Plant License Renewal - February 24, 2000
UNITED STATES OF AMERICA
NUCLEAR REGULATORY COMMISSION
ADVISORY COMMITTEE ON REACTOR SAFEGUARDS
***
MTG: PLANT LICENSE RENEWAL
Clemson University
Madren Conference Center
Room III & IV
Madren Center Drive
Clemson, South Carolina
Thursday, February 24, 2000
The above-entitled meeting commenced, pursuant to notice, at
8:00 a.m.
MEMBERS PRESENT:
MARIO BONACA, Chairman, ACRS
ROBERT SEALE, Vice-Chairman, ACRS
THOMAS KRESS, Member, ACRS
DANA POWERS, Member, ACRS
WILLIAM SHACK, Member, ACRS
JACK SIEBER, Member, ACRS
ROBERT UHRIG, Member, ACRS. P R O C E E D I N G S
(8:00 a.m.)
CHAIRMAN BONACA: This is a meeting of the ACRS Plant
License Renewal Subcommittee. I am Mario Bonaca, Chairman of the
Subcommittee. The other ACRS members in attendance are the Vice
Chairman of the Subcommittee, Robert Seale, Thomas Kress, Dana Powers,
William Shack, Jack Sieber, and Robert Uhrig.
The purpose of the meeting is to meet with the
representatives of the NRC staff and the Duke Energy Corporation to
discuss the staff's resolution of the open and confirmatory items
identified in the Safety Evaluation Report related to the license
renewal of Oconee Nuclear Station, Units 1, 2 and 3, and related license
renewal activities. Our Subcommittee will gather information, analyze
relevant issues and facts, and formulate proposed positions and actions
as appropriate for deliberation by the full Committee.
Noel Dudley 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 13, 2000.
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 are readily heard.
We have received no written comments or requests for time to
make oral statements from members of the public.
Yesterday, the Subcommittee toured Oconee Nuclear
Station and meet with representatives of the Duke Energy Corporation to
review the details of how Duke conducted the license renewal scoping and
aging management review processes.
Before we proceed, Jack Sieber of the Committee needs to
make a statement.
Mr. Sieber: Thank you, Mr. Chairman. I would like to place
on the record the fact that under Federal Ethics Laws I am not eligible
to vote on matters effecting Duke Energy Corporation because I am a
stockholder of Duke Capital Corporation, and, therefore, my non-voting
should be construed in that light. Thank you.
CHAIRMAN BONACA: Thank you. We will proceed now with the
meeting and
I call upon the Duke staff to begin. Good morning.
MR. GILL: Good morning. Thank you, Dr. Bonaca. My name is
Bob Gill. I am on the Oconee License Renewal Team. I'm here to start
our presentation. And on behalf of Duke Energy, the Team, and, of
course, Oconee Nuclear Station, we welcome you to the upstate South
Carolina area. Hope you've enjoyed your visit, your short visit
although it may be.
We have several presenters today to go over topics of
interest that have been identified. Before I do that, let me go through
just a little bit of a background before we get into the first topics.
I'm going to cover briefly the project status, where we are. This is a
very important meeting, because it is leading up to the recommendation
by the staff in the next couple of weeks. There were three open items
that the Committee decided they would like to review in depth; the
resolution of scoping methodology, electrical insulated cables and
connecters, aging management program, and vessel internals. We have
presentation prepared on each one of those.
Briefly, on the status, the current status as we understand
it is that the Recommendation Letter to the Commission will be sent by
the staff by April 14. There are a number of milestones that have to be
completed before then, many of which have already been done. The
Facility Operating License, the new draft, has been provided us for
review. We have a meeting scheduled on March 19th with the staff to go
over that.
There were no technical specifications or changes
identified.
The Final Safety Evaluation Report, which we have copies on
the table, have been published by the staff. We were very welcome on
that. A lot of good work has gone on both sides there.
The UFSAR Supplement, a draft, was provided to the staff and
the staff is reviewing that. We intend to formally submit a revised
UFSAR Supplement by the end of March so the staff can have that as part
of the package. We are expecting a Region II Recommendation Letter by
the end of March. There is a site inspection scheduled for next week,
with a Public Exit Meeting the end of next week announced.
Final Supplemental Environmental Impact Statement was
received in December. That closed out all the environmental reviews
associated with renewal of the license for Oconee. We are expecting
your recommendation Letter in a couple of weeks, after the full
committee has a chance to review all the issues.
And for the final piece was the Indemnity Agreement, which
was required by the regulations to be looked at. We did not identify
any changes. I believe the staff has concurred in that.
So, those eight pieces are the total package that we needed
to renew the license.
The purpose of this morning's discussion is for us to
provide additional information to the members of the committee on the
resolution of three open items, and the insights that we used to do
that. We will follow the handout that is in here.
The first item that will be discussed is the Scoping
Methodology, with Rounette Nader.
Second, will be Paul Colaianni talking about the Electrical
Aging Management Program on cables and connectors.
And, finally, Jeff Gilreath from our corporate office staff.
And you see a couple of models here and diagrams of the vessel
internals. That will be our last presentation, and we will be able to
answer any questions the staff has on that.
Are there any questions at this point in time on what we are
covering? I turn it over now to Rounette Nader, who will go over the
Scoping Methodology validation that we did late last year.
MS. NADER: Thank you, Bob. I'm Rounette Nader with Duke
Energy. I'll be discussing the Scoping open item. On slide number
seven, we have the issued defined and the resolution, all here together
at the beginning. But the issue really evolved into from the scoping
open item was, is the set of events that was considered by Oconee
license renewal scoping methodology sufficient for scoping.
The issue was resolved by case study. Ten events
identified by the NRC. Duke researched the licensing basis of the ten
events, and the end result was that the scoping methodology had
identified all the appropriate systems, structures and components for
license renewal.
On slide number eight, really the next three slides, eight,
nine and ten, are a chronology of some of the things that occurred
between Duke and NRC on this issue. I'm not going to go through each of
these. It is really more just to show the rigor of what really went
into this issue. You can see that Duke submitted the license renewal
application in July of 1998. And in October of '98 the NRC staff,
several members traveled to Charlotte to look at the internal
documentation related to scoping.
Several meetings occurred. The request for additional
information was issued in December. Several meetings occurred the first
half of '99. On slide number nine you will see the second half of '99
were more meetings. The SER open item was issued.
On slide number ten, on October 28th of 1999, which was a
year and a day after our first meeting, Duke and NRC had a meeting to
discuss resolution of the issue.
Duke submitted the response in November and the SER that was
issued just this month closed the open item. To really understand the
technical basis behind the issue, on slide eleven begins a presentation
of, really of the Oconee scoping methodology for license renewal. The
methodology for all three disciplines combined, we have boiled down into
seven steps. The first four steps were the mechanical steps for
mechanical scoping.
So the first step was to identify functional flow paths,
mechanical functional flow paths required to mitigate design basis
events for Oconee.
The second step was to add pressure boundary to these flow
paths. Passive pressure boundaries required before you could impact the
flow paths.
The third was to identify physical interference commonly
known as two over one, any piping whose failure could interfere with a
safety related or a central system. On slide twelve, the fourth step,
was to capture any other safety related or seismic equipment at the
plant that had not already been identified. Because of Oconee's design
there were some incidences where there were safety related piping that
didn't get identified in the first three steps. They got identified in
step number four.
From a structural standpoint starting with item number five,
class one structures meet the 54.4(a)(1) criteria. Class two structures
meet the (a)(2) criteria. Those were scoped by looking in the UFSAR for
those definitions.
Step number six was electrical in nature. You heard about
the spaces approach. All electrical components were initially assumed
to be within scope, and then the screening staff screened out active
equipment.
In step seven was to meet the 54.4(a)(3) criteria, which was
to look at the licensing basis of the five regulated events that are in
(a)(3) and include those systems, structures and components within
scope.
So upon completion of these seven steps, the scoping for
license renewal was complete for mechanical, structural and electrical.
On slide thirteen we did a graphical representation of the
methodology and really the results. You can see on the pie chart the
structural pie piece, the electrical pie piece, the 54.4(a)(3), the
regulated events pie piece. On the top piece of the pie is the
mechanical methodology. It is broken into the four steps that I just
mentioned.
The first step, the input into the first step, is really
the issue of the open item. The first step was accomplished by
identifying the functional flow paths required for design basis events.
What are those events, that's how the issue got identified. So with
design basis events, the passive pressure boundary, the seismic two over
one, and the other safety related in seismic. So we felt like the focus
of the issue was really -- is there anything, any little bump in this
pie that should be added. The NRC had concern that there were other
events that Oconee should have considered when scoping for license
renewal.
So what did Duke consider as a design basis events. Design
basis events are as the term that is used in 54 for scoping. Oconee's
UFSAR, Chapter 15, is the accident analysis chapter for Oconee. The
first sentence, the introductory sentence for that chapter, is the
following: "This section details the expected response of the plant to
which the spectrum of transients and accidents which constitute the
design basis events." So, historically, this is
the -- the Chapter 15 accident analyses are the events that
Oconee has considered the design basis events.
Modern day regulations get written very similar to the way
54.4 is written. When applying these regulations to Oconee, it is
important to recognize that Oconee's design really preceded the
regulation that defines these on-basis events today in 50.49. We had
our definition that was on the previous slide, on fourteen. We did
institute a project in the early 90's to really confirm since all the
regulations that were coming out really used this new type of
methodology and new approach. To confirm Oconee's licensing basis and
design, and they really confirmed that the UFSAR Chapter 15 events are
what constituted the licensing basis for Oconee as the design basis
events.
In addition, this project said, the end result of the
project said, you know, really since original licensing there have been
some other events that have come up through licensing that are really
important. When you are scoping these regulated programs you should
probably consider these additional events. A license renewal was an
issue that did that. We call them scoping events. It goes beyond the
Chapter 15 licensing basis, design basis events.
On slide sixteen, the definition of the scoping events that
was used by Oconee for license renewal scoping. For the design basis
events in Chapter 15. Natural Phenomena Criteria, which are in Chapter
3 of the Oconee UFSAR. The Post-TMI Emergency Feedwater Designs, the
scenarios associated with that. And the Turbine Building Flood, which
is mitigated by the Standby Shutdown Facility. You saw that in your
tour yesterday.
So the Chapter 15 events, plus these other three criteria,
were the scoping events set that was used by Oconee scoping.
So throughout the year as Duke and NRC had our meetings and
our correspondence on the issue, we finally came down to Resolution, the
NRC Perspective, as you see on slide seventeen. It is the staff believe
that more events should be considered, and should have been reviewed in
order the insure the functions identified in 54.4(a)(1).
So the resolution was for Duke to conduct a case study of
ten additional events that were identified by the staff and given to
Duke, and to research the current licensing basis and these five
documents: Commission regulations, license conditions, Commission
orders, the UFSAR, and exemptions.
On slide eighteen, the purpose of the case study was to
really validate the scoping methodology that had been performed by
Oconee, the seven steps that we just spoke of. That those seven steps
as executed identify all the SSCs required to be within the scope of
license renewal for 54.4.
On slide nineteen you can see the results of the case study.
The assessment performed by Duke revealed that the current licensing
basis associated with those ten events did not identify any additional
systems, structures, or components that met the license renewal scope
that met the criteria of 54.4.
The final SER that was issued earlier this month agreed with
that, the Duke assessment. That no additional SSCs needed to added to
the scope of license renewal.
So slide twenty is the conclusion from the case study. The
Oconee License Renewal Scoping Methodology is described in the
Application in that you saw in the seven steps that we just described,
identified all systems, structures and components relied upon to remain
functional, to insure the functions identified in 10 CFR 54.4.
The case study provided the validation for Duke and the NRC,
that the methodology that was employed by Oconee, by Duke, was indeed
sufficient. And the NRC could use that validation in making their
finding that the scoping methodology was sufficient and that the results
were sufficient.
The final SER, as I mentioned before, did resolve the
issue. It closed the open item related to the scoping issue. It does
talk about the validation that was done, the case study that was done,
and that the NRC gave reasonable assurance that the set of events that
were used in the scoping methodology were sufficient to get all the
important SSCs in the plan, and all the SSCs that met the license
renewal scoping criteria 54.4.
We feel good about our scoping methodology. We've felt good
about our scoping methodology for awhile. Our project that was
instituted at the beginning of the early nineties, like I mentioned
before, did a validation of Oconee's licensing basis, and design basis.
We felt good because we felt like we were consistent with our current
licensing basis. You saw the statement of the Chapter 15 of UFSAR. We
felt like our scoping process was really applied in accordance with the
rule. We read the rule, we read the SSCs. We felt like the methodology
we employed was a good one.
