs that we
reviewed, this is a list of those which we identified
some sort of issue. Primarily, they were issues with
-- the program was stated as consistent with the GALL
and there were minor differences between what we read NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 100 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 as being required of the GALL and their procedures.
For example, with the external services
monitoring program, the applicant agreed to improve
their procedures to add specific acceptance criteria
for degradation and include other types of
degradation besides just corrosion, like blistering
paint, flaking paint, that sort of thing.
MEMBER ABDEL-KHALIK: Back to the previous
slide, is there a system health report for the
refueling cavity?
MR. SHELDON: I couldn't tell you that.
Does anybody over there -- can answer that?
MR. MCCALL: Yes. This is Scott McCall.
I'm the system entering manager at Prairie Island.
There's not a specific system health
report for refueling cavity. However, the spent fuel
pool and its associated components -- there is a
health report for that.
MEMBER ABDEL-KHALIK: What does the health
report say -- system health report?
MR. MCCALL: I has -- have there been
problems with the system.
MEMBER ABDEL-KHALIK: No. Specifically
with regard to the leakage issue.
MR. MCCALL: For the refueling cavity? It NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 101 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 says that there has been problems in the past
regarding that. However, we have used, like we
previously talked about, means to arrest the leakage.
MEMBER ABDEL-KHALIK: And this problem has
been documented in the system health reports for the
past 20 years?
MR. MCCALL: No. System health reports
have really only been around the station in the last
five years, so five to six years. Don't quote me on
the exact date, but we've not had system health
reports since the late 80's.
MEMBER ABDEL-KHALIK: Thank you.
MR. BARTON: Stu, during the inspection on
the aging management review of the closed cooling
water system, your inspection team discovered that
the site hadn't taken some chemistry samples for
several years due to a shortage of chem techs -- this
is probably a question for the applicant.
They took the samples while you were
there, but my question is, if I hadn't taken a sample
for three years, do I really need the samples? And
have you corrected the chem tech issue, shortage of
chem techs?
I guess I'm addressing that to the
applicant. It was an item that you brought up in your NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 102 1 2 3
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MR. ECKHOLT: This is Gene Eckholt. The
answer is yes, we need to take the samples. They
weren't stopped because there was a lack of need or a
perceived lack of need. There were some personnel
losses that we responded to probably inappropriately
by management, supervision at the time that suspended
the inspections. That has been remedied. They are
being taken again.
These are EPRI-required parameters we're
monitoring, They are to monitor the long-term
condition of the components, so they were never
stopped because of any perception that they weren't
important.
MR. BARTON: Since that's been corrected
and they are important and you are taking them as
scheduled. Is that what I'm hearing?
MR. ECKHOLT: That's correct.
MR. BARTON: Okay, thank you.
MR. SHELDON: Okay, any other questions
about the aging management program?
So the results of our inspection, which
we presented at our February 18 public exit meeting, is that our results support a conclusion that there's
reasonable assurance that the effects of aging will NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 103 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 be adequately managed.
We found scoping of the non-safety
systems was acceptable and that documentation
supporting the application was auditable and
retrievable. I've listed the inspection report there.
The next few slides deal with current
licensee performance. All other performance
indicators are currently green. Both units are in the
regulatory response column, column 2, to do some
white inspection findings.
The fourth quarter 2008 finding was aux
feedwater pump failure because of a mispositioning of
a valve. The most recent white finding was a
transportation issue where the package arrived and
the survey showed that it had existed DOT limits.
CHAIRMAN RAY: Is the aux feed pump
turbine driven or motor driven?
MR. SHELDON: I don't know. I can't tell
you on this particular pump.
MR. PLASSE: I believe it's turbine
driven.
MR. SHELDON: But it was a discharge
pressure switch that was isolated to protect the pump
so that it doesn't build up discharge pressure.
MR. MCCALL: I can speak to that.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. SHELDON: Go ahead.
MR. MCCALL: Scott McCall again. It was a
turbine driven aux feedpump. Was that the question?
CHAIRMAN RAY: It was. I was interested in
then, but I've already found out what the
misalignment was.
MR. SHELDON: That's all I have.
MR. PLASSE: Any more questions? Okay, we'll move on to section 3. This first slide shows
the break down of section 3. It's pretty standard
with license renewal applications.
I did not plan on covering each
subsection. I will touch again on the open items and
other information that may be of interest.
The first slide, that's just documents. I
think the applicant had a similar slide. He might
have broken them up a little differently.
This shows the breakdown of the aging
management programs. 14 were identified as new
programs. There's a total of 43 programs. 29 were
existing programs. 22 were identified as consistent
with GALL. 9 were identified as consistent with the
GALL with enhancements. 4 were ere identified with
exceptions to GALL. 6 were identified with exceptions
and enhancements to GALL. 2 were identified as plant-NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 105 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 specific programs. We have a bullet.
We mentioned earlier about the
contentions. One of them was they didn't have a 10
element program, nickel alloy, which they put a
plant-specific program March 27. Also, the vessel
internals program, which is an open item I'll get to
on a subsequent slide. With that, unless someone has
question on the break down of the AMPs, I'll move to
the next slide.
The vessel internals program, as Brian
had mentioned in his lead-in, is a timing issue. The
applicant put in on May 12 -- they voluntarily
submitted an amended program with the 10 elements.
The staff is in the process of reviewing that.
It also has additional AMR line items, which the staff is going to have to digest the
document, so that is a task that's in place right
now. That will all be documented in a final SER.
I don't have anything negative with
respect to the letter at this point, other than that
the staff is still continuing to review that item.
MEMBER SHACK: Just on a generic question
-- that commitment for the PWR internals has been in
all the license renewal applications and the 24 month
clock is ticking.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 When is the first guy up to the plate?
When are we actually going to see a plan?
MR. CHERUVENKI: This is Ganesh
Cheruvenki. I work with the MMR, vessel and technical
branch.
The first one is being reviewed. They
submitted the PWR AMP, vessel internals. We are
currently reviewing it. We are also reviewing MRP-
227, which was submitted in early January of this
year.
