Plant License Renewal (ANO-1)- February 22, 2001
Official Transcript of Proceedings
NUCLEAR REGULATORY COMMISSION
Title: Advisory Committee on Reactor Safeguards
Plant License Renewal Subcommittee
Docket Number: (not applicable)
Location: Rockville, Maryland
Date: Thursday, February 22, 2001
Work Order No.: NRC-081 Pages 1-177
NEAL R. GROSS AND CO., INC.
Court Reporters and Transcribers
1323 Rhode Island Avenue, N.W.
Washington, D.C. 20005
(202) 234-4433. UNITED STATES OF AMERICA
NUCLEAR REGULATORY COMMISSION
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ADVISORY COMMITTEE ON REACTOR SAFEGUARDS (ACRS)
PLANT LICENSE RENEWAL SUBCOMMITTEE
+ + + + +
ARKANSAS NUCLEAR ONE, UNIT 1
LICENSE RENEWAL APPLICATION
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FEBRUARY 22, 2001
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The Subcommittee met at the Nuclear Regulatory
Commission, Two White Flint North, Room T2B3, 11545
Rockville Pike, at 8:30 a.m., Mario V. Bonaca,
Subcommittee Chairman, presiding.
MARIO V. BONACA, Chairman
THOMAS S. KRESS
WILLIAM J. SHACK
ROBERT E. UHRIG
Z. BART FU
ROBERT J. PRATO
J.H. RAVAL. NRC STAFF: (CONT.)
Y.C. (RENEE) LI
RAYMOND BAKER, Southern Nuclear
RICK BUCKLEY, Entergy
RICHARD HARRIS, Entergy
NATALIE MOSHER, Entergy
JEFF RICHARDSON, Entergy
MARK RINCKEL, Framatome
CHARLES WILLBANKS, Scientech
GARY YOUNG, Entergy. I-N-D-E-X
I. Opening Remarks. . . . . . . . . . . . . . . 5
II. Staff Introduction . . . . . . . . . . . . . 6
III. Overview of SER Related to ANO-1 License . . 7
IV. Entergy Operations, Inc., Presentation . . .42
V. SER Chap 2.0 - Scoping and Screening of. . .73
Structures and Components Subject to an
Aging Management Review
VI. SER Chap. 3.3.1 - Common Aging . . . . . . .92
VII. SER Chap. 3.3.2 - Reactor Coolant System . .95
VIII. SER Chap. 3.3.3 - Engineered Safety. . . . 108
IX. SER Chap. 3.3.4 - Auxiliary Systems. . . . 113
X. SER Chap. 3.3.5 - Steam and Power. . . . . 123
XI. SER Chap. 3.3.6 - Structures and . . . . . 128
XII. SER Chap. 3.3.7 - Electrical Components. . 136
XIII. SER Chap. 4.0 - Time Limited Aging . . . . 148
XIV. Overview of the License Renewal. . . . . . 158
Environmental Review Process
Subcommittee Discussion. . . . . . . . . . 170. P-R-O-C-E-E-D-I-N-G-S
DR. BONACA: The meeting will now come to
order. This is a meeting of the ACRS Subcommittee on
Plant License Renewal. I am Mario Bonaca, Chairman of
the Subcommittee. ACRS members in attendance are
George Apostolakis, Thomas Kress, William Shack, and
The purpose of this meeting is to discuss
the license renewal application for the Arkansas
Nuclear One, Unit 1, and the associated NRC staff's
draft Safety Evaluation Report. The Subcommittee will
gather information, analyze relevant issues and facts,
and formulate proposed positions and actions, as
appropriate, for the liberation by the full Committee.
Sam Duraiswamy is the Cognizant ACRS Staff Engineer
for this meeting.
The rules for participation in today's
meeting have been announced as part of the notice of
this meeting, previously published in the Federal
Register on January 29, 2001. A transcript of the
meeting is being kept and will be made available as
stated in the Federal Register Notice. It is
requested that the speakers first identify themselves
and speak with sufficient clarity and volume so that
they can be readily heard.
We have received no written comments or
requests for time to make oral statements from members
of the public regarding today's meeting. We will now
proceed with the meeting and I call upon Mr. Chris
Grimes, of the NRR, to begin.
MR. GRIMES: Thank you, Dr. Bonaca. I am
Chris Grimes, Chief of the License Renewal and
Standardization Branch, and we're here today to
present the results of this staff's safety evaluation
with open items for the review of the license renewal
application for Arkansas Nuclear One, Unit 1.
As you may recall, this is a B&W unit, and
our review followed very closely the Oconee license
renewal application. And in order to make this most
useful for you, the staff's presentation has been
organized to highlight differences and uniqueness of
this review over other license renewal reviews that
we've presented to you, in order to focus on what was
special about Arkansas Nuclear One in terms of the
conduct of this staff's review.
I would like to introduce Robert Prato,
who is the license renewal project manager for the
ANO-1 license renewal review. And he'll go over the
license renewal application and the main part of the
presentation. And then we have other staff members
who will cover other topics in our agenda today.
As the Subcommittee, or the full
Committee, I can't recall now which, as you requested,
we've also arranged to present a brief overview of the
environmental review, in order to familiarize you with
the parallel activity that the staff had ongoing
related to the review of the environmental report and
the preparation of the supplement to the generic
environmental impact statement. And that's arranged
later in the agenda.
Unless there are any questions that you
have for me, I'll turn it over to Bob Prato, and we'll
get started with the presentation.
DR. BONACA: We can start.
MR. PRATO: Thank you. Good morning.
Again, my name is Bob Prato. I'm the -- should I go
ahead? I'm the Project Manager for Arkansas Nuclear
One License Renewal Application. On slide two is a
listing of the topics, and the presenters of those
Now, I'll begin with the overview. On
slide -- we'll start on slide three if we could,
please. Unit description: ANO-1 is a two-unit site
consisting of a Babcock and Wilcox pressurized water
reactor and a combustion engineering pressurized water
reactor located in Pope County in central Arkansas on
Lake Dardanelle is a man-made lake. It
was constructed around 1960, in the very early '60s.
On February 1, 2000, the applicant, Entergy
Incorporated, submitted a license renewal application
for ANO-1, Arkansas Nuclear One, Unit 1, the 2,568
megawatt thermal Babcock and Wilcox pressurized water
Unit 1 construction began in 1968 and went
commercial in 1974. The current facility operating
license expires in May of 2014. This facility is
similar to ONS in the interpless design aspects.
Comparing ANO-1 site with the Oconee nuclear facility,
Oconee nuclear site is a three-unit site.
It has a stand by shut down facility,
which is not only a difference between Oconee and ANO,
but it's unique to the industry. And Oconee uses a
keowee hydroelectric dam to provide emergency power,
which again, is unique to that site.
The difference between ANO-1 and Oconee is
ANO-1 has an emergency cooling pond as an alternate
ultimate heat sink. With respect to the applications,
you need to understand that Oconee submitted its
application prior -- or developed this application
prior to issuance of the standard review plan.
As a result, their outline was
considerably different than was anticipated in the
standard review plan. The outline for the Oconee SER
application was -- Chapter 1 was the introduction.
Chapter 2 was scoping. Chapter 3 was aging effects.
Chapter 4 was age of management programs. And Chapter
5 was time limited aging analysis.
The ANO-1 application was more consistent
with the SRP, where we had Chapter 1 was the
introduction. Chapter 2 was scoping, and Chapter 3
was the aging management review, which is combined
Chapter 3 and 4 putting in the Oconee application.
Chapter 4 was also a TLA.
As far as the safety evaluation reports,
the SER was out in time for the staff to develop the
SER for Oconee consistent with the SRP. And
therefore, both applications are very similar. There
is a couple of extra chapters in the Oconee
I believe it's Chapter 2 is -- I'm sorry
-- Chapter 2 is aging effects from mechanical systems,
and I believe Chapter 3 is containment. They
separated out containment from the rest of the
structures. The ANO application, a safety evaluation,
starts with an introduction, goes to scoping, goes to
aging management review, and goes to time limit aging
There is a unique feature about the ANO
application, the Chapter 3, is what they call the
mechanical tools. This chapter is what they use to
develop the aging effects for mechanical components.
This -- understanding that this is a separate focus of
the applicants will help us later on in presentation.
What we did to try and provide you a
comparison of the two applications was we took the
open items from Oconee and ANO, and we identified the
differences in the application for those items. So
we're going to begin with scoping.
ANO-1 safety-related criteria is based on
the more current definition consistent with 10 CFR
54.4(a)(1) and (a)(2). That is that the safety-
related criteria is based on the safety-related
criteria and a non-safety-related criteria for scoping
for license renewal.
Oconee's safety-related criteria was
considerably different. Their definition was based on
very deficient products, and that caused some contrast
between what the staff was used to and the rule
itself. And we spent quite a bit of time trying to
rectify the differences in ensuring that the scope was
complete for Oconee.
We did not have that difficulty for ANO.
We'll begin the presentation on the scoping
methodology here a little bit later. ANO-1 spent fuel
pool cooling was not included within the scope of
license renewal. This was consistent with the Oconee
conclusion that the -- Oconee's recirculating cooling
water system was not required because the spent fuel
pools are similar designs. Neither one were required
for being within the scope of license renewal.
ANO-1 chilled water was not excluded from
DR. BONACA: Excuse me.
MR. PRATO: Yes, sir.
DR. BONACA: But Oconee had an emergency
make-up to the pool that is a part of the aging
management programs. And I believe, also, Arkansas
has an emergency make-up capability, right, to serve
MR. PRATO: Yes, sir. And both of them
are required to keep their fuel full, and rather than
requiring emergency cooling, it's just required to
keep the materials in the fuel -- spent fuel pool
DR. BONACA: Yes. And you tell us also
about the liner, because there is a one --
MR. PRATO: We will cover that a little
bit later as well when we get down into the specifics.
DR. BONACA: Yes. Was the Oconee
application -- did it include the liner as part of the
components under -- in the scoping?
MR. PRATO: Yes, sir.
DR. BONACA: Okay.
MR. PRATO: Yes, sir.
DR. BONACA: Do you also want to discuss
the boron flux issue?
MR. PRATO: Yes, we will. We will. We
will get to that as well.
ANO-1 passive long-lived skidman equipment
were not excluded from an aging management review and
the license renewal application. ANO-1 structural
sealant, water stops and expansion joints were not
excluded from an aging management review as well in
the license renewal application.
DR. BONACA: The chilled water system.
You didn't -- I interrupted you at that point.
MR. PRATO: Yes, sir.
DR. BONACA: Did you have any comment on
that one? You have a bullet here.
MR. PRATO: I thought I added that. It
was included within the scope of the license renewal
in the application. You'll find out as we go through
this presentation that ANO took considerable advantage
of the lessons learned from Oconee.
And a lot of what issues were raised
during Oconee, the great majority of them were
resolved right in the application. And that's really
the theme that we're trying to bring out here, is a
lot of what we identified early on for Oconee was
DR. BONACA: Among the comparisons here,
I would like to talk about also the reactor vessel
level measurement system.
MR. PRATO: Okay. I'm not sure we were
prepared to go into detail on that, but if you'd like
DR. BONACA: Well, I would like to hear
about that. I understand it's been excluded from the
MR. PRATO: Yes.
DR. BONACA: -- of the application. And
I can't remember if we excluded it for Oconee too. It
probably was excluded.
MR. PRATO: It's just one of the measuring
devices. I don't believe that all of them were
excluded. They have --
DR. BONACA: When you go through the
scoping, it will be interesting to understand the
logic for excluding the reactor vessel level
MR. PRATO: Okay. And we'll try to
prepare for that. I'll go back. I believe that
presentation is probably scheduled for after lunch.
DR. BONACA: Okay.
MR. PRATO: The applicant is going to be
here as well, and you may be able to get the details
if you need, as well, from them.
DR. BONACA: Good.
MR. PRATO: Structural sealants, water
stops and expansion joints were included. Electric
cables were not excluded from this scope. They were
included and required an aging management review for
Arkansas Nuclear One.
Initially, in the application there were
some contradicting statements with respect to Lake
Dardanelle and the Turbine Building, and as to whether
or not they were included within the scope. Those
were straightened out in the RAI process, and it was
straightened out prior to issuing the SER.
ANO-1 ventilation sealants were also
included within the scope, and an aging management
review was performed on those. ANO fire detector
cables were also included. ANO aging effects
discussed and accepted by the staff were consistent --
were consistently applied throughout the application.
This is where that Appendix C came into
play. Because they had tools and they applied those
tools consistently across all their systems, they
didn't have the problems that arose in the Oconee
application with applying aging effects consistently
across the different systems.
ANO-1 buried pipe were included within a
scope, and an aging management review was performed in
the license renewal application. And ANO-1 committed
to 10 CFR Part 50, Appendix B, for corrective actions,
confirmation, processes, and document control
activities were both safety-related and non-safety-
Oconee had only committed it for safety-
related, and they applied different techniques to
resolve those for non-safety-related. ONS just
committed to Appendix B for all components within the
scope of license renewal.
MR. GRIMES: Excuse me, Bob, are you on
MR. PRATO: Yes, I am.
MR. GRIMES: Is slide six up? Thank you.
MR. PRATO: The last two items on that
page are the two items that are open items for ANO-1
with respect to scoping. The staff identified in the
FSAR that one of the full control offices was required
to control the injection of sodium hydroxide for pH
The applicant included that orifice within
the scope of license renewal, but solely for pressure
boundary. And the staff requested that they justify
excluding it for full control. The other item, which
is the item that right now is the center of our focus
for proceeding with the -- final safety evaluation --
is the fire protection system.
ANO-1 was built prior to 1968. They were
not subject to all of Appendix R, just the three
subsections they were back fitted to. They, at that
time, they were not submitting specific components for
fire protection. They were doing it in general terms.
The staff were reviewing them in general terms.
There was some confusion as to whether or
not they were ever within the applicant's CLB. In the
mid-'80s, they did a design basis reconstitution to
convert their safety-related definition from Fischen
product barriers to event medication. And when they
went through that process, they identified all the
components on site.
And then they made a determination whether
it was safety related, whether it was required for
fire protection, ATWS, et cetera. When they were done
with that evaluation, they had what is known as the
ref list, which is the fire protection list.
And there were a number of components that
were not included on that list that the staff feels
should be included. And we're in the process of
evaluating whether or not those components need to be
added to their current licensing basis. If it is
decided that it needs to be added, they are going to
be required to submit an aging management review on
The components in question is the fire
protection jockey pump. The carbon dioxide system,
fire hydrants, the water supply to the low level rad
waste building fire protection system, and the piping
to the manual hose stations -- are they components
that are within question.
There will be a staff meeting on that.
Right now, we're trying to figure out a final date for
that meeting. It's going to be a public meeting.
It's currently scheduled for the 7th. There are some
scheduling conflicts, and we're trying to work those
out as well.
MR. SHACK: Does this report sort of
follow the NEI suggested format? That is, is this
close to a template for what we expect future license
renewal applications to look like?
MR. PRATO: Their application did
basically follow the NEI template. They did something
unique. They incorporated a lot of tables. And the
staff had mixed feelings about that. Having the
tables were really helpful. It had a lot of compact
information that sat in front of you and it helped you
do your evaluation a lot quicker.
However, it being in table form, did raise
some questions on the details. And we had
approximately 250 REIs as a result of the application
review, which is less than our predecessors. However,
if you take a look at them, about 90, 95 percent were
questions on details that the information really was
contained in the tables, but it wasn't clear.
The staff is not discouraging the use of
the tables. We're trying to get a balance between the
tables and the detailed information that we need
writing the application.
DR. BONACA: I didn't see any, you know,
extensive reference to the GALL2 report. Was it just
because of timing, the GALL2 came after the
application was essentially submitted, or was it just
because the GALL would be mostly referenced by the
MR. PRATO: The GALL hadn't been issued
during the development stage. They followed a lot of
it, and the staff requested a lot of information. And
the applicant made a lot of adjustments to be more
consistent with GALL.
DR. BONACA: Okay. So they played the
role, although maybe less a role just because of the
MR. PRATO: I believe it played a role for
the applicant as well as the staff.
DR. BONACA: Okay.
DR. SHACK: Well, the B&W topical reports
also had a tremendous impact, just to cover huge
chunks of stuff --
MR. PRATO: And that's another difference
between Oconee and ANO. A couple of the topical
reports were not issued when ANO were developing their
application. And that generated a lot of open items.
And a lot of those open items were just not applicable
to Arkansas because they had incorporated the
requirements in those topical reports.
DR. SHACK: One other general comment,
just as you're coming up on the aging management
review, I didn't see really do a -- I didn't see
nearly as many one-time inspections. Is that correct,
or am I just -- that there's not a call out as one-
time inspections as there were for Calvert Cliffs or
MR. PRATO: There were a couple one-time
inspections, but I think you're right, because I've
worked both on Calvert and Oconee's.
DR. SHACK: Plus, there were like 30 of
them or something.
MR. PRATO: Yes, yes, sir. And a lot of
those were as a result of open items, and it was a
resolution to a lot of the open items. I'm not sure
why there aren't as many as at ANO, but I believe the
reason is is because they were aware of the fact that
they were open items.
And instead of trying to address the
resolution of the open items, I believe the applicant
tried to address the issue itself. And as a result,
some of those one-time inspections just materialized.
DR. BONACA: But you performed a
comparison with the previous applications to make sure
that of one of the reasons a one-time inspection is
because there is a different commitment that fulfills
the need anyway.
MR. PRATO: We did not do a specific
evaluation to verify that itself. I think we did --
and I think a large part of that is because we had
different reviewers. Again, another unique about
Arkansas is that a lot of the review is done by
We had staff personnel overseeing it,
making sure it was complete, making sure that it was
consistent, that we weren't recreating the will, if
you will, for Arkansas. But I think as -- because we
got different reviews involved, there wasn't that
Another thing is I don't think the staff
wholesale accepts one-time inspections. We, in
general, request them to justify the use of that if
that's what they want to use. It has to make sense,
and it's the applicant's responsibility to provide a
justification for that.
DR. BONACA: But as you go forth, I mean
I imagine that although you have different reviewers,
you will want to capture lessons learned from
individual -- this, by the way, is one of the reasons
why we have a presentation that we discuss with Mr.
Grimes, which includes some comparison.
Because we are trying ourselves, as a
committee, to gain from previous experience.
MR. PRATO: Don't misunderstand me.
There's a big effort and a lot of focus on lessons
learned between plants. And not only with the staff
itself, but with the industry.
The industry meets quite often internally
to themselves, and talk about what they've learned and
where the problems are, and why is it a problem here
and it wasn't in another place, and what is a good
solution for it? And a lot of that work is going into
GALL, I believe.
MR. GRIMES: As a matter of fact, I wanted
to point out that I think that you say fewer one-time
inspections here, primarily, because some of the
uncertainty associated with the treatment of potential
aging effects in Calvert Cliffs and Oconee has been
resolved in the work on GALL, that has either
determined where there is no need to verify the
existence of an aging effect, or the effectiveness of
And I think also my sense was, as we were
going through the review of the Arkansas safety
evaluation, I got the sense that Entergy put more
reliance on existing programs and periodic inspections
to determine the existence of aging effects, where
Calvert Cliffs and Oconee look more to the one-time
inspection to check for the existence of aging
DR. SHACK: I notice they even opted for
a periodic pressurizer cladding inspection, whereas
you accepted a one-time inspection and a topical
report, which struck me as a considerable improvement.
MR. PRATO: Yes, well -- and we thought
DR. BONACA: Yes, at some point, Appendix
B on the application has at least seven -- I believe
seven new problems. Among those are a couple of one-
time inspections. And at some point, we will get an
overview of those programs?
