Plant License Renewal - June 30, 1999

UNITED STATES OF AMERICA
NUCLEAR REGULATORY COMMISSION
ADVISORY COMMITTEE ON REACTOR SAFEGUARDS
***
MEETNG: PLANT LICENSE RENEWAL

U.S. NRC
Two White Flint North
Room T2-B3
11545 Rockville Pike
Rockville, MD
Wednesday, June 30, 1999

The subcommittee met, pursuant to notice, at 8:30 a.m.
MEMBERS PRESENT:
MARIO BONACA, Chairman, ACRS
THOMAS S. KRESS, Member, ACRS
ROBERT SEALE, Member, ACRS
WILLIAM SHACK, Member, ACRS
ROBERT UHRIG, Member, ACRS. P R O C E E D I N G S
[8:30 a.m.]
CHAIRMAN BONACA: Good morning.
The meeting will now come to order.
This is a meeting of the ACRS Subcommittee on Plant License
Renewal.
I am Mario Bonaca, Chairman of the subcommittee.
ACRS members in attendance are Dr. George Apostolakis --
actually, he's on his way, I guess -- Thomas Kress, Robert Seale, Bill
Shack, and Robert Uhrig.
The purpose of this meeting is for the subcommittee to
review the NRC staff's Safety Evaluation Report related to the Oconee
license renewal application, crediting of existing programs, and related
matters.
The subcommittee will gather information, analyze relevant
issues and facts, and formulate proposed positions and actions as
appropriate for deliberation by the full committee.
Mr. 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 June 1, 1999.
A transcript of this meeting is being kept and will be made
available as stated in the Federal Register notice.
It is requested that speakers first identify themselves and
speak with sufficient clarity and volume so that they can be readily
heard.
We have received no written comments or requests for time to
make oral statements from members of the public.
On June 16, 1999, the NRC staff completed the Safety
Evaluation Report for the Oconee license application. This is the
second Safety Evaluation Report for a license renewal application.
The report identifies only three items that must be resolved
for the staff to complete the evaluation. The open items include the
basis for excluding specific structures and components from an aging
management review, applicability of certain aging effects to structures
and components, and the need for additional periodic inspections.
The Safety Evaluation Report also identifies six
confirmatory items that involve documentation of certain information or
commitments.
The ACRS plans to review and comment on the Safety
Evaluation Report at its September 1999 meeting.
On June 3, 1999, the staff issued a Commission paper
identifying options for crediting existing programs for license renewal.
ACRS plans to review and comment on crediting existing programs at its
July 1999 meeting.
This is just one example of the license renewal policy
issues that the staff is evaluating and that the subcommittee plans on
considering.
We will now proceed with the meeting, and I call upon Mr.
Christopher Grimes, Chief of the License Renewal and Standardization
Branch, to begin.
MR. GRIMES: Thank you, Dr. Bonaca.
We're very pleased to be here today.
The NRC staff is prepared to respond to the committee's
questions concerning both the basis for the staff's review of the Oconee
license renewal application, and also, this is different from Calvert
Cliffs to the extent that Duke Energy refers to B&W topical reports that
establish generic bases for aging management programs, and so, we're
also -- we have also arranged on the agenda to speak to the topical
report reviews and to discuss the basis for the staff's evaluation of
those reports, as well, and as you mentioned, we have designated time on
the schedule after we've discussed Oconee to discuss the staff's paper
on the generic issue associated with credit for existing programs, and
we'll cover that topic when we've finished with the Oconee
presentations.
Beyond that, we're here prepared to answer questions, and
we've arranged for specific members of the NRC staff to make
presentations on the material covered in all three of those areas.
Thank you.
CHAIRMAN BONACA: Thank you.
The Duke staff -- we have a presentation on the topical
reports, actually the specific BAW-2251.
MR. ROBINSON: Good morning.
I am Greg Robinson. I am the Project Manager for Oconee
license renewal, and on behalf of Duke and our Framatome Technology
gentlemen here, I appreciate the opportunity to come share this
information with you.
I'm going to take just a few minutes and give you an
acclamation and overview of the project and how the topical reports fit
into the Duke application. Then I'll turn it over to our Framatome
colleagues, who will give you the details of the reactor vessel report.
Also, this afternoon, in your hand-out package that you have
in front of you is the remainder of the presentation materials for the
afternoon session. It will be a short session that we will cover, and
we put all the information in the one hand-out.
This morning, Mark Rinckel from Framatome will take the lead
on a bulk of the reactor vessel material. Matt Devan is here, Ken Yoon
is here, and Bob Gill will then give us an overview of how the owners
group topical information fits into the application itself.
Paul Colaianni will cover the afternoon session for us.
A little background on Oconee: Oconee Nuclear Station began
construction in the late 1960s and completed construction in the early
1970s, a three-unit site, 2,538 mega-watts, initial capital cost around
$500 million. Commercial operation began in 1973 for units one and two
and 1974 for unit three. The initial licenses obviously expire 40 years
later, in 2013 and '14, and about 1,300 people are employed on-site.
Here is an aerial of the Oconee site. It's set in
northwestern South Carolina in the foothills of the mountains, on a
peninsula out in the lake, Lake Keowee. So, you can see the three units
there, and you're looking from the discharge out over the plant -- or,
excuse me, the intake out over the plant.
Before Mark gets into the details of the owners group work,
I thought it would be fair to show you just how long ago we began to
work on the technical information that ultimately ended up in the
application.
You can see, back in the mid-'80s, there were a number of
technical reports, the lead plant work that you're all familiar with, a
scientific perspective on aging and aging phenomena, a good bit of
research going on both in the industry and by the NRC.
The focus was on aging mechanisms at that point in time.
The time-line here is meant to show you the progression in
thought over the last 15 years, where you can see we've evolved from
more of a scientific thought process into more of a practical
engineering end point that we were ultimately able to use and put in the
Oconee application, and I hope you'll be able to see that today.
I won't go through each of the areas. I'm sure you're very
familiar with them.
I will point out that the Oconee efforts really began back
in the same time period, in the mid-'80s, where we were a participant in
the industry efforts and then, later, in the owners group efforts and
ultimately got to the 1998 submittal in July of last year.
Current project status, just to acclimate us again here this
morning -- I think you hit most of this in your introduction this
morning -- safety responses to RAI's were completed, and the safety
evaluation was issued just a few weeks ago.
The environmental area, the Draft Oconee Supplemental
Environmental Impact Statement was issued the end of May.
There is a public meeting on that in the Clemson-Oconee area
here next week, and then, in the hearings area, the NRC commission has
affirmed ASOB's decision to deny the petition of our potential
intervenor, and that was done in April of this year.
I showed you the time-line, the progression of thought over
the last 15 years, and I thought it fair to give you another little rule
of thumb as we get into the technical details of the vessel report.
One of the things that we began to notice when we put
together the initial B&W's owners group reports was we were beginning to
see a pattern emerge, and the pattern ended up fitting into this
equation, and the pattern was, if we can define the component and its
materials of construction, we understand where it's located in the
plant, then we can understand the aging of that component, material,
environment, stress conditions.
Then we can look and see if we have programmatic action that
can manage that material/aging combination. If, for example, those
programs had been in existence for a good long time, there ought to be
demonstrable evidence that the programs work or they don't work or
they've self-corrected, and all of that taken collectively gives us
assurance that we have something that will continue to serve us on into
the future.
That was written in many, many words in many, many technical
reports.
What we did for ourselves is boil it out into this rule of
thumb to give us the confidence that, each time, we could measure back
against the standard, making sure that we had covered each of the
aspects of this in our integrated plant assessment.
The other area that Mark will touch on with the vessel and
that we certainly touched on completely in the application was the time
limit that aging analysis, the boundary conditions on the initial design
that we had to investigate.
Begin to progress toward the owners group topicals and how
they fit into our application.
We divided the application work, the development work, into
five areas. We covered the reactor coolant system, which is where the
B&W owners group topicals fit, as a separate area, for a couple of
reasons.
One, it was an important area of focus for us. It demanded
a lot of additional attention, we felt, and also, that is where the
owners group work fit back in. So, when the match line between the
owners group work and the Duke work -- we wanted to be very clear that
we didn't miss something. So, we delineated that area.
The reactor containment was another area that we felt needed
special attention.
Radiological line of defense -- we broke it out as a
separate area from the remainder of the structures, so that we could
study it. Then the other three areas were the classical discipline
areas -- mechanical, electrical, and structural.
So, today, we're here to focus on the reactor coolant system
and, more specifically, on the reactor vessel.
Here are the reactor coolant system components, just to give
you a feel for how they break down. You'll see the piping, pressurizer
vessel, and reactor internals and, beside them, some small notation.
Those were the technical -- or, excuse me, topical reports
from the owners group that we submitted to the staff for approval over
time. They absolutely equal the information that's over in our
application for the piping pressurizer vessel and internals.
We also developed through the owners group additional
information for the remainder of the components. We did not submit that
for approval, but we did use it in the Oconee application.
You'll see there's a safety evaluation for piping, the
pressurizer, the reactor vessel, and a draft safety evaluation recently
issued for the reactor internals, and today, we're here to give you the
details of BAW-2251, and with that, I'll turn it over to Mark Rinckel
from Framatome, who will give us the details.
MR. RINCKEL: Good morning.
My name is Mark Rinckel. I'm from Framatome Technologies.
I've been the project engineer, generic license renewal project engineer
since approximately 1993. I have Matthew Devan here, who is an expert
in our materials area, on our surveillance program, and Ken Yoon to
assist me in the fracture mechanics area.
So, I will proceed to give you a summary of 2251, and the
topics I'd like to go over today are who the participating plants were
in the report, the contents of the reactor vessel report, basically how
it's divided into the various chapters of our report, the scope, which
tells about the component, the aging effects, how we came upon the aging
effects for the reactor vessel, the demonstration of aging management,
which would be the programs that we credit for those aging effects, and
the time-limited aging analyses, which in my mind are really the crux of
the reactor vessel report, because it deals with all the reactor vessel
embrittlement issues. We'll finish it up with the conclusions.
Now, the participants in our program include ANO unit one,
Oconee units one, two, and three, and TMI unit one. Crystal River unit
three and Davis-Besse unit one were not participants in our generic
program in the reactor vessel report.
All of our plants are similar in design. They're 177 fuel
assembly lowered-loop plants, and all of the operating licenses expire
somewhere between 2013 and 2016.
So, because of the similarity in the design and
construction, it certainly lends itself to generic report treatment.
Now, as Greg had mentioned before, the basic formula that we
follow in almost all of our report was establishing an RCS piping
report, and I saw Sam Lee here earlier, and he was instrumental in
helping in the iteration process in developing how we go about doing
these evaluations, and basically, the first thing we do is the first
bullet, is we define the intended functions of the component, and for
the reactor vessel, there are two intended functions, one of them being
maintain RCS pressure boundary and the other one being to support the
internals. We find that through going through our design specs,
equipment specs as the designer. So, we define those two functions.
The next thing we do is to provide a description of the
component, including materials of construction, and this was fun for me,
because when most of these components were fabricated, I was in
elementary school. So, I had to go back and understand the construction
and see how all these things were put together, and the objective there
is really to find -- you know, to define the component materials of
construction and really go through the fabrication part, and that was a
lot of fun for me, because you know, we seem to have lost some of that
technology as time has gone on.
DR. KRESS: Did you have sufficient records that you could
find the material?
MR. RINCKEL: Yeah, we did. We had -- all the QA data
packages were in our records system, and then, when I got stumped, I'd
go downstairs to the component engineers, who were in Mt. Vernon when
these things were fabricated, and I'd ask them, and I found that they
were usually the best source of information.
DR. KRESS: But QA is worth something.
MR. RINCKEL: Yes, it is, even back to the 1968-1970
timeframe.
So, that's really chapter two of our report, is providing
the description of a component.
Chapter three of four report is to define the applicable
aging effects, and again, we look at material construction, we look at
operating environment, and we look at level A and B service conditions.
Those are normal and upset conditions.
Those are the normal aging stresses of the component. We
did not assume emergency and faulted conditions, as that is not a normal
aging stresser.
So, the assessment of aging effects is very much qualitative
in this whole process, and again, that whole process was established
through our first report, which was the RCS piping report.
Once we've defined the aging effects for the component and
the various items, then we look at the programs that manage those aging
effects. One of the primary programs is ASME Section XI. There are
other programs, forecast and wastage program, Matthew's surveillance
program for reduction of fracture toughness and so forth. I will get
into that in more detail a little bit later.
The last item is to evaluate the time limited again
analyses, includes the upper shelf energy, lots of the reduction of
fracture toughness in the belt-line region.
So, that's the basic outline for the report.
DR. KRESS: Was Oconee one of the plants that was used in
the original pressurized thermal shocks?
MR. RINCKEL: I believe it was.
MR. YOON: Ken Yoon from Framatome Technologies.
In the initial 1980 period, one of three plants was Oconee
1, Oconee unit one.
MR. RINCKEL: All of the vessels within the scope of this
report were designed in accordance with ASME Section III, 1965 edition,
67 addenda.
We have found it very convenient in our report to describe
the various components in chapter two of our report, really in
accordance with the ASME Section XI examination categories.
For instance, we would divide it into groups.
Examination category BA can include the reactor vessel shell
enclosure head.
Reactor vessel nozzles would be examination category BD.
That included the inlet-outlet nozzles, core flood nozzles, in-core
monitoring system nozzles, and CRDM penetrations at the top of the
vessel.
The reactor vessel interior attachments, examination
category BN-1 -- those are the core guide lugs, and the last item would
be pressure retaining closures, which would be the closure head and the
CRDM closure at the top.
Now, the reactor vessel shell and closure head I'll point
out here. These are all fabricated from low-alloy steel, either A508
class two forgings or they're A533, was a grade B, plate or a 302 plate.
The closure head and the shell are about 14-foot inner diameter, 37-foot
high. They're shown here.
These are all clad on the interior surface with Austin
stainless steel. They were put in with a weld deposit submerged arc
process, usually a two-wire or a six-wire process, which would be a high
heat input process was used for cladding the interior surface of the
vessel shell and the vessel head. That's the first item.
These shells were usually about six-foot sections that were
welded using an automatic submerged arc process, using a Linde 80 flux
weld wire that was coated with copper.
At the time of construction back in the late '60s, the
copper was put on the weld wire to preclude rusting of the weld wire,
and we didn't know at that time that it would result in accelerated
reduction of fracture toughness.
So, many of our welds, most of the welds in the belt-line
region, are Linde 80 welds that have some copper in them, a little bit
more than they probably would without the coating, and therefore was the
beginning of our surveillance program that Matthew will talk about
later.
So, that's the shell and the closure head.
DR. SHACK: It's clad with stainless steel. There's 82-182
pads underneath the core guide lugs. Is that the only place that you
have the 82-182 on the shell?
MR. RINCKEL: Yeah, that's right. These are alloy-600 guide
lugs, and they're connected to the cladding with 82-182 weld material.
So, that's the only place in the vessel where there's 82-182 weld
material.
DR. SHACK: Now, are they welded to the cladding, or there's
an 82-182 deposit on the shell and then they're welded to that?
MR. RINCKEL: I believe they're welded to the cladding, to
the stainless cladding, but there is a stress evaluation done to show
that -- I mean the purpose of those guide logs is to catch the
internals, should there be a fracture of the core barrel up near the
ledge, and so, it's designed to accept about a quarter-inch drop, and
it's blended in with the cladding, but it is a structural weld that's
able to withstand that weight.
DR. SHACK: Okay. So, it's not sustaining load most of the
time.
MR. RINCKEL: There's nothing on it.
DR. SHACK: It's really just a catcher.