So we are trying to issue the SC some
time next year for both the reports, AMP and also
MEMBER SHACK: Okay.
MR. PLASSE: Next slide is relative to the
ground water in the area of the plant. What the data
shows is that the ground water in the area of the
plant is not aggressive to rebar embedded in
concrete. The data and the results are in a table.
The structure monitoring program includes
sampling of the ground water and river water
chemistries once every five years for the period of
extended operation.
The bottom line is the ground water is
non-aggressive to rebar in concrete.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 The next item -- we went through at
length with the applicant on the status of this open
item with respect to the water seepage from the
reactor cavity.
I don't have anything to add at this
point, unless you have a specific question that you
would like to gear towards the staff on the issue.
MEMBER ABDEL-KHALIK: Have you done a sort
of a calculation that would show how much margin
there is, so if they were to do an inspection and
find that there's a quarter of an inch of wastage, would they still have plenty of margin?
MR. SHEIKH: My name is Abdul Sheikh. I
work in the license renewal branch. So far, we
haven't done any calculations on this issue.
MEMBER ABDEL-KHALIK: Wouldn't it be a
reasonable thing for the staff to do?
MR. SHEIKH: Are you talking about the
liner?
MEMBER ABDEL-KHALIK: Right. We're talking
about 10 mils. What if it was 100 mils. What
difference does it make?
MR. SHEIKH: We looked at the report, which the licensee as applicant has produced and
there's not too much margin in their calculations. So NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 108 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 if it is, say 100 mils or 200 mils, it won't satisfy
the code requirements. This is according to the
licensing department.
MEMBER ABDEL-KHALIK: Let me just try to
understand what you just said. By reviewing the
analysis of record, you have determined that they
really don't have much of a margin. Is that correct?
MR. SHEIKH: I have not looked at the
analysis of record. I have looked at the report
produced by the applicant in which they stated that
there is not too much margin.
MEMBER ARMIJO: Can you put a number on
that? What do you mean by not too much?
MR. SHEIKH: It is just barely -- I mean, it's like 1.5 inches thick, the containment. The
actual figure quoted in the report was about that
number.
MEMBER SHACK: Remember, if you assume
uniform thinning, you can't take all that much. You
can take localized thinning, sort of a la that famous
New Jersey plant.
MEMBER ARMIJO: But the burden is going to
be on the applicant to find this. Whatever they find, they're going to have to justify acceptability of it
to be reviewed by the staff.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. HOLIAN: This is Brian Holian again.
We had wanted to put this in -- the licensee did a
good job, I think, in the presentation earlier. But
in safety significance perspective, it's an item that
we think we're ahead of. I mean, ahead of in some
ways.
They've been living with leakage for
awhile, but they've been allowed to live with leakage
based on regional inspectors and other folks looking
over their shoulders for years and assessing the
safety significance.
So in this particular plant, they thought
they've had it fixed a few times and that's come back
at them. On safety significance though, we do believe
that there have not been instances where there's been
corrosion through and isolated instances.
I think that comment on the margin was
more of an overall view. We'll take a look at that
again closer. I think it was, as was mentioned there, kind of uniform thinning along that line.
We don't see that and we think the
licensee is getting ahead of that, but I did want to
mention that from a safety significance perspective.
This is minor leakage, all within containment -- no
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I think license renewal has taken a
closer look at it because this plant, in particular, raised the issue of what is the flow path. It was
harder for the staff to understand here.
We had presented to this committee
another plant a few months ago that had much larger
leakage, but had a little better idea of where it was
coming down from the refueling cavity -- out of the
welds and almost straight down.
So that's one reason why, in particular, we're looking at an issue like this for, is the GALL
sufficient? Is there any other aging mechanisms or
programs that need to be in place to increase the
inspection frequency as you go over longer periods of
time?
MEMBER ABDEL-KHALIK: I was just trying to
put this thing in perspective. When the applicant
says they've done a conservative analysis and it
shows that the maximum is 10 mils, I want to compare
that against what margin they have.
It would seem like a reasonable question
to ask for which somebody should have an answer right
off the top of their head.
MR. HOLIAN: The applicant can respond to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 111 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 that, if you like.
MR. DOWNING: Hi. My name is Tom Downing.
There are a couple of things one considers on that
question. One was the design code of the vessel. It
was built for section 8. Under that code, we
calculated minimum thickness was 1.5 inches.
Now, that's very conservative in that
pressure vessels are designed with a safety factor of
- 4. The allowable stress is 17.5 KSI. The actual
minimum potential stress is 70. So consequently, you
could potentially have thinning of 3/4 of the way all
the way through wall and not expect the vessel to
fail.
However, once the vessel is built and
installed, it moves from section 8 code to section 11
code. Under section 11, any thinning will need to be
evaluated. However, thinning of 10 percent or less is
acceptable without further evaluation.
So consequently, we could have up to 150
mils of thinning over a very large area and
immediately evaluate it as acceptable. Any more
thinning would require further evaluation, but could
still be acceptable under section 11.
MEMBER ABDEL-KHALIK: Thank you.
MEMBER STETKAR: Just to clarify my NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 112 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 understanding of the leakage. There is no place where
they have actually found evidence of leakage against
the liner itself. Is that correct?
MR. DOWNING: That's correct.
MEMBER STETKAR: The places where they
have found leakage is places where the liner is
embedded between two layers of concrete -- one below
and one above. Is that correct?
MR. DOWNING: That's also correct.
MEMBER STETKAR: Okay, thank you.
CHAIRMAN RAY: The discussion just given, by the way, does appear in the response to one of the
RAIs in part C.
What I would observe, Brian, is that
we've learned through bitter experience to be very
concerned about leakage of borated water on
mechanical components. We're now aggressively
removing deposits of boric acid.
We don't have any comparable way of
assessing in a context like this what would be the
significance of the leakage we're talking about here
for structures or, in this case, the containment
pressure vessel.
It does seem as if we ought to -- I mean, the applicant has done all that, I think, in the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 113 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 context of a license renewal application, one would
expect him to do in terms of trying to address things
such as the interaction between boric acid and
concrete and the likelihood that it doesn't represent
a threat to the rebar and so on and so forth.