MR. PRATO: Not as a separate
presentation. But if you'd like, I'll be glad to
DR. BONACA: No, you don't have to, but as
long as we get it sometime today from the licensee or
MR. PRATO: Okay. We'll do what we can.
DR. BONACA: Well, I mean, some of them
I'm sure you're going to go through, because --
MR. PRATO: Absolutely.
DR. BONACA: So there might be a couple
extra, but I would like to review them a little bit to
MR. PRATO: There are a number of them
that are common aging management programs, which we're
going to cover that as a separate entity as well. So
you'll get most of them. We weren't prepared to do
those by themselves, and I'm not sure if the applicant
is prepared to do that.
But if there are any --
DR. BONACA: Well, we just have a few
questions. I'm sure you are cognizant enough to
provide some answers.
MR. PRATO: Yes, sir. As for aging
management, the plant differences ANO-1 did not
exclude the heat transfer as an applicable intended
function for heat exchangers. And they use
performance monitoring consistent with generic letter
8913 to manage the following itself -- 8913 is the
service water generic letter.
ANO-1 performed an aging management review
of all the piping in the service -- all the piping
within the scope of this service water system
regardless of the materials. Oconee limited their
initial evaluation just to carbon steel piping.
ANO-1 did not perform an aging management
review of the tendon galleries in the license renewal
application, which is consistent with the previous two
applicants. They weren't required to do that.
Continuing with the aging management
review, this is specific to the reactant coolant
system aging effects. ANO-1 pressurizer spray head
was not included within the scope of license renewal,
because it's not required by the current licensing
basis. They don't use it for design basis events
ANO-1 addressed void swelling in its
license renewal application as an applicable aging
effect for the reactor vessel. And manage the related
aging using the reactor vessel internal aging
management program consistent with the topical report
BAW-2248 and the Oconee lessons learned.
Next slide is on reactive coolant systems
aging management programs. ANO-1 heater bundle
penetration welds are designed differently than
Oconee's heather bundle penetration welds. ANO-1
heater bundles are all stainless steel and consist of
a stainless steel heater sheet weld directly to a
stainless steel diaphragm plate.
Oconee Unit One contained alloy 600 heater
sheets. And the design was a heater sheet to sleeve,
plate weld to a heater sleeve, to a bundle diaphragm
plate weld. ANO-1, in this license renewal
application, committed to examine heater bundles upon
removal consistent with the lessons learned from
DR. BONACA: Now, in the application,
however, it states that if Oconee performs the
inspection and doesn't find anything, then they would
not perform an inspection in Arkansas. But in the
SER, I didn't see the exclusions. So is there some
agreement that you reached through some
MR. PRATO: Yes, I don't believe there's
an open item on that issue at all. The agreement was
that when they replace it, they're going to inspect
it. There's not going to be any specific inspection,
unless when Oconee does its inspection, they find a
Is that correct?
MR. YOUNG: Gary Young with Entergy.
We're going to follow the Oconee work and they're
going to follow our work. So what we're going to do
is compare notes. If we do our heater bundle first,
then the results from that will be factored into the
And if they do their heater bundle first,
then we'll factor that result into our program.
Though, it's really more of a B&W program to look at,
you know, both units together. That's why it's stated
the way it is. And the staff, if they have any
problems with that --
DR. BONACA: Okay. Yes, because the
application is clear on that issue, but the SER did
not -- assuming the SER says that Arkansas would
perform in any event, an inspection of the heater
bundle, which in turn, it means that it may not, in
case Oconee does it first.
MR. PRATO: Right.
DR. BONACA: And I think it's fine.
MR. PRATO: If the Oconee comes out, you
know, with no problems whatsoever, and there's no
benefit from doing a subsequent inspection in
Arkansas, that's what that section was all about.
DR. BONACA: And that was part of the B&W
MR. PRATO: Yes.
DR. BONACA: That kind of --
MR. PRATO: Dr. Bonaca, I have a note
here, and we will go through the SER again and in our
revision and in our final version, we'll make sure
that's made clear.
DR. BONACA: Okay.
MR. PRATO: ANO-1, in its license renewal
application, included cracking as an applicable aging
effect for reactor vessel internal non-bolted items.
And the identification of limiting components when
considering irradiation embrittlement in its reactor
vessel internal's aging management program. This is
consistent with topical report BAW-2248 and the Oconee
DR. BONACA: Now, Arkansas-1 experienced
thermal shields and cobarold bolt cracking, right, as
experienced in the past.
MR. YOUNG: Yes, that's right.
MR. RINCKEL: This is Mark Rinckel from
Framatome, and that's correct.
DR. BONACA: And so as part of the
internal inspections, it would be also -- probably you
have a periodic inspection of those components.
MR. RINCKEL: They are in the reactor
vessel internal as aging management program. Yes,
DR. BONACA: And that program involves a
one-time inspection, right?
MR. RINCKEL: It could be one or it could
DR. BONACA: But now, if I remember, that
inspection is also tied to an Oconee inspection.
MR. RINCKEL: That is correct, yes, and
DR. BONACA: Okay. Which means if Oconee
performs the inspection first, then you may not
perform the inspection for Arkansas?
MR. RINCKEL: It's possible. I think it's
in the application we are committing to doing some
type of inspection, but I -- you know, I think there
will be lessons learned from the Oconee inspections
because they'll be first.
DR. BONACA: Yes, the reason why I'm
asking that question is, since you've experienced
already the cracking of the bolts, in both the thermal
shields and the wiring, why would you consider the
experience from Oconee applicable to our -- or, let me
just put it the other way, which is why would you
consider Arkansas to be -- you know, I mean, you have
experienced the problem.
Wouldn't you want to see -- don't you have
already the inspections to look at those --
MR. RINCKEL: We do, not necessarily
biometric inspections. But if you remember back in
the original issue, they thought it was stress erosion
cracking, and a lot of it with the fabrication, you
know, overtorquing and so forth.
And so they've replaced those. And now
what the issue is, is possibly a radiation assisted
stress erosion cracking, which is more of an aging
phenomena as opposed to a fabrication type issue, so
it's kind of something different now with regard to
aging, even though it's the same component.
DR. BONACA: Okay. But you are tracking
MR. RINCKEL: Yes.
MR. PRATO: Next page, we're going to
continue with reactant coolant system. ANO-1 included
IASCC as an applicable aging effect for baffle bolts
in its license renewal application consistent with
topical report BAW-2248 and Oconee lessons learned.
ANO-1 evaluated reactor vessel internal
cast components. In this license renewal application,
for reduction of fracture toughness by thermal
embrittlement and a radiation embrittlement consistent
with the EPRI technical report 106092.
This is also consistent with the topical
report 2248 and the Oconee's lessons learned. ANO-1
included vent valve bodies and retainer rings in its
reactor vessel internal's age and management program
and its application.
DR. SHACK: Just let me get back to the --
the cast stainless was a sort of a extended topic of
discussion for Calvert Cliffs and Oconee. And this
one -- it just -- I mean, it did go smoothly, right?
I mean, they incorporated acceptable plans from the
lessons learned, basically, from line one, or was this
another exchange before we iterated to a successful
MR. PRATO: I believe it went so smoothly
at ANO because they followed the topical report. Is
that correct --
MR. YOUNG: Yes, Bob. They -- and we also
followed the lessons learned from Oconee. We just
basically incorporated what the staff determined to be
acceptable. And you have to remember the CASS
includes the retical and pump casing, valve bodies,
and those we follow the same solution that Oconee did.
And then the rad vessel internal's CASS,
you had not only thermal embrittlement, but
irradiation embrittlement. And we address those by
putting them in our rad vessel internalization
management program, which is consistent with Oconee.
MR. PRATO: And the last item, ANO-1
identified cracking and loss of material of letdown
cooler tubing, and loss of material for external
ferritic surfaces due to boric acid wastage as
applicable aging effects in the license renewal
application, which is consistent with the lessons
learned for Oconee.
That completes the RCS aging management
review. We'll go on with the rest of the system's
aging management review. ANO-1 did not consider
vibration loading as an applicable aging effect for
the HVAC system in its license renewal application
consistent with the staff's determination that caused
similar concerns on Oconee.
ANO-1 included an acceptable scope for the
aging management review of the reactant cooling pump
motor oil collection system inspection program. There
was some questions as to whether or not Oconee
included the entire -- enough of the system based on
lessons learned from Oconee. ANO included the
appropriate evaluation boundaries for the system.
DR. BONACA: If I remember, for Oconee,
the only inspection was for corrosion due to water
intrusion in the --
MR. PRATO: Wet system.
DR. BONACA: -- in the drain, for the
drain in the tanks, collection tanks. And now, so the
Arkansas has included in the piping of the system and
any other component?
MR. YOUNG: Yes, we included the oil
collection pans and the piping that went down to the
drain tank, the whole system.
MR. PRATO: ANO-1 spent fuel concrete
thermal exposure is limited to less than 150 degrees
Fahrenheit, which is contrary to the Oconee. They
experienced temperature of up to 183 degrees, and
being less than 150 degrees is less than the threshold
for potential cracking and changes in properties of
And the applicant addressed this directly
in the application. ANO-1 considered results of
inspections and instances of reporting unusual event
in this demonstration of aging management programs in
the license renewal application. In general, part of
the demonstration was operating history.
The staff had a number of questions as to
whether or not they considered operating history, and
in a couple of cases, the applicant had to go back and
take a look at it. But in general, they did include
operating history, both industry and on-site history
ANO-1 primary and secondary shield wall is
reinforced concrete without any tendons, and
therefore, monitoring of applicable forces is not
needed. And there was a question with Oconee's
monitoring of tendon forces in the secondary shield
ANO-1 consistently considered applicable
aging effects with cable trays and conduits located
inside and outside of containment.
DR. SHACK: Want to flip your slide?
MR. PRATO: Oh, I'm sorry. The last two
items there on this page common to both ANO and
Oconee, ANO meets -- and these are two of the -- two
of the six open items. ANO-1 needs to provide
additional summary description for a number of their
selected program descriptions in the FSAR supplement.
And a second item is ANO-1 needs to
identify an aging management program for buried
medium-voltage cables exposed to ground water that are
within the scope of license renewal and subject to an
aging management review. This was an issue both for
Oconee and ANO, and the applicant is developing a
program similar to what ANO resolution -- I'm sorry,
similar to the resolution for Oconee.
DR. UHRIG: Are these primarily load
carrying cables, or are these there for emergencies?
MR. PRATO: It's load carrying.
DR. UHRIG: Load carrying.
MR. PRATO: Yes, sir.
DR. UHRIG: So they would have heating?
MR. PRATO: Right. That's part of the
problem, that along with moisture causes a number of
aging effects to occur. Slide 13. Time limit aging
analysis. ANO-1 did provide a discussion on the
cumulative effects of fatigue for the containment
liner plate and penetration in the application.
ANO-1 provided an adequate TLAA for the
reactive coolant system to address environmentally
assisted fatigue concerns for operation beyond 40
years in the application. ANO-1 committed to 10 CFR
Part 50, Appendix B, for all -- for corrective actions
for all components within the scope of license
renewal, including Section 11.4 evaluations.
ANO-1 addressed the reduction of fracture
toughness related to susceptibility of the reactor
vessel internal -- internals under loss of coolant and
seismic loadings. And its reactive vessel internals
aging management program consistent with the topical
report BAW-2248 and Oconee lessons learned.
ANO-1 addressed the applicability of flow
of growth in accordance with the ASME boiler pressure
code Section 11 ISI requirements in the application
consistent with topical report BAW-2248 and Oconee
The last two items are ANO open items.
These are the last two of the six open items that
exist right now in the safety evaluation. The first
one has come to both Oconee and ANO. ANO did not
demonstrate the adequacy of the existing pre-stress
forces in the containment tendons by providing the
trend lines for the containment post-tensioning system
for the period of extended operation.
There were some questions as to how they
described their program in the application. They used
the same aging management program that they used in
Chapter 3 for managing the aging of those tendons.
The staff wanted something more for the time limit
aging analysis, more trending, more than was required
by the code itself and the applicants in the process
of developing that.
And the last item is the boraflex
monitoring program. The ANO monitoring program is
similar to Oconee's monitoring program. However,
sometime between the time they submitted their
application and during the staff review, they
collected additional data. They plotted that data,
and they found out that the boraflex is not going to
last much more than five years.
Therefore, they had to do something under
Part 50. Because they felt that it became a Part 50
issue, they turned around and told the staff instead
of sending additional description, as the staff
requested in the REI, they turned around and said,
"Look, we have this problem. We have to fix it prior
to entering into the period of extended operation.
Therefore, we don't consider it a TLAA anymore."
Initially, the staff accepted that. But
as we thought about it more and more, it was a
difficult concept for us to accept that we were going
to give them a license for 60 years without knowing
whether or not they have sufficient boraflex to
maintain the shut down margin.
We spoke with OGC. OGC said it's not --
if you look at the definition for TLAA, there's one
item that says as defined by the current licensing
term. They said that does not necessarily need to be
interpreted as 40 years. In other words, if it was a
TLAA in the initial application for initial licensing,
we can still consider it a TLAA in the license renewal
So the applicant is working out a
resolution. The resolution is targeted for late 2002.
What we're going to do is we're going to insist that
they maintain their boraflex monitoring program until
the resolution is not only developed, reviewed, and
approved by the staff, but implemented as well.
That completes the overview. Next item of
topic is scoping of systems.
DR. SHACK: I think it's -- when you say
they handled the environmentally assisted fatigue in
the application, that means basically, it came in in
an acceptable form, and you weren't negotiating back
and forth the way you were with Oconee and Calvert
MR. PRATO: That is correct. After
resolving Oconee and Calvert Cliffs satisfactorily,
the information was out there. And they took
advantage of that, and they took the lessons learned,
and they submitted. That's not to say the staff
didn't have any RAIs on this subject.
If I remember correctly, we had a number
of RAIs, but they responded satisfactorily.
MR. YOUNG: Bob, in that regard -- this is
Gary Young again with Entergy. We did have a number
of conversations with John Fair, and we had originally
proposed what we felt was a complete solution to the
environmentally assisted fatigue involving in-service
But we couldn't come to terms on the
interval for the inspection, the ten year interval.
So we wound up, through their RAI process, revising
our commitment to deal with whatever comes out of the
changes that may occur with the definition of flaw
growth tolerances for environmentally assisted
And also open the possibility that we
might go back and do analysis once the methodology is
established for doing analysis for environmentally
assisted fatigue. So there was an adjustment made,
but it was through the RAI process.
MR. PRATO: Are there any more questions
MR. GRIMES: Actually, before you go on to
the next topic, Dr. Bonaca, I would like to emphasize
that in describing these differences between Oconee
and Arkansas, I don't want to leave the impression
that we were Oconee bashing in some fashion.
Bob referred frequently to deficiencies in
the Oconee application, and given that they were
flying blind as one of the first two license renewal
applicants. I still think it was remarkable that we
only had, I believe, it was 48 or 49 open items on
And the purpose of Bob's presentation was
to explain how Arkansas was issued with six open
items. So we got from 48 open items to six open
items. And I think that if you went through and
counted the number of times Bob referred to,
consistent with lessons learned from Oconee, the
Arkansas application did reflect a lot of the
experience from Oconee and also incorporated the
resolution of a number of the Oconee open items.
And that was the vast majority of the
reasons for the difference between the number of open
items. You also heard reference to a number of B&W
programs that were resolved and a staff evaluation was
issued at about the same time that the Oconee safety
evaluation was issued. And so we took advantage of
And then there were a handful of
circumstances where Bob explained that there were
plant unique features, plant unique environment.
There were only a few cases where unit differences
between the Oconee site and Arkansas site accounted
for the basis for the differences.
So those are the categories of differences
that we described. You also will observe that there
were -- there are a handful of these open items that
will probably always be open items. The content of
the FSAR supplement is always going to have to have a
finishing touch to it. And there are going to be open
items in the scoping area where there -- we're trying
to pin down the precise nature of the current
So you can expect that future license
renewal safety evaluations are going to have open
items that look like that, but they're going to vary
from plant to plant based on the differences in the
current licensing basis.
DR. BONACA: Thank you. I must say at
least I didn't get the impression that there was any
bashing of Oconee. I mean, I recognize the fact that
Oconee was the second -- one of the first. Anyway,
the first two coming through the gate. And they had
to really start from scratch.
I mean, so clearly, there were many more
open issues. I think what we're seeing here for
Arkansas is encouraging. However, the lessons learned
are being clearly implemented and used. And the
issues are closed before they are opened. That's
good. Okay, thank you.
MR. PRATO: Okay. Next presentation will
be on scoping. Greg Galletti will make that
presentation. The next presentation is supposed to be
Entergy. I apologize.
DR. BONACA: Yes, okay.
MR. PRATO: We're just getting a little
ahead of ourselves.
MR. YOUNG: My name is Gary Young, and I'm
with Entergy. I'm the Project Lead for the license
renewal project. And one thing I'd like to make you
aware of is about 22 years ago, I was part of the ACRS
staff. I worked as an ACRS fellow for one year, and
then as an ACRS Staff Engineer for one year.
And that was in 1979, 1980, and 1981 time
frame. So I'm glad to be back, and especially in the
context of presenting license renewal as the subject.
So that's a very nice subject to be talking about with
To my right is Natalie Mosher, who is our
Lead Licensing Engineer for the license renewal
project. She's been doing all of the interfacing and
coordinating with the NRC staff as we've gone through
this process. I've also got several members of our
Reza Arabli is from our structural group.
Jeff Richardson worked on our electrical portion of
our application. Mark Rinckel, who spoke earlier with
FDI, helped us a lot with the Class 1 and the
mechanical portion of the work.
Rick Buckley was our Environmental Lead
and did a lot of work in that area. And Richard
Harris, who worked on our SAMA portion of our
environmental application. So we brought all these
people here to help address any questions you might
have and help facilitate your review process.
DR. BONACA: I'll have a number of
questions about specific components in scope. I don't
want to interrupt your presentation. So you tell me
when is the best time for me to ask questions.
MR. YOUNG: At any time. At any time.
Yes, I'd rather you ask at the point that the question
comes up, and then we'll try to address it right then.
We'd like to than the ACRS for the
opportunity to come here, and to go through this part
of the process. We're anxious to answer your
questions and to help you facilitate your review.
We'd also like to thank the NRC staff, because we --
this process, although it's been somewhat grueling to
go through all the questions and the RAIs, and the
site visits, and the meetings, we think that the end
product justifies all the work that we've had to put
And we know the staff has put an awful lot
of work into it, too, because getting down to just six
open items was -- I mean, we'd like to take all of the
credit for that, but we don't deserve all the credit.
The NRC staff did a lot of work in order to get the
list down to just the six open items.
Okay. Next slide. Now, Bob covered a lot
of this, so I'll skip through a good portion of this
and try to move on. Again, we're located in
Russellville, Arkansas. We are similar to Oconee, a
B&W 177 fuel assembly plant, a 2,568 megawatts
thermal. Our current license expires May of 2014, and
with license renewal, we will have the option to
operate until 2034.
And again, one issue that we always like
to make clear, is that by getting this renewed license
doesn't mean we will operate for 60 years because
economic factors will dictate how long we operate even
if we go beyond 40 years.
But by getting this license, it gives us
that option that if economic factors are good, then we
can continue to operate. Now, you know, two is not
included in this application or this review. It's a
combustion engineering unit, and so, we're going to
have to submit a separate application for ANO-2. And
we plan to do that by September of 2003.