MR. RINCKEL: It's a catcher, and the purpose of that is, if
the internals should drop down, is to catch it to prevent the internals
from going down to the bottom of the vessel and therefore taking some of
the control rods out of the active fuel region. That's the whole
purpose of the guide logs.
DR. SHACK: Then the only other alloy-600 and 82-182
weldments would be at the penetrations for the instrumentation and the
drives.
MR. RINCKEL: That's right. The nozzles up top, which would
be the control rod CRDM nozzles, which would be these up here, are all
alloy-600, and then the in-core monitoring system nozzles down at the
bottom are alloy-600.
So, that's the inconel or alloy-600 that you have in the
vessel.
DR. SHACK: Thank you.
DR. UHRIG: How thick is the wall, pressure vessel?
MR. RINCKEL: The shell region is about 8 1/2 inches in the
belt-line, and then it increases to approximately 12 1/2 inches where
the nozzles enter the vessel, and the head, the flanges are
approximately 24 inches.
The heads -- the bottom head and the top head are, I think,
about 4 1/2 to 5 inches thick, and those are made from plate, both the
top and the bottom head are plate.
DR. UHRIG: So, the head is about 7 inches.
MR. RINCKEL: About 7 inches, yeah.
We have two outlet nozzles, 36-inch diameter, all clad with
stainless steel. Those are forgings, 508 forgings.
We have four inlet nozzles that are 28-inch inner diameter,
again 508 forgings clad with stainless steel, two core flood nozzles
that are approximately 10-12 inch inner diameter, again 508 forgings
clad with stainless steel, and then we just talked about the alloy-600
penetrations which are at the top and bottom of the vessel.
Now, the alloy -- I don't have this in the packet, but since
you're interested in the alloy-600, we had problems with the original
configuration of the in-core monitoring system pipes down at the bottom
of the vessel.
They were three-quarter-inch Schedule 160 pipes that
extended through the bottom head and met up with the internals package
so that the in-core monitoring system would go up and through there.
In hot functional testing in Oconee unit one, those all
broke off, and so, these pipes here, the pipe through the bottom would
extend all the way up, and those all broke off right in that vicinity
there, and what we had to do was make a reinforcement to increase the
strength of this so that it would not break under the flow conditions at
the bottom of the vessel, and those were all done after the -- again,
after hot functional testing was completed at Oconee unit one.
That made it bigger, made it stronger, but that's really the
only major problem that we have had with the vessel to date. We've had,
really, very little problems.
DR. SHACK: Do you have cracking in your instrumentation
nozzles?
MR. RINCKEL: Not that we know of, and they do a visual
inspection of those, VT-3, every interval, and to my knowledge, they
have not seen any, and we have not had any leak at present, and of
course, they are at the bottom of the vessel, so they are at about 550
degrees, which is a lower temperature and, therefore, less susceptible
to PWSCC than the penetrations, probably, at the top, since temperature
does play a factor in that, even though they would be susceptible to
cracking by PWSCC.
DR. SHACK: You do a VT-3 on those, but in the license
renewal application, you're going to do at least a one-time VT-1
enhanced?
MR. RINCKEL: That was not discussed in there, no. The only
thing that we would -- that we committed to in our report was to
continue the inspections that we would commit to as part of Generic
Letter 97-01, and those included the closure head penetrations and not
the bottom head penetrations, but the alloy-600 -- all of the alloy-600
in the loop is within the Oconee alloy-600 program, and that requires
some additional looking for the most susceptible components.
So, Oconee took an approach where they looked at all of the
alloy-600 items, and they said, okay, let's catalog these and find out
which are the most susceptible to PWSCC and then we will look at the top
five locations. To my knowledge, that IMS nozzle did not come up as one
of the top five locations.
DR. SHACK: That's the way you do it; you look at the
limiting component --
MR. RINCKEL: That's right.
DR. SHACK: -- in the inspection.
MR. RINCKEL: Yes.
DR. SHACK: And what can you actually see with the VT-3?
MR. RINCKEL: Well, you can see if there's cracking there,
not fine cracks, obviously, you'd have to have pretty good size cracks.
I think you can see if there is any cladding missing, if there's any,
perhaps, cracks big enough to extend to the base metal where you can see
some rust or something there.
So, that is what you can see, and you only really do a VT-3
of the reactor vessel internals and the interior surfaces of the vessel
itself.
Anyway, the other thing that we typically do is, based on
the functions -- and I'll put this back -- we identify what items we
will subject -- that will be subject to aging management review based on
the functions that they -- whether they support an intended function,
and there are a couple items that were sent with the vessel to the
Oconee units that are not -- do not support an intended function, that
are not subject to review.
One of them would be the monitoring pipes, which are there
to detect leakage. These items don't support the pressure boundary and
are not subject to review.
The other item that's not subject to review is the seal
ledge on the outside. It does not support the pressure boundary
function.
And the other items that were -- are subject to review that
weren't in the scope of the report are the lower CRDM service support
structure and the lower portion of the reactor vessel skirt.
Now, those items we simply chose not to include in the scope
of the report, because we, in general, were consistent with the IWB
inspection boundary. Those aren't inspected in accordance with IWB, so
we simply didn't include them, and Oconee would then have to evaluate
them in the plant-specific application.
So, that's what's in the report, what's not in the report,
what's subject to review, what's not subject to review.
Once we have the component, the materials of construction,
we look at the operating environment, the operating stresses, which are
service levels A and B, and we determine the applicable aging effects,
and again, it was easy for us to group them.
Examination category BA, which are reactor vessel shell
enclosure head -- we looked cracking, where would cracking occur at
welded joints, why would that be the case, growth of pre-service flaws,
fatigue. Fatigue would be time-limited aging analysis.
The external surfaces of the shell enclosure head could be
subject to loss of material, boric acid wastage, could have leakage at
the closures, bolted closures. So, we looked at loss of material.
Reduction of fracture toughness in the belt-line region.
The last one, growth of inter-granular separations, and I'll
get into growth of inter-granular separations with -- the easiest to
show is a figure of it here.
That was a time-limited aging analysis. We found this when
we went back to the early 1970s, when the components were fabricated and
licensed. We found a fracture mechanics analysis that was done for
this, and so, we had to evaluate it.
DR. SHACK: There's absolutely no consideration of stress
corrosion cracking of the low-alloy steel.
MR. RINCKEL: That's correct. We did not do that, because
there was no indication that that's occurred for any of the primary
system components, and you also have cladding.
DR. SHACK: Okay. I guess that was my question. Is that
because you felt that, in this environment, the material would -- the
low-alloy steel, even if exposed, would be resistant --
MR. RINCKEL: Yes.
DR. SHACK: -- or you're simply relying on in the integrity
of the cladding, that it will never get exposed?
MR. RINCKEL: I think both.
I mean, if you go back, the only aging effect that we said
would crack welded joints would be to the pre-service flaws, and that is
why you look at the joints now, is that those things may be there and
they may grow over time, and so, we dismissed stress corrosion cracking
of the low-alloy steel cladding, and even if it were exposed to borated
water in this environment, we do not feel that stress corrosion cracking
would be a mechanism, and plus, that's one thing I liked about the rule
that changed, is that you talk about cracking and the mechanisms, and
you know, we could argue a long time about those, but the fact that we
have said we would -- it's possible that we would crack the welded
joint, and what do you have there to look for?
So, the aging effects we looked at, again for the shell
enclosure head, are listed there.
This figure shows the reactor vessel shell region in the
welded joints for Oconee unit two, again cracking at the welded joints,
but we had to look at reduction of fracture toughness and where on this
shell reduction of fracture toughness would be applicable.
The traditional belt-line region -- and I'll show it to you
in just a second -- is primarily the regions of the shell that are
adjacent to the active fuel assemblies, and I'll show you right here.
So, that portion of the shell is the traditional belt-line
region, and that includes the lower -- the intermediate shell and the
lower shell and the welds that connect those shells together, the little
portion of the nozzle belt region, which is a forging on the top, and
then this region right down at the bottom here with the transition
forging.
DR. SEALE: Those are all ring castings?
MR. RINCKEL: Those are all ring forgings, not castings.
DR. SEALE: I mean forgings.
MR. RINCKEL: Yes, sir.
Now, unit one is different from units two and three. Unit
one has a plate that's -- two plates to make the cylinders, and that's
302 plate, and units two and three have 508 forgings.
DR. UHRIG: There is some longitudinal welds on unit one.
MR. RINCKEL: Unit one does have some axial welds, yes, sir.
Now, the belt-line region, as I said, is traditionally those
regions that are just adjacent to the active fuel assemblies, and then
the question for license renewal is would the belt-line region grow and
would it, in fact, grow up and include some of the weld that includes --
that connects the nozzles to the nozzle belt region, and the nozzles are
subjected to different loads than the shell, because it basically
supports the weight of the piping.
So, you have discontinuities where the nozzle comes into the
nozzle shell and also piping loads under design basis conditions.
We looked at estimating what the fluence would be up in that
region, and it was above 1 times 10 to the 17th, which is the number
that says that you need to have that type of material in the
surveillance program. At present, we don't have that material, that
specific material in our surveillance program.
So, what we did is we had Dr. Yoon do a fracture mechanics
analysis for that particular region to see if, in fact, it was more
limiting than the shell region of the belt-line. It was not.
Therefore, we could dismiss that region as not being
limiting and therefore not within the belt-line region, and the
classical belt-line definition for -- that we have used for 32 effective
full-power years was also applicable to 48.
So, we were able to narrow the region where a reduction of
fracture toughness was applicable to the classical belt-line region,
where we are irradiating all of the materials up until fluences, well
beyond what we would expect at 48 NPY.
DR. SHACK: Let me just understand that screening analysis.
You do the fracture mechanics analysis from a purely
fracture mechanics point of view to get the loads regardless of the
presumed toughness of the material, and you're saying that the loads
just aren't as high there, or are you really making some assumption
about toughnesses, also?
MR. RINCKEL: Well, we included the toughness, because we
estimated what a fluence would be. The fluence up in that region was
about an order of magnitude lower than the maximum in the belt-line
region, and so, we did look at material degradation, reduction of
toughness.
DR. SHACK: Okay. So, you don't have that material in your
surveillance program, but you then make some reasonably conservative
assumption about its loss of toughness.
MR. RINCKEL: Because it's really very similar to the
Linde-80 welds and very similar to the weld material that was used in
the belt-line region. I believe that's right.
Now, the only portion of the reactor vessel, the base metal,
that would be subject to cracking would be the 508 forgings, class two
forgings that were clad using the high-heat input process such as the
submerged arc two-wire or six-wire, and all of the forgings in the scope
of our report were clad using a six-wire process, and what's shown here
in this figure are the two beads.
They had bead one, including the six wires, would be the
first pass, and this was all clad. They put the forgings on a machine
and turned them, and they had an automatic submerged arc welding process
where they would lay down the cladding in six wires.
So, they'd roll the thing and make one pass, pick it up and
move it, and do another, and that's what these two beads are shown here,
bead one and bead two, and at the region where they overlap, in the
heat-affected zone underneath, it subjected the forgings to some
cracking. This was discovered, I believe, in Germany sometime in the
late '60s or early '70s.
What we found at B&W was the largest crack that we had seen
when we did NDE.
It was about .1 inches deep and a half-inch long, and what
happened back in roughly 1970 was that a fracture mechanics analysis was
done to show that that flaw would not grow and the reduction of
toughness would be such that it would not be -- it would not jeopardize
the integrity of the reactor vessel at the end of the 32 effective
full-power years.
So, this became an issue that we had to address for license
renewal, because it was an issue that was -- that resolved this at the
beginning of operation of our plants.
This will be the subject of Ken Yoon's discussion about
Appendix C of our document.
For the other items, we have just covered the aging effects
in the last slide on the record for the vessel shell enclosure head.
The other items will be the reactor vessel nozzles -- these
are clad low-alloy steel nozzles, again cracking at welded joints,
cracking at the inside nozzle radius. There are higher loads on some of
our bigger nozzles that could be subjected to stresses at the inside
radius, and loss of external material due to boric acid wastage. Again,
the closures could leak.
For the alloy-600 nozzles, which would be the CRDM
penetrations, the IMS nozzles down at the bottom, we have cracking at or
near the heat-affected zone. We have seen cracking not of any of these
nozzles but other alloy-600 items.
It typically occurs at or near the heat-affected zone in the
base metal, as opposed to the 82-182 weld. So, that has has been our
experience, but that would be an applicable aging effect for those
nozzles.
The reactor vessel interior attachments are alloy-600.
Those are the items that catch the internals should they fall. Cracking
at or near the attachment welds. And for the reactor vessel, pressure
retaining bolted closures, loss of mechanical closure integrity.
We could have loss of material of the alloy steel studs,
cracking, or stress relaxation, but again, the aging effect is loss of
mechanical closure integrity that must be managed.
Listed here are the generic aging management programs that
are credited for managing the aging effects of the items that we
discussed earlier. ASME Section XI, subsection IWB, 1989 edition -- the
staff has to have -- NRC staff has to have something to pull off the
shelf to look at.
It's the 1989 edition, with appendices seven and eight.
Appendix seven and eight deal with qualification of NDE for UT and
performance demonstration for UT. These are credited for managing
cracking in welded joints, again the fabrication flaws you're looking
for.
B&W owners group for reactor vessel integrity program is
credited for managing reduction of fracture toughness.
Those are NRC requirements for 10 CFR 50.60, which is
fracture toughness, and 50.61, which is pressurized thermal shock, both
of which are time-limited aging analyses, and 50.60 gets into the
surveillance program.
Technical specifications, the pressure temperature limits,
again tied to 50.60, RCS chemistry is credited as an aging management
program and RCS leakage limits, primarily for bolted closures.
Commitments to NRC generic communications -- Generic Letter
88-05 is the boric acid wastage generic letter that required all
licensees to prepare a program to address boric acid wastage.
Bulletin 82-02 is degradation of threaded fasteners in RCS
components, and most recently, Generic Letter 97-01 concerning PWSCC of
reactor vessel head penetrations -- we made a commitment in our report
that inspections and activities that will be done in the current term of
operation will be carried forward to the period of extended operation to
manage this aging effect in the next 20 years.
DR. SHACK: The analysis that's used to identify the most
limiting components there is based on the EPRI susceptibility model?
MR. RINCKEL: I believe it's -- Matthew, you may be able to
answer that.
I believe it is the EPRI susceptibility model that is used
to do that, and it considers the material, the stress, the chemistry,
and there is a time to crack initiation probability and so forth.
So, I believe that is the EPRI model. Our expert on that is
not here today.
I wanted to get into now, really, the time-limited aging
analyses associated with the reactor vessel, and the first one that we
addressed in our report is thermal fatigue. So, I'll give a summary of
that, and then the next item would be compliance with 10 CFR 50.60 and
50.61.
Again, that manages reduction of toughness of the belt-line
region. That includes pressurized thermal shock to 480 FPY and the
upper shelf energy evaluations.
Growth of inter-granular separations I referred to earlier.
We did a fracture mechanics analysis, and Ken Yoon will be discussing
that.
The last item would be flaw growth acceptance in accordance
with ASME Section XI. When NDE is performed on structural welds in the
vessel, if there are any indications that exceed allowable, they become
defects, and the options are to repair or to evaluate.
We have found some flaws that have exceeded the acceptance
criteria in some of the vessels.
I think Oconee unit two has one. Not many, but they've been
evaluated, and there is a fatigue flaw growth evaluation that's done to
assess how big the flaw will get at the end of the design life of the
component. So, we've had to revisit those.
We did not do that in our generic report. That was a
plant-specific evaluation. So, Oconee is handling that through their
application.