And now we've been talking about the
containment, which we have other reason to be
concerned about as well, just from an experience
stand point.
But what's lacking is some generic
conclusion about this subject. I just think it would
be bad for us to wait until we, in fact, discovered
something that was seriously problematic to then say, well, we need to decide whether this is a serious
problem or not.
As I said, the applicant has said we're
going to stop it. Although it has gone on for along
period of time, it doesn't -- we don't have any
reason to think that there's a problem. Nevertheless, they're going to excavate and look at a sensitive
area here and tell us, at least with regard to the
period of extended operation, that it's okay.
So my personal view is that we've got as
much from the applicant as we can, but still, it's
not very satisfying that we don't have a better NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 114 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 generic way of assessing these kinds of things and
saying is this a big deal or not a big deal? Should
we worry about it or not worry about it?
I'll just leave you with that comment.
You can respond as you wish.
MR. HOLIAN: No, I think that's a good
comment. Prior to making our presentation, we've come
here particularly to talk on the license renewal
presentation and oftentimes the staff doesn't bring
in at these same meetings what we might be looking at
generically or generic correspondence or even with
research.
I know research is pushing NRR and the
license renewal staff for operating experience on
these type of issues. They are themselves working
with EPRI on light water reactor sustainability and
cables and concrete for extended periods. So there
are actions back at the staff that we're doing.
We do interface from license renewals
with the reminder with the ROP, reactor oversight
process, for kind of moving inspection insights.
Should we be doing more from inspection oversight
over the years for a problem like this? Is it worth
more samples from an inspector? That's one piece.
We interface with the individual tech NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 115 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 branches on the containment and the cables issue. We
do, and I compare this to a recent issue with
submerged cables. It's both a license renewal issue.
It is in GALL and it is a current operating issue.
I don't know what the answer is, particularly today. I did want to put it in the
safety significance that the issue does not appear at
the plants we've seen to date to be a current issue
over the next one year, two years, four years, five
years at all at any of these plants.
It is something we know we need to track
through the period of extended operation and we will
pick it up on a generic aspect in some of our task
within OR.
CHAIRMAN RAY: Well, I don't know where
we'll ultimately and the full committee come out on
this, but I just don't think we want to leave the
impression that while we read all of this stuff, we
waited, and we've come to a conclusion in this
context.
MR. PLASSE: Okay, any other questions for
the staff on this issue?
Well, with that, that concludes the
section 3 review with the exception of the two open -
- the new plant-specific vessel internals 10 element NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 116 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 program and the cavity issue.
The staff concluded that the applicant
has demonstrated that aging effects will be
adequately managed during a period of extended
operation in accordance with 10 CFR 54.21(a)(3).
Moving on to chapter 4, just as a note in
section 4, we do not have any open items. This is the
general layout of section 4.
MEMBER ABDEL-KHALIK: Back to the previous
slide, if you don't mind.
MR. PLASSE: Sure.
MEMBER ABDEL-KHALIK: Have you reviewed
their root cause evaluation report?
MR. PLASSE: We spent -- early on, I
showed a slide of the activities of the staff. The
staff sent out a team of three individuals -- our
contract from Oak Ridge, a branch chief, and a tech
staff to review the root cause.
Subsequent to that, they had an RAI, which went out, that the applicant responded to on
June 25. I can have someone from the staff who was on
that one day audit could speak to that, if you would
like?
MEMBER ABDEL-KHALIK: And you're satisfied
that the root cause they have identified is indeed NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 117 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 the root cause?
MR. PLASSE: That item is still under
review. As I stated, the letter just came in June 25.
Abdul spoke. He was the tech staff individual.
At this point, the staff is still
reviewing it. I can't comment unless they would like
to comment.
MEMBER BONACA: That is a critical element
because they now have created a monitoring problem.
Then of course, you got the knowledge you're going to
monitor and why you're monitoring. MR. HOLIAN: Yes, I think from the staff perspective, we're still reviewing the root cause.
You heard another plant talk about
refueling cavity leakage right through the weld
connections halfway up -- refueling cavity.
So I know there's some thought of are the
bolted connections the primary aspect of the leakage, but the staff will still cover that and cover that in
the SER update for the final.
MR. PLASSE: Any other comments? Okay, back to section 4.As I stated, we do not have any
open items in section 4 in TLA.
We do have a few slides of some items NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 118 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 that have been of interest in previous ACRS
subcommittees and we provide some of that data for
your interest.
The first area is section 4.2, reactor
vessel neutron embrittlement. Review was performed to
evaluate fluence and embrittlement in terms of upper
shelf energy and pressurized thermal shock. That will
be the first couple slides.
With respect to upper shelf energy, the
limiting beltline materials are stated. Of note is
the last two columns, the irradiated Charpy V notch
upper shelf energy at 54 effective full power years
is 59 foot-pounds for unit one, and 57 foot-pounds
for unit two.
The acceptance criteria of appendix G for
a period in operation is greater than 50 based on
since the upper shelf energy values are projected to
be greater than the acceptance criteria at 50 pounds.
The vessel will have margins of safety
against fracture equivalent to those required by
appendix G through the end of the period of extended
operation.
The next slide is with respect to thermal
shock, pressurized thermal shock values. Again, eliminating beltline materials, the RTPTS off unit 1 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 119 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 is 157 degrees Fahrenheit. For unit 2 is 136. The
acceptance criteria for 10 CFR 50.61 is less than
270.
The staff independently calculated RTPTS
values and these values are below the threshold
criterion specified in 50.61. Therefore, end of light
RTPTS values for all beltline materials at Prairie
Island are acceptable.
Any questions? The final slide, metal
fatigue, we kind of got into a little bit of
discussion with the applicant early on.
The original application did use
FatiguePro. The applicant, as he stated earlier, understood some of the recent issues in the industry
and they went through a contract with Structural
Integrity in June of `08, completed calcs, which was
commitment number 36, which they docketed April 28.
Staff competed a review and basically, the results of that were the 60 year fatigue re-
analysis applicable to the 6260 locations. None of
the cumulative usage factors were greater than one.