The ANO-1 effort, too, is going to set the
platform for all the subsequent Entergy applications.
And we have a number of other plants that we plan to
pursue license renewal on. So we'll use this as our
template, and the lessons that we learn from this.
And we have learned a lot of lessons going through
this process. We plan to apply to the other units,
and then hope to come in with even cleaner
applications in the future.
Next slide. And again, as mentioned
earlier, we did follow Oconee, and we tried to apply
as many lessons learned as we could. The timing of
our application was very good relative to the
resolution of a lot of the issues on Oconee, and the
completion of some of the topical reports.
Those were completed at a point where we
could take advantage of them in our application. And
as mentioned earlier, there's a lot of credit to be
given to that for reducing the number of open items.
We did participate with the B&W owners
group in developing generic aging management reports,
which were the topical reports we talked about
earlier. But in addition, we developed, or
participated in the development, of mechanical and
structural guideline documents to help actually do the
aging management review.
And those things are sometimes referred to
as mechanical tools and structural tools. We took
full advantage of those, and that's part of what is
described in Appendix C of our application. Also, we
looked at the RAIs that had come out on Oconee, and
tried to incorporate as much of that as we could.
I certainly cant' say that we incorporated
all of the RAI resolutions from Oconee, but we did try
to incorporate the ones that we felt were the more
significant ones. And then also, we got few back from
the NRC prior to submitting our application on what
kind of format they would like to see.
And this was what became known as the
standard format for license renewal application. It
was published a few months before we were to turn in
our application. So again, we took advantage of that,
and formatted our application to the standard format
that was draft at that time.
In addition, we had some conversations in
meetings with the staff to discuss some of the
details, and got some direction there. In fact, some
of the tables that you see in our application were
worked out with the NRC staff ahead of time. Now,
again, it was the first time that we tried to use
those kind of tables.
There were some problems with them as far
as, maybe, level of detail. But again, I think we've
learned some lessons from that and we can apply them
on the next applications. In addition, we worked with
NEI to obtain industry input. During the final stages
of our application, we actually had a peer review of
the draft application with several other utilities
through the NEI License Renewal Task Force. And we
get a lot of benefit from that by getting the
perspective of other utilities on our application.
This slide shows the hierarchy of the
documentation that exists to support the application
itself. The application is the top box on this slide,
and then all of the other documentation below that
represents on-site engineering reports that were
create to support the license renewal project.
The first grouping of documents is what we
call the Class 1 mechanical. These are the ASME Class
1 or the RCS related components. In this grouping, we
had eight reports that were created, eight on-site
engineering reports. And these benefited from the
generic topicals that were done by the B&W owners
And four of those had received prior NRC
approval so that we could actually reference those in
our application. And that was on the reactor vessel,
reactor vessel internals, the pressurizer, and the RCS
The second grouping of documents is the
non-Class 1 mechanical. There were 25 system reports
generated, and these were on systems such as the high-
pressure ejection system, and the emergency feed water
and main steam. For this grouping of documents, we
used the mechanical tools to guide us through the
And those mechanical tools, at the time,
were B&W report. They've now been transferred to EPRI
and they're being published as an EPRI document so
that the whole industry can use those and reference
In the structural area, we had seven
reports that were broken into major structures on-site
and commodities. For example, we had one report on
the reactor building, one on the OTS building, and one
on the intake structure. And for these reports, we
used the structural tools, which at that time were
also B&W document, which has also been transferred to
EPRI and is now an industry document.
And then the electrical area, we had ten
engineering reports on the cables, connectors,
terminal blocks, et cetera. And these were generated
using the Sandia Spaces approach, which is also a more
or less an industry document that we -- that the whole
industry can use to do their review on electrical
equipment the same way.
Then we had separate reports on the
environmental issue, TLAA's, our program's document,
and an EQ. We separated EQ out, simply because of the
volume of work that was required to go through a
reevaluation on our EQ components.
Region 4 has just recently been at
Arkansas on site, performing a review of these
engineering reports as part of this review process.
And they're having an exit meeting on the results of
that on, I believe, it's March the 9th. So we think
that went fairly well.
We haven't got the full results from that
inspection yet, but it seemed to go quite well as they
went through and reviewed the details of these
DR. BONACA: In the phase of scoping, you
know, the documentation shows that you were pretty
much helped by the fact that you have -- you included
all the supports in the system, and those include a
lot of support systems that somebody else could not
call them until later, actually.
MR. YOUNG: Yes.
DR. BONACA: So you have a pretty
comprehensive scope. You all do list in the
application the -- your design basis events that you
considered as the basis, I guess, as the source of
this information. Since you have a pretty extensive
definition, you know, not the minimum requirement
definition of safety-related, I was kind of surprised
a little bit regarding the reactor vessel level
measurement system. And I can see how you don't have
any specific design basis event that would reference
that and become, therefore, excluded. On the other
hand, I mean, that's a true -- the only function of
the system is to provide a safety function of some
type, which is under certain conditions to measure
What was the logic for excluding it that
you presented that was then accepted by the NRC?
MR. YOUNG: Okay. The reactor vessel
level instrumentation was added as a post-TMI
modification. During the development of our emergency
operating procedures, which is where that component
comes into play -- first of all, in the safety
analysis, we take no credit for vessel level
It's not something that we include in any
of our safety analysis as credit. On top of that, in
our emergency operating procedures, they're based on
maintaining a sub-cooling margin in the core. And
that is the safety source of information. And as long
as we can maintain the sub-cooling margin, then we
don't get into any vessel level problems.
As the staff went through and reviewed the
Entergy staff in developing all of these emergency
procedures, they realized that the vessel level
monitoring system is a good piece of information for
the operators to have, but they don't take action on
that information. They take action solely on the sub-
cooling margin in keeping the core cool.
DR. BONACA: But once you lose sub-cool
MR. YOUNG: Again, that piece of
information is available to the operators, but they
take action based on losing sub-cooling margin, not
based on vessel level.
DR. BONACA: Okay. Now, what's the
consequences of not including that system? Does it
mean that --
MR. YOUNG: Really, a lot of -- one of the
things I think is important to understand is by not
having it in the scope, license renewal doesn't change
how it's treated. It's still treated as a full
quality requirements PBX type inspections,
surveillances. It has specifications on if it's out
of service, how long you can continue to operate, or
what you do if it goes out of service.
There's a number of requirements that
still exist because of the post-TMI commitments, and
those have not changed. And they will continue
through the extended term.
DR. BONACA: Yes, that goes to the
commitments issues. What I mean is that, on the other
hand, you could change commitments regarding the
system and not have a linkage to the commitments of
the license renewal. I mean --
MR. YOUNG: Yes, all of that, though,
would have to go through a 5059 review process. And
depending on the outcome of that, you know, possibly
having NRC staff approval before we can make any
changes to it.
DR. BONACA: Okay.
MR. YOUNG: Another factor that would
probably be important to point out here is that we did
include the pressure boundary portions of the vessel
level monitoring system, since that is in the scope of
DR. BONACA: Yes, I saw that.
MR. YOUNG: And most of the other
instrumentation would have been excluded anyway
because it would have been an active component. So I
doubt that even including it would have changed very
much on how we would have handled the aging management
review. Because most of it is just electrical thermal
couples and so forth, inside the reactor vessel.
DR. BONACA: Okay. But certainly, I mean,
right now you may have some guidelines that says that
if it fails, you have some commitment on how long you
can stay with the system failed.
MR. YOUNG: Yes.
DR. BONACA: And, you know, you can change
MR. YOUNG: Well, those, I believe, are
tech specs. So we would have to go through NRC review
and approval to change that. They're not -- they're
not just commitments. They're actually in our tech
DR. BONACA: All right. Thank you.
MR. YOUNG: Okay. On the -- again, on the
scoping, I think we've talked about most of this. The
first, we used NEI 95-10 as our guidance document for
doing the scoping review. And the guidance documents
that were available from the NRC in the form of the
rule and the draft and the review plan.
Safety-related definition we have -- was
mentioned earlier as component level Q-list, and also
a summary level Q-list that's in the SAR. And those
were the basis for determining what equipment was in
the scope of A-1, which is the safety-related
A-2, which is the non-safety-related
components that can prevent a safety-related function
from being performed. At Arkansas, most everything
that would really fall in this category, we had
already classified as Q, or safety related. The
history on that was simply that at the time that we
were building the plant and licensing it, was that if
you had a support system that was needed -- for
example, a cooling water system to a pump.
And that cooling water system was needed
to make that pump operable, we'd call that Q, safety
related. We didn't call it non-Q that could affect
safety related. So we had very little equipment that
fell into the A-2 category. We did have some, because
it is an older plant, and there were a few things like
seismic category two over one, that fell in this
But the majority of equipment was actually
falling in the category of A-1 for us. Next slide.
The A-3 category, which is sometimes referred to as
the regulated events category, included the fire
protection, environmental qualification, pressurized
thermal shock, anticipated transits without scram and
We simply used the design documentation
for those events to come up with a listing of what was
in scope. And as was mentioned earlier, fire
protection is one that we still have an open item on.
We're working through that. You know, we have what we
defined as the scope of our fire protection equipment.
And the -- I think it was four or five
sets of components are being evaluated right now with
the staff on whether or not they should have been
included. And we're going to have meetings on that in
another week or two.
Okay. On the next slide, going into the
screening process, after we had scoped -- we scoped at
the system level, the system and structure level. And
then we went in to do screening to identify the
passive long-lived components that were within those
structures and systems, that had a function that
required an aging management review.
And this was, I guess, the second major
step in the process before you got into aging. And
this again, was using the guidelines of NEI 95-10.
Next slide. The -- once we got into the scoping and
screening work, again, we split it up into mechanical,
electrical, and structural, and did those pretty much
in parallel with separate activities.
All of this work, of course, was done on
a plant specific basis. But for the Class 1
mechanical equipment, we did have the benefit of the
generic B&W topical reports to use, and that was a
tremendous benefit, because when we started into the
site specific, we could basically take those topical
reports and simply deal with the site specific
So most of our actual on-site effort was
in the areas of the non-Class 1 and the electrical and
structural. We didn't have any generic or topical
type reports that we could rely upon. I think that's
all we have on that slide. Next slide.
Okay. The aging effects. Again, the
mechanical review was done on a system basis. We went
system by system, and did and evaluation for the Class
1. Again, we used the topical reports. For the non-
Class 1, we used the mechanical tools to help us go
through that review process.
On the electrical side, we used what's
called the spaces approach, which is based on the
Sandia aging management guidelines. And then on
structural, we used a commodity and a building
approach. We looked at major buildings, but then
within those buildings, we took commodities basically,
steel and concrete, and just did an aging review on
And based on that, we identified the aging
effects that required management. Okay. Next slide.
After we had identified the aging effects that
required management, then we'd identify the aging
management programs. And as was mentioned earlier, we
had -- well, first of all, we had about 30 major
groupings of programs that we've identified.
Now, there's probably about over 100
actual specific programs, but we grouped them, such as
our preventive maintenance program, which has a lot of
individual preventive maintenance activities that we
credited. We just put it in the category -- one
category called preventive maintenance. Same thing
with our chemistry.
But in the aging management programs, we
have a group called the new programs, and then a group
called the existing and modified programs. And there
were seven major categories for new programs that
didn't exist before.
And I've listed a few of them here, our
buried piping inspection program, our electrical
component inspection, certain pressurizer
examinations, reactor vessel internals aging
management, which was a B&W topical issue, and our
Smithfield fuel monitoring programs.
DR. BONACA: I have a number of questions
on these programs. And is it a good time to ask?
MR. YOUNG: Yes.
DR. BONACA: On the buried pipe inspection
program, you know, when I go back to Appendix B, and
I'm looking at what it says, it says that the program
consists of, you know, whenever you have an
opportunity to expose one of these pipes because of
maintenance or a design change, you will look at the
MR. YOUNG: Right, right.
DR. BONACA: And how different is this
program from what you do right now?
MR. YOUNG: The main difference is that
right now, when we expose the piping, it's really up
to the individual work group doing the activity to do
an inspection, so what we want to do is formalize that
and give them criteria so that when they uncover one
of these pipes, they know what to look for, what sort
of things we were concerned about.
We went back in history and looked at the
times when we have exposed buried piping, and we found
that in most cases, they did do an inspection beyond
just the location they were either doing a repair on
or doing instruction. But there was no requirement
for them to do that.
So we felt like that because of the review
that came out of the license renewal, that we should
formalize that into a set of activities or inspection
criteria, that then they would document those results,
and we could watch for trends. So that's the main
DR. BONACA: The other question is just on
the top of your head, what's the frequency of, you
know -- I mean, how many times in the past 30 years
you had an opportunity to --
MR. YOUNG: Yes, we've got about 26 years
of operation now, something like that. And we didn't
go all the way back to the beginning, but we found
that in the last ten years or so, we've had about, I
think, two or three situation where we've had to dig
up piping for various reasons.
So we're thinking that, in general, it's
about once every five years. Sometimes more,
DR. BONACA: Okay, thanks. Second
question I had was on the heat exchanger monitoring
I thought you have core problems, which I'm looking at
performance. I think it's --
MR. YOUNG: We do. That's a little
confusing, the title of that program is a little
confusing, because what we have is our service order
integrity program, which is an existing program. And
it looks at service water heat exchangers.
But what we found in doing our review,
there were some heat exchangers that were not covered
by the service water integrity program. And in fact,
the issue that we're dealing with on the heat
exchanger program is actually a cracking or loss of
integrity, primarily from a seismic viewpoint. So
that gets into things like doing some sort of non-
destructive testing, like maybe 80 current, or
something like that.
So those -- it's a very limited set of
heat exchangers that fall under what we call this heat
exchanger program, because the majority of the heat
exchangers on site are already covered by the service
water integrity program. So they work hand in hand.
We gave it that title, and we found out later that
even the staff questioned us on that, is why are there
so few heat exchangers in your heat exchanger
The reason is we have what we call the
service water integrity program that covers most of
DR. BONACA: Yes. The third question I
have, probably you already answered, I mean, you're
not augmented, because you already have extensive
pressurizer examinations --
MR. YOUNG: Yes.
DR. BONACA: -- to perform as part of the
MR. YOUNG: Right, right. These were some
new commitments on very special locations. And so we
went ahead and called it a new program, just to kind
of, you know, add to the visibility of it. We, in
fact, could have put it over into the category of an
existing ISI program that was just augmented.
But we felt like it was worth making this
one more visible in our report.
DR. BONACA: Okay.
MR. GRIMES: Dr. Bonaca, if I could add,
this is Chris Grimes. And I think that there is still
a certain degree of controversy over the clad
integrity inspections, and the need for them, and the
conduct of them. So, you know, Arkansas has called it
out. They have proposed to do more than we've been
able to negotiate on a generic basis.
But that will continue to be an area where
I think there's ongoing dialogue with the industry.
DR. BONACA: Thank you. On the -- let's
see -- on the reactor vessel internal aging management
program, the application did not specify at all the
time when you would perform the one-time inspection.
But the SER states specifically, I can't remember now,
it refers to some kind of periodic time when it will
MR. YOUNG: Yes.
DR. BONACA: What's the commitment there?
MR. YOUNG: Okay. I might turn this over
to Mark Rinckel. He's the one that has helped us
develop that program. Mark?
MR. RINCKEL: Yes, this is Mark Rinckel.
I think the commitment came through the RAI reposes to
do one inspection towards the end of the fifth
interval. So that would be, you know, towards 45 to
50 years. But also, realizing that Oconee will have
already inspected probably Oconee Unit 1. And we're
going to certainly incorporate lessons learned.
Now, there is, you know, a question as to
whether or not we will have to inspect Unit 1 and O-1,
once Oconee has, but, you know, we are -- made a
commitment to do an inspection towards the end of the
DR. BONACA: So that the fifth interval?
MR. RINCKEL: Yes, the fifth interval is
between years 40 and 50. So it's towards -- I believe
it's towards the end of the fifth interval is when we
made the commitment. Now, I'm going by memory here,
DR. BONACA: I couldn't understand, in
fact, what I was referring to. I only know that
clearly they were specified, although it was not
specified in the application.
MR. YOUNG: Yes, at the time we wrote the
application, I think they were still developing some
of these details in the reactor vessel internals
program, and we coordinated with Oconee in coming up
with this inspection. Because obviously, this really
is a generic B&W inspection effort.
So whatever we find, we feed to the other
plants. Whatever they find, they feed to us. So we
tried to coordinate our commitment on when we would do
an inspection so that we wouldn't wind up doing two
inspections at the same time. We would sequence them
DR. BONACA: Once you have all these
agreements in place, will you amend the application
for your own purpose, I mean, to include these
MR. GRIMES: If I could answer that. It
is our expectation that by drawing a conclusion on the
proposals and the commitments that have been made, and
then are codified in changes in the FSAR, we would
expect that after issuance of a renewed license, that
commitments could be changed in accordance with 50.59
and 50.71 E.
And that -- and much like the vessel
surveillance program this internals program relies on
a sharing of information that we would expect would
feed the different B&W plants, and cause them to
reflect on whether or not they need to make changes in
these programs. And whether or not they trip the
threshold of 50.59 that would warrant a license
MR. YOUNG: And we do plan to document
that inspection frequency in the SAR supplement that
will be, you know, issued with the new license. So it
will be documented.
DR. BONACA: I just wanted to point out,
at this stage, a reader like myself who come in cold
MR. YOUNG: Yes.
DR. BONACA: I went through the
application first, and I found a lot of open issues,
vague -- not vague, but simply they were specified
for, in this case, it will be one inspection.
Then I go to the SER and I find there is
a timing of the inspection stated, and everything
else. So it seems as if something has been negotiated
in between that is not reflected in the application
MR. YOUNG: Yes, we don't plan to amend
the application, but in the commitment itself would be
contained in the SAR supplement.
DR. BONACA: In the supplement?
MR. YOUNG: Right.
MR. PRATO: A lot of this was discussed on
the RAI process. It's documented in the RAIs and
MR. YOUNG: Yes, right.
MR. GRIMES: Yes, Dr. Bonaca, this is
Chris Grimes. Now, I would like to emphasize that
we're at that stage in the review where we expect to
have more dialogue with the applicant in order to
resolve the open items. And then, before we draw a
final conclusion on it, a renewed license, we'd
present the resolution of the open issues along with
any clarifications to the safety evaluation, and it
would feel warranted.
And then those would be reflected in
changes to the SAR supplement where appropriate. But
the whole record will consist of the application along
with all the correspondence since the application was
submitted, in support of the final safety -- the
safety evaluation, the FSAR supplement, and those will
be the two case in terms of having a consistent
explanation of the treatment of these issues.
DR. BONACA: One last question I had on
the problems was -- well, on the spent fuel pool
monitoring, I think already we talked about that. But
I had a question regarding the mineralizers heat
exchangers in part of the scope?
MR. YOUNG: No.
DR. BONACA: They're not? Because they're
not included in the cooling pool?
MR. YOUNG: Right.
DR. BONACA: Just the emergency addition
from the service water.
MR. YOUNG: Yes, right.
DR. BONACA: And the last question I had
was, when I was reading about the program of wall
thinning inspections, specifically the major portion
of the description, you know, regarding application,
Arkansas claims that visual inspections have been
effective in maintaining the integrity of the walls.
When I look at the SER, the SER states
that ultrasonic testing will be neutralized in wall
MR. YOUNG: Yes.
DR. BONACA: Again, there is a disconnect,
and I don't understand.
MR. YOUNG: I believe that we got an RAI
on that, and that was actually an error in our
application. We meant to say that in service
inspections, instead of visual inspection, and it does
include volumetric inspection.