Our first time-limited aging analysis is thermal fatigue,
and when we started into this thermal fatigue area, all of the RCS
components have cumulative usage factors calculated for them, and we
found that a lot of the transients that go into the calculation of that
not only apply to the vessel, they apply to the piping, they apply to
every component.
So, you can't really just look at cumulative usage factors
for one component; you need to look at all of the components and really
get a good basis of what your fatigue design basis is.
So, what we did is we summarized -- Framatome summarized the
cumulative usage factors for all the class one components, including the
identification of what the transients were that were the controlling
factors for those usage factors.
We determined that the current number of design transients
would be valid for the period of extended operation, and we also were
requested and required to assess the impact of environmental-assisted
fatigue. All of that was done in our specimen of fatigue.
And what we started off doing was looking at preparing
matrices summarizing the usage factors and the applicable normal and
upset transients that contributed to the usage, and for instance, you
would have heat-ups and cool-downs from 70 degrees up to 580 degrees.
That would be one transient that would have a contribution to usage
factor.
The Oconee is designed for 360 such cycles over the 40-year
design life. It's stated as such in the FSAR. That's why it became a
time-limited aging analysis. There's nothing magical about 40 years; it
was just stated that way.
Our job was to look at all of the transients that went into
those usage factors, the heat-ups and cool-downs, reactor trips -- there
are a number of them that go into the calculation -- and really assess
where they are now and where they're going.
Are the original design cycles still okay for 60 years?
That was our whole objective of doing this, and we found that, yes, a
lot of these plants come up and are base-loaded, and they simply are not
accruing cycles such that would put them beyond their cycling at 60
years.
We found the controlling transients for almost all of the
RCS components to be listed here -- heat-ups and cool-downs, reactor
trips, HPI actuations, EFW, rapid cool-downs, and natural-circulation
cool-downs. So, those are the controlling transients for the usage
factors for almost all of the RCS components.
For the controlling transients listed on the previous slide,
we made an assessment of the number of transients accrued to date for
each plant, and I had one for Oconee. Let's see if I can find that.
Here we go. This is something that we did.
Oconee unit one is shown here, and these are the heat-ups
and cool-downs that they have accrued over time, and you can see, up to
2001, they have accrued about 100. We then did a conservative
projection about -- for the next 20 years, up until the end of the
period of extended operation or close to it.
The line up above shows the number of design cycles, 360
design cycles.
So, you can see that they are projected to be well below
that at the period of extended operation. Therefore, there was no need
to increase the number of design cycles for any of the design basis
transients.
And we did conclude that, for the reactor vessel and really
for all of the RCS components, that the current design cycles are
accepted for the period -- acceptable for the period of extended
operation.
DR. UHRIG: Do you also add in reactor trips --
MR. RINCKEL: Yes.
DR. UHRIG: -- rapid cool-downs? So, that would make it a
higher projection on there.
MR. RINCKEL: Well, each one of those transients would have
its own curve.
DR. UHRIG: Oh, okay.
MR. RINCKEL: If you have a usage factor of .9, let's say .5
would be attributed to heat-ups and cool-downs, perhaps .1 to reactor
trips, and so forth. It's based on each of those transients you
consider, and oftentimes, the heat-ups and cool-downs are bounding.
They bound many of the other transients because of the stresses applied
and so forth.
So, that's where we had it. We had a separate curve for
each one.
In our report, we had demonstrated that the existing usage
factors, with the exception of the Oconee ONS reactor vessel studs,
remain valid for the period of extended operation, and the reactor
vessel studs actually have a usage factor of 1.04 now that I think has
since been revised due to -- and recalculated. So, I believe Oconee has
taken care of that.
There is a program in place at each of the utilities to
monitor these design transients, and we could not go into the detail in
our generic report of describing the plant-specific programs.
So, that became a license renewal applicant action item, to
describe their thermal fatigue monitoring program. As part of the
license renewal application, Oconee has done that, and I think Bob Gill
will discuss that a little bit later.
The last thing is, once we had a good handle on the fatigue
design basis, understood what the controlling transients were,
understood where they were today and where they're going, we had to do
an assessment of environmental-assisted fatigue, and we did that for the
items, the reactor vessel items evaluated in NUREG-6260.
We used the ANO model described in NUREG-6335, applied
environmental factors for the faradic items, and showed that the usage
factor would be less than 1. So, we did address environmental-assisted
fatigue for the vessel items again.
The factors are not as high for the faradic items as they
would be for stainless steel, and I think there is some controversy as
to the stainless steel, but we didn't have that to deal with, because we
were all faradic in the vessel.
DR. SHACK: On the limiting items, is that on a design
basis, or that's actually going back and looking at the actual
transients and seeing -- and looking at those usage factors?
MR. RINCKEL: It was a study that was done by, I believe,
ANO or the NRC on identifying the limiting items in the vessel, and the
items were the nozzles, inlet-outlet nozzles, the core flood nozzle, the
weld that connects the lower shelf to the transition forging, I believe
were the specific items, and I think I saw John Fair here.
Is that right, John? Okay.
Yeah, John's nodding his head.
So, we looked at those specific items as the items to apply
the environmental factors to.
I'm not sure -- I think we also looked at the IMS nozzles at
the bottom and I believe the CRDM penetrations at the top, of the
alloy-600 items.
So, that was our assessment of thermal fatigue in the
reactor vessel report, and the next item is compliance with 10 CFR 50.60
and 50.61, which addresses the reduction of fracture toughness in the
vessel, and I thought, really, the best way is to have our expert on our
surveillance program give you kind of a history of our reactor vessel
integrity program.
It was formed, I think, about 20-some years ago to address
the problems with the Linde-80 welds that we have, and it's really an
outstanding program, and I was very fortunate to have Matthew help out
with this. So, I'm going to turn it over to Matthew here.
I'll turn the slides for you, Matthew.
MR. DEVAN: I'm Matt Devan from Framatome. I'm a
metallurgical engineer, and as Mark indicated, I want to give you a
brief background of the master integrated program, which I'll refer to
as the MIRVP throughout this presentation.
What I would like to do first is pretty much just restate
the NRC requirements for fracture toughness requirements and material
surveillance requirements.
As Mark indicated, 10 CFR 50.60 requires that all
light-water nuclear reactors must meet fracture toughness requirements
and material surveillance requirements, as documented in Appendix G and
Appendix H of the Code of Federal Regulations.
Also, as part of fracture toughness, we have 10 CFR 50.61,
which requires the protection against pressurized thermal shock.
10 CFR Appendix G has requirements, again, for fracture
toughness requirements for reactor vessels. One of the requirements is
that the upper shelf energy shall not be less than 50 foot-pounds. This
was a problem for the Linde-80 welds in that, during the life of the
plant, these welds had a low upper shelf energy value and would drop
below 50 foot-pounds.
Again, Appendix G allows an equivalent margins analysis per
ASME, Section XI, Appendix G, and this has been performed through the
end of life with an -- at the NRC with an SER.
Also, in Appendix G, they have requirements for
pressure/temperature operating limits, and they utilize the predicted
shifts of the reference temperatures, which utilize -- which you can
utilize the Reg. Guide 199, Rev. 2, methodology used to calculate the
adjusted reference temperature, which is then used to develop these
pressure/temperature operating limits.
10 CFR Appendix H is the material surveillance requirements.
It utilizes the ASTM E-185 standard, which is basically the standard
practice for conducting surveillance tests for light-water nuclear power
reactors.
It also states approved withdrawal schedules for capsules
for surveillance, for monitoring reactor vessel embrittlement.
It also contains integrated program rules, rules for
integrated program, which, again, the MIRVP is an integrated program.
So, these are keys that we had to develop when we created this program.
Some keys for the integrated program were for similar design
and operating features of reactor vessels, and reactors must have an
adequate dosimetry program and also the data-sharing arrangement for
these reactor vessels.
For the B&W fabricated reactor vessels, for the PWRs, there
were two NSS designers. One was B&W and one was Westinghouse.
The materials that were used to fabricate these vessels, as
indicated by Mark earlier, were -- for the plate vessels, they utilized
SA-302B, modified, which was modified by a code case, and those were the
earlier plants, Oconee one and TMI one.
Also, the later plants or the plants that were fabricated at
a later time were -- the SA-508 -- or, excuse me, SA-533, grade B, class
one, plate material, and the Oconee three and Oconee two and Davis-Besse
plants were forgings, fabricated from A-508, class two.
The welds, again, were utilized for the plate materials.
They both contain circumferential welds and also axial welds. For the
forgings, they only had circumferential welds, as indicated by the
earlier drawing.
All the welds in the belt-line region were automatic
submerged arc welds. They utilized the Linde-80 flux, which had a low
initial upper shelf energy, and again, as Mark indicated earlier, they
were fabricated using a copper-coated wire, which, with the introduction
of the copper or the increased amount of copper, can accelerate the
reduction of fracture toughness.
For the welds used in the fabrication, each weld wire heat
and flux lot had a unique identifier which basically went through a weld
qualification for that particular wire heat and flux lot. There were --
welds were qualified both at the Mount Vernon facility and also in the
Barberton facility.
The welds, when you see -- for the B&W fabricated vessels,
you'll see a WF numeral. That indicates that that weld qualification
was performed at Mount Vernon, and SA numerals were basically qualified
at Barberton, and all the weld seams in the belt-line region are
traceable to either a WF or an SA identifier.
Surrogate welds, just for information, is a -- weld-wire
heat can be fabricated from a different flux lot, but when -- as for a
surrogate weld, the wire heat is the key, and the flux lot can differ,
and it would be a surrogate weld of that.
But the wire-heat has got the unique equivalent copper and
-- the copper content, nickel content, and also mechanical properties.
For the surveillance material or surveillance capsules
contained in these capsules, again, in accordance with ASTM E-185,
contains both base metal and weld metal. The early capsules, which the
B&W capsules fall into, they may not have the same WF or SA weld in the
vessel belt-line as what's in the capsule.
This requirement was changed in later editions of ASTM
E-185, but they do contain both a plate or forging material that is
within the belt-line region and a Linde-80 weld associated with that
program.
The test specimens that are contained in these capsules --
they are charpy V-notch impact specimens, tension test specimens, and at
a later time, compact fracture test specimens were included.
No compacts were included in the very early plant-specific
capsules. As time went on, half-T's were included in some of the
plant-specific for the B&W reactor vessels, and once the integrated
program was developed, supplemental capsules were fabricated using
actual 1-T specimens.
Also included, neutron dosimetry wires to calculate fluence
and temperature monitors which were low-eutectic alloys which would melt
and show the actual radiation temperature exposure that the specimens
would receive.
DR. UHRIG: Could you tell me what you mean by compact
fracture specimen here?
MR. DEVAN: Ken?
MR. YOON: Compact fracture specimen -- it is a fracture
specimen according to the ASME standard. There is various size
specimens with two holes in the specimen you can pull under a test
machine. You can perform fracture test using these specimens.
DR. UHRIG: It's not impact loaded.
MR. YOON: No. It is just a slow pull.
DR. UHRIG: Okay. It's pre-cracked.
MR. YOON: Yes, pre-cracking is a requirement.
DR. UHRIG: You do mean impact on the tension specimens.
MR. DEVAN: Oh, no. The tension specimens are actual
tension tests.
DR. UHRIG: Okay. There are tension impact tests, also.
MR. DEVAN: Right. But what I'm classifying are the slower,
actual tension tests.
MR. YOON: In our program, to accommodate the cylindrical
shape of the capsule, we used the round compact instead of square, which
both are according to ASTM standards.
DR. UHRIG: Okay. Thank you.
DR. SHACK: So, even the half-T are really round geometry?
MR. YOON: No. The 1-T's are round. Actually, it's
.9-something.
MR. DEVAN: This is a slide summarizing the reactor vessel
integrity program. Again, it was established in the late '70s.
The primary purpose of this program was to resolve fracture
toughness concerns with Linde-80 welds because of the low upper shelf
energies.
The original participants were the B&W design reactor
vessels, which included Arkansas Nuclear one, Crystal River unit three,
Davis-Besse, Oconee's unit one, two, and three, Rancho Seco, and TMI one
and two.
As time went on, some later participants with B&W-fabricated
vessels were included. These were Westinghouse design reactors, which
include R.E. Ginna, Point Beach one and two, Surry unit one and two,
Turkey Point three and four, and Zion unit one and two.
The reactor vessel integrity program -- the goals were to
obtain materials and irradiation effects data, develop test methods and
analytical procedures to -- for determination of fracture toughness, and
also to provide an effective communication among the owners themselves
with these materials, also effective communication with the NRC, and
also with the industry.
As I indicated earlier, the plant-specific capsules had
deficiencies in that the limiting materials within those plant-specific
capsules were not the actual limiting materials within the vessels.
Also, fracture toughness specimens were not included in the
plant-specific.
So, the integrated program was developed, in addition to the
fact that there were some failures of the capsule holders within the
vessels.
So, the B&W owners group developed the integrated program at
that point, which established an integrated program for the B&W-design
reactors because of the failures of the holders within a few of the
reactor vessels.
What they would have would be host reactors, which would
host the actual plant-specific capsules themselves, and the other ones
would be just basically utilizing -- these host reactors would be
obtaining the data because of the similarities of the reactor vessels.
They would be able to pull and test their capsules after
being irradiated in these host capsules and provide them the irradiation
data that they needed.
The integrated program also added some additional capsules
which were classified as supplemental capsules, which were providing
additional data for other Linde-80 welds that weren't included in some
of the plant-specific.
At the time, the master integrated program has 14 capsules,
14 different individual supplemental capsules, and these were inserted
all in power reactors.
DR. SHACK: What are the flux limits on these things, and
when you -- presumably, you accelerate these somewhat, but what's the
limit on the flux rate acceleration you can give it?
MR. DEVAN: It's all limited on where the location of the
capsules themselves are within the reactor vessel. They're based on --
again, their exposure is based on their location, and we project the
fluence that's going to be received by these capsules and withdrawn per
a withdrawal schedule that is efficient for the participants to obtain
the data that's necessary to fill in the data that's necessary for end
of life and also for license renewal.
DR. SHACK: But when you add these supplemental capsules,
presumably in order for them to catch up, you have to somehow put them
in a location with a somewhat higher flux?
MR. DEVAN: These are the same locations of the
plant-specific.
The plant specifics are inserted and also withdrawn at
different times to -- well, they're inserted, and they get the exposure
that is required per ASTM E-185, and then, once they hit that limit or
that window, the capsules are actually withdrawn and then stored in our
Lynchburg Technology Center, and they are either tested or they're
actually stored.
MR. RINCKEL: What's the lead factor?
MR. DEVAN: Well, the lead factor for -- there's two
locations within the B&W reactors, and the lead factors for the quarter
thickness vessel thickness, which is one quarter of 8 1/2 -- the two
locations have lead factors of around 7 and 9. So, they are
accelerated.
DR. UHRIG: Do you have any of the weld material among these
samples, these capsules?
MR. DEVAN: Yes.
DR. UHRIG: Including the copper that was put into the
original welds.
MR. DEVAN: Yes. We have, I believe, eight different weld
wire heats, eight or nine, I can't remember, but we have a large number
of weld wire heats represented in these capsules, so we have an idea of
how each of these weld wire heats is behaving with respect to
irradiation and embrittlement.
DR. UHRIG: They use essentially the same amount of copper
on the electrodes for the different vessels that -- generally familiar
with the Turkey Point situation.
MR. DEVAN: Uh-huh.
DR. UHRIG: Is this comparable to, say, the vessels at
Turkey Point?
MR. DEVAN: Yes. Yes.
DR. UHRIG: It was the same procedure, same welding rod or
welding wire.