We were also consistent with other regulations, regulations
that used the same type of wording, such as maintenance rule, in-service
testing, scope, motor operated valve testing scope. Other regulative
programs that have been instituted in the last decade or so that used
the same kind of words, the license renewal scoping methodology was very
consistent with those. And traditionally when you look at the plant,
you look at Oconee, you pull out the drawings to see what is in license
renewal scope, we feel like we really captured all the important
systems, structures and components. Just a gut feel. All the SSCs that
we traditionally view as important to a plant, we really feel like we've
got them.
Questions?
CHAIRMAN BONACA: One of the main events that you reviewed
for the items, and you yesterday described to me that was a study that
was done -- could you tell me the dates when it was done? At least to
the extent that the review that that accident evolved?
MS. NADER: That's true. One of the events that was
researched in the case study was a high energy line break event that
Oconee had done a report on in 1973. It was based on a Jim Bouso, Mr.
Jim Bouso letter that was issued really after Oconee Unit One was
licensed, but before Oconee Units Two and Three were licensed. The
report that was conducted looked at the susceptible locations of high
energy lines, where they might break, and what sort of safety related
components it may impact.
There were some resultant actions that came out of the High
Energy Line Break Report. There were several modifications that had to
be done to the plant in order to insure that the plant could be safely
shut down in the event of a high energy line break as such.
One of the ten events was the high energy line break. We
did review the report. We had Duke and the NRC, we had some guidelines
on what sort of things should be reviewed. The UFSAR talks about the
high energy line breaks. The licensing basis associated with the high
energy line breaks were the -- there was actually a license condition on
Unit One to get the modifications performed. Units Two and Three, we
did the modifications before they started up.
So we looked at the licensing basis associated with high
energy line break and determined that the systems, structures and
components that were within the licensing basis for that event were in
the scope of license renewal.
CHAIRMAN BONACA: I guess the question I have is from the
perspective of ACRS and the review you performed. There should have
been a scope, a review of that particular event, right? Because, I
mean, it is part of your licensing basis and I was curious to know why
in your going through the first six events that we went through did not
include that one. I'm sure that one already was reflected in your
piping systems. You showed us those diagrams. I'm just trying to
understand for future applications the fact that why you would not have
included that specific event as one that you used originally.
MS. NADER: That event is discussed in the UFSAR. It is in
Chapter 9, I believe, of the UFSAR. It is not one of the
Chapter 15 accidents in the UFSAR. It is not traditionally considered a
design basis event for Oconee. It was used as part of the design for
Oconee, a design criteria to insure that you don't route high energy
lines over safety related switch gears. But as far as having an
accident analysis, you know, such as a safety analysis on this event, we
traditionally don't treat this event as a design basis event that is
included in scoping. Like I say, if we modified the plant correctly the
way we were supposed to according to the license condition, and we
perform our modifications like we should, and we don't route the high
energy lines over safety related piping, then there is really, there is
really ---
CHAIRMAN BONACA: Certainly. But shouldn't beginning the
scope that you cover to include more than Chapter 15 events. In fact,
on the list of items in which you gave us, I believe, they would be on
that.
MS. NADER: That's true.
CHAIRMAN BONACA: I'm not questioning the scope of which you
have
covered today. I'm only asking questions about these events
in my judgment should have been part of the original review. And it
would fit within the categorization that you've described here which say
Chapter 15 events plus, TMI, and I can't find it now.
MS. NADER: It is on slide sixteen. There were several
reasons for identifying the plus; the Natural Phenomenon, the Post-TMI
Emergency Feedwater scenarios, and the Turbine Building Flood. Some of
them were based on risks. The biggest thing I think that really went
into the plus events, if you will, is the fact that they bring in
important parts of the plant. If you exclude the plus, for example, you
will not have the standby shutdown facility within scope. You saw it
yesterday. It is a pretty impressive facility. It is safety related.
But it would not come in the scope for a Chapter 15 event because it was
all in post-licensing. It was not an event that was added to Chapter
15.
CHAIRMAN BONACA: And, again, on slide number sixteen you
have expanded the basis from Chapter 15 with other things. You showed
us diagrams yesterday, and I'm sure that the high energy line break
locations for physical interactions I think have been identified in some
of the diagrams already.
MS. NADER: That's right.
CHAIRMAN BONACA: Okay. For the purpose of to get license
renewal in general, that to me is an understanding of where the staff
was going and I think that it was good that this was done as part of
that.
MS. NADER: And I think that's the thought process that went
into these, the plus events, was that if you really did scope using
Chapter 15 and these plus events, you have bound things like high energy
line break. That's what we found out from the validation and from the
case study.
Any other questions? Comments?
CHAIRMAN BONACA: None, thank you.
MS. NADER: Okay.
MR. GILL: Next up we will have Paul Colaianni, who is our
electrical lead engineer on the license renewal project. He will
discuss in detail the Insulated Cable Aging Management Program that
we've added, that was not part of the original submittal. That was
added to the program late last year.
MR. COLAIANNI: Hello.
CHAIRMAN BONACA: Good morning.
MR. COLAIANNI: All right, we will start out, basically this
open item was opened up after the original review of plants UFSAR came
out. It came out of the on-site inspections, and basically a review
offered experience, showed that, indicated that something was needed.
The items basically fell into two categories that are generated via the
program that came out of this. And, basically, to resolve the item,
basically Duke committed to initiate a cable aging management program.
I will go through the details here.
We pretty much included all the verbiage in these, we tried
to make them readable so you'd have all the details. So, we will take
the two separately then, thermal/radiation aging versus moisture aging.
So, this is the thermal/radiation aging.
Basically, what was found was insulated cables in a small
number of localized areas in containment were identified in station
problem reports as exhibiting accelerated aging due to their proximity
to this high equipment.
Corrective actions, these, of course, showed up in the
problem investigation reports. Corrective actions at the time tested
the cables and they were all functional. So that confirmed that.
Future surveillance was also put into corrective actions. Modifications
to eliminate the adverse environments were to be evaluated. That's the
corrective actions that came out of it. Yes?
DR. SEALE: Have you got any indication based on the initial
examinations where things were still functional, that down the road you
might expect a deterioration in performance and that was the reason for
the future surveillance item that is in that bullet?
MR. COLAIANNI:
Yeah. There were not -- if the cables look in a condition
that they seem to accelerate at that same rate, you might have a
problem.
DR. SEALE: Okay.
MR. COLAIANNI: Yeah, that was the reason for continuously
monitoring of the area. The evaluation of the modification, I mean, the
ideal situation where you can actually eliminate it. One case was where
they had routed some cables over a large feedwater line. The ideal
would be to fix it, shield it, so that you no longer have that design
feature in that area. So that's the thought process behind that.
DR. SHACK: How were the problems identified? That's
basically visual inspection, saw degraded cables, or functional
problems?
MR. COLAIANNI: No. Visual inspections. Some of them were
actual dedicated walkdowns, but these same areas were also found just by
maintenance people walking around doing their jobs and they would notice
something and report it back. Then an engineer would come out and
evaluate it. But it turned out that many of these got identified more
than once, so you had more than one PIP on the same area simply because
the area kept being noticed by maintenance people. But walkdown
inspections, just visual indications were what was noted.
When these are identified in the early stages of license
renewal review, this is like 1996 time frame. This is the walkdowns I
told you about yesterday, that I went over. A lot of these were
initially noted in PIPS at that time. The problems were judged to be
design installation problems and not relevant to license renewal. That
may seem, on hindsight it kind of looks strange to say that, but at the
time what we were thinking was, you know, we were trying to draw a
distinct line between design problems, or maintenance problems, versus
actual aging problems. So that was the judgment that was reflected in
the original application, that these were design issues that should be
dealt with more in the modification area to alleviate the problem rather
than an aging issue that should be part of license renewal. So, that is
kind of what got reflected in the original application.
CHAIRMAN BONACA: But you may have a design feature, not
from a cable but from the environment that is causing the aging problem.
MR. COLAIANNI: Right.
CHAIRMAN BONACA: So the environment is part of the license
renewal, but not from the aging then because you can just make the same
application, eliminating that environment.
MR. COLAIANNI: Right.
CHAIRMAN BONACA: So, you are addressing that?
MR. COLAIANNI: Yes. Yes. And as you will see in the next
slide the progression that went on, basically, in what we realize now is
that if you have a design installation problem that you don't fix, then
basically then you've got an aging problem that is part of license
renewal. But if they went ahead and fixed it so to alleviate the
problem and it goes away, then it is not an aging problem. So it is
kind of a progression of thinking through the process.
So, as I was just describing, basically in 1999 now that we
did the on-site inspections, the problem reports were identified by the
staff. The problems the staff identified as indications that aging
management was needed, which was a good call because the areas had not
been modified to alleviate the problem. So that is basically what this
explains here. So we agreed at that point since the areas had not been
modified to alleviate the problem then aging management was needed.
And, basically, these sort of lessons, I call as lessons learned. I
tried to, you know, the incident I told you about yesterday, give them
this type of lesson meaning, you know, if you discover in walkdown
something that you can label as a design and replace the problem. If
you don't ever fix it, then you better include it in the license renewal
program, because then it becomes an aging problem. If you are going to
fix it, take care of it then and you won't have to worry about it. So,
that is one of those lessons to learn going through this process the
first time. It is always a challenge to label something.
CHAIRMAN BONACA: Say that you didn't go through license
renewal till you find some cable like that, what would you do? I mean,
you would just have the decision to either remove the cause of the
problem by corrective action, or just simply monitor. That depends on
if they have built it in the system, right?
MR. COLAIANNI: Right. Yeah, and it may depend on a
particular situation. But, the continued surveillance of that
particular area would go on and either we'd modify it or continue to be
surveilled down the road. License renewal just more or less made that
process a commitment to make sure that that actually does get done as
part of the program.
CHAIRMAN BONACA: But it is not different from what you
normally would do?
MR. COLAIANNI: No.
CHAIRMAN BONACA: This is just establishing some specific
commitment that you would do it?
MR. COLAIANNI: Right.
CHAIRMAN BONACA: An alternative to just simply moving the
environment that is caused by the design problem?
MR. COLAIANNI: Right. Now even in this stage, even though
those areas will be wrapped into the program, if they actually do modify
them in the future to alleviate the situation, the adverse environment,
then basically they can be brought back out of the program. Then there
would be no need to have them in there.
CHAIRMAN BONACA: Yesterday you showed us some very
aggressive inspection on your part, which I think should be commended.
You wrote down a lot of systems, and you showed snapshots of areas where
there were indications of challenging the equipment. Is this just a
one- time initiative, or is it going to be part of this aging management
program, which you are going to have walkdowns with some frequency?
MR. COLAIANNI: The inspections that are envisioned, even
though we found in specific areas, basically around the steam generators
and pressurizers revealed some hot pipes we found specific areas. The
inspections themselves are going to be enlarged to basically say, you
know, basically we are going to look around all areas that the steam
generators where you have cables to see if you have these things. In a
three or four foot proximity all around the pressurizer is where you
might have cables. Those are the areas that are most prone to where
these problems would pop up. So it should make sense to just include
the whole area around the steam generator and pressurizer in the
inspection program.
CHAIRMAN BONACA: So you really haven't identified, or you
will in
the aging management program of cables with specification
location which are regulated by the aging program?
MR. COLAIANNI: Right. And one of the elements you will see
in there, because those fall close to hot equipment basically, you've
got that similar adverse environment from the cables and those
similarities. So that would also be included.
CHAIRMAN BONACA: Okay.
MR. COLAIANNI: I've already covered this. Next slide.
Mr. Sieber: While you are doing that, there are some
cables, power cables and control cables that you can't visually inspect.
Those are ones that run in duct lines or conduits. What steps are you
taking with those types of cables to insure that their condition is
satisfactory?
MR. COLAIANNI: In our Reactor Building we have very few
cables in conduit, basically because we have the armored construction
cables. So that is really not a problem. In most places we have very
limited use of conduit for areas that would just be subject to heat
degradation. Now, the moisture degradation issue is covered, and I'll
be covering that in some later slides for medium voltage cables exposed
to moisture.
Mr. Sieber: All right.
MR. COLAIANNI: So what we came out with, this is the part
of the program specific to the Thermal and Aging, Radiation Aging
Effects. Basically, all in-scope cables installed in adverse, localized
environments will be inspected. And those adverse localized
environments basically, since they sort of did it on a spacing approach,
basically we are going to be inspecting areas looking at cables and
areas as opposed to specific identified cables.
And, again, because of the way the rule is set up, these do
not include the acute program cables. They are already in an adequate
program. The staff found that to be adequate for managing the aging of
those cables. They've already been through a lot of pre-testing for
their environments. So, this program itself does not explicitly include
EQ cables, although in the inspections you are not really determining
whether something is in or out of EQ, but this is more of a programmatic
statement.