DR. BONACA: So you will go to --
MR. YOUNG: Yes.
DR. BONACA: Okay, thank you. I think
that's pretty much it. Thanks.
MR. YOUNG: Okay, this next slide is just
a summary listing of the 22 existing programs that we
had. And of course, these are some of the major
programs that all plants have, a Section 11 program,
chemistry program, preventive maintenance program, and
One of the things we did find that
literally, probably 95 percent of all of the
components and equipment, that need an aging
management program, already have one. And the new
programs are really covering a limited set of
components. So most everything we need, we already
had in place.
DR. SHACK: Your risk informed ISI, you
referred to as a -- translate that for me. Is that
every risk informed, or the Westinghouse?
MR. RINCKEL: That is, as Mark -- it's the
EPRI, EPRI method. And I think they'll get into that
later, but those application numbers from form ISI,
and essentially resolve the small buried piping issue,
which is a good precedent for future applications.
MR. YOUNG: Right. Okay. The next slide
here is on the time limited aging analysis, and here
I've just listed some examples of the TLAAs that we
had and evaluated. This was done separately from the
rest of the review process. Our list of TLAAs was
very similar to Oconee's, and of course, similar to
other utilities. I think we're all coming up with
very similar lists on our TLAAs.
And we've already talked a little bit
about the boraflex issue. That was something that we
thought was going to last for the full 60 years, but
as we got into the review, we got some test results
back showing that it would not. So we're working with
the staff now to deal with that as far as getting our
Next slide. Yes, that's the end of the
discussion on the application on aging management.
Now I'm going to move into the environmental report.
In the environmental report, again, we --
DR. BONACA: How long do you think you'll
need for this portion here?
MR. YOUNG: About five minutes.
DR. BONACA: Well, let's go through it,
and then we'll take a break so we are on schedule.
MR. YOUNG: And the reason I say that, the
environmental review is going extremely well. We've
really had no problems in that area. Again, we used
NEI and NRC guidance documents. We incorporated
lessons learned, primarily from Oconee. We looked at
what they had done, and tried to adjust our
environmental report accordingly.
We did a new insignificant information
review to confirm the adequacy of the category one
conclusions that were in the generic environmental
impact statement that the NRC staff credits for
Next slide. The environmental impacts in
all areas were identified as small, which is I guess,
an EPA definition meaning that there are no
significant impacts. There were no unique plant
characteristics that would effect the environment
based on license renewal. And we had no threatened
and endangered species present on site.
In the area of SAMA, Severe Accident
Mitigation Alternatives, we identified 169
alternatives to be considered. This was based on the
Calvert Cliffs and Oconee work that had been done
previously. Eighty of those were screened out as
either being not applicable or already having been
implemented at ANO.
And then 89 were subject to benefit cost
evaluation. Of those 89, we only found one that was
actually cost beneficial. It dealt with a training
program -- or -- yes, a training item that dealt with
the operator switchover when they're going from the
water storage tank to the sump during ECCS
That was the only on that turned out to be
cost beneficial. As we looked into it further, we
determined that the training program had been
appropriately modified, and there was no further
action required there.
No SAMAs were identified that were age
related, including the one that was cost beneficial.
Tom Kenyon, our NRC Project Manager on that, has done
a very good job, I think, of going through and doing
the review. We had a couple of public meetings.
Those went quite well.
And we're now, I think, in the final
stages of getting the supplemental environmental
impact statement issued and published. And then the
last slide, just a quick conclusion, again we utilized
a number of the lessons learned from Oconee and the
industry to get to where we are.
We appreciate that support that we got
from the previous applications, and from the NRC's
previous reviews. We were able to reduce the number
of RAIs during the review process, as was mentioned
earlier. I think Oconee had over 350 and we had
pretty close to 250.
Of course, we'd like to get that number
down even further and later applications, but still
that was quite an accomplishment. And we also reduced
the number of open items down to six, with taking
benefit from those lessons learned. In our opinion,
the license renewal process is stable and predictable.
We, as well as the other utilities that we're working
with on the NEI group, are building our applications
off of each previous application.
So I think you'll see that the
applications, for example, Turkey Point, that has come
in fairly recently, used a lot of lessons learned from
our application as well as Oconee. And hopefully,
they'll come through with a lot of the issues we're
dealing with, and our RAIs will already have been
dealt with in their application. So that's all I had.
DR. BONACA: Thank you. Any additional
questions from the members? I thank you for your
presentation. I think we will hear about the
specifics in this scoping methodology, and design
basis events, and open items after the break. So
let's take a break now until 10:15.
(Whereupon, the foregoing matter went off
the record at 9:59 a.m. and went back on
the record at 10:16 a.m.)
DR. BONACA: Let's resume the meeting, and
we now can proceed to the next presentation on the
MR. GALLETTI: Good morning. My name is
Greg Galletti. I'm an operations engineer with
Nuclear Reactor Regulation, Division of Inspection
Performance Management. I'm in the Equipment Quality
and Performance Branch, and our Branch had the
responsibility for the screening and the scoping
methodology review for the license renewal
What I wanted to go over today was quickly
give you an overview of the methodology review that we
performed, that was both done in-house and as an on-
site audit. And then get into some of the findings
from that review, our conclusions from that review and
then we'll switch over and discuss a little bit about
the plant differences between the Oconee and the ANO
With respect to the scoping methodology,
the staff's mandate was to review the license review
application to ensure that the information provided in
the application was consistent with the 54.4
regulations. In order to do that, the staff
implemented a two-tiered approached, one being the in-
house review of certain design documentation.
Specifically, what we looked at was the license
renewal application information and some of the
supporting information that was provided by the
Some of that supporting information we had
already in-house, for instance, the updated final
safety analysis report, which we used quite heavily;
the B&W ATOG, which is their emergency procedures
guideline documentation, which the licensees have used
to generate their own site-specific EOPs. And we had
the benefit of using the applicant's summary report
from their IPE.
The basis for our doing the desktop review
was, as I mentioned, first, to ensure that their
application documentation was consistent with the
regulations, that it encompassed all of those aspects
of 10 CFR 54.4 that were required. And then,
secondarily, the supporting documentation provided the
staff some additional insights as to how the applicant
had implemented their procedures and processes to
ensure that their final product was consistent with
their LRA application.
In addition, some of the background
documentation, like the updated final safety analysis
report and the EPGs, provided the staff some better
understanding of the design basis, certain design
basis events that the licensee basically was
responsible for reviewing, and gave the staff some
additional understanding of some of the CLB issues.
In addition to the desktop review, we had
the opportunity to do an on-site audit, and that was
performed by three staff members over a period of
about three days, and that was done on-site at the
engineering facilities of the licensee, the applicant.
The purpose of the on-site audit was initially to
verify that the documentation provided in the LRA, in
terms of the process used to generate the scoping
methodology, was consistent with the actual
application in the field; that is, that what they
described in the LRA was consistent with the actual
application of the engineering procedures and the
process that they -- the implementation process the
licensee used at their own facility.
Secondarily, what the on-site audit
provided us is an opportunity to look at some products
from their LRA implementation process to ensure that
there was consistency in those products; that is, the
different reviewers, different engineers that were
involved in the review basically had the same level of
detail, same analysis approach, same processes used to
generate their final reports.
And thirdly, the on-site audit provided us
an opportunity to look more specifically at the
implementation guidance of the licensee. Their
engineering reports, that Gary had mentioned earlier,
we got to look at some of the detail associated with
those reports, and we got to look at their actual
implementing procedures; that is, what specific
guidance, if you will, and operating procedure, if you
will, for this purpose, specific guidance that the
engineers had at their disposal that governed what
sort of information they looked at, how they
approached the process of developing the LRA, the
scoping methodology and the results.
DR. BONACA: This on-site visit was three
days, you said?
MR. GALLETTI: Yes, sir.
DR. BONACA: Okay. Because in the
application and also in the NCR there is a lot of
statements regarding the fact that the applicant
stated that or has stated that. So that was the
extent of the verification process.
MR. GALLETTI: The initial verification
process, which was done in-house, which was to review
the LRA and make it very clear what the applicant
provided to us.
DR. BONACA: Okay.
MR. GALLETTI: In addition, the on-site
audit provided what I would characterize as a
verification and validation process for the staff.
That is, we were able to verify that the process used
by the applicant matched very well with the
description that was provided in the LRA.
And in terms of verification -- or in
terms of validation, again, we got to see the end
results. We got to look at the specific design
documentation that the applicant used. We got to
understand the scope of that design documentation, and
that was quite important, because what we wanted to
set out to do was establish that the licensee had done
a credible job of reviewing their CLB and ensuring
that they went, certainly, just beyond like accident
analysis or just design basis events.
DR. BONACA: One statement regarding the
involvement of the staff was that you took some
systems or some components that were not included in
the scope by the application, and they were
borderline. And for those, you verified that in fact
the contention of the applicant was correct.
MR. PRATO: This is Bob Prato. That's
part of the scoping inspection.
DR. BONACA: Yes.
MR. PRATO: What Greg is talking about is
the methodology review.
DR. BONACA: Okay.
MR. PRATO: We actually spent an
additional -- there was seven us I believe. And we
actually did a verification that what they actually
included within the scope of license renewal was
consistent with the methodology, the application and
DR. BONACA: Okay. So there were two
visits then to the site.
MR. GALLETTI: Right, right.
MR. PRATO: When we do that scoping
methodology, we do it in really two stages. The first
stage is we pick a number of systems that we feel are
important, that can be important, that were not
included within the scope of the license renewal, and
we verify that those systems do not meet the criteria.
And once we do that verification, we have a
comfortable feeling that they've included all the
systems within the scope, and then we go into the
screening and the actual scoping activities.
DR. BONACA: All right. Two visits there,
and this was meant.
MR. GALLETTI: Correct, yes. The purpose
of our audit was to ensure that the methodology that's
been outlined --
DR. BONACA: I understand.
MR. GALLETTI: -- in the engineering
documents is consistent with the regulations.
Basically, one of the things that we did
in the on-site audit was to review some of the design
documentation as the results of the LRA application.
In essence, we looked at what's called the upper level
documents. These ULDs are essentially a library of
documents that cover systems, structures, events, if
you will, design basis events, as well as additional
topics. And by looking at those ULDs, as well as
looking at what Gary brought up before, the Q list
development process, the staff was able to come up
with reasonable assurances that the process
implemented by the applicant was consistent with 54.4.
If I could go on to the specific findings,
as a result of our in-house review, as well as our on-
site audit, we did find that the applicant's approach
was consistent with 54.4 in terms of defining what
safety-related equipment was consistent with A-1,
understanding their consideration for non-safety-
And what's been brought up already is the
fact that many things we would characterize as non-
safety whereby the virtue of the licensees desire are
already safety related. And those things above and
beyond that, such as the seismic two over one or some
internal flooding types of systems and components were
brought into play as a result of the review.
And, finally, we did verify that the
regulated events, if you will, the ATWS, the station
blackout, those sorts of events were well analyzed by
the applicant. There is sufficient design
documentation available to us to ensure that they had
done a credible job of reviewing those events and
scoping in the proper equipment components and
What we found is that their scoping
process was very well defined in their engineering
reports, and that the implementation of those
processes was very consistent. The audit also
provided confirmation that the process implementation
was consistent with the descriptions provided in the
LRA and also consistent with the specific engineering
procedures that the licensee had been developed for
In conclusion, the staff made a safety
finding that the applicant's methodology and
implementation was sufficient to develop and we
believe maintain the scope of the license renewal
application over the period of extended operation.
If I could, I'd like to -- if there's no
specific questions on those areas --
DR. BONACA: Well, I have two questions on
scoping that you and you with the applicant may
answer, if I could ask them now.
MR. GALLETTI: Certainly.
DR. BONACA: Because we're going to be
getting into section three, which is more of the aging
management problems, right?
On scoping, I have just a few questions.
One is, I was looking at page 217 of the SER where it
talks about the fact that Arkansas included components
not addressed in the B&W 2243(a). And I was -- one
thing I was aware of is that some of the B&W plant
experienced letdown system pressure breakdown,
orifices failures. Are those included in the scope?
MR. YOUNG: The orifices are included from
the viewpoint of pressure boundary, but they don't --
I don't believe those particular orifices perform a
safety function, so they weren't in there for flow
control or anything like that. But they were in there
for pressure boundaries, so they were included.
DR. BONACA: Pressure boundary. So they
are for pressure boundary.
MR. YOUNG: Yes.
DR. BONACA: Okay. Thank you. The other
question I had was -- maybe this is just a confusion
on my part -- in the section that speaks about the
steam generator, there is a reference to the fact that
the auxiliary feed water in the piping is not in
scope. But then when I look at the SER, and
specifically it talks about the emergency feed water
system, it seems to be in scope, the piping. And I am
confused. I mean do you have two different systems,
an emergency feed water system and an auxiliary feed
water system or is it the same system and then these
MR. RINCKEL: This is Mark Rinckel. I
believe that was an error in the original application.
There was an RAI on that. That piping is in the
scope. I've got a picture of it here if you want to
see it. But it's the riser piping that goes from the
header into the generator.
DR. BONACA: If I could see that?
MR. RINCKEL: Sure. Oh, wait, let me make
sure I brought it.
DR. BONACA: So you don't have two
systems. Because also I found at times it's referred
to as auxiliary feed water system; at times it's an
emergency feed water system. I think the application
is auxiliary, and the SER is emergency. So I thought
maybe they're two different systems. I wanted to
MR. RINCKEL: I apologize, I didn't bring
the picture of the generator.
DR. BONACA: All right.
MR. RINCKEL: But what it is is there is
a main feed water header, there's two of them, and
there's riser piping that goes up and attaches to the
shell of the generator. And all of that's in scope.
And emergency feed water has a similar application,
but I think it goes almost all the way around, it's a
header, and there's riser piping that goes up and
attaches to it. All of that is in scope.
DR. BONACA: Okay.
MR. RINCKEL: And what was in the
application was an error. That was clarified in RAI
DR. BONACA: All right. Is the mechanical
seal package of the reactor coolant pumps in scope?
MR. YOUNG: Sorry, what?
DR. BONACA: The mechanical seal package
in scope for the RCPs?
MR. YOUNG: No. The seals are replaced
based on --
DR. BONACA: Because you have periodic
MR. YOUNG: Right. So they don't have a
DR. BONACA: All right. One question I
had was regarding the reactor vessel head leakage
monitoring piping, which was excluded, and the staff
accepted that on the basis that Arkansas estimates
that the leak flow would be within the capacity of the
makeup system. Could you explain to me what estimates
MR. YOUNG: Well, first of all, the head
leak-off path is after the first o-ring in the reactor
vessel head, and it does have an orifice in it, or a
small opening that goes into the piping. So what we
did is we did a review on what would happen if that
was orifice was exposed to the full RCS pressure and
how much flow we would get out and could we handle it
with our makeup capacity? And we found that we could.
But in reality the path to get there is so torturous
that the flow would actually be much lower than that.
DR. BONACA: Okay. But still you
performed the calculation.
MR. YOUNG: Yes.
DR. BONACA: All right. So it wasn't just
MR. YOUNG: Oh, no; you're right. Right,
we did some analysis on it.
DR. BONACA: Yes, I was just questioning
the word "estimates."
On the emergency room drains there was a
request for additional information, and then you said
that there is a drain there that is a 10-inch drain,
I believe, that will allow you to prevent flooding.
What prevents the drain to be clogged, I mean, and to
have the flooding?
MR. YOUNG: The drain that was being
referred to there is actually a pipe. I think 10
inches, is that what --
DR. BONACA: Yes.
MR. YOUNG: It's a fairly big pipe. It's
actually a hole in the wall.
DR. BONACA: It's a 10-inch pipe, yes.
MR. YOUNG: It's an exterior wall, and
it's just a straight pipe right through the wall, so
there was no aging mechanism or anything that could
come into play.
DR. BONACA: So it's not a question of
aging. It's a question of -- no, I understand.
And I had one more question. It was of
the auxiliary building hitting a ventilation. They
have a function of maintaining 60 degrees during
winter. Now, I don't know, maybe you never get below
60 degrees in America, but the question I had was do
you have -- are the heating components in scope?
MR. YOUNG: I believe the way that's
handled, pressure boundary components are in scope.
So any portions of the system that had pressure
boundary would be. I don't believe we had -- you're
talking about electrical heating elements?
DR. BONACA: Yes. Because the 60 degrees
contingent is to prevent components from freezing.
MR. YOUNG: Right. The electrical
equipment, like heating elements and so forth, are
considered active, because they have to be energized
in order to perform their function. So they were
excluded upon that basis.
DR. BONACA: Okay. I agree with that.
Okay, thank you.
MR. GALLETTI: Okay, if I could, I'd like
to switch to a quick discussion of the differences
between the Oconee review and the ANO review with
regard to the scoping methodology, specifically
looking at the design basis events, which I understand
from previous discussion was a topic of concern.
With respect to ANO, clearly, as part of
their scoping methodology, they looked specifically at
their Chapter 14 accident analysis events. But far in
addition to that, as part of their Q list development
process and as part of this ULD development process
that we discussed earlier, the applicant went far
beyond Chapter 14, clearly looked at all of the FSAR
as it related to the events, and then went beyond that
still to consider the current licensing basis.
And if you look at that supporting
documentation, the ULDs and the Q list development
process, when we went through that as part of the on-
site audit, we were able to take a look specifically
at the types of information that the licensee had
employed for those reviews.
In doing so, we confirmed that they had
looked at operational experiences, they had looked at
commitments they had made to the NRC regulations, they
had looked at exemptions that were made to the
license. So they really encompassed all of their CLB,
as far as the definition was concerned, in those
reviews. And it was a major difference between the
two right off the bat.
The second difference which was brought up
had to do with the definition of safety-related. For
the Oconee review, they relied on, basically, three
barriers to the release as their definition. For ANO,
as was brought up, they relied on basically the 54.4
A-1 definition -- A-2? And A-2 definition for what
So in that respect, we were aligned from
the very beginning with ANO-1 in terms of coming to a
formal and agreeable definition.
DR. BONACA: Now, the difference in
definition between the Oconee application and the
Arkansas, did it lead to significant differences in
the equipment that is in scope?
MR. GALLETTI: I don't believe it really
led to a change in the equipment versus led to an
understanding of if the requirement was that you look
at these three criterion, instead of doing that you
looked at these criterion, what was the nexus? How
could the staff make a safety finding that in fact by
using these other criteria, that you were using the
same approach or was going to have the same effect.
DR. BONACA: I don't want to reopen the
issue of Oconee. We know that was a difficult scoping
process. But as we go forth, for similar plans, I
would expect that once we make a determination that
certain components had to be scoped, that logic should
extend to sister plants. And I'm not saying that
they'll identical these plants, but they're very
MR. GRIMES: Dr. Bonaca, this is Chris
Grimes. I think Greg has struck on it more from the
standpoint of our ability to understand the current
licensing basis and the associated intended functions
that are relied on is going to be easier when there's
a process and a methodology associated with
maintaining that Q list that is as comprehensive as
the one that Entergy employs at Arkansas.
Our struggle at Oconee was more from the
standpoint of understanding their licensing basis.
With the resultant set of components, we would expect
to see only minor differences in plant licensing
basis. So it really gets to our ability to understand
and have reasonable assurance in the scoping process
that is benefitted by a process that maintains the
licensing basis with such clarity.
MR. GALLETTI: And I guess to close out
this discussion, the final change, or difference,
between the two applicants was that with the Oconee
review, initially they looked at their accident
analysis design basis events and then included natural
phenomenon and external events. And one of the areas
of concern or issue was the anticipated operational
occurrences and defining what those are and scoping
those in. And there was a lot of discussion between
the staff and the licensee on doing that.