MR. DEVAN: The same process was used to coat the wires, but
there was no requirement as to how much copper was going to be put on
the wire.
In other words, it went through a copper bath, and then --
so, there are some areas where -- I mean there's no set thickness of the
copper coating. So, that's why there are some variations within the
copper contents within these Linde-80 welds.
Some welds have, you know, copper contents of .3 weight
percent. Others have copper contents of, say, .25 percent. So, there
is variation, and again, all these are measured based on a large number
-- a very large database of chemistry data that we have at hand right
for Linde-80 welds.
DR. SEALE: Let me see if I understand some of the code
words you're using here. When you say you have a lead factor of 9, does
that mean that I have to essentially put a capsule in for seven years in
order to replicate a 60-year anticipated irradiation?
MR. DEVAN: What that means is -- the lead factors that I
specified reflect the fluence that has attenuated through the vessel at
the quarter-T location, and what that means is that the capsules will
lead the vessel wall by seven.
So, if the vessel sees a fluence of 1E18, the capsule
exposed at the same period of time would receive, at the quarter-T -- or
equivalent to the quarter-T location of 7E18.
DR. SEALE: If that's your lead factor.
MR. DEVAN: Yes.
DR. SEALE: Okay.
MR. YOON: So, your question is correct.
DR. SEALE: My question was correct. Okay.
DR. UHRIG: Do you have thermal seals?
MR. DEVAN: Yes.
DR. UHRIG: So, therefore, there would be a significant
reduction.
MR. DEVAN: Yes.
DR. SHACK: Those pressurized thermal shock calculations
that you showed -- that was essentially with no additional neutron
management or neutron reduction. That's sort of calculated as you're
doing it now, so that they have the option of going to a low leakage
core or something?
MR. RINCKEL: Yes, that's correct. I think all of our
plants have gone to low leakage cores now. They're already there.
DR. SHACK: Okay. So, you can't buy anymore that way.
MR. RINCKEL: No, sir.
MR. DEVAN: B&W, when it generated this integrated program,
had a unique situation where they had with I would classify as nozzle
drop-outs. These are the areas within -- in the pressure vessel where
they cut out to -- for the nozzles themselves, the outlet and the inlet
nozzles.
So, what we had was a unique situation in that we had these
large disks with an actual Linde-80 production weld within that nozzle
drop-out that we could utilize for these supplemental capsules.
This -- again, it added additional data for weld wires heats
that were not included in the surveillance program. So, this expanded
the database that was necessary to cover some of the belt-line welds
that aren't -- were not represented within the plant-specific capsules.
Again, the drop-out -- the welds that were in these
drop-outs were utilized in these 14 capsules, supplemental capsules that
are part of the master integrated program.
The master integrated program is documented in BAW-1543.
The current rev is Rev. 4, and what we have is a supplement document to
that which provides the surveillance capsule withdrawal schedules that
the plants are scheduled to withdraw the capsules and so whatever is
required per E185.
The SER that was issued for Rev. 3 indicated some requests.
In particular, we had to do a TMI-2 supplemental capsule
re-qualification because of the accident at TMI-2.
They also asked for an analysis of sub-size tensile
specimens, because we utilized a smaller specimen than standard tensile
specimen themselves, and also, we -- they requested an analysis of our
reconstitution process, because one of the capsules we had included
reconstituted specimens from previous irradiated capsules, charpy
specimens.
These requests were answered and had no further comment from
the NRC.
And I would like to conclude with my background by
indicating some of the current activities that we're involved with and
concluded with as of right now.
We had a post-irradiation testing of a capsule called W-1,
which was irradiated in a Westinghouse-design plant, Surry unit two, and
what this capsule's purpose was was to document or provide irradiated
data from exposure in a Westinghouse reactor vessel, and we had the same
material from the same source included in B&W, in capsules that were
irradiated in a B&W reactor, and the intention is to compare the
irradiated data from a Westinghouse plant to the B&W plants and see what
differences, if any, are there, and this is currently -- the evaluation
is currently going on and should be completed as part of the 1999
integrated program.
And lastly, the --
DR. UHRIG: What kind of difference would you expect? A
spectrum difference?
MR. DEVAN: The spectrum difference I don't think is a
problem.
Again, there are some questions of irradiation temperature
differences due to the fact that B&W's operate at a higher -- their cold
legs are a little bit higher than the Westinghouse folks, and again, I
don't know what kind of conclusions we're going to be able to make,
because this is such a small database, but it provides a unique
situation where we've got the same welds irradiated in two different
reactor designs.
The B&W reactors have a cold leg temperature roughly of
about 550. The Westinghouse -- there are differences within the
Westinghouse. They range from anyway -- 545 to 540, I believe,
somewhere in that range.
Now, there was one reactor -- or reactor vessels, I should
say -- Zion unit one and unit two, which operated at a much cooler
temperature. They were around 530, but they are no longer part of the
program. So, the concern for that is not there.
The last capsule, which was a unique capsule in that it
included a previously-irradiated charpy tested charpy specimens that
were reconstituted to form new charpy specimens.
So, what this provided was specimens that already had
exposure to irradiation and already had the embrittlement, and we could
reconstitute those, further irradiate those specimens to get a higher
fluence exposure and embrittlement on those specimens, and that testing
has just been completed, and the report has just been signed off, and
that concludes my presentation.
DR. UHRIG: You alluded earlier to some of the specimens
having an impact, a charpy impact value of less than 50. How low was
it?
MR. DEVAN: They were --
MR. YOON: Between 40 and 45.
DR. UHRIG: So, it was not a big difference.
MR. DEVAN: No.
DR. UHRIG: Okay.
MR. YOON: Depending on the fluence, but that's about the
number we've seen.
DR. UHRIG: Okay.
CHAIRMAN BONACA: Any other questions for the presenter?
[No response.]
CHAIRMAN BONACA: What I would like to do -- we are
scheduled for a break, and this seems to be the right time to take it.
So, I would like to take a break now and resume the meeting at five
after 10.
[Recess.]
MR. RINCKEL: What we're concerned about is the fluence at
the inside surface of the vessel. The capsules, the surveillance
capsules that Matthew talked about are in Crystal River unit three and
Davis-Besse. They are not in ANO and they're not in TMI and they're not
in the Oconee units.
Those units all rely on ex-vessel cavity dosimetry, but
basically, when we projected out to 48 EFPY, the NRC asked us, well,
that's a long ways away, that's about, you know, 30 years from now, and
how are you going to ensure that those fluence values that you've used
at 48 EFPY are accurate and within uncertainty limits of the
correlations that are used for the embrittlement evaluations?
Well, in so doing, that was certainly a valid question.
During the same period of time of the NRC review of our
vessel, there was a separate effort going on with the NRC in review of
uncertainty and fluence calculations and so forth, and that resulted in
the approval of topical report BAW-2241, which addresses the
uncertainties of fluence and projection of fluence and so forth, and
basically, as a condition of acceptance of the fluence vessels, our
fluence values used in our report, our owners have to monitor, using
ex-vessel cavity dosimetry, reactor -- the fluence, and using the
calculation-based method that's described in BAW-2241, update those
calculations on a periodic basis to make sure that the fluence that we
have used out to 48 EFPY is still going to be valid.
So, we cannot just put our blinders on and not -- and ignore
fluence. We're going to have to continue monitoring.
We'll be using ex-vessel dosimetry to do that, and we will
be continually extrapolating out to 48 EFPY to make sure that what we --
the values we've used in our report remain valid.
If, all of a sudden, an extrapolation goes beyond what we
used in our calculation -- and our maximum fluence projection was
approximately 1.5 times 10 to the 19th -- if, at a later time, it
exceeds that, then we would have to update these evaluations.
So, we have committed to a monitoring process that will
ensure that these values that we have used in here remain valid.
Now, these values form the basis for the upper shelf energy
evaluation that Ken's going to talk about and also the RTPTS evaluations
that are performed in accordance with 10 CFR 50.61, and that's the
subject of the next slide here.
The next bullet is compliance with 10 CFR 50.60 and 50.61,
and the two items I'll talk about would be the RTPTS to 48 EFPY, which
is Appendix A of our BAW-2251 report.
Appendix B is a low upper shelf energy. Ken Yoon will be
talking about the fracture mechanics evaluation, and then the last
bullet is the growth of the inter-granular separations. That's Appendix
C of the BAW-2251.
Once we had the end of life or end of 48 EFPY fluence
estimates at the inside surface of the vessel for all of the
participating plants, we demonstrated that the RTPTS values at 48 EFPY
comply with the requirements of 50.61 using Reg. Guide 199, Revision 2.
The results of our calculations, RTPTS welds for all of the
participating units were calculated to be below the PTS limits, with the
exception of WF-25 in Oconee unit two reactor vessel, which had a value
of 300.1 -- screening criterion is 300, so it was a tenth of a degree
above -- and one weld at another plant.
Oconee has subsequently done a plant-specific analysis.
That's reported in the application, and the RTPTS value for WF-25 has
been reduced to 296.8. They had updated fluence, they had looked at
surveillance data, and Bob Gill will get into that a little bit later.
And at this time, I'm going to turn it over to Ken Yoon, who
will describe the Appendix B to our report, which is the low upper shelf
toughness fracture mechanics analysis, and that's for the limiting
belt-line welds that are below 50 foot-pounds, you have to perform
equivalent margins analysis in accordance with 10 CFR 50, Appendix G,
and that's what Ken is going to describe here.
MR. YOON: Again, my name is Ken Yoon, and I work in the
fracture mechanics analysis area.
One of the two fracture mechanics analysis included in the
license renewal project -- first one is the low upper shelf toughness
issue.
That is really the driving force behind the first creation
of B&W owners group, and subsequently, we had all the material testing
program was under this program, and for the analysis method and
acceptance criteria, we didn't have any in the beginning, but early
'80s, NRC wrote a letter to Section XI of ASME pressure vessel pipe
boiler and pressure vessel code to provide the acceptance criteria.
So, we started working on it, on this project. It took only
12 years, but we finished it in early 1990s, and the technical basis is
well documented in the Welding Research Council Bulletin 413.
Additionally, there is a regulatory guide, how to do low upper shelf
analysis, is also issued.
For the 40-year design life, all four owners groups,
including BWR owners group, completed the evaluation and was approved
for their justification for low upper shelf issue.
B&W owners group also performed the analysis for not only
B&W-designed plant but our reactor vessel working group members, which
is some of the Westinghouse plants having B&W-fabricated the vessels.
So, I'm going to go over the next slide, acceptance
criteria. There are three criteria. First one is based on -- all three
based on service levels.
First one, for levels A and B, there is a requirement for
the crack size, postulated crack size of quarter-T, just like Appendix
G, and the safety margin of 1.15, and crack extension of .1 inch was
specified.
This J material is the crucial input to this analysis, and
B&W owners group performed J resistance curve testing from day one and
collected many JR curves for this activity. Some are non-irradiated
material and some are irradiated material.
Also, B&W owners group donated weld material specimens to
the HSST program, namely 62-W through 67-W series of the both
un-irradiated and irradiated specimen testing. That specimens were a
B&W contribution to the program.
We collected many specimens, and Ernie Eason took the job of
modeling it using the pattern recognition program, and we have a B&W
owners group J resistance model as a function of temperature, fluence,
copper content, and specimen size. So, that's the basis of this
critical evaluation.
For the level C --
DR. SHACK: Now, how does Ernie's curve for the owners group
differ from Ernie's curve for the NRC?
MR. YOON: Slightly different, because he exclusively used
our database, and he has two or three different ways to look at that
data, but ours is exclusively Linde-80 weld data but in a similar
format.
For level C, the differences -- the postulated flows depth
should be one-tenth of a thickness instead of a quarter-T, and a safety
factor of one was given.
In level D, the same as level C, but in this case, the best
estimate mean curve was allowed instead of some sort of low bounding
materials curve, but those are the only difference.
So, based on this, we used the B&W J material model, and the
next one shows some plots of -- because the J material is the key
information, I plotted that against the fluence, and you can see that
the dotted line is a mean curve and solid line is a mean sigma curve,
and this is for high copper Linde-80 W-70 and 209 data points, were
plotted as in the illustration.
So, it's trying to show that the model is doing an adequate
job, and one thing to notice is B&W plants, design plants, early on,
went into low leakage fuel scheme.
So, at their extended life, 48 EFPY, fluence is a lot less
than some of the other plants' regular 40-year design life.
So, the results of this evaluation is it is found at all the
plants under this program, was found acceptable by the Appendix K. So,
that was the conclusion of this program.
DR. SEALE: I must make a comment. This sounds like on-time
code development, to mix the jargons of modern management analysis with
the codes and so on.
Fifteen years ago, a letter was written to suggest that we
needed to look at low upper shelf energies. It was available three
years ago, and now you're using it.
It's truly on-time development. I don't think you could cut
it any closer. I wrote myself a note here that Demming would be proud.
MR. YOON: It made some of us a career in this business.
[Laughter.]
DR. UHRIG: Could you define what you mean by level A, B, C,
D?
MR. YOON: That's the --
MR. RINCKEL: Level A and B are the normal and upset events.
Normal events would be like your heat-ups and cool-downs. An upset
event would be like a reactor trip.
Level C is an emergency event. For us, that's defined as a
stuck-open turbine bypass vale.
Level D is a faulted event, maybe a loss-of-coolant
accident, or a safe shutdown earthquake.
So, those are the various loadings that these things are
designed for.
DR. UHRIG: Thank you.
MR. RINCKEL: The next item Ken's going to talk about is
Appendix C to our report, which is the growth of inter-granular
separations. I had talked about those earlier.
Those are the regions on the forgings where the weld overlap
is that there are some under-clad cracks, and so, that's what he's going
to talk about, is evaluation of those under-clad cracks or
inter-granular separations, as we call them.
MR. YOON: Like Mark alluded to earlier, in the early '70s,
we found out these under-clad cracks. We have an SER on it. So, that
became one of the requirements on this project.
So, we revisited that flow evaluation using modern-day,
better solution, as well as a lot more complex loading tables we
generated for this project.
So, the cracks we worry about is separation -- I'm a
fracture mechanics guy, so it's a flaw. The flaw has maximum depths of
.165 inches and lengths of .5 inches. This diagram is not to scale.
So, we assumed, very conservative way, depth of .353,
including the cladding, and a length of 2.12. You know, that was the
basis for the input flow size, and used this to go through all the
particulate growth analysis using all the load tables we created.
So, toughness curve -- so, we used code KONC, KONA method of
IW-3600 out of Reg. Guide 199 and particulate growth out of Appendix A
of the ASME Section XI code.
DR. SEALE: I'm curious. That looks more like a separation
on the lamination --
MR. YOON: Yes.
DR. SEALE: -- between the clad and the base material.
MR. YOON: It's not really truly sharp crack.
DR. SEALE: It's not a crack, and you're not saying that
that kind of flaw would propagate in the same way that a crack would
propagate.
MR. YOON: It would not.
DR. SEALE: Okay.
MR. YOON: But there's no precise way of predicting that.
DR. SEALE: Okay.
MR. YOON: So, we're attaching it all with very conservative
evaluations.
DR. SEALE: So, this is kind of a level of detail in the
modeling, even.
MR. YOON: Yeah. It's overkill, but it's a sure way to get
rid of the issue.
DR. SEALE: Well, as long as you can say it's a conservative
analysis.
MR. YOON: Yes, it is.
So, we had a normal and upset condition, 19 transients.
It's all reported in the Appendix C, and all the design
basis transients were used from functional spec, and the stresses from
various strategic locations -- we just didn't take one location stress.
We just went around, sampled various locations, and we lumped all the
fatigue calculations into five groups, and we did thorough job, as much
as we can.