As the applicant stated earlier, they will continue
to manage the cycle counting in accordance with
54.21(c)(1)(iii).
Any questions on that? Okay, with respect NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 120 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 to chapter 4 -- well, with respect to the application
in total, pending resolution of the three open items, the staff has determined on the basis of its review, there's reasonable assurance that the requirements of
54.29 have been met with respect to managing aging
effects through the period of extended operation for
the Prairie Island plant.
With that, if there's any other further
questions, that's the end of my presentation.
CHAIRMAN RAY: Thank you, Rick. I have at
least one. You heard our discussion of the
measurement of the condensate storage tank bottom
thickness and the applicant's position that measuring
the bottom UT on one tank is sufficient to verify the
integrity of all three. I understand the staff has
accepted that.
The explanation for it, I'm still
somewhat at a loss for except maybe the dialogue that
said well, if either of the other two were subject to
a lot of corrosion, you would see some rust stains
external to the tank.
Does the staff have anything to add to
that?
MR. PLASSE: Well, a lot of -- we go
through a lot of the one time inspections. There is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 121 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 sampling done to give you data points and then if you
find something then you do extended condition --
maybe increase the scope.
We had several discussions on that
particular issue and I probably could have the
responsible individual speak to that.
CHAIRMAN RAY: Please.
MR. YEE: This is On Yee from the division
of license renewal.
As the applicant stated, they're doing it
on a sampling basis of the three tanks. They are
going to do the inspection of one tank and then if
based on those results, they'll extend the scope and
increase the frequency depending on what it is that
they find. Other than that, I'm not --
MEMBER BONACA: I have a related question.
If you find expected degradation in that tank, will
you -- do you have a program that says how you will
expand your inspection or are you just simply waiting
for it to happen and then you'll go to corrective
action program and figure out what you have to do?
That's important because one could have a
narrow view and say okay, we're going to fix the tank
and that's it or monitor the tank, but do nothing
about the other two.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Or you could have a comprehensive
response that says since you have found a problem in
this tank, I should expand it to the other two and
have additional monitoring. We haven't heard anything
about the fallback.
MR. YEE: This is On Yee again. It's my
understanding that of the inspection that they do on
that one tank, if they find anything, they'll expand
the scopes to the other tanks. If I'm incorrect, correct me.
MR. LINDBERG: This is Phil Lindberg. That
is correct.
MEMBER ARMIJO: The assumption is that all
the tanks are identical. They've operated in the
identical manner and they're all going to behave
identically. I just don't see why that's a sound
assumption.
CHAIRMAN RAY: One out of three -- the
reference to sampling just doesn't seem to fit here
to me because nothing has been done to demonstrate
that the three tanks would be identical if for some
reason there was water intrusion in one in the area
of concern because of a failure of the seal at some
time in the past.
It just seems very odd to have three NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 123 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 tanks like this and to decide that just one of them
needs to be inspected because it will be indicative
of the other two. I'll leave it at that.
MR. BARTON: I have a question. What's the
consequences of a failure of the bottom of one
condensate storage tank?
CHAIRMAN RAY: Well, we're doing about a
seismic event presumably. Some design basis event, which there's a need for condensate to remove decay
heat following the event.
It's very hard to say if there's one tank
or two of the three tanks that has a weakened tank
bottom. I guess you've answered the question.
MR. HOLIAN: This is Brian Holian. Just to
add, the staff appreciates these comments because we
similarly during reviews, we bring up those same
questions and we're not constrained by GALL. GALL is
written as guidance.
We're continuing to learn from operating
experience, as we expect the applicant to do so. On
this particular item, we'll take a closer look at
their justification for three tanks in a similar
environment.
On these tanks, we do expect current tech
specs control, water level in the condensate storage NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 124 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 tanks. Those get monitored by operators on a daily
basis. So there's other layers of safety here for
reviews that might pick up degradation in these tanks
vice this one time inspection.
But the general thought about crediting
one term inspections and going from there -- the last
item I'll add in is that the region will be back.
They will be back at the 71003 inspections during
another period of extended operation.
We've learned a lot from the region 1
inspections that we've just done on the plants prior
to going into a period of extended operation. I know
the next RIC that's going to be an item of discussion
with the industry is in general.
But that's a time for us to learn and
kind of generic industry learn on is this sampling
appropriate for what we're seeing as they go into the
extended period.
CHAIRMAN RAY: That's fair enough, Brian.
I would just say we sometimes forget that what we're
looking at here are, as I say, design basis events
and not simply as a leak developed during the course
of normal operation. So I'm not sure that ongoing
satisfactory operation is always an adequate
indicator that we're in compliance with our design NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 125 1 2 3
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MEMBER BONACA: I guess my question goes
in the direction of a one time inspection concept is
you do it once because you believe that there is an
effect in place. You just want to verify it.
By definition, when you do that, you
don't provide any information about what else you may
do should you find, in fact, that there is some
degradation.
The implication is that you throw it to
the corrective action program and then you establish
some kind of program. So it's hard for us to make a
judgement about the adequacy of the thought process
there because of that.
I guess I don't have an objection with
one time inspections, but I'm always left with a
question in my mind of what answer can you except the
licensee to do and I can see a big range, depending
on how they respond to a root cause of an event of
that nature.
MR. PLASSE: Let me see if I can maybe
shed some light from a part 50 perspective. I used to
be a resident and I worked for an applicant for 13
years as a licensing engineer.
Plants, every day that they find NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 126 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 deficiencies, over a course of a year, a single unit
will write 3000 corrective action reports. The
challenge for the applicant for a licensee is to
review those and take the appropriate corrective
actions, look at extended condition.
That's always subject to second-guessing, Monday morning quarter-backing by their own people
and the NRC. So to be able to sit here and tell you
for any deficiency that the plant identifies, what
are they going to do, what's the right thing --
that's kind of that little bit abstract.
But in the course of business, everything
that they identify, it is a challenge to them to do
the right thing.
Now, they don't always do the right thing
in 100 percent of the cases and they have lessons
learned and they try to improve it the next time.