With respect to Arkansas, we didn't see
the same issue arise, again, as a result of their Q
list development process and their ULD development
process. Those anticipated operational occurrences
were in fact considered during those review programs.
In conclusion, there were two open items
as a result of the scoping methodology. The first is
the applicant needs to provide a technical
justification for not including in-line flow orifice
flow control intended function to ensure proper sodium
hydroxide injection rate for pH control.
The second open item we currently have is
to have the applicant provide a technical
justification for not including fire protection jockey
pump, carbon dioxide systems, fire hydrants, the water
supply to the low-level rad waste building fire
protection system and the piping to the manual hose
station as being within the scope of license renewal
and subject to an AMR. I believe both of these issues
have been previously brought up today.
DR. BONACA: As part of this open item is
the question also about fire water storage tank. Is
there a fire water storage tank or is the source of
MR. YOUNG: The source of water is our
service water system, the lake, so it's an infinite
DR. BONACA: Okay. Thank you.
MR. GALLETTI: That concludes my
presentation. Thank you.
DR. BONACA: Thank you. Any other
questions for Mr. Galletti?
MR. PRATO: Next presentation will be
"Common Aging Management Programs," by Meena Khanna.
MS. KHANNA: Good morning. My name's
Meena Khanna. I'll be talking about common aging
management programs, and I guess I'll go ahead and
A common aging management program, as you
already may know, is a program that covers and manages
the applicable aging effects of two or more systems'
inner structures. Entergy identified 12 common aging
management programs in their ANO-1 LRA, and these
include the Chemistry Control program, the QA program,
structures and system walkdowns, the Heat Exchange
Monitoring program, buried pipe inspection, Wall
Thinning Inspection program, Boric Acid Corrosion
Prevention program, flow accelerate corrosion
prevention, leakage detection and reactor building,
oil analysis, Reactor Building Leak Rate Testing
program and the ASME ISI program.
The staff and the contractors evaluate the
Aging management program against the following
elements, as discussed in the standard review plan.
These include scope, preventive actions, parameters
monitored, protection of aging effects, monitoring and
trending, acceptance criteria, corrective actions,
confirmation process, admin controls and operating
Now, there's three of those that are
covered under the Corrective Actions program, as was
stated in the LRA. For ANO-1, the elements involved
corrective actions, confirmation process and admin
controls are all discussed in the Corrective Actions
program, so we don't address those elements in the SE
Okay. For open items, there were no
significant open items. However, there are a few
minor FSAR supplements that will be needed to be done
by Entergy. They're listed in the SE. We don't have
to go into those, because they're not really
important. They're just basically summaries that need
to be beefed up in the FSAR supplement.
Okay. Plant differences. If you compare
the ANO-1 LRA to the Oconee, basically, with respect
to the common aging management programs, Entergy's
description of the aging management programs were
written very closely to those for Oconee. And we
noted a few differences. If you compared the elements
to those of the SRP, there are some differences;
however, we were still able to do a parallel review.
So, basically, you know, we didn't have a problem in
reviewing those programs.
ANO-1 applied many of the lessons learned
in determining their aging management programs. That
was the difference with Oconee. And, finally, the
aging management programs for ANO-1 were very similar
to those for Oconee. There were only a few
deviations, and those were due to site-specific
differences or limitations, such as the Buried Pipe
DR. BONACA: Okay. Of this common aging
management programs, some of them are the new
programs, right, like the Buried Pipe Inspection
MS. KHANNA: Right, exactly.
DR. BONACA: -- Heat Exchange and
Monitoring program. And some of them are existing
MS. KHANNA: Exactly.
DR. BONACA: Okay. Now, okay, we have
some questions about the new programs. And you use
the ten elements of the SRP.
MS. KHANNA: Right. We look at the SE.
That's how we actually evaluate them against those ten
DR. BONACA: That's right.
MS. KHANNA: A couple of them were a
little different the way they were written up, but you
could still get the same information if you read the
DR. BONACA: Okay. For example, the Flow
Accelerated Corrosion Prevention program, that's a
standard programs or existing program --
MS. KHANNA: Right.
DR. BONACA: -- that's being used. In
fact, those, in the evaluation, it's referring to
standards that are in place already.
Okay. Any questions for members regarding
this? Thank you.
MR. PRATO: "Reactor Coolant System,"
MR. LEE: Good morning. My name is Andrea
Lee, and I work in the Materials and Chemical
Engineering Branch. I was the technical monitor for
the contract to review the RCS and also the lead
And in terms of an overview, there were
several topical reports for the RCS system. There was
one for the reactor vessel, for reactor vessel
internals, for piping and also for the pressurizer.
And there were several applicant action items in each
of those reports, which license renewal applicants
have to respond to.
Most of the applicant items were addressed
in the initial application, but through the request
for additional information process, we got expanded
information and additional clarifications, which
allowed us to draft the safety evaluation report with
no open items.
In terms of differences in Oconee and some
of the other applications, one difference was the
Alloy 600 and Alloy 82/182. The applicant is
monitoring the locations that are most susceptible to
cracking during the period of extended operation. And
the method used to identify these locations was a
susceptibility model. That model is similar to a
model that was accepted for the CRDMs, and that was
based on an EPRI model.
And just as a summary, the model that was
used, there was a reference Alloy 600 item that was
picked. And that item was the pressurizer
instrumentation nozzle, and that is a nozzle that was
found leaking in 1999 -- or excuse me, 1990. Once
that item was selected, there is a relative time to
crack initiation that was calculated for the item. So
to extend that to the other locations, a
susceptibility factor was calculated.
And throughout the process there was a
comparison of material parameters and other items,
such as chemistry, in order to extend that reference
to the subject component, Alloy 600 component that was
being compared. Once that process was done, there was
a susceptibility factor calculated for the new item.
And in terms of the items that were determined to be
most susceptible, they were all piping components in
Another difference was the way small bore
piping was handled. And just as background, small
bore piping, as you probably know, is piping that's
less than four inches nominal pipe size. And also as
background for the ASME code, any piping that's
between one inch and four inches, there's no
requirement for volumetric examination. There's just
a surface. And for any piping less than one inch,
there's no volumetric or surface requirement.
So in light of that, and the final safety
evaluation for the piping topical, the staff suggested
that all applicants do a one-time inspection. And ANO
was unique in that they implemented a risk-informed
process. And through that process, they picked the
most susceptible locations. And from that, they're
going to do an ongoing program. And this was already
approved for the current license.
So it was just extended into, and the
materials and the parameters were looked at for the
period of extended operation. So because of that
extension, it negated the need to have a one-time
inspection. This is an ongoing program, which is an
improvement than just doing the one-time inspection.
And the --
DR. BONACA: If I remember now, the
previous applications we had one-time inspection in a
MR. LEE: Yes.
DR. BONACA: Right? So this is now a
MR. LEE: Well, for the -- if I'm not
mistaken, for the other applications it was one-time
inspection for a susceptible location.
DR. BONACA: Yes, that's right.
MR. LEE: And just as a matter of
interest, the susceptible locations were the
pressurizer spray line, make-up and purification
lines, letdown lines, and cold leg section drain
lines. And these are all one and a half- or two and
a half-inch lines.
And during the course of the request for
additional information process, we got very detailed
in asking, "Well, this is a good procedure for between
one and four. Is this extended to less than one?"
And throughout the process, it's the same materials
and the same kind of considerations, so that was
rolled into the evaluation for all of small bore
piping. So we didn't have to keep making the
distinction between less than one and between one and
DR. BONACA: Okay.
MR. LEE: And that's all that I prepared,
unless you have any more questions.
DR. BONACA: Now, there are no Class I
piping fabricated from CASS-1 at Arkansas-1; is that
MR. LEE: Pardon me?
DR. BONACA: There are no Class I piping
fabricated from CASS component?
MR. LEE: No.
DR. BONACA: In Arkansas. Now, the SER
refers to five leaks associated with RCS small bore
MR. LEE: Yes.
DR. BONACA: -- which have been identified
in the past? And there's a comment that says that the
applicant states that all leaks and cracks were caused
by vibration of fatigue due to design problems. And
how far back in time -- oh, yes, I can see that. As
late as 1998, however, it occurred.
MR. YOUNG: Yes. Right. What we found
was all of those leaks that occurred before, when we
did our root cause evaluation, identified some sort of
a vibrational problem or a support problem or a change
in the way we operated the plant. And the solution in
all those cases was to do a design change to correct
the problem that caused the cracking.
DR. BONACA: Okay.
DR. SHACK: I guess I had one question.
I'm a little surprised to find that everybody believes
Alloy 600 is the more limiting component over the
Alloy 82/182, and so that when you look at the most
susceptible Alloy 600, you've bounded the 82/182. And
I just wondered if any rethinking of that since the
MR. LEE: That may be a better question
MR. RINCKEL: Yes. This is Mark Rinckel.
The program that -- Alloy 600 program that Arkansas
has relies upon the B&W Owners Group program. And it
includes all the Alloy 600 items and all of the Alloy
82/182 weld locations. Up until this point, it was
pretty much expected that the base metal would be the
more limiting item. Recent events may change that.
DR. SHACK: Certainly in my laboratory
tests I wouldn't believe that.
MR. RINCKEL: Well, it was because of the
stresses and the way it was fabricated, at least our
components and what we had seen before. You know, the
nozzle that cracked at Arkansas was the base metal; it
wasn't the weld. And so for the B&W design
components, that's what we had seen.
But this is a living program, and they're
going to have to go back and see how this new
information affects the ranking. And the ranking was
done for ANO, as well as Oconee. Oconee used a
similar type ranking process, and identified the top
five locations amongst the three. But the program
will evolve, you know, as they get more operating data
and so forth.
DR. SHACK: Yes. It's hard to look at one
without looking at the other.
MR. RINCKEL: Yes. So to answer your
question, every weld and every Alloy 600 item is
catalogued and is in the program. It's how it's
treated, you know, will evolve and will change. And
it may result in focusing on different locations for
MR. ELLIOT: Barry Elliot, Materials and
Chemical Engineering Branch of NRR. As far as a weld,
82/182 welds, that's a current problem. We're
evaluating -- the industry is a proposing a program
right now to evaluate the entire -- all welds in the
reactor coolant pressure boundary that are 82/182.
And whatever program we come up with for those welds
will carry forward into the license renewal term.
DR. SHACK: I guess I had one other
comment too, and that was in the SER, there was a --
they were evaluating the program for thermal fatigue,
and they were taking credit for the primary water
chemistry. Now, I'll yield to nobody in my dedication
to good primary water chemistry, just how much it buys
you in terms of thermal fatigue, I'm a little
MR. ELLIOT: We agree. And that's why we
have the Small Bore Piping program.
DR. SHACK: Well, but if you read the SER,
it's a preventive factor for thermal fatigue.
MR. ELLIOT: Yes. And that's why we have
inspections, to find that out.
PARTICIPANT: I don't believe that's the
only aging management program.
DR. SHACK: No. It was just under one of
the ten element assessments. I agreed that it
certainly does -- you wouldn't want bad water
chemistry on top of thermal cycling. Good water
chemistry isn't going to save you from thermal
MR. GRIMES: When we go back -- this is
Chris Grimes -- when we go back and address the open
items in the final safety evaluation, we'll check to
make sure we haven't overstated water chemistry.
DR. BONACA: Now, my understanding is that
for this presentation it includes the reactor vessel
and pressurizer, right?
MR. LEE: Yes.
DR. BONACA: Not the TLAA portions.
They'll be later.
MR. LEE: That will be later.
DR. BONACA: And I guess for this
component, it's pretty much B&W document supply.
MR. LEE: Yes. The only component that
did not have a topical was the pump. There may have
been another one, but from my recollection, the
reactor coolant pump did not have a topical.
DR. BONACA: Okay. And there is a
specific description here of the programs to manage
MR. LEE: Yes.
MR. RINCKEL: This is Mark Rinckel. The
other component that did not receive or have a topical
report was the steam generator, the OTSG. And, again,
the review of that was very similar to Oconee, since
they have the same OTSG.
DR. BONACA: Any comments on that, Bill.
You had some comments yesterday.
DR. SHACK: I looked at that again. I
have no idea -- what is the status of the steam
generators at ANO-1? Do they show degradation? Are
there plans to replace them or they're still marching
MR. YOUNG: They're still marching along
fairly well, but we are in the early stages of doing
an evaluation for possible replacement because of the
industry experience and the Oconee experience. So I
think at this point it would be safe to say we don't
expect them to last the full 40 years, but they
haven't started degrading to the point that we have to
make any definite plans for replacement. We're just
doing some preliminary plans at this moment.
DR. BONACA: Okay. Thank you. Any other
questions for Ms. Lee? No, so thanks a lot.
MR. LEE: Thank you.
DR. APOSTOLAKIS: Speaking of risk-
informed stuff, what is the core damage frequency at
ANO Unit 1 from the IPE?
MR. HARRIS: For the IPE, it was 3.47 E --
DR. BONACA: Please introduce yourself.
MR. HARRIS: This is Richard Harris at
Entergy. For the IPE, I believe the core damage
frequency was around 3.67 E minus 5. I may be off a
little bit, but it was a net in that area.
DR. APOSTOLAKIS: You say from the IPE.
I mean have you done anything to it afterwards?
MR. HARRIS: Yes. We have done a couple
of revisions to --
DR. APOSTOLAKIS: And what is it now?
MR. HARRIS: The current core damage
frequency is around 5.6 E minus 6.
DR. APOSTOLAKIS: Went down by, wow,
MR. HARRIS: There are some specific
reasons that for. One of the dominant contributors to
risk in the IPE was the station blackout sequences
lost that power. Since that time, we've put in a SBO
diesel, which took us from around 3.6 down to about
1.90 minus 5. And then our small break LOCAs became
a pretty dominant contributor after that revision.
We've since gone to new reg 57.50. We're initiating
the frequencies. And that's not the small break LOCA
frequencies. Our contributor's down significantly.
And there's some other changes included in that, and
those are addressed in the environmental report, but
those are the main things that took the core damage
DR. BONACA: And this is only internal
MR. HARRIS: Yes.
DR. BONACA: And you've done the IPEEE as
MR. HARRIS: Well, we have done IPEEE. We
did a vulnerability assessment for fire and a seismic
margins method for that portion. We haven't
calculated a core damage frequency for our fire
DR. BONACA: But you will?
MR. HARRIS: Well, at this point, we'll
see where we're going with that. The intent of the
IPEEE effort was to identify vulnerabilities and
weaknesses in your operation system, et cetera. And
we've done that. And we've met the intent of IPEEE.
But there was no requirement to generate a core damage
frequency in that effort. And although we did use our
PSA models and fire methodology to do screening, we
didn't calculate an absolute core damage frequency for
DR. BONACA: Well, I guess that's not a
question to you, but I'm really curious now how one
can find vulnerabilities without calculating the core
MR. HARRIS: Well, you can -- what you can
do, or what we did, and I think most of the industry
did, was we did a screening analysis. By removing
those components within the zone that would be
affected by a fire in that zone, you can then quantify
and determine what your CDF is. And if it's below 1E
minus 7, it screens, you're done. If it's above 1E
minus 7, then you go in and you look and say, "Well,
is this -- does this really fail or does this really
impact this equipment? What are the circumstances?"
And you work on it until it either screens or it
And once it gets -- if it screens, you
stop. If it doesn't screen, then you work on it a
little bit more until you get to a point where you
feel comfortable that you've adequately assessed that
zone. Then you go to the next zone and you do the
same thing. But you're not really trying to determine
an absolute core damage frequency for each and every
zone. You're simply doing a screening analysis.
DR. BONACA: Okay.
MR. PRATO: The next presentation is on
"Engineering Safety Features," by Bart Fu.
MR. FU: Again, my name is Bart Fu. I'm
with EMCB NRR. I'm also the tech monitor for the ESF
section during ANO's license renewal process.
Just a brief overview of ESF system. They
consist of ECCS actuation part of it. That's the
LPI/HPI. And core flood. Then it also includes
reactor building spray, reactor building cooling,
purging, isolation. There are a few more: sodium
hydroxide system, hydrogen control system. So they're
designed, again, for the engineered safeguard purpose
in case of a LOCA, in case of -- well, during shutdown
you use them to cool the core.
Most of the components are made of
stainless steel and carbon steels. In a few systems,
we've seen 90/10 carbon nickel and also inc alloy 800.
And they're exposed to air, ambient air, water and
borated water. Those are the environments.
Aging effects identified. Major aging
effects are pretty much a loss of materials, cracking
and fouling. Aging management programs. I believe
Meena discussed the common again management programs
a little earlier. For a few of the systems, they have
specific aging management programs just for the
specific aging effects identified in the process.
We don't have any open items. There is
one item that was added to the supplemented FSAR.
That items calls for a one-time inspection of the
piping in the sodium hydroxide system. But all issues
are resolved at this point.
I was told to focus on the plant
differences. Really, as you all are aware of, they're
sister plants with Oconee, and even the process is
pretty much similar. The way I've seen, you know,
they've got, I think, a little bit more streamlined in
their process. The few differences that I know of,
one is the hydrogen control system. It was identified
and reviewed as part of the auxiliary system in the
Oconee's process but as an ESF system, part of the
ESF. In ANO's process, under the same -- it should be
listed the same system.
Under this hydrogen control system, no
aging effects were identified for the Oconee's review
process, but at ANO, fouling was identified as an
aging effect. That was the only difference for this
system. And it's actually fouling at the external
surface for the EP changers. They're exposed to a gas
The other difference, halide impurities.
The concern was raised during the process, and we
talked to the plant engineers about the -- we called
it a little bit too high of impurities in the sodium
hydroxide system -- or sodium hydroxide. And we
addressed this issue. And it resolved the item I
mentioned that was added to the supplemented FSAR that
calls for a one-time inspection of the system.
DR. SHACK: I mean there was some
difference in the specification for the purchase of
the sodium hydroxide that would let you expect more
MR. FU: I'm not sure about Oconee, but at
ANO that was the case, yes, because they may have
purchased sodium hydroxide from different sources.
But when I reviewed the Oconee's SER, this concern
wasn't raised. So it could be the sources, but I'm
not so sure.
DR. SHACK: What temperature is that
system? I mean that stuff sits around at room
MR. FU: Right. Ambient air. So we're
talking about 90-some.
DR. SHACK: Oh, so it's -- yes.
DR. BONACA: Much of this piping is
exposed to boron, right?
MR. FU: Boron streaming.
DR. BONACA: I'm sorry? Many of the
systems are exposed to boron.
MR. FU: Right. Or to water or boron.
DR. BONACA: Yes. So I guess -- so this
must be controlled by some kind of -- oh, yes, boric
acid, corrosion --
MR. FU: Right.
DR. BONACA: -- carbon. Is this problem
looking at piping inside and outside only or just
simply focusing on the internal corrosion of piping?
MR. YOUNG: Are you referring to the Boric
Acid Corrosion Prevention program?
DR. BONACA: Yes, yes.
MR. YOUNG: It's external piping carbon
steel and components. So the program is basically a
walkdown inspection looking for boric acid crystals.
And then if we find them, we trace them back to the
source and see if it has contacted any carbon steel
components. And if so, corrective action is taken.
DR. BONACA: Okay. Now, this piping
typically sits there standby with boric acid diluted
in the water. And what prevents internal corrosion,
I guess, is lining of the piping?
MR. YOUNG: All of the piping that has
borated water in it is stainless steel. There is no
carbon steel, right. The only time we get boric acid
on carbon steel is if it leaks out and gets on another
piping system that is carbon. But all internal
surfaces are stainless that have borated water.