Accessible cables in these areas will be visually inspected
every ten years. Basically what you are going to be looking for is
cable surface anomalies to be used as an indication that something is
going on with the cable. You obviously can't see the actual
installation, that installation, which is the thing that really matters.
But you are looking for surface indications that something is going on
with the cable. So, these are the types of things you would look for in
addition to other things. We've got a guide that I can show you that
gives a lot of information on what kind of things to look for and where
to look for them.
Unacceptable indications found during the inspections will
be investigated further by engineering. So, basically where something
is found either by a maintenance person, going through and identifying
something, or an engineering problem itself, finding something, if it
looks, and depending on how it looks, further investigation would be
done and it could include testing and any sort of corrective actions
that seem appropriate.
MR. UHRIG: In the armored cables are you looking for dents
in the armor? What kind are you looking for?
MR. COLAIANNI: Actually, in a lot of cases there are some
cables in the Reactor Building that just have the armor on the outside.
But there are quite a lot of cables. In most cases you are more
concerned with control of the cables. Those do have jackets that you
can see, or they have a braided armor and you can actually see the
jacket underneath the braided armor, or you can see deterioration of the
braid. But you can actually see it. There are those pictures I showed
you yesterday. You can actually see there is some deterioration that is
going on. Although we do have armored cable, it might seem kind of
strange to look for surface dents, but there are indications that you
can see. This was found in the PIPS. Basically, a lot of things can be
seen. A lot of things have been seen as time goes on.
So now we will move onto the Moisture, Medium-Voltage Cable
Moisture Aging Effect part of the program. The history is basically on
the outside inspection reviews. Areas of particular concern to
inspectors were water collection and cable trenches and potential
degradation of direct-buried cables. To answer those concerns during
the inspection, basically Oconee cables installed in trenches are
designed for a rain and drain type exposure. The inspection reports for
the direct buried cable tests, as also documented in the inspection
report, do not show, do not indicate ongoing degradation. So, we feel
good about at least the rate of whatever mechanism involved with those
cables.
We did have one LER of a medium voltage cable back in 1980,
where the cable failed. The documented root cause of that was their
moisture intrusion due to improper installation, due to damage of the
jacket during installation, or improper installation where water was
allowed to intrude into the end of the cable. But those were the
documented root causes in the LER itself. But that's the only instance
that I'm aware of of medium-voltage cable failures with the conduit at
Oconee.
CHAIRMAN BONACA: How was this failure identified?
MR. COLAIANNI: It was identified as part of testing of the
motor. It might have been a mega test, but I'm not positive, but they
were testing the service and found an indication and narrowed it down to
the cable itself.
CHAIRMAN BONACA: So there was nothing to -- it was just
part of a test?
MR. COLAIANNI: Right. So based on the site inspection, the
staffing concluded that aging effects for medium-voltage cables exposed
to moisture were applicable to Oconee and that aging management was
needed.
So here we have the program elements pertaining particularly
to this aging effect. Basically the program includes an inaccessible
in-scope medium-voltage cables installed in adverse localized
environments in conduits and direct-buried. Water collection in
manholes will be monitored to prevent cables from being exposed to
significant moisture as a preventive action. Inaccessible
medium-voltage cables exposed to significant moisture and voltage will
be tested at least every ten years. Now, basically when we talk about
significant -- I use the term significant moisture and significant
voltage. Those are defined as part of the program. It depends on the
particulars of the cable itself as to what to submit. We do have the
framework of definition. If you are not real sure of what your cable is
capable of withstanding when we talk environments, we have sort of a
threshold value in there. But a lot of it depends on how the cable is
designed, what environment it is designed for. You could have a
submarine cable which is designed for a hundred percent exposure, a
hundred percent voltage all the time. So that does depend on the cable
itself.
MR. UHRIG: What kind of testing are you talking about
there, measuring the resistance, the pulse transmission?
MR. COLAIANNI: Right now, and because the first testing
under this program will not be done for another decade, didn't specify
what type of test. Basically, before the test is performed, the cable
engineer with the help of our NGO cable engineer, would determine what
is the best type of test performed and to give him the best information
on the individual cable. But that really won't need to be determined,
won't be determined till another decade before the test. And hopefully,
you know, mainly because there could be new test arise between now an
then. A lot of the test that we will replace now, that may not look
good now, maybe customized down the road. So we didn't want to specify
and lock into any particular type. But it would be something that would
give the cable engineers a good confidence about the condition of the
cables.
CHAIRMAN BONACA: But you plan to do the testing? You've
committed
to some testing by what?
MR. COLAIANNI: The first test would occur sometime before
the end of the Unit One initial period of operation.
CHAIRMAN BONACA: And you would have a bona fide program at
the time, of course problems can change as you learn more, or something
different.
MR. COLAIANNI: That's correct. The program would be fully
in place before the first test would be performed. So this is the
reason we are talking prior to each test, the specific type of test
performed along with test acceptance criteria will be determined.
The criteria will depend on the type of test, and what are
the particulars at the time, and the particular type of cable. The
cables not meeting the test acceptance criteria will be investigated
further by engineering, be it testing, be it replacement, whatever seems
to be corrective action.
All right, so those are the particular aspects to each of
those types. Now, there are aspects of the program that deal with both
thermal aging and moisture. These are basically that a determination we
made as to whether an identified unacceptable condition or situation is
applicable to other accessible or inaccessible cables. So in the case
of thermal or radiation, of course you can't see cables in the middle of
a bundle. So if you see some indications on the surface of the ones you
can see, you know, an evaluation would be determined whether is that a
condition applicable to other cables that I can't see. And the same
thing for the moisture. They find some cables and they do a test and
they find an unacceptable condition, an evaluation would be done. Is
this occurring on other units with the same configurations, but that
would be applied. The initial inspections or tests would be completed
by February 6, 2013. That is the end of the initial four year period
for Unit One.
And to use as a guidance, there is a new document posed
by EPRI now that gives good walkdown guidance. Here are some of the
kind things we look for, here is a good way to organize your activities
related to these things. And it will be used as guidance to the process
of completing the program.
I think that is it. Any questions?
With this we feel confident that we will be able to manage
the problems that were seen by the staff in that whole process of
license renewal.
CHAIRMAN BONACA: Thank you. Any questions? Thank you.
MR. GILL: Jeff Gilreath will come up now and he'll talk
about Vessel Internals. We have a display over to the side.
Do we want to bring that up before here so you can use it
here, Jeff?
MR. GILREATH: People can look at it there.
MR. GILL: Okay. So on the break perhaps we will talk more,
if that is all right, Dr. Bonaca. We do have some backup slides that
will give the details on each specific location. Jeff has been involved
for several years in industry efforts of vessels internals. He is
well-versed in the current activities. They are ongoing, not only at
Duke but also in Anderson.
MR. GILREATH: As Bob said, my name is Jeff Gilreath. I
work in Materials, Mileage and Piping group for nuclear engineering
section.
The purpose of the presentation today is to review how Duke
Power addressed the open items concerning reactor vessel internals.
Directly, there were six open items that we needed to address on certain
reactor vessel internals. One had to do with potential void swelling,
potential changes. The second had to do with potential cracking due to
radiated assisted stress corrosion cracking, radiation embrittlement.
And basically the 3 and 4 materials, reactor vessel internals, the third
had to do with cracking of the baffle former bolts. So there has been
some cracking identified in industry on back about baffle former bolts
to date and the potential effect that could occur in the license renewal
period. The fourth had to do with the embrittlement of cast austenitic
stainless steel. The concern there was that we knew that there was
thermal embrittlement, and we know that there is potential for radiation
embrittlement. But is there any synergistic-type effect and do we have
the material properties to evaluate that.
The fifth had to do with the thermal embrittlement of the
vent value. And that, too, is just that a vent value has a
castaustenitic stainless steel body and it has a retained ream that is a
martensitic stainless steel.
And then the last had to do with the reduction of fractured
toughness of the internals to the radiation embrittlement. Duke
resolved these issues in the end by committing to an inspection plan to
inspect what are the effects of these particular mechanisms, and also to
participate in industry and research and to report our program at it
matures and evolves over the next few years. On slide 34, just to point
out different components of the internals. In the internals, and there
is a picture over here, and even our model, you can look at that later,
it is really made of two sections. It has a plenum area that is removed
when we defuel every outage. In the plenum area assembly there is a
sixty-nine control rod guide tube assembly. Within these control rod
guide tube assemblies, there are actual spacers, ten spacers in each
assembly as of castaustenitic stainless steel. So, therefore, we were
asked to address those components.
Also, there is your core support assembly. Your core
support assembly is actually made up of three components that are bolted
together. You have your support shield. In your support shield area
you have some vent values. Well, we just mentioned vent values. And
also the, on unit three there are outlet nozzles that are castaustenitic
stainless steel.
Then your core barrel assembly. This is really where most
of our focus is, because in the core barrel assembly there is high
levels of radiation. There are the baffle bolts that we've been
addressing. There are also the baffle plates, former plates, your core
barrel itself. So there is a lot of research going on right now
evaluating those components.
And then in your lower internals assembly there, too, in the
encore guide tubes there is a spiral right in this area that is
castaustenitic stainless steel and we will have to evaluate that.
DR. SHACK: Are your baffle bolts 3.04?
MR. GILREATH: Yes, sir.
DR. SHACK: And no coal work?
MR. GILREATH: No coal work.
DR. SHACK: So you are relatively unique that way in B&W
units?
MR. GILREATH: Yes, sir. Which may, actually, you know, we
think we can use that to our advantage because the bolts themselves, you
know, we obviously could remove those in an inspection and do further
studies that would reflect how pretty much the whole internals would be
behaving, because that would be your lead component. And, so, we think
that is going to really help us.
DR. SHACK: It could be more susceptible to swelling, too.
MR. GILREATH: Well, Frank Gardner has mentioned that to us
also, and he is helping us develop a program. He has looked at our
internal design, and a few things about the internals are unique to B&W.
Let me just point those out real quick. This is a backup slide. When
Frank was evaluating -- you know, this is just first shot discussing how
our internals may perform. He noticed that in our baffle plates we have
some holes that are drilled throughout the plates, or bypass flood
holes, pressure relief holes. And also in the plates there are big
slots. And so the deferential pressure against the baffle plate is very
minor, but even to a more concerned with swelling is that the cause of
all the interchange of water and the heating effects are not going to be
as high on these particular bolts and plates as you might see an
internal design does not have all the flow holes. Next slide.
CHAIRMAN BONACA: I have a question. You mentioned before
we got into different -- that is pretty unique to B&W design. And you
mentioned martensitic steel for that?
MR. GILREATH: Well, the vent valve itself, this is a
drawing of the vent valve. The valve body is castaustenitic stainless
steel. Then the retaining wedge here is a 15.4 participate hardening
stainless steel. Those particular items have been known to thermal
embrittle. And so what we want to do is make sure that with -- there is
not much radiation in that area, but it may get to the 10.17th, neutrons
per centimeter square range. So, therefore, we just need to evaluate
how that will effect the toughness of the material.
MR. UHRIG: Will it be a theoretical evaluation or will it
be a measurement?
MR. GILREATH: Well, presently we do an active test on these
valves every outage. We will do an analysis. But in that analysis what
we hope to do is to actually take castaustenitic stainless steel from a
plant that is shutting down that has a high level of radiation on that
component so that we can get some real material properties. Because
today there are not many out there in the industry on this item.
CHAIRMAN BONACA: The reason why I'm asking is that just the
hinges on there. I mean, the valve is supposed to open freely.
MR. GILREATH: Yes. Sure.
CHAIRMAN BONACA: So you have just hinges there. I'm just
not familiar with the size of them, but certainly embrittlement would be
a concern that it could drop
if we had a failure in there.
MR. GILREATH: And that will be evaluated in our program,
and we will be inspecting it. But we do inspect those every outage even
today, the activation.
CHAIRMAN BONACA: That specifically is in your program?
MR. GILREATH: Yes, sir.
CHAIRMAN BONACA: Well, how do you inspect them now, I'm
just
curious. You do push it to see if it opens?
MR. GILREATH: It is a functional inspection. No visual
inspection of cracking or anything.
MR. GILL: There is a visual inspection. They lower a tool
valve and lift it, and they measure the force of lifting.
It is a strobe test, basically. These are considered to be check valves
for Section 11. There are about four, I think, for each internals, for
us eight. But it is unique to B&W design. It is actually a strobe test
that they can visually look at it with a camera sticking in so they can
see physically if there is any other abnormalities you can visually look
at. This is actually replaceable with the jack screws. You can
actually replace the valve itself.
DR. SHACK: Now, you look at it with a camera. Did you
actually do a visual inspection?
MR. GILREATH: Yes.
CHAIRMAN BONACA: Now, you mention martensitic steel for
those hinges. Is there any specific reason why there was a different
kind of material?