DR. SHACK: Five fatigue groups mean you had five
contributions to the CUF?
MR. YOON: This is a little different than CUF.
DR. SHACK: You're right. You're crack growth. kay.
MR. YOON: So, the conclusion of this evaluation is, for 48
EFDY, we'll be using all the base transient, design base transient into
the cycles. We can show that this crack is no concern. Even though the
assumption was very conservative, even that we could show that this was
okay.
DR. SHACK: Now, in the crack growth analysis, does it make
a difference how you order the groups? Is that what you do? You take
the most conservative ordering?
MR. YOON: You mean for the crack stuff?
DR. SHACK: Yeah. When I do the fatigue crack growth, it
would be dependent on the order of the cycles, wouldn't it?
MR. YOON: Yeah. So, what you do is you group them and you
somehow combine them per yield base, instead of finishing one type of
transient all the way through the life, then attacking another one.
DR. SHACK: Okay. So, you bunch them by yield.
MR. YOON: Right. So, you take a portion of that particular
duty cycle as part of a per-yield base spectra.
That's my presentation.
MR. RINCKEL: Anymore questions for Ken?
CHAIRMAN BONACA: I have one.
You say that this crack -- you postulate it's a conservative
estimate. Why do you say that is a conservative start for the analysis?
Is it because, in inspections, you have never seen a crack --
MR. RINCKEL: Yeah. The original size for the B&W vessels
was never bigger than 0.1-inch depth and a half-inch in length, and
we've started off with a larger depth than that, which is the biggest
that they saw in industry, and so, that -- to start off with, and then I
think the methods that we used were just very conservative.
CHAIRMAN BONACA: I'm just trying to understand what the
words mean. That's because you have never observations of cracks of
that size. In fact, they are much smaller than that.
MR. YOON: But the analysis assumed that that flaw is
breaking through the cladding.
CHAIRMAN BONACA: I understand that. I'm trying to
understand the context.
MR. RINCKEL: Did you have something, Barry?
MR. ELLIOT: This is Barry Elliot.
We addressed that issue in our SER. These are under-clad
cracks. Because they're under-clad, they have a very, very slow growth
rate. They're not surface-breaking.
As a result, they grow very, very slow, and the assumption
they make is that the clad goes entirely through the clad, which is a
very conservative assumption. We addressed that in the SER, that issue.
MR. RINCKEL: Well, that really concludes our presentation
of the B&W owners group report, BAW-2251, and then there are -- I think,
certainly, you can see that we demonstrate that aging of the reactor
vessel will be adequately managed to ensure the component-intended
functions during the period of extended operation in both requirements
for 5421A3 and 5421C, which are the aging management review, and TLAA
portions of the requirements in the license renewal rule.
This report has been built on experience and methodologies
developed over the past 20 years and outstanding reactor vessel
integrity program, and the work -- the fracture mechanics work are
really the keys to show that this vessel, the intended functions will be
maintained in the period of extended operation, and at this point, I'm
going to turn it over to Bob Gill, who will tell how Oconee has used
this report in their license renewal application, unless there are
further questions.
DR. SHACK: My question goes probably to Mr. Gill, but when
you do the plant-specific analysis for the Oconee weld that didn't make
the screening for PTS, the plant-specific uses the surveillance data
instead of Reg. Guide 199 to estimate the shift?
MR. RINCKEL: Well, maybe Matthew is probably the one to
answer that, because we did re-do the fluence evaluation, and it was
somewhat -- a little bit lower than what we had used in 2251.
What we used in 2251 for 48 EFPY was based on a 1994
estimate, and we have since revised all of that. There had been a
topical report that had been approved. So, the fluence was a little bit
lower, not a lot, I think within about 3 to 5 percent, and there was
some other chemistry surveillance data.
MR. DEVAN: The evaluations were in accordance with the
regulations, which did -- you did have to consider the surveillance data
that was available. That was taken into account in the evaluation. And
based on all these additional informations and reduced fluences, we came
up with a revised value of 296.8.
MR. GILL: This is Bob Gill.
Just a footnote on that. The original analyses for the
topical were done in the '94-'95 time period, and you can see how robust
the program is, that over time, as more information is available, we had
an even better calculation at the time of application last year of
300.1, and then subsequently we've done even more and gotten it below
300.
So, it's just the evolution, and we'll continue this
program, the vessel integrity program, which I'll get into briefly here.
So, it's just a natural process.
My name is Bob Gill. I'm with the Oconee license renewal
project. I was one of the members of the B&W owners group vessel
materials committee back in '77 at Duke, at the very fledgling committee
that we started out, and we had serious concerns at that time of the
licenseability of Oconee and all the B&W vessels due to the upper shelf
energy concern.
So, a lot of effort was put forth at that time, and
thankfully, we've been able to continue that, and I think this committee
was also one of the main reasons why the B&W owners group got involved
in license renewal some five or six years ago, and I appreciate the
opportunity to come back and speak to you all again. I think I was here
about 18 months ago.
I am going to talk to you about how Duke has taken the
generic owners group report and addressed the plant-specific
requirements that are identified there, and in our application, we'll
cover the overall Oconee application where the report is covered,
briefly go over the process we use to incorporate it by reference in
actually all the reports that we are using, all four of them.
We'll address the plant-specific items, renewal applicant
action items. This is typical for any owners group topical report that
you saw, 95 or 98 percent of the issues, but there are always going to
be a handful of items to be done on a plant-specific basis.
We consciously identified some of those. They were just not
mature at the time we put this report in in '96.
And then I'll go over the Oconee-specific programs and
TLAA's that we addressed inside the application.
We organized the application so that the -- chapter two is
primarily the scoping and screening results, and 2.4 is the reactor
coolant system, and 2.5 is the vessel, and you'll see a parallel on the
numbering scheme that allows easier review.
All the vessel components that are subject to aging
management review, all the piece parts are discussed and pointed to in
section 2.4.5. All the aging effects associated with the vessel are
part of section 3.4.5.
The many programs that we credited are all described in
chapter four. We did not keep it similar to the previous chapters
because there are many programs that cover components associated with
other areas, like boric acid wastage will be used in several areas, not
just the reactor coolant system.
Section 5.4 is our plant-specific time-limited aging
analyses, and the approved owners group reports are referenced in each
of these sections where applicable, if you go through and review that.
We did that by conscious to make sure they are on the public
docket, they are on our docket at the time of application.
In addressing the renewal applicant action items, we created
an item-by-item, two-column format table to facilitate review by the
staff, the public, the ASLB, whoever.
In fact, we had some questions or potential issues regarding
that, because this report was still under review. But we do have a
two-column format, makes it very simple. Here is the action item that's
required; here is the Oconee-specific response.
We provided to the staff in a May 10th letter, and that was
less than two weeks after the final SE was issued. We knew pretty much
what the issues were going to be, because we had seen a Draft Safety
Evaluation Report, and we knew what the open items were. So, we were
well prepared to go ahead and address those.
For BAW-2251, there are 13 renewal applicant action items,
and we addressed all those in the report.
Just to summarize rather than belabor each one, we had to
verify that Oconee was bounded by the topical report, and since we were
intimately involved in the creation of the report through the several
years leading up to its submittal and in the review, we were real
confident about that, but we went through another step to do that.
We actually created a process -- and Mark was involved in
that -- of going back and re-reviewing the Oconee-specific information
to make sure our chemistry was the same, the materials are right, the
Oconee-specific documentation.
We have that in-house to verify that everything that's said
in a topical report does, in fact, bound the design of Oconee, all three
vessels.
We also verified that the programs and activities that we
credit in the topical report are, in fact, in place at Oconee, and I'll
go over those in more detail in a moment.
We did have to perform the plant-specific time-limited aging
analysis, and we identified the fact that the PTS value on unit two
needed to be updated, and so, we've actually done that twice now.
We did it at the time of application and then again earlier
this year.
So, we've gotten that down to below the 300 degrees, and
another area was to provide summary descriptions of all these programs
and time-limited aging analyses in the FSAR, and we, of course, did that
as part of the application.
This is a -- I believe a complete list of all the aging
management programs that we credit at Oconee, and the number one item is
a -- is our version of the reactor vessel integrity program, and you can
see here that we credit the master integrated reactor vessel
surveillance program that Matthew talked about, the cavity dosimetry
program -- we have ex-vessel dosimetry on unit two that we periodically
remove.
That gives you a -- you know what the flux is at the core,
you have this ex-vessel dosimetry, you can then project to see what the
distribution is of the fluence, and that helps validate your models.
We are updating the fluence and uncertainty calculations.
We're using the approved topical there, keeping current on that.
We do pressure/temperature limit curves. We currently have
a set of curves, I guess, under staff review for going out to 33 EFPY.
We've already extrapolated that out to 48 EFPY, so we know we're going
to be able to operate at that time.
This is an ongoing program, and another sub-part of this
overall program is counting the effect of full-power years.
We have an engineer full-time in Charlotte that monitors
this, manages the program, attends the owners group meetings that occur
periodically, interfaces with the staff, and this is his program to own
and manage it, as well the engineers at the site that actually help
implement it.
So, we're pretty well vested in this area, and it's a very
important program. It's been around at Oconee in one form or another
for over 20 years.
DR. SHACK: Are the pressure/temperature limit curves based
on the new code case?
MR. GILL: Yes. Actually, they help give us a lot more
relief. There are several code cases, I understand, that give us more
relief on the MPSH and the minimum temperatures we've got to have.
That's one of the reasons, even though that's under review
by the staff, that gives us confidence we'll be able to have valid
curves for 60 years.
Another major program that we have been involved in -- and
there's another engineer at Oconee -- at Charlotte and Oconee that's
involved -- is the control rod drive mechanism, another vessel closure
penetration inspection program.
This is the CRDM vessel head. There's a generic letter
several years ago that came out -- I guess there was European
experience. We've had several inspections at Oconee. We've been
involved in the industry efforts. We credit that as an existing
program.
We have one more inspection scheduled this fall on unit two,
and we'll determine at that point in time what additional inspections
and how often and all. That is really a living program.
That is probably the leading indicator of alloy-600 activity
in our alloy-600 program. This is the leading indicator of what's going
on due to the geometry, the temperature, that type of situation.
Chemistry control -- our chemistry control program is based
on the EPRI water chemistry guidelines. It's an industry standard. We
continue to update that as new chemistry guidelines come out. We keep
current with it. I don't believe the staff had any real questions or
concerns regarding this during the review.
We're real confident in that program in that program, too.
We have solid chemists and scientists and engineers involved in
monitoring, and this is a well-managed program.
I mentioned the alloy-600 aging management program.
Alloy-600 is in several locations. We have identified the most
susceptible locations. In addition to the control rod drive mechanisms,
there are several locations in the pressurizer which are leading
indicators because of the temperature there, and we will be inspecting
some of those locations in the future.
The in-service inspection plan is very straightforward.
That's your Section XI program. We are currently using the '89 edition.
We will continue to update that every 10 years or whatever the
regulatory requirements are.
As time goes on, we've built into our commitment either to
continue using this or 50.55(a) or whatever version of the code in the
future. So, we've addressed that.
That is definitely a living program.
Boric acid wastage surveillance program -- Duke has had one
of those for many years. There was a generic letter several years ago.
This is an ongoing program. It covers not only the reactor
coolant system, the vessel, but other areas inside containment, other
systems, and in some cases, some components in the auxiliary building
that may be subject to having boric acid wastage. It's primarily carbon
steel-type components.
We have a period monitoring program on that one, also.
RCS operational leakage is a tech spec requirement. It's
monitored periodically for the tech specs. This is a backup. We don't
want to have leakage, but if we do have it, I think the only place we
credit it in the vessel is the leakage between the head and the flange
area.
Certainly, we don't have any through-wall leakage at all.
And the thermal fatigue management program, which is
becoming more and more formalized at Oconee, we credit that through the
reactor coolant system, monitoring fatigue cycles.
We've had a lot of detailed discussion with the staff on
that, and we're working on improving the formality of that program.
DR. SHACK: Just a question on your chemistry control
program. The units are running at different pH's now, right? Some are
higher and lower?
MR. GILL: I don't know off the top of my head on that.
They should all be about the same program, because it's all one site.
CHAIRMAN BONACA: On the alloy-600 aging management program,
you said that you have the inspection planned for the pressurizer?
MR. GILL: Yes. We have identified several components in
the pressurizer that -- pressurizer heater sleeves on unit one, level
taps and safe ends, spray nozzle safe ends and the vent nozzles on unit
three all seem to be more susceptible than other locations.
CHAIRMAN BONACA: For those leading indicators, what kind of
frequency do you have for those inspections in the program?
MR. GILL: We haven't identified a frequency yet. We will
be setting that up. We've committed to do at least one inspection
during the current 40-year term and also looking at, you know,
monitoring industry experience to see what's going on.
We really need to look at the CRDM nozzles to see what's
happening there, how fast this is growing, and again, I think it's the
third inspection will be this fall, and we'll see and let the materials
engineers decide how often is important enough to look at this.
CHAIRMAN BONACA: The question I have, I guess, is regarding
the program. Does the program include provisions such that you could
have indications --
MR. GILL: Yes, that's right. You'd set up a frequency and
come back every cycle, every two cycles, whatever is important.
CHAIRMAN BONACA: So, you already have established some
criteria, some time tables and things of that kind.
MR. GILL: That's all described in our proposed program on
alloy-600, and that will be carried forth into the FSAR supplement.
So, that commitment, then, becomes visible to the operators
to carry forth on. We make changes to it; it's covered by the change
process for the FSAR. All these commitments end up being in the FSAR
supplement, and that's why that particular plant-specific action item
was very important, and it's something we're going to be discussing with
the staff over the next several months, is the right level of detail
there, make sure the right commitments get carried forward and everybody
understands how we go forward here.
It's kind of new ground. We haven't had this kind of detail
previously in programs of this sort in the FSAR.
CHAIRMAN BONACA: So, all of these programs essentially
contains elements of further inspections and frequency --
MR. GILL: Right.
CHAIRMAN BONACA: -- depending on the indications you have,
but what you're telling me is that you really don't have yet experience
in many of these programs.
MR. GILL: On the alloy-600, the commitment is to do the
inspection and, based on that, determine what additional inspections are
needed, does it need to be broadened, do you need to come back a year or
two later. Those type of decisions are written into the program.
All of our programs have about 10 or 12 attributes of things
we need to do, what the effect is that you're looking for, what the
scope is, how often you're going to do it, what's the first one, what's
the technique or methodology.
We decided that the best way to measure our programs is to
set these attributes up and then match up, make sure all the corrective
actions are done in accordance with our existing problem investigation
program, they're all done pretty much by administrative controls which
are governed by the QA topical, and in some cases, there was a
regulatory standard that applies, in some cases not, and we just put
that down there.
So, the future folks that have to look at this understand
that total history.
CHAIRMAN BONACA: Thank you.
DR. SEALE: I'm curious. You said that you had a
pressurizer sleeves, I think it was --
MR. GILL: Right.
DR. SEALE: -- that you were monitoring on unit one, and
there was something else on unit three and so on. There is discernible
differences between those two units that tells you to focus on unit one
in one case and unit three in another?
MR. GILL: Actually, during the detailed review that Mark
did, we found out that the unit one pressurizer heater bundles are
actually different than units two and three, have different design,
different welding, and actually have this alloy-182 weld in there,
whereas units two and three do not, and also, the design difference --
you'll have these as -- in the overall program, but what we're saying
is, even of this set of, say, the pressurizer vent nozzles, the unit
three nozzles are most susceptible of all the vent nozzles, so we'll
look at those. So, based on the groupings, we'll actually look at the
most leading indicators of those.