DR. BONACA: So mostly you're looking at
joints, you're looking at --
MR. YOUNG: Yes. Flanges --
DR. BONACA: Flanges.
MR. YOUNG: -- and valve packing and
things like that.
MR. FU: And just to add to your point,
when there's a leak, you see on the external surface
of carbon steel, and then they have maintenance rules
and other programs to catch it.
DR. BONACA: Yes. And so -- I mean this
is a standard program, but you come back and there are
no changes to it for the extended period of operation.
MR. YOUNG: That's correct. That's
correct. It's the existing program.
DR. BONACA: Okay. Thank you.
MR. PRATO: Any additional questions?
The next presentation will be on
"Auxiliary Systems," by Merrilee Banic.
MS. BANIC: Good morning. My name is Lee
Banic, and it's a pleasure to be here to present our
safety evaluation of the 13 auxiliary systems. As the
lead technical monitor for the contract on the
auxiliary systems for the Materials and Chemical
Engineering Branch, I'll be making the presentation.
Assisting me is Renee Lee, the technical monitor for
the contract for the Mechanical Engineering Branch and
Jim Davis of the Materials and Chemical Engineering
Branch. Our contractor, Idaho National Labs,
performed the review.
The ANO-1 auxiliary systems consists of
the following 13 systems: spent fuel, fire
protection, emergency diesel generator, auxiliary
building sump and reactor building drains, alternate
AC diesel generator, halon fuel oil, instrument air,
chilled water, service water, penetration room
ventilation, auxiliary building heating and
ventilation and control room ventilation.
We reviewed the application to determine
whether the effects of aging on the system components
were adequately managed. There were many kinds of
components. They include pumps, piping, valves,
drains, screens, tanks, cylinders, fans and filters,
The environments were water, meaning
borated, treated and well water, external buried,
external ambient, internal ambient and fuel oil. The
aging effects were cracking, loss of material, loss of
mechanical closure integrity and fouling.
Of the programs we reviewed, most were
existing programs proven by operating experience and
common to the industry. Many apply to more than one
system. The programs are: reactor building leak rate
testing, maintenance rule, Oil Analysis program,
preventive maintenance, buried pipe inspection, ASME
section 11, ISI inspections and augmented inspection,
chemistry monitoring programs, primary, secondary and
auxiliary systems, Boric Acid Corrosion Inspection
program, spent fuel pool level monitoring, service
water, Chemical Control program, fire suppression
water supply system and sprinkler system surveillance,
fire water piping thickness evaluation, control room
halon fire system inspection, emergency diesel
generator testing and inspections, reactor coolant
pump oil collection system, alternate AC and AC diesel
generator testing and inspection, Diesel Fuel
Monitoring program, instrument air quality, wall
thinning inspection, Heat Exchange and Monitoring
program, Service Water Integrity program and testing
of the penetration room and control room ventilation
We had no open items. We found that ANO
has shown that the effects of aging on the auxiliary
systems will be adequately managed so that there is
reasonable assurance that the systems will perform
their intended functions in accordance with the
current licensing basis for the period of extended
For items that are unique or different
from Oconee, we had the Buried Pipe Inspection
program. This is a new program. ANO's program is
consistent with programs acceptable according to the
Generic Aging Lessons Learned Report.
DR. BONACA: Okay. I had a question
regarding the alternate AC generator. The starting
receivers, are they in scope? That wasn't clear if
they were in scope.
MR. YOUNG: Yes.
DR. BONACA: They are in scope.
MR. YOUNG: Yes. Everything associated
with the, we call them the station blackout diesels,
or the alternate AC diesels, were in scope.
DR. BONACA: Part of the pressure
MR. YOUNG: Yes.
DR. BONACA: The other question I had was
instrument air. Now, the passive components or
elements of the compressors, are they in scope?
MR. YOUNG: No, not the compressors. The
only portion of the instrument air that was in scope
were the portions that connected directly to a safety
system or were part of a reactor building isolation
system. But the actual instrument air system itself
is not safety grade.
DR. BONACA: So you don't have any passive
component that you had to look at. I mean you're
looking at it as an active component.
MR. YOUNG: Well, the passive equipment
that we looked at were pressure boundary on the tubing
and the piping and certain valves that we credit to
ensure that we don't have a loss of air on those
systems that require air. The compressors themselves
are not -- we don't depend on them. We have air
accumulators for those systems that have a safety
function that requires an air supply.
DR. BONACA: Okay.
MR. YOUNG: Yes.
DR. BONACA: All right. Okay. Thanks.
On the -- one thing I noticed in many of these
programs, some of them make reference to preventive
maintenance as a program that supports it; some of
them don't. And yet it seems to me that preventive
maintenance is part of those components too. It's
just an oversight or --
MR. YOUNG: No. You're right. Preventive
maintenance is a part of every system in the plant.
But what we did is on those systems that required some
sort of aging management program, we looked to see if
we had a preventive maintenance activity that we could
credit for that.
DR. BONACA: I see.
MR. YOUNG: So the ones you see in the
document there are those that we specifically credited
for an aging management review.
DR. BONACA: Because they do perform an
aging management role.
MR. YOUNG: Right.
DR. BONACA: All right.
MR. GRIMES: Dr. Bonaca, this is Chris
Grimes. And I'd like to add that Safety Evaluation
explicitly considered in each of the programs whether
or not we felt there was a need to credit some form of
DR. BONACA: All right. So I understand
now. We really have a benefit from it that you can
claim for the aging purposes. Otherwise you don't
MR. GRIMES: Yes. The important part is
whether or not we felt that was a need to credit a
preventive maintenance activity specifically for the
purpose of managing the aging effect.
DR. BONACA: On the control room, this is
part of the system, yes. Are the door seals and other
penetrations in scope?
MR. YOUNG: Yes. All of the pressure
boundary for the control room was in scope.
DR. BONACA: Okay. And I had a question
here. I think we discussed it before, the buried
piping for the extent on the environment. My question
was more like you've had experience with it, because
you already set it on a frequency of once almost every
five years. Did you have any problems you identified
through these inspections in the past?
MR. YOUNG: As far as aging problems?
DR. BONACA: Yes.
MR. YOUNG: The problems that we've found
in the past have primarily been associated with some
sort of an event.
DR. BONACA: Okay.
MR. YOUNG: For example, we had an acid
leak that was routed through some abandoned piping and
got down into some buried piping and ate away the
coating and the pipe until a leak occurred.
DR. BONACA: Yes.
MR. YOUNG: And so as we went down to
repair that, we inspected the piping in the area
seeing if the acid had exposed any other piping.
DR. BONACA: Outside of those kind of
failures that you have seen because of root cause --
I mean here you have a cause that --
MR. YOUNG: Yes.
DR. BONACA: -- have you had any
experience of failures of buried piping that you did
MR. YOUNG: No, no. We haven't found any
instances where the -- all of this piping is coated
with a tar-type coating.
DR. BONACA: Right.
MR. YOUNG: And the only time we've had
problems so far has been when that coating was damaged
for some reason, such as the acid leak. So as long as
the coating is in tact, we haven't seen any problems.
DR. BONACA: Okay. Thank you.
MR. PRATO: This is Bob Prato. During the
inspection, the aging management review inspection, we
thoroughly reviewed the Buried Pipe Inspection
program. We looked at all the operating history, and
we have an extensive write-up in the inspection
report, which should be issued in about 30 days.
DR. BONACA: Okay. Oh, yes, on the
Emergency Diesel Generator Testing and Inspection
program, it's interesting that, you know, the
frequency of tests and visual exams are managed by
plant procedures. Now, question, just for learning
purposes, you know, if you make a change to those
procedures at some point in the future, for example,
by stepping down the frequency of the inspections or
tests, okay, how does that tie up to be accident of
the aging management commitments?
MR. YOUNG: In the diesel, the emergency
diesel case specifically, what we found was that the
current inspection intervals, which are normally a
major inspection every 18 months and then some more
minor inspections during the surveillance period,
which may be quarterly or monthly, was far more
frequent than what's required for aging management.
So we went ahead and committed to those programs
simply because they're existing programs.
But if we were only looking for aging
effects, we would have much longer intervals than
what's required for the active function of the system.
So we're crediting something that is looking for
active failures, but we're also finding it would see
any evidence of corrosion during those inspections.
DR. BONACA: Yes. In some cases, that may
not be the case, however. You may have instances
where -- I'm trying to understand now, you have
commitments in the FSAR addendum, and I understand
that. But you must have a configuration management
program of some type that ties commitments you made
for existing programs tied to aging, to the LRA, so
that you can flag it through that.
MR. YOUNG: Right. The way that will work
is we will have the commitment in the SAR that
changes, the SAR supplement that comes out with the
new license. And then that will tag those specific
procedures as being associated with a SAR commitment.
And then any changes that we would want to make will
have to go through the full 50.59 review process to
determine if we -- that we're meeting our commitments.
DR. BONACA: Yes. Okay, thank you. I
don't have any other questions of this issue. Thank
you. Any other questions?
MR. PRATO: Next presentation is "Steam
and Power Conversion System," by George Georgiev.
MR. GRIMES: This is Chris Grimes. While
George is getting settled in his chair up there, I'd
like to mention that we're embarking on an effort here
to get about three hours ahead of your schedule. And
so for your planning purposes, I think we now have all
of the staff representatives to cover the afternoon
materials. And so we're going to continue to try and
march through and cover the safety evaluation topics
hopefully before lunch.
DR. BONACA: Now, there is a presentation
scheduled also, "The License Renewal Environmental
MR. GRIMES: Yes. We can get Mr. Kenyon
here. He's not here. He was here. But we can bring
Mr. Kenyon in if you want to cover that before lunch.
DR. BONACA: Anyway, let's -- why don't we
just proceed about half an hour and see where we're
going at that point. And then we'll make some
decision of how long this meeting will last.
Okay. So now we are down to "Steam and
Power Conversion Systems."
MR. GEORGIEV: Yes, good morning. My name
is George Georgiev, and I was the technical monitor
for the steam and power conversion system, and ARGON
National Laboratory did the actual review.
The steam and power conversion system
includes four subsystems: Main steam, main treated
water, emergency feed water and the condensate storage
and transfer system.
The materials for those subsystems are
mainly carbon, steel. It does include some stainless
steel, bronze and copper. The environment in which
these systems operate is mostly treated water, which
is a high purity water and steam, and the external
environment is ambient, inside building environment in
the reactor building turbine and the auxiliary
There are 11 aging management programs
identified in the application. As example, some of
them are Flow Accelerated Corrosion Prevention
program, ASME Section 11, inspection -- Wall Thinning
Inspection program, maintenance rule and some others.
The components for those systems are
standard piping components: piping, valves, pumps,
feedings, there are some coolants and heat exchanges.
And it's nothing unusual.
The aging effects that the application
identified with these systems is general corrosion,
selective leaching involving CASS and peeling and
stress corrosion. Again, those are expected
degradation effects for these type of materials and
We did not identify any open items. And
as far as plan differences and Oconee and Arkansas one
very minor. Like, for instance, in the materials
area, in the Oconee application, there was copper
nickel for tubes used here. They have something else.
They do have copper tubes in some of their coolers.
As far as the aging management programs in this plant,
there are 11 aging management programs and Oconee's,
there were only four aging management programs
identified to control aging effects.
And that's basically it. That concludes
DR. SHACK: When I read the report, I was
sort of interested in the flow-assisted corrosion,
that they had done 900 inspections and replaced 125
components. That seemed to me a larger number. But
I assume all that was really in the secondary system,
by and large.
They're relying on check works, which, as
I understand it, would monitor sort of the most
susceptible regions, and then you would do an
analytical thing to sort of assure yourself that
you're okay. Are they actually directly making
ultrasonic measurements on any part of the feed water
system or the main steam or those would all rank low
in the susceptibility and so they're monitoring
something else directly?
MR. GEORGIEV: I believe that the latter
is the case in the system, including the steam and
power conversions and the lower side. However, they
do have a Wall Thinning program, which is separate for
the steam and power conversion system. They take
measurements of the management and compare, you know,
how it is to what it was before.
DR. SHACK: So there are direct wall
thinning measurements then, for example, in the feed
MR. GEORGIEV: That's right, yes, there
is. But it's more in conjunction with the wall
thinning problem. See, in this plant, they have
subdivided. They have 11 programs, and Oconee, they
have four. And part of the reason, I believe, was
They went back to their procedures, their
way of doing business. And whatever they can use
within these programs and procedures that could be
used to do an aging management, they use it. And in
doing that, I guess, they ended up with 11 programs.
They also have more of Section 11 type of inspection
in this steam and power conversion than Oconee had.
And maybe I should let them explain better why they
set it up the way they set it, but that's how it is.
The staff believes it's --
DR. SHACK: Yes. Somehow I had
interpreted the wall thinning as some sort of --
you're looking for general corrosion, but I wouldn't
have thought that you were doing that on systems that
you were monitoring for flow-assisted corrosion.
MR. YOUNG: That's correct. The Flow
Accelerated Corrosion program deals with those systems
that have that potential effect, and we do do
ultrasonic inspections in certain locations to measure
the actual loss of material and then to trend it to
see if we have a situation where we need to replace
the piping or just continue to monitor it.
Then there were some other piping systems
that were identified in this review that could be
subject to wall thinning for reasons other than flow
accelerated corrosion. That's the Wall Thinning
program that was referred to. So it does not include
any systems that have flow accelerated corrosion
problems, because that's covered under that program,
under the FAC program.
DR. SHACK: So, again, coming back to my
question then, is any part of the feed water system
directly monitored under the DFAC program or it's one
of the less susceptible ones, and so you're looking at
something else as the lead component?
MR. YOUNG: I'm not familiar enough with
that program to say which one is the lead. I know we
do a lot of ultrasonic inspections during an outage,
but I can't tell you specifically which system is
included in that at this point. We can try to get an
answer for you, though.
DR. SHACK: It just seemed to me on sort
of a risk-informed perspective, I'd worry a lot more
about losing that feed water system than I would many
of the other pipes that you're probably directly
MR. YOUNG: Well, I know that the way the
program was set up, we're looking for those areas that
are the most susceptible to FAC, and it has to do more
with geometry and the way the system --
DR. SHACK: Right, rather than risk.
MR. YOUNG: Right. Yes. In fact, I don't
think risk even comes to play on the FAC program.
MR. FU: Are you satisfied, sir?
DR. SHACK: Yes.
DR. BONACA: Any other questions? None,
so thank you.
MR. FU: Thank you.
MR. PRATO: Next presentation is going to
be on "Structures and Structural Components," by David
MR. JENG: Good morning. I am David Jeng.
I'm a member of the Mechanical Engineering Branch in
Division Engineering. And being there was for us to
perform the review of the structure sections. And I
participated in the review after the submittal.
I'm here to provide you an overview of the
structures and structure components review. The
applicant adopted so-called commodity grouping
approach in which they put together some materials and
environment items in different buildings as one
commodity group in just the aging management.
So among the commodity groups, they have
presented to us the steel structure -- concrete,
prestress concrete, threaded fasteners, fiber, and as
an embankment elastomas integral. These are the
sibling categories. They categorized, and each of
them they addressed their aging effect, their
environment, and how they propose to manage -- they
are proposing aging management programs.
The materials. Among the key materials
are structure steel, carbonized steel, standard steel,
concrete precision wires, fire protection material
like receiving for the penetrations, elastomas,
neoprenes, careful material and PVC water stopped.
With regard to the environment, I think
that, yes, so-called protected environment,
unprotected environment, high humidity, high
temperature, environments and high radiation
environment and also some roll water, baronated water,
or boric acid concentration and concrete environment.
These are the key environments which we have
Income of aging effects. The major aging
effects are the loss of material, cracking and also
the change of material properties. And also, in the
case of prestress concrete component, we have a loss
of prestress due to reaction and cracks of the
And we have not identified any open items.
As regard to any difference between the Oconee and the
ANO plant, there are a few minor differences. In the
case of Oconee, they used Keowee dams and the
hydraulic unit to provide power. ANO, we did not have
that kind of need. Also, Oconee had the so-called
safe-shutdown facility, which is sort of unique, as
compared to ANO-1 situation.
And in the case of ANO-1, they have
adopted so-called emergency cooling pond, which is the
major supplier of water for emergency situations. And
they had to perform annual inspection to make sure the
pond is maintained. And what they do is they do an
inspection to check the pond water and make sure the
volume is there. So this is sort of unique in the
case of ANO-1 compared to Oconee.
And there are other differences, such as
the trash racks in the infrastructure, which in the
case of ANO-1 was not within the AMR domain. And in
the case of the Oconee, the turbine building -- they
are part of the turbine building susceptibility, so
they had to address that portion. And this is the
difference between the two plants.
So these are the key differences between
the two sister plants. And my presentation concludes
at this point.
MR. GRIMES: Actually, I think they're
first cousin plants, but --
MR. JENG: First cousin plants.
DR. BONACA: Now, under the structural
steel portion, there's always a reference to an aging
effect being loss of material for the reactor building
liner plate. I just have a question regarding the
steel liner of the containment. Are there concerns
with any corrosion of steel liner outside of the steel
liner plate that has been addressed?
MR. JENG: In so far as the particular
issue, in the section of the steel liner operating
floor, unless there's some expansion allowances, in
the past history many plants did encounter some
difficulties, corrosion, due to seepage of the waters.
But staff has paid attention in this area. In past
LRA evaluations, we asked applicant to talk about
their previous experience. In the case of ANO-1, I
think they have not encountered this situation which
we're concerned. So they are maintaining a good shape
of these interfaces.
DR. BONACA: So you have a program to look
at it? I mean are you walking down, typically, those
MR. YOUNG: Yes. All of the reactor
building liner drills are subject to a visual
inspection on a certain frequency. And then we if see
any sort of signs of degradation that could indicate
that there may be problems with the buried part of the
liner, or the embedded part of the liner, then we
would have to come up with some evaluations of
programs to deal with that. But we haven't had any
DR. BONACA: Because the steel liner goes
into the concrete --
MR. YOUNG: Yes.
DR. BONACA: -- and that ties into the
MR. YOUNG: The base.
DR. BONACA: So there is a portion which
is not visually accessible.
MR. YOUNG: Yes. Right. But if we don't
see any signs of any problems at the surface, where
the water or whatever might get into it, then right
now that's our program to determine that there
shouldn't be any problems further down.
DR. BONACA: Okay. Regarding the
concrete, I was looking at page 232. There was a
request on the part of the NRC regarding aging effects
in an accessible area. And the response from Arkansas
was that the concrete used in those inaccessible areas
was a high cement contained, low water cement ratio
and proper curing. And that's the reason why the
applicant stated that we don't have to have an aging
management program, and the staff accepted that.
I was kind of -- I mean that kind of claim
could be made about any component which is not
accessible. And I'm not an expert in concrete
structures, just I wanted to understand how you got
the confidence that in fact because of these
assertions, you don't need to look at these
MR. JENG: Okay. In the issue, really,
most concern the situation where in a containment it's
the basement level. The liner is about two feet deep
of concrete. And the concern was if there was some
significant cracks on this two-foot concrete and the
water may seep in to become the agent for causing
degradation of the liner underneath that.
The staff originally pulls the requirement
that applicant should have an aging management
program. But soon the interaction and discussion
under the context of the LAR report discussion, most
of the staff and the applicant comes to a conclusion
that if you are ever to conclude it's of high quality,
low probability --
DR. BONACA: I see.