MR. GILREATH: Not for the hinges, but for the retainment.
I'm not sure what material it is for the hinge itself.
Mr. Sieber: Well, that would interfere, if it broke off it
would interfere with the vessel wall so you would have damage to the
vessel wall to some minor extent that it would not be floating around
inside the vessel. It would interfere with rod drops.
CHAIRMAN BONACA: No, it would be on the outside.
MR. GILL: You would probably hear it, too.
Mr. Sieber: Probably would.
CHAIRMAN BONACA: Okay, thank you.
MR. GILREATH: Initially, our approach to resolving these
open issues had to do with license and a process. In our reactor vessel
internals aging management program we were evaluating the aging effects
of the internals. We were characterizing those. We were looking to see
if any of these particular mechanisms may effect our internals, trying
to perform an some analysis on critical crack sizes, developing methods
for particular inspections. The NRC raised a concern that most of those
studies, which there are quite a bit -- a few studies are going on, both
at Duke and in the industry -- that most of those studies will be over
the next five or six years. What they were concerned with was what if a
mechanism may not show up until late in the license renewal life, would
you be able to detect that. And so they said why don't you go ahead and
commit to an inspection program that assumes all these mechanisms occur,
and then if you can prove through your evaluations and your analysis
that these, the effects of these mechanisms will not impact the function
of your internals, then you can make a submittal for us to review and
take that particular part of the inspection out of the inspection plan.
And, so that was acceptable to us. So through working with NRC we did
commit to an inspection plan, and basically took the processes that we
were already performing and incorporating them in our inspection plan to
help mature the elements of the plan, like the acceptance criteria, the
method of inspection, things of that nature. We committed to specific
timings. Instead of doing them early in the license renewal life, that
we would do some early. We would do some in the middle and some later
in the license renewal life to assure that we've been able to monitor
any type of aging effect. Also, we would participate with the industry
in doing research and trying to better characterize each aging mechanism
and we would report that to the NRC. And so we agreed we would commit
to an inspection plan, but that inspection plan would mature over the
next five years as we go through our process, and as we go through all
our research. And so the program itself, the elements in the program
will be modified or maturing or evolving over the next few years. As we
get more industry data -- we are doing a lot or research in the industry
-- and also as we perform some of our analysis. If for any reason that
we felt that we could remove any part of the inspection plan, we would
have to make a submittal to the NRC for them to evaluate the basis for
that removal and come to some resolution at that time.
What we came up with in our inspection plan is actually
three inter-related inspections. One had to do with inspecting the
baffle bolts. We would propose performing a volumetric-type inspection
of baffle bolts. There were a lot of aging effects that the baffle bolt
may actually see a cracking due to irradiation assisted stress corrosion
cracking. Reduction of fracture toughness due to irradiation
embrittlement, and dimensional changes due to void swelling. This is an
inspection that we will plan to do early in the license renewal life, in
the middle and in the end. During that inspection as we evaluate how we
might utilize some of those bolts, we may be removing some of those for
further analysis.
We committed to a, we expect our castaustenitic stainless
steel inspection will assist with some type of visual, one type of
visual about the enhanced DT-1 or DT-3. What we are going to do is
perform an analysis, and first we've got to come up with some material
property data. Once we do that we are going to perform an analysis,
come up with a critical crack size, and at that time we will be able to
determine what method we want to use for an inspection.
With the other components in the internals there are quite a
few; the baffle plates, the former plates, the core barrel bolts,
different components. We have planned to perform a visual inspection of
all the other items, and also in this area we will be looking at
material properties of three or four different plates, for instance.
That will be critical crack sizes, so that we can determine what size
crack would effect the function of the internals and develop our
inspection program around that.
We will probably be using some of the baffle bolts to lead
items on potential change and to avoid swelling, but that could change
once we do an evaluation. We are really where the gamma heating effect
is. Apparently, the gamma heating effect and irradiation are the two
concerns that need to be addressed with swelling.
We've got an ongoing program right now with our core barrel
bolts and thermal shield bolts that we have done volumetric exams in the
past. We are doing visuals now every outage. We've got a program in a
BWOG that is evaluating what would be the best method of inspection in
the future. We are kind of waiting for the deliverable there from BWOG
to determine exactly how we'll inspect those bolts.
DR. SHACK: What is your dose map look like? How much of
this core is really in a kind of a high EPA state, kind of a radiation
system track point of view?
MR. GILREATH: Let me see if I have a backup slide for that.
In the area of the fuel itself the dose rates, or the accumulated
affluence are pretty high. They can see as high as 10 to the 23rd
neutrons per centimeter square. But it falls off pretty quick. The
core barrel itself, I think, is more like 5 times 10 to the 21st.
That's a ballpark number. I'm not quite sure about that core barrel.
We knew that if we could get the lead component, three or four material,
developing an inspection planned around the lead components we will be
able to pretty much map out the effect to the whole internals.
DR. SHACK: Where do you say go below 10 to the 21? How
high up would you have to go?
MR. GILREATH: The map that I've seen, basically, they do
not go -- we do not have maps that go up into the plenum area.
Therefore, you know, we were wanting to be able to say, for instance,
the spacers may be below 10 to the 20th, and wouldn't be concerned of
radiation embrittlement, but there are some people that believe even
though you may be below that particular threshold, is there a
synergistic effect. So, what if you only have 10 to the 18 neutrons per
centimeter square, will that, coupled with thermal embrittlement, effect
the spacers. So we do not have maps right now that go up real high into
the upper internal, but here it is pretty even across the core. This
area would be like 10 to the 21st, and come all the way down to the 10
to the 23rd, and then come back off 10 to the 21st, 10 to the 20th, in
that rank. So, pretty much the length of the core you are going to have
maximum affluence.
As I have mentioned before, instead of committing to one
inspection, we have committed actually a minimum of three inspections.
One, early in the license renewal period. The second one would be in
the middle. The third would be in the third period of license renewal
period. However, it would be prior to our last year of operation. We
expect that this particular program, we'll be able to utilize it for
other plants that have the radiations out that far. So, you know, we
are pretty much committed to this inspection plan.
I just want to mention a little bit -- I don't know how much
you know about all that industry is doing in this area, but we have
committed to participate with the industry. Primarily, a B&W owners
group has a reactor vessel internals aging management program with quite
a few elements in it looking at Oconee specific, or the B&W specific
internals, and we are going to be utilizing a lot of the programs coming
out of there. To give you just an idea of that schedule, just an idea
of some of the tasks we are doing, we are doing studies on swelling and
gas. Pretty much everything we've discussed today, the B&W owners group
is addressing. We have a five year plan to come up and to evolve or
mature all the elements in the inspection program, utilizing industry
data. So at a particular time we will be submitting a program to the
NRC for review before at least two years prior to our first inspection.
Also, we are working with other groups. EPRI has a large
group, material liability program issues task group. In that group
we've got some of the same elements and other elements working with the
whole industry and addressing or trying to characterize the aging
effect. And, two, the job program, or joint baffle bolt task team.
That's a program that went out and looked at the international programs,
tried to find out where we thought the most work was being performed.
We found EDF with a very large program. And so we are funding some of
that work and we've submitted our materials also to be integrated with
their program. And just in the job itself there are over a hundred and
forty deliverables that are already part of the contract.
The reports I mentioned, our first report to the NRC was the
topical report, BAW-2248, that addressed the effects of reactor vessel
internals. We just received a SER on that in December.
Other reports that we are committed to, as our program
evolves we are going to submit reports to the NRC every time we complete
a significant milestone for review. And then our first report will go
in within one year of receiving a license. Then our last report will be
two years prior to our first inspection, when we will have all our
inspection methods resolved or committed to and what the acceptance
criteria will be, things of that nature.
Are there any other questions?
CHAIRMAN BONACA: I understand you have to report to the NRC
and the two years, it will be two years before the end of the current
cycle.
MR. GILREATH: The first report will be within one year of
receiving a license for licensing, for extended license.
MR. GILL: Sometime next year.
MR. GILREATH: Sometime next year. And then our last or
final report will be two years prior to our first inspection. So it
will be pretty much when license renewal begins, that period.
CHAIRMAN BONACA: And that report, focusing on that one,
that one will really contain much of the detail that you are going to
gain from all the activities you have with EPRI, and with the ---
MR. GILREATH: Yes. It is really essential that we get that
material property data, and we will be submitting that to NRC. As a
matter of fact, we are going to Washington in April to go over the whole
industry program with the NRC, the EPRI program, the BWOG program, and
others.
CHAIRMAN BONACA: It will be interesting because there is a
lot of activity going on. Okay, thank you. We are running a few
minutes ahead of time. We can take a break now.
MR. GILL: That concludes our morning presentation.
[Recess.]
CHAIRMAN BONACA: Okay. So let's resume the meeting, and we
have representation from the staff now regarding the SER and the closure
of the open items.
MR. GRIMES: Thank you, Dr. Bonaca. My name is Chris
Grimes. I'm the Chief of the License Renewal & Standardization Branch.
And by way of introducing Joe Sebrosky, who is the Project Manager for
the Oconee License Renewal Application. I would like to compliment the
committee on holding a meeting here at Oconee, providing an opportunity
for more access by the interested public, and also bringing the renewal
activities to the site so that the plant people can see the licensing
process. I think that is a good move on the Committee's part, and we
will plan for that for future renewals.
With that, Joe is going to go through and present the
staff's presentation and we are prepared to respond to any questions
that you have about the staff's safety evaluation basis.
MR. SEBROSKY: Good morning, my name is Joe Sebrosky. I'm
the project manager for the safety review for the Oconee License Renewal
Application. I would just like to point out that we have several
members of the staff in Washington that are standing by to support the
meeting. They have copies of the slides. So, I am going to be calling
out the slide numbers just so they can keep abreast of where we are at.
As far as the presentation, I'd like to just give you a
brief overview of where we were and where we are at right now regarding
the safety review aspect of the license renewal application. And then
discuss the resolution of the open and confirmatory items, some
discussions that were added to Oconee SER since the last version was
published in June of '99. And then a summary of the license renewal
application review activities that are to be completed before Duke gets
its renewed license.
The last time we made a presentation to the subcommittee was
based on a June 16th, 1999 version of the SER. We had a meeting with
the ACRS Subcommittee over two days on June 30th and July 1st, and we
also interacted with the full committee on September 1st. Since that
time we provided the ACRS with an update to the SER on February 3rd of
this year.
The February 3rd version of the SER contains several updates
to the June version of the SER. Specifically, it closed the open and
confirmatory items contained in the June version of the SER. There were
forty-three open items and six confirmatory items that were closed in
the February 3rd version. There were also new evaluations that were
added due to license renewal application update or because of a Duke
response to an SER open item. I'll point those out towards the end of
the meeting, specifically what added evaluations were put into the SER
as a result of those.
And, finally, we did make changes to the SER based on
technical comments that we received from Duke. Back in October when
they provided the responses to the SER open items they also gave us
technical comments that resulted in some changes.
On to slide five. I'd like to -- we are modeling this
presentation over the presentation that we gave to the ACRS for Calvert
Cliffs. And, specifically what we are doing is we are breaking down the
open items based on the division responsibilities within the Nuclear
Regulatory Commission.
There are four divisions that were involved in the review of
the license renewal application. The division that I'm in, which is
Regulatory Improvement Programs, the Division of Inspection Program
Management, Division of Systems, Safety Analysis, and finally, the
Division of Engineering.
For the Division of Engineering open items, since they
had the majority of the review, I've actually, we've broken those items
up into the respective branches. And as far as going through the
presentation for each of these divisions, what we tried to do was tell
you what the top issues were, and then also have a discussion of all the
other open items. Doctor Bonaca, Noel indicated to me that you may have
some questions that may not necessarily be in the top issues. I'll try
to call those out when we come to those slides.
As far as the top issue that was resolved within my
division, that was, we had an open item regarding the content of the
UFSAR. That was open item 3.0-1. Currently right now we are in the
process of reviewing Duke's draft UFSAR supplement that they have
updated because of the SER and because of changes that have been made to
the application as a result of the review. We intend to have that
review completed and reach an agreement on the UFSAR supplement before
we go forward with the commission recommendation.
So, the basis for the resolution was basically that the
staff would review the detail content of the UFSAR supplement, and prior
to going forth with commission recommendation agree on a resolution.
MR. GRIMES: I would like to add to that. Since we issued
the draft revised UFSAR supplement to the staff, along with guidance
explaining what the content changes are, pursuant to 57.1E, and the
guidance that has been developed and relative to changes in 50.59, so
that the staff would be able to view the contents of the UFSAR in the
context of the regulatory process that is going to maintain the
licensing basis in the future. And any issues that stem from the
staff's review of the UFSAR supplement, we would intend on identifying
and tracking in the same way that we identified and tracked resolution
of open items in the UFSAR itself.