DR. SEALE: That might suggest down the road that you need
to look at the unit two --
MR. GILL: Absolutely. If you start seeing indications, the
first thing you do is what about the adjacent units, and you have to go
in and look at them perhaps at the next outage.
DR. SEALE: It would also appear that communication between
your experience and your cohorts in the users group could very well
suggest things both ways.
MR. GILL: And the industry, anybody doing alloy-600
inspection.
DR. SEALE: Well, the users group, in particular.
MR. GILL: Absolutely. The communications is extremely
important as we start to see more and more indications, more and more
folks inspecting, rolling that into the database, and certainly, the
owners group will continue on as long as they're owners, and you know,
some of the experiences come from ANO, some from TMI. Roll that in.
They talk periodically, make decisions on which ones to inspect.
So, it's very important.
Now we're getting into owners group activities, but yes,
it's a very important thing.
That's one reason we're confident. It's not just us working
on this. We have this resource of everybody else out there in the
industry that's looking at the same thing.
The other owners, EPRI and any work they may be doing to
help us, European experience, if that comes into play -- a lot of that
helps drive -- that's why it's difficult to say an exact frequency or
when you're going to do something, because you have a lot of factors
from the outside world that may say you need to do that next outage, not
-- you can't wait five or 10 years.
CHAIRMAN BONACA: Just one last question about that
overhead, the previous one.
Of these programs that you have, I guess all of them will be
still in place if you do not go to life extension.
MR. GILL: That's correct. These are all existing programs.
Alloy-600 is -- we proposed as a new one, but in fact, we do have
activities underway today in that area. But all these others are, in
fact, existing programs that we have in place today.
We're very fortunate that we've had such a robust set-up on
the reactor vessel and in the entire reactor coolant system, very few
new programs.
DR. SEALE: Are there commitments in these other programs,
however, that have been added to those programs as a result of the aging
analysis?
MR. RINCKEL: I can answer that, Bob. The CRDM, another
vessel closure penetration, is one example of that. That is an ongoing
existing program where there's a requirement that they will have to do
and continue the inspections through the period of extended operation.
DR. SEALE: I mean have you added things?
MR. GILL: I'm trying to think on the adding. Not on the
vessel per se.
We've added some pressurizer -- based on the pressurizer
topical report that was reviewed, we've added some examinations of the
pressurizer, and in the piping, we have added some examinations of
small-bore piping, and so, there have been some small areas outside the
vessel. The bulk of our new programs and activities have been outside
the reactor coolant system completely, and of course, the vessel
internals, which we may get to later.
Okay?
I should point out, for each one of these programs, we have
some lead engineers at Duke, either at the site or in the corporate
office, that monitor -- own up to these programs, not just sitting up
there in space.
The time-limited aging analyses for Oconee -- the B&W
topical, 2251, was the first topical we had actually on the opportunity
to identify what the TLAA's would be and then take time to do the
evaluation on a generic basis.
The previous topicals on pressurizer and piping did not --
we had not identified what they would be, so we could not evaluate them.
So, for Oconee, we actually -- you know, for thermal fatigue
that Mark talked about earlier -- that's managed by our thermal fatigue
management program.
For the flaw growth analyses, we did review all the previous
in-service inspections handled on Oconee for the previous 20 years,
identified one indication at unit one on the vessel.
We've identified others in other components, but this is the
one on the vessel, and that is being addressed by our fatigue program.
For pressurized thermal shock -- and we've talked about this
several times now -- we've updated the chemistry, updated the fluence,
and now all three units are well within the limits for 60 years.
For upper shelf energy and inter-granular separation, we
determined we were bounded by the generic analysis, so no further review
was required.
The beauty of these topical reports is, once we work with
the staff and work through it, then the subsequent users of it need not
go through that. Instead of reviewing a whole document, you're down to
13 applicant action items to look at.
DR. SHACK: That reactor vessel indication -- that's a
fabrication flaw?
MR. GILL: I believe it was, yeah.
MR. RINCKEL: Yes.
MR. GILL: It was determined real early and was analyzed and
accepted at that time. We just went back and re-looked at the analysis
and updated it, and we found, you know, several across the whole reactor
coolant system we had to do that, and it was, again, the QA records we
had to go back to. We had to go back to the ISI reports.
Duke's practice at the time was to send in the actual
calculations to the staff. So, it met all the six criteria for being a
time-limited aging analysis.
So, we had the opportunity to go ahead and look at all
those, but they all turned out okay.
Okay.
On the conclusions from an Oconee perspective, the vessels
are, in fact, bounded by the topical report, and it was a well-worth
effort for us to do.
The programs that we currently have will continue to
effectively manage all the aging effects of our vessels, and the
plant-specific time-limited aging analyses have been evaluated for the
60-year operation, and we feel real comfortable and confident that we
know about the vessel. Many of us -- some of us, I guess, have been
working on this thing for over 20 years.
Any questions about the Oconee perspective on the vessel?
We'll get into more about the application in the review later this
afternoon.
[No response.]
MR. GILL: Okay.
CHAIRMAN BONACA: Thank you for that presentation. It was
informative.
MR. GILL: We'll turn it over to Barry, I guess, of the
staff.
MR. ELLIOT: My name is Barry Elliot. I'm with the
Materials and Chemical Engineering Branch of NRR. Today I'm going to
give you our perspectives on our review of BAW-2251 and also discuss
some of the open issues, how they've been resolved, plant-specific
issues and how they've been resolved for Oconee.
I had help on this review from the people over here.
We've completed the review of 2251. There were no open
issues; there were no confirmatory issues. There were aging management
programs, which was discussed by the -- by Duke and by Framatome. We're
not going to repeat all that.
We will, though, tell you that the first three programs are
discussed in our SER, and they are common aging programs, so they're
discussed in more detail under section 3.2 of our SER.
The bulk of today's discussion will be thermal fatigue and
the B&W owners group reactor vessel integrity program. As discussed by
Duke, the integrity program consists of surveillance data and analyses,
and we'll be discussing that in detail.
There were 13 identified plant-specific renewal action items
identified by the staff in its SER. Duke has responded to all 13. At
the moment, there is one open item. The 13 items deal with scoping,
aging management, and TLAA's, time-limited aging analysis.
The one open item is related to the time-limited aging
analysis, and it deals with the question of flaw growth, of the flaw in
the unit one reactor vessel. We'd like to look at that in a little more
detail to make sure it's being analyzed correctly.
That's the only open item at the moment.
DR. SHACK: That's the existing flaw that they have, the
fabrication flaw?
MR. ELLIOT: Yes.
DR. SEALE: That's strictly an analysis?
MR. ELLIOT: At the moment, it's an analysis. We want to
make sure that whatever inspections are going to be done in the future,
that they're going to be adequate for the life of the plant.
DR. SEALE: Is that flaw of a kind that's susceptible to
inspection?
MR. ELLIOT: We haven't seen the analysis yet. We haven't
gotten that far. That's the open issue, to look at the analysis, look
at the inspection methods, and come to the conclusion, you know, what we
have to -- if there's anything more than the ASME code required here.
Right now, they're only limited by the requirements of the
ASME code, and we have to decide for ourselves whether additional
requirements are necessary.
There are two significant -- very significant license
renewal issues. They are the vessel surveillance program and the
fatigue of the metal components.
Fatigue of metal components is concerned with the impact of
environmental fatigue on the usage factor. The staff has completed its
review of this issue. The licensee has done an analysis.
It has looked at the impact of environmental fatigue based
on the models described in NUREG-6335, and the staff has determined that
the B&W owners group has adequately addressed GSI-190 regarding
environmental fatigue of the reactor vessel components, and the fatigue
of the Oconee reactor vessel will be managed during the period of
extended operation.
Now we get to vessel surveillance, and this is a little
broader picture of the vessel surveillance.
Framatome described their program. Oconee is part of an
integrated surveillance program.
Participating in that program and having plant-specific
capsules in that program are from the three Oconee units, TMI one and
two, Crystal River, Arkansas Nuclear one, Davis-Besse, and Midland, and
in addition, it has supplementary capsules.
The advantage of this program is that it provides a vast
amount of data, much more than would be normally attributed to an
in-vessel surveillance program.
In a normal in-vessel surveillance program, only one heat of
weld wire would be part of the program, and it may not even be the
limiting weld, and that would be the requirement today for any in-vessel
surveillance program.
The Oconee one belt-line, unit one has three circumferential
welds and six axial welds. There are six heats of different weld
materials in that belt-line.
Oconee unit two has three circumferential welds but only two
with significant amount of fluids, and they have two heats of weld
material.
Oconee unit three also has three circumferential welds but
only two with significant fluence, and they have three heats of weld
material in their belt-line.
So, in unit one, there are six heats of weld material. Four
of the heats of the weld material have surveillance data, and if it was
just a plant-specific evaluation, we were lucky if we got one.
For Oconee unit two, both heats of weld material in the
belt-line have surveillance data, and for Oconee unit three, all three
heats in the belt-line have surveillance data.
That's the advantage of an integrated surveillance program.
The disadvantage is that there's no way to monitor embrittlement if
something changes in the reactor vessel design.
That is, if they change some core design significantly or
significant changes in the dimensions or something, or cold leg
temperature, let's say, we do not have data by which to determine the
effect of the embrittlement.
So, what we've had Duke do is establish limits on the
critical nuclear environment conditions such as gamma heating, radiation
temperature, neutron flux, and neutron fluence, and they are to monitor
those conditions during the license renewal term, and if they project
that they are going to go outside those limits, then they would have to
come back to us and propose an additional program.
The current surveillance program only applies as long as
they stay within those limits.
There are four TLAA's associated with the reactor vessel.
The fatigue of metal components. The staff reviewed the TLAA
evaluation, and the staff concluded that the TLAA evaluation performed
by the B&W Owners' Group on fatigue of reactor vessel components was
acceptable except for the Oconee reactor vessel studs. They became a
plant-specific action item. Oconee has reviewed, has reevaluated the
studs and found them acceptable, and the staff agrees. So that issue is
closed.
There is an open issue on the fatigue part, and I talked to
you about that before. That was the floor evaluation. We need to look
into that a little more.
Pressurized thermal shock. The neutron fluence -- there are
two parts to the pressurized thermal shock. There is a neutron fluence
part and the chemistry part, and the surveillance data part. I'm going
to talk a little bit more about the chemistry and the surveillance data
in a few minutes, but on the next slide. The neutron fluence
methodology was reviewed by the staff and found acceptable. There was a
charpy upper-shelf energy evaluation --
DR. SEALE: Excuse me.
MR. ELLIOT: Yes.
DR. SEALE: It was a month and a half ago, roughly, or maybe
two and a half months ago --
MR. ELLIOT: Yes.
DR. SEALE: Time flies when you're having fun.
We heard from the people in Research about a look at the
whole question of pressurized thermal shock, and in particular not only
the chemistry that you indicated, but also the distribution of the
flaws.
MR. ELLIOT: Yes.
DR. SEALE: And they indicated that a systematic look at
that problem or that aspect of the problem was under way. Is that in
any way reflected in any of the materials here?
MR. ELLIOT: No, it is not. That's a research program?
DR. SEALE: Yes.
MR. ELLIOT: This is a regulatory program.
DR. SEALE: Okay.
MR. ELLIOT: And it's based -- a regulatory program is based
upon the analysis we did early when we developed the PTS Rule, which is
SECY-82-465, and the reports that we did for Oconee -- I can't remember
the other plant.
DR. SEALE: So --
MR. ELLIOT: They were done in the eighties.
DR. SEALE: Yes.
MR. ELLIOT: And this criterion was developed from those
analyses. What Research is doing is they're taking the more -- another
look at those type of analyses using --
DR. SEALE: With hopefully a more realistic flaw
distribution.
MR. ELLIOT: With a more realistic flaw -- what they say is
more -- what we say is a more realistic flaw distribution, and seeing
what the impact is on the screening criteria of the PTS rule. It may be
that it goes up. In that case, you know, maybe no one has a problem.
Or, you know, it might go down, depending on -- there are a whole bunch
of issues here that have to be evaluated, not only --
DR. SEALE: But the expectation is after that you'll be able
to say and how.
MR. ELLIOT: Right. And -- so there's more than just --
DR. SEALE: Yes.
MR. ELLIOT: Flaw distribution here that's at issue.
There's --
DR. SEALE: Chemistry and --
MR. ELLIOT: A whole bunch of things. But this rule -- what
we're talking about today is what we developed --
DR. SEALE: I got you.
MR. ELLIOT: More than 15 years ago. Okay?
The B&W Owners' Group did a charpy upper-shelf evaluation,
an upper-shelf energy evaluation, and it's contained in a topical
report. We reviewed the topical report, and we concluded that it
provided sufficient fracture toughness data and analysis to demonstrate
that all the member plants could meet the requirements of Appendix G, 10
CFR 50, and the ASME code at the end of the license extension period.
The upper-shelf energy evaluation was just an extension of
the previous evaluation. The previous evaluation, which had been done
in the mid-nineties, was for 40 years, and this evaluation just extended
it to 60 years.
The next -- we also reviewed a Topical Report 2274 which had
to deal with growth of intergranular separation and low elasticity of
forgings in the heat-affected zone of stainless steel weld deposit
cladding. Duke went into a lot of detail on that. I would just like to
add that the previous analyses were done in the seventies. Since then
there has been a lot of changes in the fracture mechanics analyses.
This new submittal contains all those changes. It is the most
up-to-date analysis. It evaluates fatigue, the growth of cracks, as
well as embrittlement. And it incorporates the latest technology we
have in those areas.
We concluded the analysis demonstrates that the underclad
cracking will not be a problem. It will meet the ASME Code fracture
toughness requirements for fracture at the end of 60 years.
There are two things I think are very significant that I
thought were of interest, and that was the integrated surveillance
program and the PTS analysis. I discussed the integrated surveillance
program. I'd like to discuss now the PTS analysis in a little more
detail as is written here.
Our original estimate when the B&W report -- BAW 2251 was
given to us, we determined that Oconee Unit 2 upper shelves and lower
shelves circ weld would be over the screening criteria at the prior to
60 years. So we made this a plant-specific action item. Duke has
responded and they've revised the fluence, and in addition I just want
to say it revised the chemistry. This is an active program that had
been going on since 1992. It had nothing to do with this submittal.
We had during the Palisades review discovered that plants
were not sharing data sometimes and they weren't reviewing all the data,
so we put out a generic letter in which we requested everybody to
evaluate their chemistry data relative to all the other data existing in
the industry as well as the surveillance data. And it went on for about
three or four years, and as a result, there are some new chemistries.
In this case the chemistry went down slightly, and that impacted their
evaluation, where instead of having a PTS -- RT PTS value of 304, it
went down to 297.
We compared -- the methodology was the discussed earlier,
was that they used the chemistry to determine the amount of
embrittlement. We looked at that. We compared it to the surveillance
data that was available for this heat of material, and that assumption
is conservative for this heat. So we feel that the value of 297 is
applicable.
DR. KRESS: Would you have reached that same conclusion if
the value had stayed at 304?
MR. ELLIOT: It would have been even more conservative. I
mean --
DR. KRESS: Yes, it would have. That's right.
MR. ELLIOT: What we look at when we make the judgment is
the RT PTS value is the sum of three quantities. It's the sum of the
initial value --
DR. KRESS: Shift.
MR. ELLIOT: The shift, and margin. And we look at what --
the surveillance data shifted. Is it accounted for in the shift plus
the margin? And in this case it was accounted. The surveillance data
is less -- the shift in the surveillance data could be accounted for by
those quantities. Or actually those quantities were more than the shift
in the surveillance data, so they consider it's conservative.