The NRC will do what the residents --
they do reviews on a daily basis and then
periodically, they do what's called a problem
identification review inspection, P&IR, or they look
at in total from a little bit of a big picture to see
is their corrective action program effective.
I mean, that's a little bit outside of
this area, but that's --
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER BONACA: I agree with you. I
believe the corrective action program is the
foundation of everything. However, this proceeding
here is about license renewal --
MR. PLASSE: Exactly.
MEMBER BONACA: Where you put on paper
problems that you intend to implement to address
degradation, should you find it. So I don't think
it's inappropriate.
Now, the question is, to what extent
should you define that future. I agree that in some
cases, you don't want to have a fall back program
behind a one time inspection.
I'm only saying that given that these
events have happened, I'm uneasy to not know really
how it's going to be handled.
Anyway, that's as far as I'll go.
CHAIRMAN RAY: Okay, other questions for
the staff? Hearing none, thank you, Rick.
MR. PLASSE: Thank you.
SUBCOMMITTEE DISCUSSION CHAIRMAN RAY: Okay, it's now time for the
subcommittee to have some discussion of the license
renewal application for Prairie Island.
I would like to start with our NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 128 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 consultant, John Barton, and ask him to summarize
anything that he'd like to put on the table for us to
consider.
MR. BARTON: The only concern I have in
looking at all the documents I reviewed is the
decision finally to do something with the cavity leak
that's been going on for years and years without
really understanding maybe what damage has been going
on for all these years.
I mean, when you look at the fix, the fix
is relatively simple. I think when you have a problem
like this, you may try initially try to find the
leak, seal the leak.
If that doesn't correct the problem, I
think you get in. You don't wait 30-something years
before you decide to make the correction. The
correction that they're going to do is relatively
simple.
As far as overall, that's the -- I don't
have any other issues that impede this applicant from
CHAIRMAN RAY: Thank you. Jack?
MEMBER STETKAR: I have no comments beyond
John's and those that I made during this discussion.
I didn't find serious problems with what they were NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 129 1 2 3
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I do have curiosity about the limitation
of the inspection of all three condensate storage
tanks, recognizing however, that the more likely
thing that will happen is not necessarily a seismic
event but just general leakage and its safety
function is in aux feed as opposed to normal plant
operation. So it depends on the magnitude of the
catastrophic effect. MR. ECKHOLT: This is Gene Eckholt. We should clarify. The condensate storage tanks at
Prairie Island are not safety relayed.
MEMBER STETKAR: That's right.
MR. ECKHOLT: The safeguard supply is
river water to the aux feed pumps.
MEMBER STETKAR: Okay.
CHAIRMAN RAY: Well, they are, I assume, used for decay heat removal under some emergency
conditions.
MR. ECKHOLT: That's correct.
MEMBER STETKAR: That's right and that
puts them in scope.
MEMBER MAYNARD: But what they're taking
credit for is the river water. In normal operation, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 130 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 they're going to use the condensate storage tank and
in an emergency, they will, if the condensate storage
tanks are there, so they can use the cleaner water.
But the river water is always there available for an
emergency.
MEMBER STETKAR: That's a one shot deal
though. Then you replace the irrigation.
CHAIRMAN RAY: Okay, Sam?
MEMBER ARMIJO: I would like to see the
staff's final evaluation of the root cause analysis
and make sure that the staff agrees with the
applicant on the source of the leakage.
It seems to me, based on what I've heard, that they have identified the leakage because they've
been capable on more than one occasion of stopping it
with the caulking. But I would like to see that.
I think the inspection -- they're going
as far as reasonably doable to actually excavate
underneath in that sump region. I think that will
tell us a lot.
I think that 10 mil number is a little
bit unnecessary to even talk about -- should talk in
terms of how much margin there is. The applicant's
clarification of that 150 mils is the real margin
makes me a lot more comfortable.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Even if they find 20 or 30 mils of
general wastage there, it's not the end of the world
if they fix a leak. So that's all I have.
CHAIRMAN RAY: Dana?
MEMBER POWERS: I think we've identified
anything that's a smoking gun here. We've identified
a generic issue that we need to think about doing
something.
I'd say a question, which I think is an
interesting one is, is freeze/thaw more damaging than
wet/dry. I suspect that nobody has looked at that and
that's a generic issue that needs to be put on the
board some place. I'm not sure where we put that on
the board.
But, I mean, we need to preserve -- I
mean, it seems like a legitimate question, especially
since we're finding an awful lot of plants in this
licensure renewal phase that are getting their cables
very wet.
Those in Florida probably don't have to
worry about freeze/thaw. But as you move north, that
freeze/thaw question is a question.
I personally am not familiar with anybody
looking at it. As cable insulation ages, I would
assume freeze/thaw cycles break it. I don't know.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CHAIRMAN RAY: Well, I suppose we would
assume, would you not, that direct buried cable is
subject to moisture by definition?
MEMBER POWERS: By definition.
MEMBER ARMIJO: How deep is it buried
below the freeze line?
CHAIRMAN RAY: Well, moisture and freezing
are two different issues. I just assume any direct
buried cable is subjected to moisture. Anybody who
says no, it's not, I think has got a big burden to
carry. Bill?
MEMBER SHACK: No additional comments.
CHAIRMAN RAY: Mario?
MEMBER BONACA: No additional comments. I
mean, I made a concern about the underground cables
being dealt with.
CHAIRMAN RAY: Otto?
MEMBER MAYNARD: I had a clarification and
a couple of generic items.
On the condensate storage tank, I'm not
really overly concerned from a safety stand point. I
believe that the probability of a catastrophic
failure without identifying some leakage would
probably be pretty darn remote.
I'm still a little bit concerned about NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 133 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 just the justification for doing one. It's not so
much from the internal treatment of the condensate
storage tank. It's more of -- I'd like to see a
justification of why there's some type of external
environment to water getting around into places on
one that would not be getting around on another.
That's kind of part of the discussion
that I'm missing on why one is acceptable as both the
other. Or what external environment may occur as
opposed to internal.
But again, from a safety perspective, they're not safety related, counting on the river
water, and the chance of catastrophic failure is
pretty low.