MR. SEBROSKY: The next division was the division of
inspection program management. The branch within that division that was
involved with the review was the quality assurance branch. They were
the lead on the scoping issue that was discussed this morning with Duke,
and also on several other items.
This slide, just on a high level, provides an overview on
the basis for the resolution of the open item, and it reiterates what
Duke presented this morning, the fact that we asked them to look at ten
additional events, and based on them not identifying any additional
systems, structures or components, we felt comfortable and it gave us a
reasonable assurance that the scoping was done properly.
CHAIRMAN BONACA: On a genetic basis, but we are talking
about the SOP, etc. It is better for the older plants in need of being
more specific than just -- I'm not sure that 50.54 specifically felt
this is all Chapter 15.
MR. SEBROSKY: We don't, we didn't agree with the view that
design basis events. It says narrow as the way that Duke explained that
they maintained the licensing basis. But we do agree that the end
result, by virtue of the overlapping scoping techniques, captured all of
the necessary systems, structures and components that are relied upon to
prevent or mitigate events that are described in the licensing basis.
That is how we selected the ten additional events to evaluate. And I
would expect that we would take that experience and feed it back into
improved guidance for the standard review plan, and possibly even we can
work something out with the industry group, guidance for the industry
guide 95.10 that would explain how to review plant capabilities in a
broader way.
I'd also mention that after the generic aging lessons
learned, an SRP update, we have a commitment to the Commission to the
consider rule-making, and I would expect that if there is an opportunity
for us to clarify the language in part 54 that describes scoping, to
make it more consistent with the evolving design basis description under
50.2., and the other language that describes design basis events. And
50.49, for environmental qualification. And the maintenance rule.
There's a maintenance rule workshop that was just held two days ago. As
all that experience comes together it is conceivable that we can clarify
that the expectations for future renewal applicants.
CHAIRMAN BONACA: Good.
DR. SHACK: Does the latest revision of 95.10 incorporating
this? I mean, would you expect to see the future applications
discussion?
MR. SEBROSKY: 95.10 addresses scoping and addresses
methodology, but to the extent that it doesn't get into this what is a
design basis event, and how is the definition of current licensing basis
in part 54 intended to be applied to a current licensing basis, that is
still an area where these other activities going on in 50.2 with the
industry. There is guidance there. There is guidance for 50.59. There
is guidance for the maintenance rule. All of those things sort of
surround this thing. If we could bring some more focus to it, I think
that would make the process more efficient and predictable in the
future.
Go on to other issues that were resolved for the quality
assurance branch under slide number eight. We did have an open item
relative to the corrective action for non-safety related systems. The
resolution for that is basically the UFSAR supplement. Duke is
identifying under one of their attributes corrective actions,
specifically what process will apply to both safety related and
non-safety related systems.
I'd like to move on to DSSA, which is slide nine.
Basically, as far as the top issues go within this division, they are
the division that did the scoping. The systems groups looked at the
scoping to make sure that the boundaries were appropriate, and also
challenging in some cases whether or not systems should be within scope.
The top issues that I identified for the division were
the ones that added additional system structures of components. We had
three open items that did that. There was the -- we challenged the
chill water system, which is the heat sync for the control. As a result
of that Duke scoped that in and we reviewed that, performed an Aging
Management Review. So you will see added discussions both within
Chapter 2 of the SER, and also within Chapter 3 where we asked the
Division of Engineering to look at the Aging Management Review for
that.
Also, the other two open items were associated with the
ventilation sealant material, and one was with the passive long-lived
equipment excluded from AMR. If you go back to the tour that the ACRS
took yesterday of the standby-shut down facility, this one issue dealt
with skid-mounted equipment, which the diesel was considered to be
skid-mounted equipment. The question that the staff had was were the
boundaries that Duke originally drew appropriate. When they drew those
boundaries, skid-mounted equipment, like some of the heat exchanges that
were on the skid were excluded from an aging management review. We
didn't agree with that. We challenged that. Duke subsequent to the
initial application provided aging management review from its
components.
And lastly, under one of the top issues that was resolved
for DSSA, there was an issue that came up late in the Calvert Cliffs
review regarding ECCS piping insulation and whether or not that should
be within scope. The staff asked a question about that and Duke gave us
justification for their design as to why the piping insulation, they did
not need that to meet any of the criteria in 54.4A1, A2 or A3. We
agreed with that, but there was an additional evaluation and exchange of
information that was done. You also see that in the SER.
MR. GRIMES: I would like to clarify. That was
insulation on 4A water system piping and whether or not the insulation
was necessary in order to insure that the sufficient statement and
solution. So it wasn't insulation in a broader context, it was for that
specific functional capability.
MR. SEBROSKY: The next slide is other issues that we
resolved within DSSA. I didn't plan on talking about each one, but
there was one, Dr. Bonaca, that you had indicated some interest in, and
that was on the recirculated cooling water system, which is the heat
sync for the spent fuel pool. We have the staff available if you have
any questions about that.
CHAIRMAN BONACA: No. I think with the review of yesterday
in the afternoon, I think that we recognized that what you did, which
really is not part of the licensing basis, the current licensing basis
for the plant. We still have questions regarding the loss of spent fuel
cooling event as a basis for the pool. Clearly it is not the basis for
cooling. We heard that the makeup water system is circulated. It can
be used to make up water in case the cooling system is lost. That was
the basis for your cooling, I believe. I believe that the membership
accepted that yesterday as recognizing that as a means of cooling the
pool and making up the water.
DR. POWERS: I guess I would characterize the members have
heard that. I would characterize it as saying the members heard that.
CHAIRMAN BONACA: Yeah.
DR. POWERS: I wouldn't say that there was any endorsement.
CHAIRMAN BONACA: True. True.
MR. SEBROSKY: But I would also like to add that was one of
the areas that we explored very carefully in making sure that we
understood what the licensing basis was. And we did consider it very
carefully, and DSSA affirmed that was the way that a number of plants
are currently designed and licensed. We considered whether or not there
were any risk insights that warranted pursuing that separate from
licensing. Mr. Gratton explained in the conference call that we had
that their understanding of the licensing basis were prepared to pursue
that separately with the ACRS if you like.
CHAIRMAN BONACA: Before you move that, I had a question
regarding the open item 2.2.3.7-2 regarding active equipment in storage,
if I remember. I understand that you agreed not to include that
equipment in scope. I personally agreed with that. The only question I
have is that because Duke said that they are routinely inspecting and
testing their equipment, so therefore it is maintained in a way that --
but it seems to me that in any event the equipment is being inspected,
tested, installed and then tested when it is installed anyway. Why
would you consider possibly in scope? I'm trying to understand, you
know, for example, how will you address this issue? Do you still have a
requirement that this be ---
MR. SEBROSKY: The way that the issue came up was that there
was equipment that is warehoused that has passive elements, and whether
or not the passive features of that equipment need to be managed while
over time because the aging effects are the same whether or not the
equipment is being used or in storage. It is more the process by which
the equipment that is taken out of storage and then put into service is
verified as suitable for service that provides us with a process
assurance that if there are any applicable aging effects, if they are
not managed or at least checked before the equipment is put in and then
subjected to the routine inspection program. So, that's the way the
issue started to evolve. It was, well, do we need to have an aging
management program for this equipment while it is in storage. And we
concluded that by virtue of the process that certifies spare parts for
use, that provided sufficient assurance that if there were any aging
effects they would be identified and then checked before the equipment
is actually put into service.
CHAIRMAN BONACA: Yeah, that point I made, I totally agreed
with that, with the conclusions that you made regarding that. I just
believed that those conclusions are pretty genetic because the process
is by which the utilities install the spare parts. It is very similar.
You have to set the specific requirements and go through, which would
include the inspection and the testing, and then selection testing.
MR. SEBROSKY: The reason that the issue came up for Oconee
is if you look at the scoping criteria one of the criteria is regulated
events, 54.4A3. There is an appendix R. As you noted yesterday on the
tour, Oconee has some unique features. For example, the turbine
building, that's where the emergency feed water pumps are located. They
are not located in the ox building, so there is a vulnerability to a
fire in the turbine building. That's why they added, one of the reasons
they added the standby shut down facility. So, when you go their
Appendix R requirements, they rely on a lot of cabling that is in
storage. Also pumps and breakers that are in storage to help recover
from a fire in the turbine building. The staff looked at that and they
noted that Duke had looked at the passive components, the cables, and
did an aging management review and determined that the cables were in a
benign environment. But we asked about the active components, and
that was the reason for that open item.
So, it is somewhat related to the unique nature of Oconee's
licensing basis. That is why the question was asked.
MR. GRIMES: I'm sorry, I didn't respond to your specific
question. Yes, I would expect to add guidance in the standard review
plan that explains why we do not need to be concerned about aging
management programs for equipment that's in storage.
CHAIRMAN BONACA: Okay. Good.
MR. SEBROSKY: I guess as far as the top issues, I'd like to
move to the Division of Engineering. We've broken it down by branch
here. For the materials in the Chemical Engineering branch, the top
issues that we identified for this branch, if you go to slide 11, are
those associated with the reactor vessel internals. And if you go back
to Duke's slides this morning, this slide is consistent with that as far
as the open items that were associated with the internals.
Are there any questions that the ACRS members have of the
staff?
CHAIRMAN BONACA: I think that we saw a very comprehensive
program that addresses a lot of the issues from the swelling to others.
MR. SEBROSKY: The first issue on the next slide, slide
twelve, really involves a reactor vessel internals component. Again,
that was talked about this morning. That's the vent valve bodies,
internal reactor vessel.
The next set of open items dealt with CASS components.
Finally, there was a new issue, this 3.4, 3.3-9 that was added after the
SER was written in June, and that had to deal with reactor vessel
monitoring line. The staff questioned whether or not that needed an
aging management review. Are there any questions on that?
As far as other issues that were in this branch, they had
the majority of the open items. There are several items on this slide,
Dr. Bonaca, that Noel has indicated to me that you might have questions
about specifically on the pressurizer heater sheath-to-sleeve plate,
open item 3.4.3.3-2. The buried piping, the standby shut down facility
HVAC coolers, and the standby shut down facility heat exchanges.
CHAIRMAN BONACA: Yes. I had some questions on the
pressurizer heater, we discussed it yesterday with the applicant. I
understood, the question was more relating to the nature of the one time
inspection where you would not have an inspection unless you have a
failure to the heater, so I thought that we had characterized one time
inspections somewhat differently. Essentially, the inspection that you
performed to get a confirmation that in effect is not occurring. Or if
it is occurring it is a benign factor. And, so, you know, that was more
of a clarification than anything else that we got from the applicant.
Everything was fine with that.
On buried piping, the questions I have was in several
instances, two instances on this. All the inspections for the buried
piping of the Kewanee facilities are not really done there. I mean,
they are referring to the inspections at Oconee as being indicators of
the aging management at the Keowee facility. The reason is that the
materials used supposedly are the same between Keowee facility and
Oconee facility. I had some questions about two things. One, the
environment. It is, in any case did you look at the differences in
environment and possible aging effects resulting from it. And second,
the Keowee facility was not really under Appendix B program until now.
And so, therefore, there maybe -- do you have enough records to say
that, yes, you have the same material, the same conditions, and
therefore the inspections that would be for Oconee are also indicative
of the conditions you would find at Keowee?
MR. SEBROSKY: I guess our lead reviewer, and I'm hoping he
is on the phone, was Jim Davis. Are you there?
Mr. Davis (via telephone.): Yeah, I'm here.
MR. SEBROSKY: Jim, I was hoping that you could respond to
Dr. Bonaca's questions.
Mr. Davis: Well, basically, what they are concerned with is
the soil corrosion of a pipe, and with carbon alloy steel you don't see
much difference in corrosion rate. Basically what they are doing is
they are doing an internal inspection, eleven foot diameter pipes, which
counts for about eighty percent of the piping that they have. That's
not the recommended way to do things, but we found it acceptable. If
there was an oil or gas line, it would be totally unacceptable.
The downside is it is going to cost them a lot of money when
they see a leak because they are going to have to replace all that
piping, probably. But that is their decision to make. They are
inspecting eighty percent of the pipe. I see no difference in the, or
significant difference in the corrosion rate from soil anywhere that you
have buried pipe.
MR. GRIMES: And, Jim, correct me if I misstate this, but I
think that the way that you described that we would say they were not
relying so much on the identical nature of the piping, but more that the
inspections that they have provide a bounding circumstance by which any
indication would cause them to go look at the effected piping and, as
Jim points out, if they find a problem then they are going to do a lot
more digging than if they had a more focused inspection activity because
of the benign, relatively benign nature and the expectation that they
are not going to see a problem, this constitutes sort of a bounding
approach to be issued.