DR. SHACK: When those chemistries change, is that because
somebody else brought in -- I mean obviously the chemistry changes from
point to point in the weld when you take the sample.
MR. ELLIOT: Yes.
DR. SHACK: You just have more data and you do a statistical
analysis and that gives you slightly different numbers when you look at
larger data sets?
MR. ELLIOT: Yes, that's what's happening. In the past we
had plants that had their own little data sets, and no one ever put
them -- no one had put them all together. B&W had done a little bit of
that, but it wasn't all together. And when we put out the generic
letter, different owners' groups started putting all the data together.
Don't forget, B&W fabricated vessels for Westinghouse in themselves, so
we had to get all the Westinghouse data together with the B&W data and
put it all together to get the most accurate values of chemistries.
DR. UHRIG: So what you're saying is that you have more
confidence in the large sample of data as opposed to the individual
plant --
MR. ELLIOT: Right. It's a more robust data base now than
we've ever had.
DR. SHACK: You mean nobody actually went off and did more
chemistry analyses. They basically just looked at all the data that was
really around and looked at it in toto.
MR. ELLIOT: That's true.
That's all I have to say today. Thank you.
CHAIRMAN BONACA: Okay.
MR. GRIMES: If there are no other questions on the staff's
review of the B&W vessel topical and the related topicals, the staff
will proceed with a presentation on the status of the license renewal
activities. We would begin by presenting a general picture of where we
stand generically, license renewal issues, and the overall program
attributes. And that's going to be presented by the license renewal
project manager for Oconee, Joe Sebrosky, who is being ably assisted by
Steve Hoffman, who's a senior project manager in the License Renewal and
Standardization Branch.
CHAIRMAN BONACA: Yes. And the fact, you know, we are
running ahead of time, and I think it would be appropriate to continue
with the presentation and maybe a second one we have scheduled for the
afternoon so we can gain some time. So with that, let's proceed.
MR. SEBROSKY: Good morning. As Chris said, my name is Joe
Sebrosky. I'm project manager for Oconee license renewal. And to my
left is Steve Hoffman.
What I'd like to go over is in general the status of license
renewal activities, and also a broad overview of the SER related to
Oconee license renewal.
The way that we're going to present this material -- you've
already seen a foreshadowing of this this morning -- we have lead
presenters for each section that are going to do the presenting, but we
will also have the principal reviewers in a panel-type discussion up
here at the front. And for the most part, that's what you'll see. In
some selected cases, you will see just one individual up here giving the
presentation.
That's the first couple of slides, just to let you know for
the particular sections who the lead presenters are.
I guess I'd like to go to the status of license renewal
issues, which is slide number 5 in the package. And for the first
section, for license renewal issues, as the subcommittee is aware,
there's 108 license renewal issues that the staff is currently tracking.
Most of these issues were given to us by NEI in the form of comments on
the draft standard review plan that we had issued. Out of these 108
issues, we've binned them into Priority 1, Priority 2, and Priority 3.
Priority 1 items mean that the resolution of those
particular issues are needed or the staff felt it was needed in order to
resolve issues associated with either Calvert Cliffs or the Oconee
license renewal application.
license renewal which
DR. SEALE: Okay.
Priority 2 items are less important items but are of a
general nature and then Priority 3 are lower priority than that. Out of
the 108 issues, the Staff has written proposed resolutions for nine, and
the process in general for resolving 108 issues is that the Staff after
some dialogue with NEI, the Staff writes a generic position for that
particular issue and that is what we have done in the case of nine
issues.
We expect then that NEI would write back to us and either
agree with the disposition or take some exceptions to it. They have
only written back to us on one issue, so out of the nine issues that we
have sent letters to NEI on, we have gotten a response to one.
Down the line, once we have that response, once the issue is
settled, then the only activity that is left is we have to determine the
appropriate disposition for that resolution, be it NEI 95-010, which is
the industry guidance or SRP or the draft Regulatory Guide.
DR. SEALE: You've got 108 initially and it looks like you
have got a pretty tall hill to climb, but I need a little bit more
information to decide how tall.
Of that nine, you have had comments on one. Have you
received any indication that you are going to get comments on the other
eight or that the other eight are satisfactorily resolved?
MR. SEBROSKY: I will turn it over to Mr. Grimes.
MR. GRIMES: We have gotten some indications that whenever
we agree with NEI, we've gotten an indication they are going to be
satisfied with the answer.
DR. SEALE: Yes, but that still evades my question.
MR. GRIMES: We are going to talk to you tomorrow about this
issue associated with credit for existing programs, which really gets --
I think that is going to be the watershed event that is going to help us
start dealing with these issues in a more expeditious way.
There were 17, I believe -- Steve, 17 Priority 1 issues?
MR. SEBROSKY: That is correct.
MR. GRIMES: And we have addressed all of those in the
safety evaluations for Calvert Cliffs and Oconee. We have dealt with
those issues in some shape or form. As a matter of fact, the issue of
credit for existing programs, we have also addressed in the reviews for
Calvert Cliffs and Oconee because we have reviewed all the programs. We
didn't make any distinction about whether they existed or not, and that
formed the basis for our safety evaluation, but at this point I think
that once we get over a Commission decision associated with the scope
and depth of the Staff's review, then the NEI Task Force and we will
have a clearer understanding of the expectation about the depth of the
safety evaluation basis for these issues, and so I think that then we
will start to see the dialogue pick up quicker on these others, but at
this point the indications are that NEI is relatively satisfied. We
haven't heard any significant complaints.
DR. SEALE: Well, you basically have 99 or 100 rather than
108.
MR. HOFFMAN: And another point, too, is remember, these
came in as comments on the Standard Review Plan. They are not all major
issues.
DR. SEALE: I appreciate that.
MR. HOFFMAN: Some of them are just improvements, comments
where we can revise and make the SRP a little more efficient.
DR. SEALE: Sure.
CHAIRMAN BONACA: You said that there were 17 Priority 1
issues, and also you said that they were addressed in terms of Oconee
and the BG&E application. Okay. How come you only have nine proposed
resolutions? You seem to have 17 resolutions.
MR. GRIMES: Well, we just addressed the other eight issues
directly in the review, but we haven't got a safety evaluation that
addresses how we would propose to deal with it on a generic basis like
we do for these nine issues.
CHAIRMAN BONACA: Okay.
MR. GRIMES: And so we just incorporated it into the Staff's
review. We dealt with the issue as it was presented to us in these
first two applications but there is a lot more work that goes into
developing a generic safety evaluation that explains what the
expectation is for all plants.
DR. SHACK: But it is kind of a misnomer to say the Priority
1s are the ones that have to be resolved in order to do these, because
you have essentially done that part for the plant-specific.
MR. GRIMES: That is correct, but remember we described
these things as Priority 1 before we began the review for the first two
plants, and so you are correct, to continue to call them Priority 1 must
be resolved for the first two applications is misleading to that extent.
We would have hoped that we would have had generic
resolutions on these issues but that process hasn't gone as fast as we
would have liked. As a matter of fact, it got substantially derailed
with this credit for existing programs issue because almost all of our
attention has been devoted to developing the underlying policy issues to
present to the Commission.
CHAIRMAN BONACA: You seem to characterize the 108 issues as
really centering regarding the depth of NRC review. Is that a pretty
good characterization of the thrust of the dialogue you are having with
NEI?
MR. GRIMES: Yes, because as Steve pointed out, the vast
majority of those came from specific comments that we got from NEI on
the Standard Review Plan.
Since the Standard Review Plan represents the tool by which
the Staff is directed to perform a review of scoping, screening and
aging management, and time-limited aging analysis, it is fair to
characterize those issues as scope and depth of the Staff review.
MR. SEBROSKY: If there's no more questions about the
license renewal issues, I will go on to the standard format for the
application.
DR. SHACK: Let me just ask one question. Obviously you are
getting generic solutions. I mean you are not going to be going over
the pressure vessel report for ANO-1. You have reviewed that. Do you
have any feel for what fraction of the work is being done generically,
you know, for the next B&W license renewal? Are you going to say 15
percent of the effort, 20 percent?
MR. GRIMES: That is the second time that question has come
up. The CFO always asks that question when they look at the budget
numbers.
It is difficult to say because, for example, Barry Elliot
pointed out in his presentation that there is a broader generic issue
associated with how to treat the vessel for all plants.
The B&W owners have a program, but then the CE owners have a
different program. The BWR Owners Groups have two or three programs.
Westinghouse has 51 varied units and I don't know that I could find the
Westinghouse program simply because of its diversity, but at the same
time we need to put some clear guidance in the Standard Review Plan that
talks about treatment of the vessel program and so we have got one piece
of that generic answer with this B&W evaluation, but that does not
necessarily mean that what we worked out in terms of the safety
evaluation basis for BAW-2251 constitutes "the answer" -- the generic
answer that could apply to all of the owners' groups.
Looking at it from that perspective, I think that we made a
substantial gain. Whether it is 15 percent or 20 percent is very
difficult for us to measure. It will vary according to the issue. It
will vary according to the extent to which there are generic features of
these issues that cut across all plants.
I think I could contrast the reactor vessel issue with the
containment issue. What is the appropriate standard for maintenance and
surveillance requirements for containments? There are three different
BWR containment designs. There are dry -- there are three different
kinds of dry containments. There's subatmospheric containments. Yet
the industry's simple view is why don't you just say the maintenance
rule and IWL is satisfactory and leave me alone? Maybe I said that in
too pejorative a way, but it is difficult for us to say that there's a
simple explanation of what constitutes the containment program that will
manage aging effects that are applicable to all containments for a
20-year period of extended operation that begins about 14-15 years from
now, and then we'll extend 20 years beyond that.
I am not going to be here to make sure that I did it right,
even if I live that long, so that is a long-winded answer to say no, I
don't have a number for you.
MR. SEBROSKY: Continuing on, for the standard format for
applications, Steve is actually the lead for this, but I'll go ahead and
give you the highlights.
Back in March we transmitted to NEI, we transmitted the
formats for both the Calvert Cliffs and the high level format for what
the Oconee SER was going to look like. That was given to NEI with the
thought that when a high level look at what we did for operating
reactors the SRP and the SERs along with the applications are one and
the same, as far as what is discussed in what chapters.
In order to try to come to a convergence on what an
application should look life, that is the main reason that we
transmitted the SER formats for Calvert and for Oconee to NEI.
There was a public meeting on April 13th and NEI has
responded in a June 17th letter -- we just got the response -- where
they essentially provide us two different formats. One format looks
like the SERs. If you look at the SER for Calvert and you look at the
SER for Oconee you will see on a high level that they are very similar.
There's of course some differences in the details, but as far as what is
discussed in what section, the SERs are pretty close.
The one format that NEI provided in the June 17th letter
looks similar to that SER format. They also provided us a format that
is different, that's based on a commodity group approach and Steve is
trying to set up a meeting in mid-July to discuss the two different
formats with NEI. The hope is that we will converge to one format and
come to an agreement.
MR. SEBROSKY: That's where we stand on the standard format
for the applications.
DR. SEALE: Does everybody know what the commodity group
program is?
MR. SEBROSKY: I have to admit to you that that's one of the
reasons for the meeting, is to try to understand the commodity group
approach and why it was chosen.
Going on to the next slide, the status of the standard
review plan and reg guide and NEI 95-010, I think the subcommittee is
aware that these documents are in a draft form, the draft SRP and the
draft reg guide.
As far as NEI 95-010 goes, that was issued in March '96, and
the draft reg guide proposes to endorse it. As far as the SRP and reg
guide update plan goes, Chris alluded to the credit for existing program
issue that goes to the heart of the scope of the staff's review and also
the depth of the staff's review. And you'll hear some more discussion
about that tomorrow, but obviously we have to figure out where we're
going in those two broad areas before we can come up with an update plan
as to how that'll affect the SRP and the reg guide.
That is basically the high-level status of the license
renewal activities. I guess I'd like to move on and give you a broad
overview of the Oconee license renewal application.
This slide basically has the same information that Greg
Robinson provided earlier. I'll just touch on a high level on some
notes.
If you look at the schedule in general, we've met all the
milestone schedules. Both the staff and Duke have met all the milestone
schedules. The SER was actually issued a day ahead of schedule. It was
scheduled to be issued June 17, and we issued that on June 16.
As far as the hearing status goes, Greg mentioned that there
was a potential intervenor, the Chattooga River Watershed Coalition, and
the only thing that I would have to add to Greg's discussion was the
Commission did affirm the ASLB's decision to deny the petition in April.
The deadline to file an appeal by Chattooga has just recently passed,
and the staff has not seen any appeal filed by Chattooga River Watershed
Coalition.
As far as the comparison between the Oconee and Calvert
Cliffs license renewal reviews, there are some obvious differences. One
is a CE plant; the other's a B&W plant. But if you look at the
applications, you'll note that Calvert was pretty much based on a
vertical approach, in that they for a particular system would list how
they did the scoping and screening process for that system, how they
identified the aging effects, the aging-management programs and TLAA's.
It was based on a system approach.
If you look at Duke's license renewal application, it's more
on a horizontal approach. Chapter 1 is the introduction. Chapter 2 on
a high level is how they did the scoping and screening process broadly.
Chapter 3 is the aging effects. Chapter 4 is the aging management
programs. And Chapter 5 is the TLAA's.
When you look at the SER's for Calvert and for Oconee,
you'll note that the SER's actually look more like the Oconee approach,
in that chapter 1 is an introduction, chapter 2 discusses the scoping
and screening process for particular systems, chapter 3 is actually a
combination of the aging effects and aging management programs, and then
chapter 4 is a discussion about the TLAA's. So although the
applications differ in their approach, the SER's look similar.
Also, we've -- as you know, Duke relied on several topical
reports, and that's been discussed. Specifically they relied on topical
reports for RCS piping, pressurizer reactor vessel internals, and
fluence methodology. So that's a difference between Calvert and the
Oconee approach.
The only other thing that I'd like to mention as far as
differences go is when you actually look at the plants themselves there
are some differences, although we're trying to come to convergence.
With 103 plants out there, you're going to come across unique
differences. And when you look at Oconee, some of the differences are
that they have a hydroelectric plant as an emergency power supply. They
also have a building called the standby shutdown facility that doesn't
exist at Calvert.
Anyway, I just give you that as a note that generic
resolution can only go so far.
Continuing on with the license renewal application,
regarding the license renewal inspections, there's actually two
inspections that are scheduled, and there's a third inspection that's
optional. The first inspection was on the scoping and screening
process, and that was done in April. The finding out of the inspection
report or actually I'll read you a sentence from the beginning of the
inspection report.
It basically says with the exception of the items identified
in this report, your scoping and screening process was generally
successful in identifying those systems, structures, and commodity
groups required to be considered for aging management. The issues that
are detailed in that inspection report you will also see crop up this
afternoon in Bob Latta's discussion. We do have an open item in that
area that Bob Latta will talk about. And the inspection report alluded
to that open item.
The second set of inspections are on the aging-management
review, and that's actually broken up. It's a two-week inspection. The
first part happens July -- is scheduled for July 12, and the second
portion of that is scheduled for July 26. The staff has actually --
because one of the units will not be in an outage during that time
frame, the staff has already gone down there when Unit 1 was in an
outage to take a look at areas that are not going to be accessible when
they go down there in July.
And then the last inspection is a final verification which
is at the region's discretion, and that's an optional inspection.
As far as the future for the Oconee schedule, if you go back
to the schedule dates, the next target date is Duke is to respond to the
open items by October 15. The staff is scheduled to issue the SER in
February. The ACRS final meeting is scheduled for May. And then the
license renewal is scheduled for August 2000.