From just generic, there's two things.
One is for the industry. I haven't really seen any
applicant come in and give a good presentation on
what they're doing relative to water in the vaults
and their understanding and justification for the
frequency.
Everybody seems to be picking two year, one year, quarterly or whatever without much
justification as to what -- that's all right, but
that's more that I'm seeing from the industry than
specific to this.
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 The others on the NRC and this is on the
station blackout scoping as to where we stand with
that. There still some inner discussions going on.
We're spending rate payer and tax payers'
money going ahead and doing things that may or may
not be required. I think we really do need to get it
resolved, the station blackout scoping, of just what
really is required on that.
So those are my two generic comments.
CHAIRMAN RAY: On the last one, though, can you apply it more directly here to Prairie
Island?
MEMBER MAYNARD: Again, it's a generic
statement because Prairie Island decided to just go
ahead and add it to the scope. So that's an
additional cost. That's an additional activity.
There's been additional discussions going on.
Ultimately, they may or may not end up being
required.
Those are the types of things that we
need to get a resolution on whether it is or it is
not.
CHAIRMAN RAY: But you wouldn't identify
it as a comment that you would make in the context of
this application?
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MEMBER MAYNARD: No. My last two comments
were just generic. I'm just venting. I would not put
them in any letter or any contact for Prairie Island.
MEMBER ABDEL-KHALIK: I have no additional
comments.
CHAIRMAN RAY: Well, my comment is in this
generic domain, but I'm not sure that it doesn't --
this isn't an opportunity to raise it. It's
basically, without repeating myself, the dialogue I
had with Brian about how it seems to me to be
unsatisfactory that we don't have more clarity around
the significance of, to structures, of borated water
leakage.
It's something that is not unknown.
There's a lot of rational and plausible easing about
why it should not be a matter of concern, but when
you talk about a long period of time, even assuming
this fuel transfer canal is fixed, as Prairie Island
intends, there's a larger question about well, from
whatever source it may have come, it's there and it's
there for a long, long time unless you have some way
to remove it or discover that it's present.
I don't know that we have a good basis
for feeling comfortable about it. I guess I'll use
the example of, well, we've learned certainly on NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W. (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 136 1 2 3
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8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ferrous components to be very concerned, particularly
if they're at elevated temperatures. If there's boric
acid deposits, we want to discover them and remove
them right away and make sure there's no degradation
taking place.
Lower temperatures in concrete rebar, different environment, but should we have no concern?
I wish we had a better handle on that.
But I don't think it applies here, other
than this is simply a place where we might, as Dana
commented in his case, identify it as something which
deserves attention generically.
But we can -- I don't if anybody else has
anything more they would like to say that or anything
else. If not, we're adjourned.
(Whereupon, the meeting concluded at
11:32 a.m.)
1 Prairie Island Nuclear Generating Plant ACRS License Renewal Subcommittee Meeting 2 IntroductionsMike Wadley -Site Vice PresidentGene Eckholt -License Renewal Project ManagerSteve Skoyen -Engineering Programs ManagerLicense Renewal Project Team and Subject
Matter Experts 3 AgendaBackgroundOperating HistoryPlant Description & Major ImprovementsLicense Renewal ProjectRenewed License ImplementationSpecific Technical Items of InterestSummary 4 BackgroundPlant Owner and OperatorNorthern States Power -Minnesota (NSPM)Subsidiary of Xcel Energy LocationSE of Minneapolis-Saint Paul, MNOn Mississippi River 5 BackgroundTwo 2 -Loop PWR Units1650 MW t575 MW e (Gross) per UnitWestinghouse -NSSS Pioneer Service & Engineering -
Architect/EngineerDual Containment DesignSteel Containment within Limited Leakage Concrete
Shield Building (5 foot annulus) 6 BackgroundOnce-Through Cooling Supplemented with Four Forced Draft Cooling Towers (Seasonal)Ultimate Heat Sink is Mississippi River via
Cooling Water System Site Layout Drawing 7 Operating HistoryConstruction Permits Issued -June 1968Operating Licenses IssuedUnit 1 -August 1973Unit 2 -October 1974LRA Submitted -April 2008 8 Operating HistoryUnit 1Completed Refueling Outage 25 in Spring 2008Lifetime Capacity Factor 84.2%Cycle to Date Capacity Factor 96.6%Next Refueling Outage -Fall 2009Unit 2Completed Refueling Outage 25 in Fall 2008Lifetime Capacity Factor 86.5%Cycle to Date Capacity Factor 98.0%Next Refueling Outage -Spring 2010 9 Major Plant Improvements1983 -Constructed New Intake Screen House and Reconfigured Intake and Discharge Canals1986 & 1987 -Replaced Reactor Vessel Upper Internals1993 -Added Two New Diesel Generators to Unit 2 Separated Units Electrically Cooling Water Pump Upgraded to Safety Related to Provide Swing Backup to Diesel Cooling Water Pumps2004 -Replaced Unit 1 Steam GeneratorsUnit 2 Replacement is Planned2005 & 2006 Replaced Reactor Vessel Heads 10 License Renewal ProjectProject TeamScopingAging Management ReviewsAging Management ProgramsAging Management Program ExceptionsTime Limited Aging AnalysesCommitments 11 License Renewal Project TeamLR Engineering Supervisors are NSP EmployeesExtensive Plant Knowledge and Experience Trained and Mentored by Other Plants with Renewed LicensesContract Support Staff has Significant LR ExperiencePlant Subject Matter Experts Provided SupportReviewed LRA Input DocumentsSupported NRC LR Audits and InspectionLR Project Team Engaged with IndustryNEI LR Task Force and Working GroupsObserved NRC LR Audits and Participated in LRA Peer Reviews at Other Plants 12 ScopingProcess Consistent with NEI 95-10 Rev 6Boundary Drawings Highlight Components for All Scoping CriteriaSwitchyard Scoping Boundary Includes
Breakers at Transmission System Voltage 13 Switchyard Scoping Boundary 1R(U1)CT12(U2)IntakeScreenHouseTrainingCenter 2R(U2)Gen(U1)1CT (U1)SpringCreekByronRedRock 1 Gen (U2)Blue LakeRedRock 2 161kV13.8kV 345kV Bus 1 Bus 2#10TransmissionSystemPlantSystemPINGP CLB ScopeExpanded LR Scope per Proposed ISG 2008-01Distribution 14 Aging Management ReviewsAging Management Reviews Consistent with Guidance in NEI 95-10Maximized GALL Consistency to Extent