DR. POWERS: It would be interesting to see the data that
suggests that the carbon steel piping corrosion is fairly independent to
details of soil conditions.
Mr. Davis: Typically, you know the NBS in the old days and
this now did a very detailed study of corrosion in soils of steel or
alloy steel. They found that the average life is twenty-eight years.
This pipe is coated, but it is not cathodically protected, which
normally would make it worse. If you are not going to cathodically
protect it, you should leave it bare, and then after thirty years
replace it all. If you cathodically protect it is good forever. So,
I'm not quite sure what there logic is of not cathodically protecting
it. But basically, once they see problems they are going to have
problems everywhere. They are just going to have to go in and deal with
it.
DR. POWERS: I guess we would be interested not just in the
average life time, but the variable around that average.
Mr. Davis: It all depends. It depends on a lot of things.
If you find a section of pipe that corrodes through, and you replace
that section of pipe, the new pipe will last about six months, because
it acts as an anode and cathodically protects the rest of the pipe. So,
you get into a real serious problem if you don't use good engineering
practice, which a lot of the nuclear industry doesn't, and that piping
is not under, there are no rules or regulations to control it. But if
they see problems they are going to have to go in and look at all their
pipe.
DR. POWERS: I guess I'm more interested in the data that
led to your conclusion, that there was a fair insensitivity to this type
environment.
Mr. Davis: It is kind of hard to predict. The variance
probably plus or minus ten years, their soil is pretty benign. They
could do a soil conductivity measurement, and that would give them a
good indication of how corrosive it is. Usually if it is a high
resistivity, five thousand centimeters, then the soil is not considered
to be very corrosive. But if it is a lower resistance then it is
considered to be very corrosive. The program that they propose to go in
and inspect periodically, they are going to find leaks if they have any,
or depending on the inspection time it takes.
MR. GRIMES: Jim, did you mention where those studies are
found?
Mr. Davis: Yeah. They are NBS and the National Institute
Science and Technology did the big studies.
MR. GRIMES: The National Institute of Standards and
Technologies?
Mr. Davis: Yeah. It used to be the NBS when they did
the -- but, you know, and the type of soil they've got
there, I would expect it to be close to a thirty year life.
CHAIRMAN BONACA: You also made a statement before that I
don't understand the answer. You said that you would be concerned if in
fact the environment was not water, but oil or gas.
Mr. Davis: If you have oil and gas pipelines, that falls
under Title 49 of the Code of Federal Regulations, and it says, "If you
bury a pipe and you've got oil or gas in it, you must coat it and you
must cathodically protect it, and then you must monitor it using pipe to
soil potential measurements like Calvert Cliffs does.
Oconee has chosen not to do that.
DR. SHACK: But then Oconee is not transporting oil or gas
interstate through cities and ---
Mr. Davis: Yeah. And they are not required by law to do
it. If they want to replace their pipe every thirty years they have the
right to do that.
CHAIRMAN BONACA: I understand. Okay. Thank you.
DR. SHACK: I guess the other argument is you don't really
expect the soil to be terribly different at Oconee and Keowee, so
whether it is average soil or not, there doesn't seem to be a reason to
believe it is terribly different.
Mr. Davis: That's right. You normally expect the higher
corrosion rates if you have brackish water or something like that. That
is not the case for Oconee, so you wouldn't expect to have a very
corrosive soil there.
DR. POWERS: I'm going to have to comment on the technical
basis for the staff's decision, and I just don't understand the
technical basis for this. I guess I understand the technical rationale,
I just don't see the data. As far as the variability of soils I think I
can see places where soils vary dramatically over the course of a few
feet. I don't know whether that's the case here. I don't have enough
information on the site to ---
Mr. Davis: Normally you would expect to see large
variations. What we are relying on here is that they are inspecting
eighty percent of a total surface area of the pipe on a regular basis.
If they have a problem, they will detect it.
MR. GRIMES: And take appropriate corrective action.
Mr. Davis: Right.
MR. GRIMES: But we can provide the, we can provide the NIST
reference, the N-I-S-T references, in terms of the data that lists the
variability of corrosion for buried pipe. But otherwise our technical
basis is based on inspection and corrective action, not necessarily
managing the aging effects that are applicable to the buried surfaces of
the piping.
DR. POWERS: I think this gives us an opportunity to
highlight before the Commission the approach that is adopted here.
I think it is an opportunity for us to point out to the
Commission that the approach is here. Okay, they've taken the strategy,
the strategy will work, because if they find a problem they will have to
dig and replace things. You've got some confidence that there is
detection because they are doing eighty percent of the tech things, and
the other twenty percent we think is much like the remaining eighty
percent. But I think we have to have an understanding of the technical
rationale for that. We have to see the technical rationale. If it is
an engineering guess, that's an engineering guess. If it is based on a
careful analysis, it is based on a careful analysis. It is just a
matter for us to point it out to the Commission.
CHAIRMAN BONACA: Well, actually we are hearing that they
are going to inspect and if there are problems they are going to fix
them. That's pretty much what I hear. The other issue, you know, it is
more regarding the bounding of all systems of the Keowee from Oconee
systems.
And that ---
DR. POWERS: But it is not a random eighty percent they are
inspecting.
CHAIRMAN BONACA: That's right. It's ---
DR. POWERS: It is a distinctly unrandomed eighty percent.
CHAIRMAN BONACA: Right. So that would be right.
MR. SEBROSKY: Well, I'd just point out on this slide,
before we leave this slide, there were two other items, 3.2.12-1 and
3.2.12-2.
CHAIRMAN BONACA: I had a couple questions of this. One was
for the SSF HVAC coolers. You had a question regarding the need for
providing both floor measurements and measurement to assess if there was
any measure of loss of material, for example, that would effect the
changes. I believe the resolution was that the frequency of testing is
such that the flow measurement can be relied upon to detect if there is
any change. I didn't understand. There was no specific explanation in
the SER why lack of identity allows you to get that assessment and the
field loss.
MR. SEBROSKY: Our reviewer for that is Stephanie Coffin.
Stephanie, are you there?
Ms. Coffin (via telephone.): Yes, I'm here.
MR. SEBROSKY: And did you hear Dr. Bonaca's question?
Ms. Coffin: Yes, I did. The answer is they do measure
across those heat exchanges. Not as part of their, in response to open
item what they propose with the new preventive maintenance activity that
we reference in closing out this open item. And in that PM activity
they do measure it across the heat exchangers.
CHAIRMAN BONACA: Okay. That is not what is documented in
the SER, but that is fine. So I'll take it as the answer to this
question. And I had one more question regarding the 3.2.13-2. That's
where carbon steel inspection indicate, a user indicator of conditions
of known carbon steel components. And the specific question was that
the carbon steel inspections are used as lead indicator of conditions
such as, for example, a MIC attack. Or other that it may cause pitting.
And the position was that this type of corrosion does not effect the
destruction of any of the components. Okay, if you have a MIC attack
you typically have a pin hole leak and therefore you can't identify it
ahead of time. I wanted to hear more about that, because for my limited
experience with MIC attack, I've seen pipes literally devoured inside by
MIC attack. There was a pin hole leak, but the pipe was ready to go.
And maybe even in a more -- so I would like to hear the technical phases
for concluded that this is a --
MR. SEBROSKY: And Stephanie before you give the answer I
guess I just wanted to make sure I -- that, if I understand correctly,
it is actually on slide fourteen, and the question that you have is on
3.2.13-2, correct?
CHAIRMAN BONACA: Yes.
MR. SEBROSKY: I think I had the wrong slide up. Stephanie,
did you understand the question?
Ms. Coffin: Yes, I did. The basis for closing out this
open item was Oconee's operating experience with their service water
system. They have been doing these inspections for close on twenty
years now, and they have not found any, not had to replace any kind of
piping due to corrosion concerns. They haven't documented any
indications of problems with MIC, or very localized degradation with
problems that they've seen in their service water piping is general
corrosion for the techniques they are applying are acceptable. That
doesn't mean that this isn't a concern to the staff, and what the
licensee, and the licensee recognized that and they committed to
following more closely the results of those service water inspections as
well as other, say, specific materials to document any times that they
have a degradation due to a localized corrosion phenomena and consider
its relevance to the service water, service water piping inspection and
factor that into how they are approaching maintaining the integrity of
their service water piping.
MR. GRIMES: Another way I would put that is, the general,
the inspection activities associated with general corrosion and plant
conditions will identify if MIC becomes a concern in the future, or any
other aging effect for which there hasn't been any present evidence
warranting a specific aging management program. So it goes beyond just
a particular concern about microbiologically induced corrosion. I
thought I'd say what MIC is, because you have to say it so slowly. So
in that sense this conclusion is very general for us. If there hasn't
been any evidence of a particular aging effect, we still rely on the
general programs to reveal and deal with any evidence if it occurs in
the future.
MR. SEBROSKY: We've actually moved onto slide fourteen.
There weren't any other questions that I noted on slide thirteen. But
since we've moved onto a new slide, Dr. Bonaca, Noel indicated to me
that there was also a question that you had regarding 3.2.13-3 on the
relationship of the program to Keowee, and also on 3.2.13-4 on the UT
inspection capability, located degradation.
CHAIRMAN BONACA: Yes. The first one we already discussed.
That was related to the same question that we had before, relationship
between inspection for Oconee and Keowee. And the other one ---
MR. SEBROSKY: I guess the question that I had from Noel was
regarding 3.2.13-4 is, "What is the staff's basis for finding the
applicant's justification acceptable?" Some localized degradation
mechanisms may not be bounded by inspection for general corrosion and
may result in pipe failure.
CHAIRMAN BONACA: Yes. That was UT test, which are not very
effective to identify. That was the point I had. There are none, as
far as I understand it, where you are effectively localizing,
identifying localized pitting, and microbiologically induced corrosion.
And so I would like to hear more about that.
MR. SEBROSKY: Again, the reviewer for this open item is
Stephanie Coffin. So, Stephanie, if you could respond to that.
Ms. Coffin: The reason why open item 3.2.13-4 is related to
closing out 3.2.13-2 and because the staff accepted that general
corrosion with the limiting degradation note for this service water
piping, UT is an acceptable technique to use. If they have to change
their program in response to finding the localized pitting or mix, they
have committed to changing their techniques to use one that is qualified
for the application, which means it won't be UT, it will probably be a
visual inspection. I can't think of what much else you could use. I
don't know if you heard, did you hear what Jim Davis ---
MR. SEBROSKY: No, we did not hear what Jim said.
Ms. Coffin: Jim also pointed out that they also have their
heat exchanger performance testing, which would also tell
you that you may have a MIC problem because you would getting fouling.
So that is sort of a secondary measure in place to let you know that may
be of a concern in your plan.
MR. SEBROSKY: The rest, if that answers your question, the
rest of these open items on this slide dealt with TLAA's and some --
TLAA's being Time Limited Aging Analysis -- and also some confirmatory
items. Were there any questions on those? I didn't note any. On the
ones that are left on the slide, Dr. Bonaca, I didn't note any that Noel
indicated. As a matter of fact, I believe that of all the questions
that Noel forwarded to me that we addressed all the items.
CHAIRMAN BONACA: But I have more.
MR. SEBROSKY: I understand. I understand. I guess, moving
on, the next group is the mechanical engineering branch within the
Division of Engineering on slide fifteen. Our reviewer for this was
John Fair, and I'll just give a high level overview and then ask John to
address the specifics. John, are you there?
Mr. Fair (via telephone.): Yes, I'm here.
MR. SEBROSKY: And basically, I guess, what I wanted to say
as a high level overview is we presented three options to Duke, and they
chose an option that is a plant specific option, similar to what Calvert
Cliffs chose. So the resolution for Calvert Cliffs and Oconee for this
issue are the same. And, John, is there anything that you wanted to
add?
MR. FAIR: The only thing I wanted to add is that the
resolution for both Calvert Cliffs and for Oconee is consistent with the
recommendation that came in on GSI-190, which was to do something to
monitor the effects of fatigue cracking due to environmental concerns.
So it is consistent with the GSI-190 resolution.
CHAIRMAN BONACA: Did Duke use the same locations for
monitoring that the GA used? I know they identified them from the regs
60-260 or so. That's fine by me.
MR. SEBROSKY: John, did you hear the question?
MR. FAIR: Yes, I did. They are essentially the same as
were used by Calvert Cliffs, and the ones from Duke are out as new regs
60-260. Several of the new regs 60-260 locations were addressed in the
topical report on the vessel. And the remaining ones that weren't
addressed by the topical report on the vessel, Duke is going to evaluate
the GSI-190.
CHAIRMAN BONACA: Okay, and that is responsive to the
recommendation that you are giving on the closure?