MR. JENG: For this reason -- on top of
that, they had the maintenance program to perform the
regular inspection, as required by the program. And
this, too, we come to the conclusion that --
DR. BONACA: Okay. I understand. And you
have solid records that shows that you have high
cement contained to low water cement ratio and proper
PARTICIPANT: Yes, we do.
MR. YOUNG: Yes. We went back to our
construction records to document that.
DR. BONACA: Again, on the effects of
aging on the building, I guess, in the tendon gallery,
there's a statement that says, "The applicant states
that they have not observed abnormal levels of
humidity during four contaminants in the tendon access
gallery." And then there's a statement that says,
"Corrosion was identified in components during a ten-
year and 15-year in service tendon inspections. But
this loss of material did not adversely effect the
intended function of these components.
Now, I can agree that you had not enough
corrosion to affect the function. What does it give
you the comfort that we don't need to look at it in
MR. JENG: We do look at it in the future,
according to the tendon program. Yes, it is power.
It's on the side of the anchor of the tendon --
DR. BONACA: Yes, that's right.
MR. JENG: -- which is part of their
regular movement. So it's to be looked at --
DR. BONACA: Oh, so it's back to the
program already. The inspection and of course there
will be corrective action if he gets to the point.
MR. JENG: Yes.
DR. BONACA: Now, you still have an issue
of criteria for corrective action on the tendons that
you have an open item on, right? I thought there was
an open item.
MR. JENG: That's only --
PARTICIPANT: On TLAA, sir.
DR. BONACA: Okay. All right. Thank you.
I have no further questions on this.
MR. JENG: Thank you.
MR. PRATO: Last presentation on the aging
management review will be by Duc Nguyen on the
MR. NGUYEN: Good morning. My name is Duc
Nguyen, and I am a technical monitor in the electrical
system performed by the INEL, Idaho National
Engineering and Environmental Lab.
Today, I'm going to present the aging
management program for the electrical system. The
applicant yielded commodity component to identify the
long-lived passive electric component. That required
the aging management review. And you know most
electrical components are active, and therefore only
three commodity time will identify.
The first one is the connector, terminal
block and the cable. The environmental -- this can
affect the aging of this component, including the
radiation environment and the potential humidity
environment and chemical environment.
Also, cable and connector also subject to
the frequent manipulation. When you disconnect and
connect them more than once, many times, it can create
a problem, especially to have a very low voltage
current, low voltage implementation cable and
connector. That can create a problem. That is
sensitive to small variation.
Talking about the aging effect, the aging
effect of the connector it would include the potential
aging. Aging mechanism will be the corrosion of
metal, electrical tresses, water, humidity effect,
mechanical tresses and thermal radiation, aging of the
organic components. However, the corrosion is not
expected because the connector usually in the -- not
so bad on dry condition, not in the humidity
condition. So it's not supposed to have any corrosion
And mechanical tress is not significant,
because, you know, connector does not provide any
mechanical support. So the mechanical tress is not
the problem. And electrical tresses. Usually,
connector can handle lots of current, so electrical
trussing not a problem. I had the applicant identify
the number of splices that can have the moisture and
the temperature effect. And to manage that, they do
the Component Inspection program to manage that.
Also, the applicant also identified
connector that is subject to frequent manipulation,
like the multi-pin connector screw terminal and the
battery terminal post. The effect of frequent
manipulation can create wear, loose fitting, cracking,
and this can be detected by visual inspection. So
they do the good maintenance practice. That means
when you disconnect or connect something, they use a
good maintenance to check the resistance of that
And connector that are the terminating
impeding sensor circuit also has been identified by
the applicant. Oxidization and corrosion of the
connector pin could interfere with the operation of
these circuits. And in order to ensure this does not
happen, Electrical Component Inspection program will
be established to periodically inspect this connector.
And about a terminal block, the only thing
that can affect the aging of the terminal block is the
frequent manipulation. But the applicant identified
that, you know, the procedure will call for lifting of
the lead from the terminal block for testing purpose.
This will be to control the aging effect of frequent
And the last one is the cable. Cable can
have potential aging mechanism due to corrosion of the
conductor electrical tresses. Water and humidity
affect terminal degradation, aging and mechanical
tresses. About corrosion of the conductor, I think
it's not a problem, because, you know, conduction
usually covered by insulator. So corrosion of the
conductor is not a problem.
Electrical tresses can be a problem,
because the omit hitting can be significant for the
cable. That I wrote in they're continually open with
a high current, relative to that and past the limit.
However, most of this component, you know, only ruling
the normal operation, this component had very low
current. Only during the action condition then they
can create a high current. But it doesn't happen very
Another concern is exposed to the wet
environment can be significant aging effect for the
medium or high voltage cable, especially the medium
cable that you have buried in the conduced. This can
have significant effect.
Chemical attack of the organic material
also can be potential effect of this cable. Radiation
tests are not significant because this is not a cable.
So the radiation tests for this is less than one to
the eight rad, so it's not a problem. To manage this
aging effect, the applicant does the Component
Inspection program. They use the Inspection program
to manage the aging effect of this component.
Right now I would like to talk about an
open item that we have. We have the concern about the
unacceptable cable, because in the Component
Inspection program, there's only visual inspection.
And there's only visual inspection with acceptable
cable, not unacceptable. And they view the acceptable
cable to compare to with unacceptable, and we think
that's no comparable, because you cannot do visual
inspection for inaccessible cable. And we have a
concern with that one. So that one is an open item
DR. BONACA: The concern is that the
environment may be --
MR. NGUYEN: Different from the
DR. BONACA: -- different from what they
MR. NGUYEN: Yes, yes. Especially water
tree, you know, moisture intrusion, and it can crack
the insulation of the cable.
DR. BONACA: This is a separate issue from
MR. NGUYEN: Yes, different.
DR. BONACA: Yes. And Arkansas has
committed to essentially meet the requirements of GSI
168 once that is resolved?
MR. NGUYEN: That, let me ask Arkansas.
Maybe they can answer that question.
DR. BONACA: For medium voltage cables,
irrespective of accessible even. The concern which
has been raised through GSI 168 is the ability of
maintaining, for example, the environmental capability
once they are heated and in wet condition for a long
time. I mean because there has been testing that has
shown that under LOCA conditions, for example, they
would fail in a gross fashion. Has this issue been
MR. GRIMES: I'm going to attempt to
explain that the resolution of GSI 168, as I
understand it at this point, is being treated on a
manufacturer basis; that is, that the testing results
raise some question about the qualification techniques
by -- manufacturer now escapes me. But we're pursuing
those results primarily from the standpoint of
reflecting on the lessons learned from the testing.
But otherwise, I believe that when GSI 168 is
ultimately concluded, and my recollection is it hasn't
been concluded yet, that it's still in a process of
trying to draw the generic insights.
But we still rely on compliance with EQ
rule as an acceptable way to establish a qualified
life. And the process by which one maintains
qualified life to reflect on testing insights and
whether or not the qualification basis needs to be
revisited at any point, either in the current term or
the extended period of operation.
DR. BONACA: The reason I asked that
question is that, first, the issue of GSI 168 is
pretty high on the agenda of this Committee of the
ACRS. And second, for Oconee, if I remember, we had
an implicit discussion in the SER regarding the in
fact medium voltage cables.
MR. GRIMES: Non-EQ medium voltage cables.
DR. BONACA: And the need for walkdowns of
those components. Yes, I agree with you, that the EQ
program requirements are sufficient to --
MR. NGUYEN: Wait, wait. This one is not
EQ. We talk about the non-EQ cable. GSI 168, I think
they talk about EQ cable, so that's a different issue
here. We're talking about here a non-EQ medium
MR. PRATO: Cables found outside, exposed
to the environment, buried.
MR. NGUYEN: Yes, buried.
MR. PRATO: And could be exposed to
DR. BONACA: Sure. And I can see this,
and you're asking for a program.
MR. GRIMES: If I could suggest, this is
equivalent to the open item that we had on Calvert and
Oconee and are still pursuing in generic aging lessons
learned in terms of establishing some consistent basis
for concluding that on the treatment of the potential
for moisture intrusion on medium voltage buried
DR. BONACA: Yes. Well, the reason why I
raised that issue was only because of the
characterization of buried cable. I thought that the
open issue for Oconee was all medium voltage cable.
MR. GRIMES: No. It was inaccessible,
whether the inaccessibility comes through being buried
or being hidden in a conduit. But the issue is
referred to both ways, as buried or inaccessible. But
essentially it's the same issue.
DR. SHACK: But didn't Oconee have a
program to look for sort of warm temperature --
DR. BONACA: That's right.
DR. SHACK: -- or radiated conditions on
the medium --
DR. BONACA: Absolutely.
DR. SHACK: It was non-EQ, but it was a
general kind of --
DR. BONACA: They offered the program, and
the program essentially was addressing all cables.
They had pictures of cable they had identified in
locations where clearly it was accessible, because I
took pictures of it, and it was showing the damage of
high heat and water intrusion on the jacket of cable.
DR. SHACK: That's what I recall. They
looked at the cabling and then they looked where the
cabling would be in a high temperature, high radiation
area, and then they would do inspections there.
DR. BONACA: Right.
MR. NGUYEN: We talk about inaccessible
cable, and I believe at Oconee they committed to test
everything for this kind of cable. Look at the
manhole to see if the water collects so they can make
a comparison to see how the inaccessible cable -- but
they commit to do the test.
DR. BONACA: They committed to do
walkdowns and inspect and repair the cable that showed
clear degradation. That's all they did.
MR. GRIMES: But my recollection is Dr.
Shack is correct, that it's not simply water intrusion
by itself that causes a concern about potential
degradation of the cable insulation. It's the
condition of buried cables or inaccessible cables that
also are exposed to other stressors that might cause
-- that would provide a basis for you to infer from
conditions of accessible cables the point at which
buried cables would become in jeopardy and would need
to be explicitly checked. And that was the nature of
MR. YOUNG: If I may here, as far as the
Arkansas situation, we have committed to an Electrical
Component Inspection program that's similar to Oconee
for the accessible cables in high temperatures and so
on. So we are on the same path with them there. This
open item dealt with those limited set of cables that
were buried or inaccessible, and we are working on
writing a resolution on those that will also match the
Oconee resolution which is to do some sort of testing
on these cables that may be exposed to that kind of
DR. SHACK: Is this testing a leakage
current thing or something?
MR. YOUNG: It's somewhat undefined at
this point, and -- yes, Jeff, go ahead.
MR. RICHARDSON: Yes. This is Jeff
Richardson with Entergy. Right now, the way the
electrical component -- our response to this
particular issue is being formed. The test is non-
specific. There are several different tests that have
been proposed, including power factor type testing.
We're not going specifically. It will be condition
driven based on the cable and the situation. But the
DR. SHACK: But you'll do testing of some
MR. RICHARDSON: Yes. The plan at this
point, or the direction we're taking at this point is
to follow Oconee's lead into the medium voltage
inaccessible cables that are within the scope. Where
appropriate, where they're exposed to either extended
periods of being exposed to water and also in
conjunction with thermal stresses such as high system
voltage, greater than 25 percent system voltage for a
period of time, then those would be subjected to some
form of testing to be determined as appropriate for
DR. BONACA: So there is a commitment you
said, and that's going to be in the FSAR.
MR. YOUNG: Yes. We've already got a
commitment to the visual inspection portion of it.
And in response to this open item, we'll make a
commitment for the varied cable portion.
DR. BONACA: Let me just make an
announcement outside of schedule here. I've been told
the Agency will close at 12 noon, which is now.
Because, I guess, of weather conditions, they're
sending people away. I would like to propose the
following here: We don't have much left on the
agenda, and I think we can condense the overview on
the license renewal and environmental review process.
So I would like to do is to continue. Just take five
minute break right now and then continue this meeting
for next half an hour. That should be allowing to go
to discussion, and then end the meeting. I think we
can do that.
MR. GRIMES: Dr. Bonaca, the staff is
ready, willing and able. We want to march through the
time limit at aging analysis. I sent a runner to try
and track down Mr. Kenyon so that we can try and get
through the environmental review as well.
DR. BONACA: Well, let's try to do that.
MR. GRIMES: Okay.
(Whereupon, the foregoing matter went off
the record at 12:00 p.m. and went back on
the record at 12:08 p.m.)
DR. BONACA: We want to review the TLA.
I believe that's the next step of the agenda.
MR. ELLIOT: My name is -- my assistant
here is not here. My name is Barry Elliot. I'm with
the Materials and Chemical Engineering Branch of NRR.
There are ten TLA issues that cover
mechanical areas, materials areas, corrosion areas.
So it covers a broad spectrum of Division of
Engineering functions. People who have reviewed these
area functions are Hanz Asher, Carol Lauron, John
Fair, Cliff Munson, Amar Pal, Mark Hartzman, Andrea
Lee and Jay Rajan.
The first TLA is reactor vessel neutron
embrittlement. There are two regulations that are
reviewed with respect to this issue. They are the PTS
rule, which is 10 CFR 50.61 and Appendix G of the
regulations, which establishes upper-shelf energy
In this case, the applicant did a plant-
specific PTS evaluation. And as far as the upper-
shelf energy, it would be a plant-specific upper-shelf
energy evaluation. And it turns out that as far as
the upper-shelf energy, all the forgings would be
above 50-foot pounds at end of license, end of renewal
license. However, the welds would not -- and an
Appendix K analysis was done to show that it had
adequate safety margins. These methodologies are the
same as those used by Oconee, the only difference
being the plant-specific variability.
The next issue is metal fatigue. The
applicant evaluated the impact and environmental
effects on the reactor coolant pressure boundary
components. And the evaluation indicated that the
surge line and the high pressure injection make-up
nozzle and safe ends may exceed a cumulated usage
factor of one during the period of extended operation.
As a result, the applicant proposes a program which
will include one or more of the following options:
refinement of the fatigue analysis, repair,
replacement and management of the effects of fatigue
by a program that would be approved by the staff.
Essentially, this is very similar to what
Oconee did. The difference is that Oconee is counting
the cycles and may have to perform corrective action
similar to ANO-1. ANO-1 already extrapolated a number
of transients in 60 years and has identified the
potential locations with usage factors that may exceed
DR. SHACK: But they also do a monitoring
program, don't they, so they'll be able to actually --
DR. SHACK: Yes, count.
MR. ELLIOT: Yes, they do that.
MR. FAIR: This is John Fair with the
staff. They haven't proposed to do this by a
monitoring program similar to Oconee, but they do have
a cyclic -- they do keep track of cyclic transients.
But they don't propose to use the program to manage
the effect. So they did an up-front calculation,
whereas Oconee is going to monitor cycles.
MR. ELLIOT: The next issue is
environmental qualification. The applicant evaluated
environmental impact of extended operation on all
long-life, passive and active electrical components
within the scope of the rule. And the components
either had analysis that remained valid for the period
of extended operation, had analysis that projected to
the end of the period of extended operation or had a
program to reanalyze or replace components prior to
exceeding the qualified life of the component. This
is very similar to the program for Oconee.
Next issue is concrete reactor building
tendon prestress. The applicant indicates concrete
reactor building tendon prestress that we've managed
during the period of extended operation, using ASME
code, Section 11 In-Service Inspection program. This
is an open issue for us, because although this is
similar to Oconee, in the case of Oconee, they have
addressed the program in sufficient detail and given
us sufficient characteristics to approve the program.
In the case of ANO-1, they have not, and they must
address the attributes and characteristics that are in
this overhead. And then we'll be able to resolve this
The reactor building liner plate fatigue
analysis. The applicant had demonstrated that the
original fatigue analysis is valid for the extended
period of operation. In this case, the methodologies
used by Oconee and ANO-1 are the same. Individual
plant-specific transients may be slightly different.
Next issue, aging of Boraflex and spent
fuel pools. Boraflex is a neutron absorber. It is
used to maintain subcriticality margin in the spent
fuel during storage or transfer of fuel. Tech specs
require applicants to maintain the subcriticality
margin. The applicant has determined that the
Boraflex has degraded more rapidly than expected and
will not last through the current 40 years. They've
done an analysis, and that's the results.
As a result, in order to satisfy the
license renewal rule, they're going to have to propose
a program to monitor the aging of the Boraflex. This
is an open issue at the moment for ANO-1. They have
to propose a program. Oconee has already a defined
program, and that's the difference.
Next issue, as far as reactor vessel
underclad cracking, the issue here is that when B&W
fabricated the vessels, the course grade forgings had
cracks in them during fabrication, intergranule
separations during the cladding operation. We're
talking about defects on the order of a tenth of an
inch. This was evaluated in the first 40 years, and
in the next 60 years the evaluation goes to higher
neutron fluences and also more fatigue crack growth.
The analysis was a fraction mechanic
analysis, and it was determined to be acceptable by
the staff for the 60-year license. Both Oconee and
ANO referenced the B&W topical report, which contained
analysis applicable to both Oconee and ANO-1.
Next issue is the reactor vessel
instrumentation nozzle. The applicant has evaluated
the impact of flow-induced vibration on reactor vessel
instrumentation nozzles. Analyses have been projected
to the end of the period of extended operation. The
flow-induced vibration stresses are below the
extrapolated fatigue limit. Oconee and ANO-1 used the
same methodology in evaluation of flow-induced
vibration -- well, ANO-1 used the same methodology as
used in Oconee reactor vessel internals.
DR. SHACK: Do they do this because
they've actually had a flow-induced vibration problem
or is this just part of their basic design?
MR. FAIR: This is John Fair again. This
is part of the basic design on this. They just
extrapolate out the originally designed for -- what is
it, 12 cycles or something like that? And they
extrapolate it out in order of magnitude, very
MR. RINCKEL: This is Mark Rinckel with
Framatome. There were problems with the original end
core modern system design. There were three-quarter-
inch on 60 pipe that went at the bottom of the vessel.
Those cracked off at Oconee at one, and then they
built them up and repaired them all. And then this
fatigue analysis that John's referring to was with
regard to the new design.
DR. SHACK: So you basically just beefed
the up enough --
MR. RINCKEL: We beefed up, yes.
DR. SHACK: -- so the stresses are very
MR. RINCKEL: Yes. They were not designed
proper to begin with, and that was corrected.
MR. ELLIOT: The next issue is a leak
before break. The applicant did a -- there was a
leak-before-break analysis done in the first 40 years.
The applicant has evaluated the impact of fatigue
crack growth and thermal aging on leak-before-break
analysis of the reactor coolant system, main coolant
and piping. The floor growth analysis remains valid
for the period of extended operation. And the flaw
stability analysis used lower bound casts, fostering
a stainless steel fracture toughness properties for
the reactor coolant pump nozzles in adjacent welds.
And the adjacent wells will have adequate
fresh stuff at the end of the period of extended
operation. That's the result of the analysis. Oconee
and ANO-1 used the same basic approach.
The last issue is the reactor coolant pump
DR. SHACK: Excuse me, that must be a
postulated flaw assumption, right?
MR. ELLIOT: Yes, it is a postulated flaw.
DR. SHACK: What's the postulated flaw?
MR. ELLIOT: It's a leak before break.
You have to have a leakage size.
DR. SHACK: Oh, okay, okay.
MR. ELLIOT: It's criteria. There's
leakage-size flaw, and then there's a stability flaw.
There's two size flaws, and that depends on the
leakage and the size of the pipe and everything. So
there's not one flaw; it's a through-wall flaw.
DR. SHACK: It's a through-wall flaw.
MR. ELLIOT: It depends on the size of the
pipe and --
DR. SHACK: They're not just counting to
go through the wall. They're actually looking at the
through-wall flaw and making sure it's stable.
MR. ELLIOT: Right. That's for the
stability analysis. For the fatigue analysis, it
starts with a small flaw.