Practical89.2% of AMR Line Items Consistent with GALL (Notes A-D) 15 Aging Management Programs43 Aging Management Programs 29 Existing Programs14 New ProgramsProgram Consistency With GALL31 Programs Consistent with GALL (9 include Enhancements)10 Programs Consistent with Exceptions
(6 also have Enhancements)2 Plant-Specific Programs 16 Typical AMP GALL ExceptionsTypical AMP GALL Exceptions Include the Use of:More Recent Revision of Industry Standard than Revision Cited in GALLDifferent (or additional) Industry StandardsAlternatives to Performance Testing specified in GALLAlternate Detection Techniques or More Recent NRC
Guidance than GALL RecommendsAlternate to Inspection/Test Frequency Specified in
GALL 17 Time-Limited Aging AnalysesTLAA Identification/Disposition Consistent with NUREG-1800 and NEI 95-10Evaluated In Accordance with 10 CFR
54.21(c)(1) 18 Commitment Management36 Regulatory Commitments for Future Action Resulting from LRACommitments are Tracked Through PINGP
Commitment Tracking ProgramCommitments have been Assigned to Station
Personnel for Implementation Prior to PEO 19 ImplementationImplementation of LR Program is Responsibility of Engineering Programs DepartmentImplementation will be Managed under Formal
Change Management PlanAll Aging Management Programs have Plant
OwnersEngineering Staff has already been Augmented to Implement Renewed License Requirements 20 Specific Technical Items of InterestUnderground Medium Voltage CablesSER Open ItemsPWR Vessel Internals ProgramWaste Gas Decay Tank ScopingRefueling Cavity Leakage 21 Underground Medium Voltage CablesFailure of Circ Water Pump Cable Caused Unit 1 Trip in May 2009Root Cause Evaluation and EPRI Testing of Cable in ProgressPlant has Experienced Three Other Cable Failures2 -13.8 kV (at cable termination)1 -4.16 kV (at cable termination)Cable Insulation Testing Being Implemented by the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental
Qualification Requirements Program 22 SER Open Item PWR Vessel Internals ProgramGALL Anticipates Future PWR Vessel Internals ProgramSpecifies Commitment to Implement ProgramAs Part of Hearing Process the ASLB Admitted
Contention that Commitment Alone was InsufficientTo Resolve Contention a Plant-Specific PWR Vessel Internals Program was Submitted 5/12/09 Program is Based on EPRI MRP-227 Rev 0 (Dec. 2008)ASLB has Dismissed ContentionNRC Staff Review in Progress 23 SER Open Item Waste Gas Decay Tank ScopingSSC are in Scope per 10 CFR 54.4.a(1) if, in part, they Prevent or Mitigate the Consequences of Accidents
Which Could Result in Offsite Exposures Comparable
to Those Referred to in 10 CFR 100.11PINGP Maintains WGDTs as Safety Related WGDTs Not Initially in Scope Because Offsite Exposure Potential not Considered ComparableWGDTs have been Reclassified as in LR ScopeLRA Scoping Changes were Submitted 6/5/2009NRC Staff Review in Progress 24 SER Open Item Refueling Cavity LeakageNRC was Briefed on Refueling Cavity Leakage During Aging Management AuditNRC has Reviewed Issue in Public Meeting, RAIs and Specific Site Audit of DocumentationNSPM has Responded to all NRC RAIs, Most
Recently in Letter Dated June 24, 2009NRC Staff Review is in Progress 25 SER Open Item Refueling Cavity LeakageDetailed Review of Issue FollowsBackground on LeakageContainment ConfigurationLeak Locations & Leak PathsInspection Results to DateCorrective ActionsLong Term Aging ManagementEvaluation of Potential Degradation 26 Refueling Cavity Leakage BackgroundIntermittent Leakage Indications in Both Units Since Late 1980s Leak Rate is 1-2 Gallons per Hour -Seen in ECCS
Sump and Regenerative Heat Exchanger RoomSource is Refueling Cavity Based on:Leakage Indications Typically Begin 2 -4 Days After Refueling Cavity Flood and End Approximately 3 days After Cavity is Drained. Chemistry Indicates Refueling WaterSealing Methods Have Been Successful, but not
Consistently 27 Refueling Cavity Leakage BackgroundRoot Cause Evaluation was Performed Following Most Recent Refueling OutageSources of Leakage were Determined to be Embedment Plates for Reactor Internals
Stands and Rod Control Cluster Change Fixture 28 Refueling Cavity Leakage Containment Design Containment VesselSteel Containment Vessel 1-1/2 inch Thick Bottom Head, 1-1/2 inch Shell, 3/4 inch Top Head3-1/2 inch Thick at ECCS Sump (sump B) PenetrationsSA-516-70 Low Temperature Carbon SteelProvides Primary Containment Lower Head Encased in Concrete5 foot Annular Gap Between Containment Vessel and Limited Leakage Reinforced
Concrete Shield Building Containment Elevation Refueling Cavity Leakage Path Cavity Photo Overhead Cavity Photo from NW Leakage Seen in ECCS Sump and in Regenerative HX Room (below cavity)
Containment Elevation 30 Refueling Cavity Leakage Leak Locations Typical Reactor Vessel Internals Stand Support Typical RCC Change Fixture Support 31 Refueling Cavity Leakage Leak Locations Existing cavity liner fillet weld to embedment plate General Arrangement of Change Fixture Supports Existing seal weld to embedment plate not accessible. Failure of weld would result in leak.Embedment Plate Side View Base Plate Existing 1/4" thk stainless steel cavity liner 32 Refueling Cavity Leakage PathPath to ECCS SumpUnder Refueling Cavity Liner Through Construction Joint Between Floor of Transfer Pit and Wall Behind Fuel Transfer Tube to Inner Wall of Containment VesselTravels Down and Horizontally, Between Containment Vessel and Concrete, to Low Point of Containment Vessel
Bottom HeadSeeps Through Grout in ECCS SumpPath to Regenerative Heat Exchanger RoomOnce Under Liner, Follows Cracks in the Concrete, Seeping Through the Ceiling and Walls of the Regenerative HX RoomECCS Sump 33Origin ECCS SpSp Cel Transfer Te RegenRoo Leak PathsECCS Sump 34 Refueling Cavity Leakage Inspection Results to DateUltrasonic and Visual Examinations of Containment VesselECCS Sump Grout RemovedWall Thickness Measurements at or Above NominalNo Corrosion Identified.AnnulusWall Thickness Measurements at or Above NominalNo Corrosion IdentifiedSump SectionAnnulu sPhoto Containment Elevation 35 Refueling Cavity LeakageCorrective Actions -RepairsPerform Repairs to Eliminate Leakage During Next Refueling Outage of Each UnitUnit 1 -September 2009Unit 2 -April 2010 36 Refueling Cavity LeakageCorrective Actions -Repair Method Existing 1/4" thk stainless steel cavity liner New seal weld between baseplate and embedment plate.Existing cavity liner fillet weld to embedment plate Existing seal weld to embedment plate not accessible. Failure of weld would result in leak.