MR. FAIR: That's correct.
MR. SEBROSKY: Were there any other questions on that?
CHAIRMAN BONACA: No questions.
MR. SEBROSKY: As far as the rest of the issues that were in
this branch, there weren't any that were identified to me before hand.
The issues that we had open items on were: containment tendon
anchorages; letdown cooler thermal fatigue; aging effects of HVAC
sub-components; the reactor coolant pump oil tank inspection plan; spent
fuel pool temperature. And then we also had several related to
structures and the secondary shield wall. Were there any questions
about how those were dispositioned?
CHAIRMAN BONACA: No. We discussed the secondary shield
wall yesterday, the pre-stressing tendons, that the aging issues that
are different than the ones for the containment.
MR. SEBROSKY: That's correct.
CHAIRMAN BONACA: And it was explained to us that the
program that is being utilized to manage the tendons in containment is
different from the one for the shield wall. But it seems to be like a
comprehensive problem, also the one for the secondary shield wall.
MR. SEBROSKY: And, finally, slide seventeen finishes up the
issues that are within this branch. These relate, again, to time
limited aging analysis, and also some confirmatory items that we had.
Were there any questions on that?
CHAIRMAN BONACA: Yeah. There was a time-limited aging
analysis to do with the tendons, right? But they have chosen not to
just before the inspection, so that is why they are gone? And that
closes the whole issue?
MR. SEBROSKY: Hans -- yeah -- our reviewer on that is Hans
Ashar. Hans, are you there?
Mr. Ashar (via telephone.): Yes, I am here.
MR. SEBROSKY: Did you have any comments on Dr. Bonaca's
observation?
Mr. Ashar: No, I think his observation is correct. We had
hoped to have enough data that can provide a tendon drain line based on
the previous data, and the drain line so that the forces are good enough
for sixty years. But in the case of Oconee, that was not possible
because they did not have random sampling data earlier. So they chose a
management program. They are going to comply with the regulations
regarding the drain line and not meeting the second requirement in the
drain line requirement.
CHAIRMAN BONACA: I understand now they've gone from
sampling the same nine tendons to sampling random samples?
Mr. Ashar: That is correct. Yeah. That is correct and
they are going to implement a subsection item for section 11, a project
tendon inspections.
MR. SEBROSKY: If there aren't any more questions on slide
seventeen I'll go ahead and move to slide eighteen. This is in our
Electrical and INC branch within the Division of Engineering. Paul
Colaianni gave a discussion on it this morning. The issue was actually
added as a result of an inspection. Caudle Julian and Vic McCree from
region two are here. And as a result of the second inspection, they
identified that there were aging effects with the cabling. As a result
of that we added an open item. Duke gave us an aging management program
that we reviewed and found acceptable.
Our lead reviewer on that is Paul Shemanski.
Paul, are you there?
Mr. Shemanski (via telephone.): Yes, I'm here, Joe.
MR. SEBROSKY: Was there anything that you wanted to add to
that discussion?
Mr. Shemanski: No, not really. I thought Paul Colaianni
gave a
pretty good description of the overall program. I guess the
only thing I would like to point out though is that this is a new
program for Duke. When the application came in they identified
basically three potential aging effects; radiation, thermal and
moisture. In the application they concluded that none of these were
basically applicable aging effects. And as a result of our inspection
we found some evidence that the staff felt, you know, we recommended or
felt we needed an aging management program for cables. Subsequently,
Duke came in and we worked very closely with them on the attributes of
the program. Since, again, this was a new program, so I think we are
satisfied generally that the proposed program would be acceptable. It
is based primarily on inspection. That is basically what I have to say.
MR. SEBROSKY: Were there any questions on this item?
I guess that ends the discussion about the open items and
the confirmatory items. What I'd like to move on to is just to point
out to the ACRS members the added discussions that were put into the SER
from the June version. I have several slides on this.
The first slide just identifies responses to open items that
resulted in SER sections. The majority of these were identified in the
June version, but as we said you will notice that there is one on
insulated cables and one on reactor vessel monitoring pipe that were
added after the June version.
Regardless, as a result of the open items that are on this
slide, scoping was done by DSSA, Division of Systems Safety Analysis.
An Aging Management Review was done by the Division of Engineering. And
sections were changed in both Chapter 2 and Chapter 3 for the Oconee SER
for these as a result of the NRC open items.
The next slide, slide 20, and I apologize on missing a nine
here, but on the September 30th, on September 30, 1999, Duke gave us a
license renewal application update that is required by 10CFR 54. They
identified several new system structures or components that were added
as a result of changes to the current licensing basis. This slide just
details those things such as the essential siphon vacuum system,
portions of the component cooling water system being expanded and
portions of the low pressure service water system being expanded. The
staff did a review and again made changes to the SER based on this.
The next slide just provides details of what Duke's
technical comments were. If you go back to the October 15th letter that
Duke gave us, in that letter they provided us all the written responses
for the open and confirmatory items, and they also gave us this list of
ten items to look at. In some cases we identified that there were no
changes necessary to the SER and we discussed that with Duke. But in
other cases, for example, we added the discussion about the leak before
break, that was about a page long. And we've clarified some other
things as a result of Duke's comments. Are there any questions on that?
Then I guess the final slide is basically a schedule of
where we go from here. This just identifies the end gain, including the
sub-committee and the full-committee meetings, and also the ACRS letter.
But we have several actions that we have to complete, including issuing
the new regs in SER. Caudle and Vic have to do ---
MR. GRIMES: Issuing the SER as a new reg.
MR. SEBROSKY: I'm sorry, issuing the new reg as an SER.
Sorry. Anyway, Caudle and Vic have to do the final inspection and get
the Region 2 administrator letter. The schedule was to forward the
Commission paper with the staff recommendation by April 14th, then it is
in the Commission's hands.
MR. GILL: The engage schedules are presumptive. We presume
that the ACRS will write a favorable letter. We presume that the
follow-up inspection won't identify any issues that can't be readily
resolved. And we presume that we will work out the details of a renewed
license to present to the Commission in order to meet those milestones.
But, we've been able to fulfill that kind of schedule on Calvert Cliffs,
and I have a recommendation pending before the Commission that they are
going to discuss on March the 3rd. That's why we asked you to move the
full committee discussion of Oconee to March the 2nd. So, we are
playing both end games in parallel and we'd expect to follow this same
pattern for Oconee.
That ends my presentation, unless there are any questions.
DR. POWERS: I'm wondering how comfortable we are with all
of this, this rush to completion.
CHAIRMAN BONACA: I'm sorry?
DR. POWERS: How comfortable are we going to be, how
comfortable is the full committee going to be with this rush to
conclusion.
CHAIRMAN BONACA: Well, I mean, I think we would like to
have a discussion now of the sub-committee and talk about also that
issue there. And then my sense is that at the end of the discussion we
will then define for the staff and for Duke what we would like to hear
next week. So, why don't we just start and go around the table and see
what general perspective there are, and comments regarding what we heard
in the past couple of days and the closure of open items in the SER, and
where we are right now as far as having our meeting next week and where
we think we are going to be with the committee.
Why don't we go around the table and see if there are any
specific comments. We'll start with you, Bill.
DR. SHACK: No, I don't have any particular problems. The
big open issue that we sort of had was the reactor vessel internals. It
seems to me they've addressed that with a fairly comprehensive program.
You don't have all the answers, but, obviously, if you are inspecting
you will identify problems and can address those. And if you can make
some of those go away by analysis after further research, that's fine.
So, updating that.
The questions on scoping I thought were reasonably well
addressed by the discussions we had yesterday and today. So, I don't
see any real show-stoppers here from my point of view.
CHAIRMAN BONACA: Tom, your feelings?
DR. KRESS: I agree with Bill. I don't see any real
show-stoppers either. I think they did an excellent job of addressing
the scoping question. I just wonder how that will play out on the next
review. I think we need to look into how we are going to review the
scoping issue for the other plants.
But the items I had on my list to review for open items, I
think the resolution and the closure was very appropriate and
acceptable.
CHAIRMAN BONACA: Bob?
DR. SEALE: I was certainly impressed with the thoroughness,
and really the enthusiasm with which the applicant has plowed new ground
here. I guess the old story is that only the lead dog gets to see the
change in scenery. And, certainly, you are seeing a lot of change in
scenery as you go through and do this analysis.
I have one concern that just struck me that as you went
through you in some cases referred to some rather vintage analysis, even
things that were done before TMI. And I wonder if those vintages are
perhaps all they are cracked up to be. Are there things that have been
learned since then. Clearly there has been a very extensive amount of
engineering work addressing some of the issues in the TMI realm that
might cause one to ask whether or not those conclusions were completely
true. And I guess, Chris, I guess that is something your guys want to
take a look at.
MR. GRIMES: Actually, I'll address that by saying that as
we present the results of these license renewal findings, we emphasis
that the underlying principals for license renewal; the first of which
is reliance and the regulatory process to maintain plant safety.
Wherever there were lessons learned over time regarding whether the
Three Mile Island lessons learned, or other specific events, the
regulatory process has identified bulletins, generic letters, and other
actions by which vintage analysis, or vintage designs are back fit to
more modern standards. We may have learned some lessons that we
conclude did not warrant backfitting, but that does not necessarily mean
that the utility has not taken that experience and reflected that in
their vintage analysis. We rely on them to do, to reflect on those
things and go above and beyond with the backfitting requirements. So
that reliance and the process gives us the confidence that whatever
vintage features needed to be upgraded, have been upgraded.
CHAIRMAN BONACA: Mr. Uhrig?
MR. UHRIG: I, too, am impressed with what I've seen the
last day and a half. My major concern had to do with the cable aging,
and I think that was very appropriately addressed yesterday, and
summarized here again this morning. I don't have any reservations on
that.
The one surprise that came out this morning is the lack of
cathodic protection. But, again, it is not an issue as far as license
renewal is concerned. I'm just surprised. I had understood this was
always pretty much standard procedure, but it is not an issue as far as
the relicensing is concerned. Thank you.
CHAIRMAN BONACA: Dr. Powers?
DR. POWERS: I'd like to first just comment on absence of
cathodic protection. I think there are probably more instances in this
world over cathodic protection than cathodic trouble, whereas it is
protected, there are some serious problems with ground loops and things
like that. But it can occur on a complicated site. So, the fact that
there is no cathodic protection doesn't bother me very much. I work
with some sites where it is just a nightmare trying to cathodically
protect things.
I think it is important that we be able to write a
letter that is fairly parallel to the one that we wrote on Calvert
Cliffs. So it is important to make sure we have the information that
can do that. Now, clearly, there are sites specific, but we ought
to have a certain parallelism to the extent if we can. On the other
hand, we do have to recognize that we are talking about methodology and
setting a pattern that is going to be adopted in the future.
So, I don't think we should hesitate to comment on
methodological issues in the sense that they've been proven out here at
Oconee.
DR. KRESS: Do you see the scoping methodology they use as
being generally applicable to other plants? That was the concern I had.
DR. POWERS: I think that I would take from their scoping
methodology, if I were a different plant, to be, the lesson learned
there is to be imaginative in your approach on scope rather than trying
to follow somebody else's line of script. That's the take home lesson I
would get from that.
There is a question in my mind on how much we want to speak
to the technical issues of information to the Commission, and particular
on the, what I would say betting on the aspects of this, since we've
gotten explicit questions from the Commission on the issue
of one-time inspections. I'm wondering if in our presentation for the
full Committee it might not be valuable to have a little more discussion
of philosophy on that one-time inspection. Why do they think that this
is a good way to look at something. How can you set the time frame for
when it would be useful to do and when it is not useful to do.
CHAIRMAN BONACA: Yeah. And it is not set by the program.
DR. POWERS: Just because it is clear that is a question
that is on the mind of the Commission. Enough for them to write us and
ask us a question about it.
DR. KRESS: Well, their basis that they used was, I thought
it was strictly pragmatic; how can we fit it into the remaining
shutdowns we are going to have between now and the end of the original
license.
DR. POWERS: I think there is nothing wrong with that, and
I'm not objecting to it. I'm trying to understand why ---
DR. KRESS: Understand why that's good enough?
DR. POWERS: Why that is good enough, yeah.
DR. SEALE: And what the circumstances might be under which
one inspection wouldn't be adequate.
DR. POWERS: That's right, because there is, one of the
things that is going to happen is you are going to set a precedent here,
and you may well have to find, come up on occasion where you have to
undue that precedent. And so you want to make sure that precedent is
cast in the right light, so that somebody can't come back and say, "hey,
you let these guys do this and I want to do the same thing," or it is
almost the same thing, and now you are not letting me do this.
CHAIRMAN BONACA: And the other thing is that clearly we
understood the philosophy of the NRC in accepting one-time inspection as
a confirmatory inspection that in effect is not occurring. That in of
itself has a logic behind it that says you should wait and allow for
time to give yourself time to make sure that you give it time to this
improbably effect to manifest itself.