And then the final issue is the reactor
coolant pump motor flywheels. The applicant has
evaluated the impact of fatigue on the growth of
cracks in the reactor coolant pump flywheel bore
keyways. This is another postulated flaw. There is
no flaw there. And the analysis is projected --
growth remains acceptable for the period of extended
operation. There is nothing unique about this
analysis. This is standard fatigue crack growth
DR. SHACK: Is that in a standard design
procedure for all coolant pumps with keyways? Do they
have to do this?
MR. ELLIOT: No. There is a different
here, now that I think about it, a little different.
They did the analysis -- in the case of Oconee, they
proposed a program. Instead of doing the analysis to
the reactor pumps, they do inspections, periodic
inspections. So you have this alternative. You can
either do analysis or you can do inspections. And at
ANO-1 they chose the analysis, and Oconee chose the
inspections. And this is a continuation of each of
their licensing bases. The ANO-1 licensing basis was
the fatigue study, and the Oconee licensing basis was
the inspection program.
DR. BONACA: Okay. One last question I
have is regarding the Boraflex. So the expectation is
that there will be a solution needed prior to entering
the 20 additional years of life.
MR. PRATO: In reality -- this is Bob
Prato -- in reality, they had submitted a program that
was consistent with Oconee. We asked for some
additional description in our RAIs, and that's when
they found the data would -- that the Boraflex would
not last the current licensing term.
DR. BONACA: All right.
MR. PRATO: They did not respond to our
description. They said it's no longer TLAA. Staff
took exception. So, basically, what they're going to
provide is that same program they had initially with
the additional information we requested in our RAI.
And from the staff's perspective, that should resolve
DR. BONACA: Okay. Thank you.
MR. ELLIOT: Thank you.
MR. PRATO: That concludes the safety
inspection review. Tom Kenyon, for the environmental
evaluation review, will give his presentation at this
DR. BONACA: And the plan we have right
now is to have a brief overview of this environmental
review process, maybe ten minutes or so. Then I would
like to just have a brief discussion among the members
here, and then a decision on how we're going to
address this at the full committee next week.
MR. GRIMES: Yes, sir. Dr. Bonaca, this
is Chris Grimes. I would like to introduce Tom
Kenyon, who's the Environmental Project Manager for
Arkansas. I would like to remind you that the staff
made presentations to the Committee about the
regulatory guide and the standard review plan for the
environmental process. Tom's going to just basically
run through the main features of the review process
and our NEPA obligations. And he should be able to do
that in about ten minutes.
DR. BONACA: Okay.
MR. KENYON: I'll try. My name is Tom
Kenyon. I'm an Environmental Project Manager with the
Generic Issues Environmental, Financial and Rulemaking
Branch. I've been asked to make a presentation
regarding the environmental review process that we
undertake under the license renewal reviews.
I plan to talk a little bit about the
statutory requirements. We'll focus on the National
Environmental Policy Act. I'll be talking about the
review process that we go through and give you an idea
of the schedule. My goal is to just kind of put into
perspective the environmental protection activities
that we undergo for license renewal purposes. And the
presentation is for information only. We're not
asking for a letter in this area. Of course, you
always have the option, if you want to, to provide
DR. BONACA: We don't intend to write a
letter on this now.
MR. KENYON: Thank you. Some of you may
recall that Barry Saltman had made a presentation like
this a couple years ago, and I think it's safe to say
right now that not a whole lot has changed, other than
we've implemented the process, we've completed the
review on two plants, Calvert Cliffs and Oconee, and
we're undergoing a review right now of three
As you well know, the NRC is governed by
the Atomic Energy Act and the Energy Reorganization
Act of '74. There are a number of other statutes that
define our mission in terms of the environmental
protection mission as well, but I'm going to focus on
the National Environmental Policy Act.
This slide gives you -- it's a slide of
all of the -- the entire license review process. The
top path shows the path that you're used to working
in. The Part 54 review includes the inspection
activities, it includes the safety review that Mr.
Prato is involved in, and of course, it includes the
ACRS' review as well. Now, the bottom path is the
path that we follow as part of our Part 51 review.
And I'm going to go into more detail about each one of
these steps as we go through this presentation.
Now, I'm going to give you a bit of
background on the National Environmental Policy Act.
It was enacted in 1969, and it requires all federal
agencies to use a systematic approach to consider the
environmental impacts of certain decisionmaking
proceedings. It's a disclosure tool that involves the
public and involves the process in which we gather
information, we document the findings that we have and
then we invite public participation to evaluate it.
The NEPA process results in a number of
different documents, but the one that we're going to
focus on is the Environmental Impact Statement, which
describes the results of our detailed review, that is
the environmental impacts for major federal actions
that have the potential to significantly affect the
quality of the human environment. And the NRC has
already determined that NEPA -- I'm sorry, that
license renewal is just such a major federal action.
Now, to implement NEPA, the staff has its
regulations in Part 51. And the regulation describes
the process that we undertake, it outlines the
contents of the Environmental Impact Statements, and
it also defines the objective of our review. And I'm
going to have to read this, because it's a big
unwieldy. Our objective is "To determine whether the
adverse environmental impacts of license renewal are
not so great that preserving the option of license
renewal for energy planning decision-makers would be
Now, that's a quote from the regulations.
It's Part 51.95. I prefer to just think of it as
we're trying to determine whether or not the
additional 20 years of operation is acceptable from an
Now, if I could go back to the previous
slide for a second. Early on when it was decided --
when we were developing the license renewal process
back in the '80s and '90s, it was recognized that the
original Environmental Impact Statements that were
developed to support the construction permits and the
operating licenses about 20 or more years ago would
have to be updated to reflect the additional 20 years.
And so the NRC undertook a rulemaking effort to modify
Part 51 and to have it reflect the license renewal
As part of the rulemaking effort, the
staff developed a generic Environmental Impact
Statement, known as the GEIS, which took a systematic
look at the thousands of hours of operation of the
nuclear power plants to help us identify where our
potential environmental impacts could occur. In
addition, the staff developed regulatory guidance, the
Environmental Standard Review plan, and a regulatory
Now, the GEIS was used, as I said earlier,
as a supporting document for the Part 51 rulemaking,
but it's also an integral part of our review process,
and so I wanted to go in a little bit of detail as to
what's enclosed in that document. The GEIS was
published as NUREG-1437 and was issued in 1996.
During the development, the staff met with the states,
the Presidential Council on Environmental Quality.
They met with the Environmental Protection Agency and
other groups, and they had a series of public
workshops to develop the final GEIS.
And suffice it to say that during this
period the staff was trying to identify what
environmental impacts needed to be reviewed in license
renewal. And we identified a total of 92 issues.
When the staff evaluated those issues, they found that
some -- noticed that some of those were generic in
nature; that is that they are common to all plants or
a class of plants regardless of where they're sited.
And so the NRC wanted to kind of categorize them
differently, and so we came up with this Category 1,
Category 2 scheme, Category 1 being, of course,
generic issues, and Category 2 requiring plant-
Now, I did not mean that we do not look --
well, I'm trying to figure out what I can skip
through. An example of Category 1 issue is a the off-
site radiological impacts. And the staff took a look
to see if whether or not it was likely that there
would be an increase in off-site radiological impacts
due to the increased operation. So they did a
historical review and determined that the public --
and determined that the doses to the public have been
maintained below those allowed by the regulations.
And staff has not been able to see any
reason why the doses would increase due to the
extended operation, provided that the control programs
and the monitoring programs are maintained and
implemented acceptably. So because the expected
radiological impacts apply to all plants in a similar
manner and that the impact is considered small at all
the plants, the staff concluded that this could be
addressed on a generic basis.
Now, that does not mean that we do not
need to look at this issue anymore. What it means is
that we look only to see if there's significant new
information that would cause us to change the
conclusions that we made five years ago. As you can
see, there are 69 issues that were resolved in this
manner, considered generic issues, and the remainder
of the 23 issues that were identified need to be
addressed on a plant-specific basis.
Now, when the staff completed the GEIS in
'96, we evaluated it to determine their impact
significance, in terms of whether or not their
environmental impacts are likely to be small, moderate
or large. And what we determined was that the generic
issues, the Category 1 issues, all had a small impact
on the environment, and that the impacts of Category
2 issues could range across the full gamut, from small
to large, depending on the particular site and the
particular issue. I guess I don't know need to show
Now, this slide shows a little more detail
about the NEPA process. There are certain steps that
we have to follow, and these steps are consistent for
all Environmental Impact Statements that are prepared
by federal agencies for any major federal action. The
first step is the notice of intent. It lets the
public know that we're going to prepare for an
Environmental Impact Statement. It is issued in the
Federal Register shortly after the acceptance review
To prepare for our reviews, we've
assembled a team of NRC staff with backgrounds in a
specific technical and scientific disciplines that is
needed to do these reviews. We have people with
backgrounds in biology, ichthyology, zoology. There
some people with human health backgrounds. And they
have generalists like me, project managers who
coordinate the reviews.
In addition, to supplement the expertise
of the staff, we've engaged the assistance of various
national laboratories to ensure that we have a well-
rounded knowledge base to do these reviews. For every
review, we put a team together of about 20 people.
The next step is the scoping process,
during which we tried to narrow down the scope of the
Environmental Impact Statement for the plant that
we're looking at. And we solicit public input. The
scoping process runs for about a minimum of 30 days
and could be as long as -- what we've been doing,
because we have to gain some experience, we've been
allowing for a 60-day comment period. About midway
into the comment period, we have two public meetings
near the site where we describe what we do, and we try
to solicit public input. We also perform a site
visit, and we obtain information from the applicant
during the site visit and from federal, state and
Now, during this time, we seek information
to define the scope of the plant-specific
Environmental Impact Statement and determine what
needs to be studied in detail and what is not
appropriate to address. We start with the potential
list of 92 issues that came from the GEIS, and then we
try to determine which ones are applicable and which
In addition, we require the applicant to
submit an evaluation and to let us know whether or not
they're aware of any new, significant information that
could affect our conclusions on Category 1 issues.
And during the scoping phase, of course, we take a
look and see what the members of the public have to
say and other federal, state and local authorities.
And if something new and significant information does
arise, then we review it on a plant-specific basis.
And if not, we adopt the generic conclusions from the
GEIS, and we incorporate those conclusions into our
Category 2 issues, of course, we look at
at the plant, and we obtain information during our
site audits. And finally, we also try to find out if
there's any new issues that we hadn't considered in
the GEIS five years ago. And if a significant new
issue does come up, then we would review that as if it
were a Category 2 issue.
The most important thing about this slide
that I wanted to point out was that -- I'm sorry.
MR. GRIMES: Tom, if I could suggest, if
you'd go to 15, because you basically covered what the
process steps are, and just flash 15 and 16 for the
MR. KENYON: And then finish up.
MR. GRIMES: Yes.
MR. KENYON: Okay. This gives you an idea
of the ecological issues. The next slide shows you
the kind of issues we look at in terms of social
economics and environmental justice.
DR. APOSTOLAKIS: How do you do social
MR. KENYON: Well, we have a sociologist,
and we go out and we interview a number of different
people, like the local businessmen; we talk to local
charities; we try to get a flavor for what would be
the impact of the plant not being there, in terms of
what it would do to their tax base, that sort of
thing. It's kind of a different kind of review.
When you're talking to the people who run
the charities, you know, when they think of the plant
leaving, in some cases there would be a significant
impact; in other cases, these people that they take
care of are probably not likely to be working at the
plant to start with. Okay?
DR. APOSTOLAKIS: Okay.
MR. KENYON: I'll just breeze through this
real quickly. There are issues that are not
considered in the environmental review, such as the
need -- this is by regulation. The other important
thing I wanted to point out is that we don't look at
the safety-related issues. That's left up to Mr.
Prato, and we don't get involved in his review.
DR. APOSTOLAKIS: So let me understand
this. A coal fire plant is not licensed by the
federal government; is that true? Are they licensed
by the federal government?
MR. KENYON: I don't know that they're
licensed by the federal government, but there's a
number of environmental statutes that they have to
meet, and they're covered by the Environmental
MR. GRIMES: We have to be careful with
our choice of terms, because I would contend that
there's an EPA permit requirement that is not like our
licensing process, but it is a federally imposed
restriction. Hydroelectric facilities are licensed by
FERC in a process that looks very much like ours.
DR. APOSTOLAKIS: So, ultimately,
everybody does an Environmental Impact Statement.
MR. GRIMES: Yes. Ultimately, everybody
does an Environmental Impact Statement but with a
MR. KENYON: And that concludes my
presentation, unless you have any other questions. I
did provide you with the document of the last
Environmental Impact Statement that we produced on
Oconee just to give you an idea of what we do.
DR. BONACA: Thank you; appreciate it.
MR. GRIMES: I'd also like to add that Tom
made a point that during the process that they go
through, they reach out to the public in order to find
out what the public's interests are. But the
environmental review does not address safety-related
issues. So if safety issues are brought to them, they
refer them to the safety review, and Mr. Prato checks
to make sure that they're being covered as part of our
review process. But we don't necessarily tailor a
safety evaluation to address the public's interest in
issues like waste or so forth. But we do keep the two
trains separate during the review process.
DR. BONACA: Thank you for the
presentation. And I would like to thank also the
applicants and Framatome's support for the
presentations; very informative for the application
that was -- well, I'll comment on that. And also the
staff for the presentations we received.
And I would like to go around the table
and ask the two surviving members of the Subcommittee
here if they have any additional insights to whatever
they provided me before regarding the presentations.
I would like to just make a few comments.
One is that I spent quite a bit of time reviewing the
application as well as the SER, and I thought that the
application was effective. I thought the SER was
complete and effective. I thought that definitely
there were a lot of lessons learned that were used to
make this application and the review more complete.
I think that it was easy to trace the issues.
And I also appreciate the staff's
willingness to make this presentation on a comparison
basis. It was helpful for us, because I mean we spent
quite a bit of time on Oconee, and it was a profit for
us to benefit from the experience in our review of
Arkansas, and that took place.
I felt that the scoping process was
thorough and part was helped by very effective quality
listing that already Arkansas seemed to have. That
was quite helpful. We didn't go through the pain and
suffering that we had in previous applications. That
was good. I thought that it was pleasing to see that
there wasn't too much of a focusing on legalistic
narrow limits in the extent in which management
programs were implemented.
There was some expansion to give proper
consideration to important items, and that was
important. And because of that, I feel that there are
very few open items. That's one of the reasons. And
I don't think those items are contentious. The way I
see it there is no measure of contention there. So I
don't see any show stoppers from a perspective of the
review of the staff, as well as a review of the CRS.
What I would recommend is that we do not
have an interim report. And I would like to have your
thoughts, Chris, regarding this.
MR. GRIMES: My view is we don't need one.
I think that we've benefitted from your review, and
the level of detail that you've gone into is evident,
and the feedback is helpful, and we're going to
reflect on ways that we can improve the safety
evaluation just based on the exchange that we'd had.
But unless you have any particular views on the
issues, we don't need an interim report in order to
proceed, and we'll plan on coming back to the
Subcommittee again to report on the resolution of the
open items and --
DR. BONACA: And we will plan to write a
letter at that time.
MR. GRIMES: Correct.
DR. BONACA: We will write just one
letter. That was part of our plan, in fact, when we
go to a second and third review of a similar type
plan, unless there are major issues to which we can
contribute observations, then we'd have simply a final
report, which we plan to have on this plant.
What I would propose, then, is that I'll
report these conclusions to the full committee next
week. That will take probably 15 to 20 minutes, maybe
half an hour at the most. And I would request that
the staff supports me maybe with a couple of people
there present in case there are any specific questions
from the members of the full committee. And that's
what I would like to do.
So for that presentation we do not need
applicants present, right, at this stage. We will
plan to have you come at the final -- when we receive
the final SER with the closed open items. And then we
will have a full presentation in front of the
Committee at the time, and then we'll write a full
So if there are no disagreements, that's
pretty much what we're trying to do. We will somewhat
change the schedule --
DR. APOSTOLAKIS: How much time are we
DR. BONACA: We're scheduled for an hour
and a half, George.
DR. APOSTOLAKIS: But we will take only
half an hour?
DR. BONACA: About half an hour, yes.
We'll take a half an hour and --
DR. APOSTOLAKIS: We'll do something else.
DR. BONACA: Oh, yes. We've got a lot
things to do.
DR. APOSTOLAKIS: We can finish the safety
DR. BONACA: No. With that, I'm pleased
to see that even our review was facilitated by the
lessons learned. So with that, if there are no
further comments --
MR. GRIMES: Dr. Bonaca, I have a couple
of questions, though, that I'd like to pose before you
adjourn. The first is I'd like to ask -- you
mentioned during the course of the presentation
several times that you had some questions: The
question on the reactor vessel level measurement
DR. BONACA: Yes.
MR. GRIMES: -- the nature of the seven
new programs, the clarity of the SER as it relates to
the B&W integrated internal's activities. Dr. Shack
asked about impurities in the sodium hydroxide and FAC
on the feed water. And I wanted to know whether or
not there were any of those questions that you'd like
us to pursue further and get back to you?
DR. BONACA: Not for my part, no. I was
satisfied that it was more like I needed
clarification. In many cases -- in my case, it was
the point I made that the application said something
and the SER contained resolutions of issues that were
not reflected in the application.
MR. GRIMES: I understand. And as I said,
that was useful for us, and we'll reflect on that when
we close the open items to see if we can improve the
clarity of the SER in those areas.
The other question I had is the style of
this presentation was largely built off of Oconee, but
I would expect that when we bring Hatch to the
Subcommittee at the end of March that we do something
that largely focuses on BWR uniqueness and perhaps the
particular issues that we felt were challenging
because of the boiling water reactor. So in that
sense, we would have a presentation that would be
organized in much the same way, allow about the same
order and level of detail, and highlight unique BWR
challenges rather than differences from previous
DR. BONACA: I agree with that. That
seems to be a positive approach. The thing that I
would like to make sure, of course we have not
reviewed the BWR/VIP documents; we're reviewing them
MR. GRIMES: We have a separate meeting
scheduled for the VIP, the day before.
DR. BONACA: That's right. I was
referring to the full committee meeting we have the
week after that. So if I understand it, the SER for
Hatch will be very much based on -- okay, but we're
saying we're going to deal with them separately.
MR. GRIMES: Right. We would attempt to
try and cover as much of the VIP during the first
meeting as possible so that the focus of the second
meeting would largely be the same kind of format as
today -- scoping -- our methodology, scoping, aging
management programs in each of the areas. And then
wherever VIP occurs, we'd refer away from that and
concentrate on the other aspects of the Hatch review
that were unique and challenging from an aging
DR. BONACA: And I agree with that.
Actually, that would be helpful for another reason,
that although we think of these plants very
differently, but in many of the support system we find
similarities. And to the extent to which you can
capture the experience we have for those similarities,
that helps. I mean, clearly, emergency systems and
the steam -- well, not completely, but many portions
would be singular.
Any other questions?
MR. GRIMES: That's everything I need.
DR. BONACA: Questions or comments from
DR. SHACK: I like the format of the
license renewal report. I thought it was rather
helpful to get through it. It was easier reading than
the first two that we went through. For the SER, how
about a list of the initialese up front. For those of
us that ULDs don't slip off our tongue, and when I
come back in two weeks I forget what a ULD is again.
MR. GRIMES: Acronyms up front, right
behind the executive summary.
DR. BONACA: If there are no further
comments, I'll adjourn the meeting. Thank you very
(Whereupon, the Subcommittee meeting was
concluded at 12:49 p.m.)
Page Last Reviewed/Updated Tuesday, August 16, 2016