Replace existing nuts with fabricated blind nuts seal welded to baseplate.
Side View 37 Refueling Cavity LeakageCorrective Actions -Monitoring & AssessmentEnhance Monitoring by Removing Concrete from Sump Below Reactor Vessel to Expose
Containment Vessel Next Outages Following Refueling Cavity RepairsInspect (VT and UT) Containment Vessel and Assess ConcreteEvacuate any Water ObservedAdditional AssessmentMargin Assessment of Containment Vessel, Concrete
and Rebar Evaluate Structural Requirements and Potential
Degradation in Concrete Around Transfer Tube Containment Elevation 38 Refueling Cavity Leakage Long Term Aging ManagementMonitor Areas Previously Exhibiting Leakage for Next Two Outages After Repairs to Confirm That
Leakage has not Recurred Continue General Monitoring for New Leakage Using Structures Monitoring Program and ASME Section XI Subsection IWE Program for
Remainder of Plant LifeUtilize Corrective Action Program for Evaluation and Correction of New Issues 39 Refueling Cavity Leakage Evaluation of Potential DegradationEvaluations have been performed for potential degradation of:Steel Containment VesselConcreteRebar 40 Refueling Cavity Leakage Evaluation of Potential DegradationSteel Containment VesselNo Corrosion has been Identified Water is Essentially Stagnant -Oxygen Would be Consumed to Preclude Continued CorrosionAlkalinity from the Concrete Would Elevate pH
to Inhibit Corrosion in Wetted AreasContainment Vessel Corrosion Behind
Concrete in Areas Wetted by Refueling Cavity
Leakage Would be no More than 10 mils 41 Refueling Cavity Leakage Evaluation of Potential DegradationConcreteLong Term Exposure to Acid can Dissolve CaOH in Cement Binder and Soluble Aggregate Dissolving CaOH Neutralizes Acid if not Refreshed.At Refueling Cavity LinerEvaluation Concluded Negligible Effect on Refueling Cavity Walls and FloorConcrete at Transfer Tube End Still Being Evaluated
Since Thickness <1 foot.
42 Refueling Cavity Leakage Evaluation of Potential DegradationConcrete (Contd)At Containment Vessel Inside SurfaceWater is Essentially Stagnant so Acid Would be Neutralized by Alkalinity in Concrete with Minimal EffectAt CracksWater is Essentially Stagnant so Acid Would be Neutralized by Alkalinity in Concrete with Minimal Effect 43 Refueling Cavity Leakage Evaluation of Potential DegradationRebarSome Potential for Refueling Cavity Leakage to Reach Rebar in CracksCorrosion of Wetted Rebar is Inhibited by Alkalinity (CaOH) of Concrete, Which Promotes
Protective LayerQualitative Assessment Concludes There Have Been no Significant Signs of Rebar CorrosionCorrosion of Rebar, Whether Wetted Periodically or Continuously, Would be Minimal 44 Refueling Cavity Leakage Evaluation of Potential DegradationConclusionsExpected Containment Vessel Corrosion Behind Concrete in Areas Wetted by Refueling Cavity
Leakage is MinimalConcrete Degradation or Rebar Corrosion Would
not have had a Significant Effect on Reinforced Concrete That Has Been Wetted by Refueling Cavity Leakage 45 SummaryLRA Developed by Experienced TeamLRA Conforms to Regulatory Requirements and Follows Industry GuidancePINGP Will Be Prepared to Manage Aging
During the Period of Extended Operation 46 Questions?
47 Backup Slides 48 Plant Electrical Distribution X 1RCT12 2R 1CT 161kV13.8kV (#10) 345kVTransmissionSystemPlantSystemCooling TowerCT112RX2RYIntakeScreenHouseUnit 2Unit 1Cooling Tower SubstationSwitchyard Fence Y 345kV 13.8kVNon-Safety Related Buses 4kVSafetyRelated 4kV 34.5kVPINGP CLB ScopeExpanded LR Scope per Proposed ISG 2008-01 49 Aging Management ProgramsPrograms with Exceptions to GALLBolting Integrity Program Closed-Cycle Cooling Water System ProgramCompressed Air Monitoring ProgramElectrical Cable Connections (E6) ProgramFire Protection ProgramFlow-Accelerated Corrosion ProgramFuel Oil Chemistry ProgramSelective Leaching of Materials ProgramSteam Generator Tube Integrity Program Water Chemistry Program 50 Shield Building Annulus UT exam of containment vessel from annulus was performed.
Scanned 18long x 2high area with all readings
above 1.5 inch nominal plate thickness.
51 ECCS Sump Showing GroutTo 33 (Cont. 3D)To 34 Insp.
52