And so, then we had some communication that says, well, you
know, there should be no restriction when you do it. Well, you have
twenty years behind you. It doesn't make all sense. I think it would
be good to have that discussion with the staff planned for next week.
DR. KRESS: Well, my concern with that, Mario, is that I'm
afraid it is an unanswerable question.
DR. POWERS: And I think that is an acceptable response from
the staff.
CHAIRMAN BONACA: That's fine. Sure. Okay.
DR. POWERS: I think you, if the staff came in and said,
"Look, here is what we are trying to accomplish." You are trying to
respond to a negative hypothesis. You are doomed to failure here.
DR. KRESS: Yeah. You are doomed to failure, yeah.
DR. POWERS: So you are looking for plausibility, and that's
all we've sought is plausibility here, and a program that
has these characteristics to us is plausible and the ones that have
these characteristics is implausible to us, I think that is an
acceptable answer, because that is pretty much the answer we've given
the Commission on that, this plausibility document.
CHAIRMAN BONACA: We never gave a communication we expect to
establish a criteria, but we said that this seems appropriate to the
extent possible that you would delay as much as you can. They go in
cycle. And that's why, I mean, I think it is important we understand
why not, or there is a different criteria. One is, you know, can you
perform a one-time inspection when your license the new plant. He says
that he can do that. So, that's an issue we should hear about.
DR. POWERS: I think it's that I personally would like to
see, understand a little better, the technical underpinning for the
decisions on the sampling of piping for the ground corrosion.
CHAIRMAN BONACA: Yes.
DR. POWERS: I don't know that it is wrong.
CHAIRMAN BONACA: No. But to hear the criteria ---
DR. POWERS: In other words, a little more details on this
so that I would be in a position to defend it, as well as the staff.
CHAIRMAN BONACA: Okay, Mr. Sieber?
Mr. Sieber: As you know, I'm recused from voting on the
application with Duke Energy. On the other hand, I'm not recused from
assisting the committee in making its investigation, reviewing the items
that were assigned to me, and commenting on those. I have done all of
those. Along with Dr. Uhrig, I was assigned to look at the electrical
issues here. But there are other items that I was particularly
interested in. As a general conclusion I believe that there is nothing
that bothers me to any significant extent that would prevent the
issuance of an extended license. I would point out that in my
discussions with individual Duke employees, they were very forthright
and honest, and very willing to tell me everything that I asked them, or
volunteer information straight from the shoulder, and I think that
that's a prime and essential ingredient to being able to maintain a safe
plant. But I got that impression while I was here and I would encourage
them to foster that amongst all the people that are involved with
Oconee.
CHAIRMAN BONACA: Thank you. In my impressions -- first of
all, I would like to just make some comments regarding the interim SER
as we received it, and the final SER. There are some big differences in
my mind, and that's mostly for the issues we sought. Scoping. I think
that the extended review by the staff was important in my mind because
it gave us further assurance that in a pretty cloudy definition, as we
have for an older plant like Oconee, they have gone the extra mile to
verify that there are components out of scope. I think that by looking
at a number of additional, particularly the high energy line break,
which really spans the whole gamut of the plant. When you cover that
and you find no additional components, that gives a good feeling that
really you have covered the scope issue reasonably well, or well.
The reason the reactor, RVI-AMP, which is Reactor Vessel
Internal Aging Management Program, I think is a significant commitment.
And I think that -- you know, so many of the issues we had regarding
fatigue, regarding swelling, is really captured by that program. I
really like to see that program is so tied in with the initiatives of
the industry to aggressively go after these issues because the industry
has not addressed those issues. So that is really their -- it has to be
that leadership.
Also, I was satisfied about the closure on the issue of
attendance, because that is a program where inspections, you know, you
are not relying any more on those that, you know, we had other questions
on when we met for the interim review.
Also, the cables. What I appreciated the most was the
initiative of the plant to go out and look at locations and take
pictures and be candidate with us, and that we could see and then to
respond. It means that they intend to take care of it.
I was impressed by the physical conditions of the plant.
Most of all, by the fact that I didn't see a difference between the
components which are going to be aging and those which are not, which it
is telling me that there is a tendency to look at all components and
take care of that.
One statement though, I'd like to make, has to do with
more an impression, the reliance on established CLB. That is part of
the rule. But my feeling is always that there is a rule and then there
is we want to run a safe plant anyway. And so I, and I'm not saying
that Oconee would not in fact look outside of the rule, but you --
particularly when the CLB is very old, you have to be alert to all
components that you know by other means or any means that are important
to safety. There will be some that you didn't capture in that CLB, and
some that you captured, for example. And, so, I know that we have
discussed this with the staff, these questions that got raised, and I
believe again that the scope is adequate, but I think it is important
that we all always recognize that, you know, we know as much as we, you
know, our tools give us to know.
DR. KRESS: Mario, do you think the addition of the
additional events to look at following this Chapter 15 is almost like
doing a PRA? If you add enough of the events in ---
CHAIRMAN BONACA: Let me give you a feeling for what -- let
me just give you -- I mean, this is a high energy line break analysis
done most likely in the early 70's. I heard 1973. You know, there were
computer codes used at that time. You don't even recognize it was for
heat, but you blow super heat inside certain rooms at times and you get
significant effects. And, so, you know, as in a PRA, what you know is
as good as the methods you use. And, so, and there is nothing wrong
with the licensing base of older plants, but the fact is, you know, they
are more limited and we have to recognize that. Now, that is really
what I meant.
DR. KRESS: All right. I was encouraged that the staff was
able to add additional, what I would call design basis
events, into this.
CHAIRMAN BONACA: Yes.
DR. KRESS: Because I think that sets a bit of a precedence
that even though we can't see how to work the PRA, and that precedence
to me does give a way to make sure the scope does cover all safety
significant to the components of the system. That was encouraging to
me.
CHAIRMAN BONACA: Yeah. And to me, too. It was
significant, you know, cross verification of scope. And I agree with
Dr. Powers that we should hear something about one-time inspection, the
initiative as being somewhat belabored. Again, the perspective of the
committee is not one that we should impose any requirement as being done
the last day, but one that says it is prudent to do it. Later and
earlier because you want to keep a chance for this effectively.
DR. KRESS: I realize there is pragmatic and practical
consideration there. It takes so long to do an inspection.
You can't do it all at once, even though it is a one-time inspection,
and it ought to be spread out over time. My thought there is that I
think there is a need to prioritize. Which ones do you do first and
which ones do you do last, and not worry too much about the timing, but
the order in which you do it. I haven't seen much discussion on that.
DR. POWERS: I think what you are looking for is some
language, some thought on a question of detectibility and sizing.
Clearly, you want to inspect for those things that are most easily
manifested and most easily detected, most easily sized earliest. And
the most difficult latest. And in that, that maybe all the guidance you
can offer.
DR. KRESS: I haven't seen any guidance.
DR. SEALE: Well, in this case, in this case, too, there is
going to be the additional attraction, if you will, and
advantage perhaps of having an extended outage or two having to do with
steam generator replacement that is going to sort of open the plant up
for perhaps more detailed examination of some things than others. It
would be a shame to not be sure that the tough ones that needed time to
do, or to gain access to, were ignored when that opportunity arose. But
you can't count on that every time. Not everybody is going to do that,
but serendipity does come up and bite you every once in awhile.
CHAIRMAN BONACA: My thoughts on what to put in the letter.
I agree with some of the comments that Dr. Powers made in the beginning,
but as we, I would like to use the same format we used for Calvert
Cliffs. I would like to highlight in that letter some of the problems
which have been instituted in this list of open items, which I mentioned
before. We were very significant, I mean, the reactor vessel programs,
the containment commitments, and the cable problems. I would like to
address the closure of GSI-190. I think that is important because this
comes right after we close another genetic basis and we have a licensee
who has responded and has essentially committed to certain specific
inspections to deal with additional concerns that really, they could
take our position on that and say, "Well, we are not going to do it
because GSI-190 is closed." So I think that was something I wanted to
identify in the letter. I would like to put something regarding
one-time inspection just to clarify the committee perspective on that.
We may have been misunderstood in the past, or they may have believed
that we were trying to impose some kind of specific requirements, which
we never intended to.
Dana, you mentioned before the importance of communicating
some of the methodology that the staff is using to accept closure of
open items, and said to me the one of corrosion of carbon steel pipes.
It is a good example. And, so, we will ask the staff to give us, you
know, a very brief summary of the logic as they go through that we heard
today verbally, and I would like to further summarize that just for
information for the Commissioners. That was pretty much, I mean, there
may be additional items that seem to be important enough for them to put
in the letter for comment anyway, for your review. But that would be
the bulk of where I would like to go. And I will hopefully have a firm
draft for you before we travel to Washington so that you can take a look
at it, because we have a very short time table.
DR. KRESS: Well, once again, I was impressed with the depth
and comprehension of the staff's review. That gives you a lot of
comfort to know they do a really good job on this.
CHAIRMAN BONACA: Yeah, likewise. I was very impressed with
their work. I was very impressed with Oconee. Unfortunately, and I say
unfortunately, it gives us a benchmark as we did for Calvert Cliffs, and
sets up expectations at least on our part for the next applications, and
we hear about people coming in groves and groups and lumping together.
We will have to really be watchful of the process that Oconee is going
through to identify components of established programs. We will be with
them for a long time, because they are taking the time to look at it,
inspect it, and hopefully as well will happen on the next applications.
We have identified a couple of things I would like to hear
for a full committee meeting, and it seems to me that from Oconee, from
Duke, we would like to hear about the three items represented today,
which is scoping, cables and the Reactor Vessel Internal Aging
Management Program. Any other items you would like to hear from Duke?
DR. KRESS: Well, their plans for the one-time inspection.
DR. SEALE: Yeah.
CHAIRMAN BONACA: Okay. Plans for the one-time inspection,
and maybe just some basic information regarding their embedded pipes
corrosion inspection so we can understand that philosophy.
And on the part of the staff, we need to hear pretty much
the summary of closure of open items with -- I will expect special focus
on the three areas that are being presenting by Oconee, which is
scoping, cables and reactor vessel internal. Also, explaining their
philosophy and accepting some of, you know, the approach for example on
the corrosion of embedded piping.
And they heard us today talking about one-time inspections,
so if there is any additional information that, or other perspectives
that you are to give us, that would be the place for us to receive them
so we can possibly address them in the letter.
MR. GRIMES: Dr. Bonaca?
CHAIRMAN BONACA: Yes.
MR. GRIMES: Just so that I make sure we are clear, Duke is
going to make a presentation of the full committee that is going to
describe scoping, cables, reactor vessel internals, their one-time
inspections, and the buried piping?
CHAIRMAN BONACA: Yes.
MR. GRIMES: And the NRC staff is going to provide a summary
of the closure of open items, and will specifically emphasize -- I'm
going to start first with the reliance on the CLB and the regulatory
process in terms of what the scope or renewal is. One-time inspections,
both philosophically and in terms of what our expectations are, and then
how we do them in the change to the licensing basis. And then the
buried piping issue, in terms of the illustration of the
staff's approach to evaluating aging management programs.
Is that correct?
CHAIRMAN BONACA: Correct.
MR. GRIMES: Thank you.
CHAIRMAN BONACA: Okay. Do we have any other comments? Any
comments from the public?
MR. TUCKER: My name is Mike Tucker. I'm Executive
Vice-President for Duke. I rarely miss the opportunity to get up in
front of a microphone. I would just like to thank the staff very much
for the work that you have done in reviewing the Oconee application. I
think you are correct, the NRC staff has done a very rigorous review of
this topic, and our staff has certainly put a lot of effort into it.
Doctor Seale, we very much appreciate your view that the view is only
different as a lead. This team has done a good job and we look very
much forward to the review next Thursday, I guess, with the full
Committee moving on this project, so we have an opportunity to bring
some more to you in the future.
CHAIRMAN BONACA: Thank you. If there are no other
comments, we will ---
DR. SEALE: We do need to get to visit plants a little more
often.
CHAIRMAN BONACA: I agree.
DR. SEALE: I think you learn a lot.
DR. POWERS: We've got one coming in June.
DR. SEALE: I know.
DR. POWERS: I would personally like to thank the Oconee
staff for the hospitality and the fine tour we had.
CHAIRMAN BONACA: And for the lunch that was delicious, I
must say, and plentiful, too. Okay, so with that I think we can adjourn
the meeting. The meeting is adjourned.
[Whereupon, at 11:15 a.m the meeting was concluded.]
Page Last Reviewed/Updated Tuesday, July 12, 2016
Page Last Reviewed/Updated Tuesday, July 12, 2016