I'd like to move on on a high level and let you know how we
handled the Priority 1 license renewal issues for Duke. The next two
slides in the package basically tell you what the issue is, a brief
description, and then where it's dispositioned in our SER. And the lead
presenters will talk about the issues when they come up here. There
are, however, four issues that will not have further discussion, so I'd
like to touch on those quickly.
The first of those would be 98-0003, which is operating
experience, and the note that we have is Duke provided the information.
If you look in their application and also in our SER you'll see
references to operating experience. And in general the Priority 1 issue
is how are you going to use operating experience and to what extent are
you going to use it for your SER. We've done that. It's not contained
in one section in our SER, it's spread throughout the SER.
The second issue I'd like to talk about just briefly is
98-0009, which is the FSAR content. We have an open item in our SER.
The open item number is 3.0-1. We have not settled with Duke what the
FSAR supplement should look like. In part of their application they
gave us what they believe is the necessary changes to their FSAR. The
staff has reviewed that as part of their application, but there are
several things that are intertwined with that issue, and if you look at
the open item in the SER, I'll just read a quick sentence from it, it
says therefore, the resolution and the information that needs to be
added to the FSAR will be addressed after other open and confirmatory
items are resolved prior to issuance of a renewed license. That will be
one of the last open items that we'll take care of.
Another issue that I just note is consumables. It's
98-0012. It is actually not a Priority 1. The reason that I mention
it, though, is that there are several open items that are in Section 2.2
of our SER that touch -- that refer back to this consumable position
that we just recently issued. So that's just a piece of information for
the subcommittee.
And the last issue that will not be touched on by a specific
reviewer is 98-0068, which is the coded additions. The note that we
have on the slide is Duke provided the information. The concern with
this open item was to what extent -- or the concern with this Priority 1
issue was to what extent are code additions going to be used and how is
the staff going to judge them to be acceptable or not. And basically
what you'll see throughout the SER and the guidance that was provided to
the staff is if Duke references a code addition, you have to make sure
that they -- a code, they have to reference the addition. And the staff
has to agree with that addition. So you'll see that throughout the SER.
That's not contained in a particular section.
And as far as the status of the Priority 1 issues, those are
the things that I wanted to note.
Unless there's any questions, I'm done with the
presentation.
CHAIRMAN BONACA: Okay. I think the next presentation we
have on the schedule is Duke's presentation.
So we adjourn now and then resume at one o'clock, and give
time also to the subcommittee to participate in that meeting with BG&E.
MR. GRIMES: We're going to hold our monthly management
meeting at noon with BG&E and Duke and talk about the status of both
reviews, and we'd be pleased to have the ACRS subcommittee join us.
CHAIRMAN BONACA: Okay. With that then we adjourn this
subcommittee meeting for the morning, and we'll resume the formal
presentations from Duke Engineering at 1 p.m.
[Whereupon, at 11:36 a.m., the meeting was recessed, to
reconvene at 1:00 p.m., this same day.]. A F T E R N O O N S E S S I O N
[1:01 p.m.]
CHAIRMAN BONACA: We are going to resume the meeting of the
subcommittee, and I believe we are about 40 minutes ahead of time in our
schedule and we have now the Duke Energy Corporation presentation.
Hopefully, we will complete the scheduled SCR reviews on time. If we
are ahead of time, I would like to possibly advance some SCRs from
tomorrow morning into today.
MR. GRIMES: We will attempt to accommodate that. We will
keep an eye on the clock and see where you are going and then we'll see
whether or not the Staff that had planned on coming tomorrow is
available.
CHAIRMAN BONACA: Okay, and in case we can, we will adjourn
the schedule at 4:00 p.m. for the discussion of the ACRS, so with that
in mind, let's start now with Duke Energy Corporation's presentation.
MR. COLAIANNI: I am Paul Colaianni. I will be doing the
presentation this afternoon. Also I do have Mike Sumner up here, who is
the mechanical lead. I am the electrical lead for the project, so if
you have any questions, which I encourage, do ask as I go along.
First, I would like to put up the slide -- photograph again,
and of course being mechanical Greg Robinson forgot to point out the
most important feature of the slide, which is the switchyards, which as
an electrical --
[Laughter.]
MR. COLAIANNI: -- engineer, I just wanted to point that
out. Electrical seems to be forgotten in many things in license
renewals.
VOICE: That is our loading dock.
MR. COLAIANNI: For the disciplines, as Greg explained this
morning, we split it up to the engineering disciplines basically, and
the basic rule of thumb we used is that if it carries current it is
electrical, if it supports, protects or restrains the movement of a
component, it is civil structural, and pretty much everything else is
mechanical. There are maybe a few exceptions to that, but that is kind
of the basic rule that we took the whole plant and split it along those
lines to begin our reviews.
For the scoping of components, each discipline used a
slightly different approach. Structural relies on a CLB definition that
appears in the UFSAR, Mechanical went straight from a functional review
process and Electrical uses an encompassing approach, so you will see
these differences play out as I describe them in the presentation.
All the reviews that are taking place, as Greg described
this morning, we had a separate review for the reactor coolant system,
separate review for the containment structures, and then we had a
systems, structures and components review, mechanical components, and
electrical components. These three are what I will be covering this
afternoon, the three discipline reviews.
This gives a layout of the topics I will be touching on
during the presentation. The first one, the IPA, Integrated Plant
Assessment, scoping and screening for each of the three disciplines, and
then the aging management review for all three disciplines, TLAA reviews
for all three disciplines, and the programs and activities that are
credited for license renewal. So that lays it out. The first topic
will be the scoping and screening.
We will take up each engineering discipline separately.
Next slide.
Now an overall look at the scoping and screening for the
three disciplines, the structural and mechanical component methodologies
are consistent with NEI 95-10. We use that as the basic guide for going
through the reviews. The electrical component methodology follows the
requirements of Part 54 and also uses guidance in the statement of
considerations that was published with the rule and is generally
consistent with the guidance provided in 95-10, although there are some
differences and exceptions to that guidance.
The structural review, scoping and screening methodology,
the basic methodology was to identify the structures and the structural
components within the scope of the rule, and their intended functions,
and then from that list to identify the structures and structural
components subject to an aging management review, there again applying
all the scoping/screening criteria.
This is laid out in a simple flow chart where all the
structures are identified, then the structures are scoped and intended
functions are identified for the scoping process, then these in scope
structures are broken down into the structural components that make up
those structures, and the intended functions of those structural
components are scoped, so within each structure the structural
components are determined whether they meet an intended function or not.
From all that you get the structures and structural components subject
to an aging management review.
Here is an example of the scoping summary. Basically all
the structures are listed in the left-hand column, and this would
continue on for all the structures. This is just a sampling of the
first few. The classification of structure is here, and that is either
Class 1, 2, or 3 as defined in the Oconee SR.
This defines whether it is within license renewal or not,
yes/no, and the function. Basically on these I think there's 12
criteria that define all the intended functions that a structure could
have, so basically if it meets any of these functions then it is within
the scope of license renewal.
Then the break-out of the detail for safety-related and
nonsafety-related and the regulated events, those are broken out
separately and each of those criteria is answered yes or no as to
whether parts of the structure meet the license renewal intended
functions, and in documentation information on the right, so that is
like a first page.
I will give you an example of that process. The results
shown on a global scale are these are the structures that were found to
be within the scope of license renewal. There are several structures
that are outside normal structures and equipment pads, and those are
grouped down in the last one called Yard Structures, which includes a
lot of outside things such as trenches and towers and elevated tanks and
transformer pads.
This is a complete list of all the structures that were
included in the scope of review.
Going from those, basically this shows a matrix that was
used for each of the structures that was listed in the last table. We
have got them listed here and then what was broken out here was all the
possible components, structural components, that might be in any of
these structures. The list would go down further than this for a
complete list, and then for each of the structures an "x" would indicate
that there are some anchors, anchorages or embedments in the auxiliary
building, and the same determination would be made about all the
structures, basically outlining all of the structural components, all
the piece parts within that structure that would pertain to it.
That pretty much ends the structure scoping and screening.
The mechanical component scoping methodology basically looks at --
splits it based on systems, splits up the plant, and the systems are
scoped using the criteria and rule along with determining the intended
functions to see what intended functions they serve, and then the
identification of components within these in-scope systems are
determined along with their intended functions, so it is broken down
first into system, and then looking in those systems for what components
in those systems are in scope.
The mechanical scoping process for each criteria look like
this for 54.4(a)(1) and (a)(2), the safety and nonsafety, a functional
flow path identification using event, mitigation and calculations. At
the start of the process, fluid pressure boundary determinations were
made, physical interface identification was made, and then other
designated item identifications, anything else that should be included
within the review, and this information was documented not only in
calculation but also onto mechanical system flow diagrams where the
diagrams were highlighted to show the portions of those systems that
were in the scope of license renewal for any of the criteria.
This slide shows scoping events that were used scoping
calculations that were done in the mechanical scoping process. This is
basically all of the events that we used to determine what components in
the mechanical systems need to be part of the scope of review.
CHAIRMAN BONACA: I understand there is some difference with
the Staff or some questions to resolve, and I am trying to understand
what is it. Let me ask a question. For example, you have loss of main
feedwater in the scoping. Why didn't you have feedwater line break? I
am trying to understand what the issue is, okay?
MR. COLAIANNI: I know the Staff is going to go into some of
that explanation of the issue also, but Mike, do you want to get that
or --
MR. SUMNER: I think I need to refer that to Greg.
MR. COLAIANNI: Okay.
MR. ROBINSON: In that particular example, we did not
exclude looking at things like feedwater line break. What we did is we
focused on including the things that have traditionally been part of the
design and licencing basis of the plant and make sure that we clearly
defined what that set of events was, and then focused on that.
We recognized that over the course of the last 25 years many
other events and topics have come along and we have looked at them and
addressed them and made sure that we understood their applicability to
the plant, but we did not see them as design basis events or events that
we would use for scoping.
CHAIRMAN BONACA: Okay. I tried to go through a little
exercise to see if I understood this issue, because I think it's one
that keeps going back and forth.
For example, I made the example that if you go to line break
because if you had to go to line break, you have to have certain
equipment to deal with it. In that case you would want to have
isolation of the lines.
My understanding is that Oconee doesn't have main feedwater
isolation valves but it has control valves used for that function.
Therefore the expectation from the rule would be that the control
valves, at least the passive portions of that, would be addressed in the
rule. Now if you told me they are addressed in the rule because we are
including them by some other means, that would be satisfactory to me,
but I would like to know what the answer is to that question.
MR. COLAIANNI: And there again we have tried to go strictly
from Oconee's definition of what we have traditionally had as our design
basis events, and from that, that is basically where we got this list.
CHAIRMAN BONACA: So going back to the question, then there
would be passive components in the feedwater control system or the
piping. Are they included in the scope of the application?
MR. SUMNER: My name is Mike Sumner. Yes, they are. They
are included.
CHAIRMAN BONACA: So they are by some other means. Okay.
MR. ROBINSON: This is Greg Robinson. They were classified
on our documents set as being safety-related and how they got to be
tagged as safety-related we can debate forever, but in that particular
example the piping and the valve bodies and things that were already
identified, and Paul mentioned on the highlighted flow diagrams we did
go through and highlight the schematics to point out the areas that we
have traditionally had labelled as safety-related in the plant, and it
does include those.
CHAIRMAN BONACA: All right.
DR. SHACK: But the answer is the process was essentially
done by tradition then?
MR. COLAIANNI: The process was to go by what we understand,
what Oconee understands as Oconee's design-basis events, and that is the
starting process.
DR. SHACK: What are the infamous additional 32 events for
possible inclusion? Somehow you did seem to sort through these things
in some way. What was that process? Was it again tradition? The 32
weren't traditionally considered safety?
MR. ROBINSON: This is Greg Robinson. I will try to answer
that.
MR. COLAIANNI: I'll refer to Greg, yes.
MR. ROBINSON: What we did was somewhere around the late
'80s or early '90s with our design-basis documentation program, we
realized we needed to write down some of our tribal knowledge in a
history.
We had longstanding licensing and design engineers who knew
how the plant design evolved over time, but we did not have that written
down. In the process of writing that down through the course of the
1990s, we got to a point where we said it would be nice to step back
from the particulars of writing down each item as we think it applies to
Oconee and take a more global look.
When we did that, we said let's go look around the industry,
everything everyone has considered, and we came up with about 58 -- I
believe that was the number -- 58 different events that had been
considered, some of which were never considered on Oconee, but we wanted
to include them in the mix. From that, we sorted through the licensing
basis, essentially compiled the licensing basis of the plant to find
these numbers of events that you see up here on the screen, and the
other number, the 32, were the ones we found not to be applicable, but
the broad view didn't occur until the early to mid-'90s.
We backed away from the problem and said let's take a broad
view of this and make sure we are in the right ball park.
DR. KRESS: Did the PRA play any role in this at all?
MR. ROBINSON: Not directly in establishing these event
sets, no, sir.
CHAIRMAN BONACA: I understood the licensing basis for the
plant, but we are looking here for aging of components which play a
significant safety role, so to me it doesn't matter if they are
safety-grade or control-grade at this stage -- that was part of the
original license and we are not questioning that. We are questioning
whether or not we are capturing them in aging programs, and you gave me
an answer for the feedwater system that said yes, we do. Well, that
specific one.
The question is broader in general. It is are you capturing
them in any case?
MR. GRIMES: Dr. Bonaca, this is Chris Grimes. I would like
to clarify that we have concentrated on applying the scoping criteria
and 54.4 and the Staff will explain in its presentation the open item,
but when we apply those criteria we apply them to identify those
intended functions that are associated with the design basis and so if
we find, as you pointed out before, if we find that we can think of an
event that they didn't include in their methodology, the first thing we
are going to do is go see whether or not it matters in terms of whether
or not that excludes an intended event -- or system, structure or
component.
But in the event that we find that they did not consider an
event and they don't have, as you pointed out, they have got some design
differences, if it ends up excluding some system, structure or
component, the first question we have to ask is is that a deficiency in
the licensing basis that should be treated under Part 50 today, rather
than trying to solve it as part of license renewal, so we are trying not
to backfit the design basis in license renewal.
We tried to be very careful about that in order to make sure
that license renewal wasn't doing something it was not intended to do.
MR. ROBINSON: May I add, Chris -- Greg Robinson -- in
addition to the focus that both Duke and the NRC had on meeting the
regulations or working to meet the regulations, we did on a
plant-specific basis take a look a the risk-significant results from the
maintenance rule efforts, and the results from the license renewal
efforts, and when you overlay them we have found that the
risk-significant mechanical systems that were determined through other
risk processes are included in the license renewal scope and do receive
aging management review, so I can answer that part of your question.
CHAIRMAN BONACA: So also indirectly you are answering Dr.
Kress's question?
DR. KRESS: Yes, indirect answer to mine, too.
MR. NEWBERRY: Scott Newberry, Staff. Just by way of
example -- that is a good question and I remember back in rulemaking we
talked about risk significance, and one of the reason the scope --
because of those questions, the scope was expanded to explicitly include
ATWS, station blackout, and fire protection equipment and they are
listed explicitly in the scope.
CHAIRMAN BONACA: Okay.
MR. COLAIANNI: So using also in addition 54.4(a)(3),
basically the mechanical systems that satisfy the regulated event
criteria were picked out of the licensing commitments and design
documents. They related to those for each of those four -- those five
events -- and those components were pulled out and made sure that they
were included in the scope of review.
Now for the screening -- that was the scoping -- for the
screening basically Mechanical used, put a menu up of active versus
passive components, and the mechanical groups that were highlighted were
run through that menu to determine the passive components in the systems
in the in-scope systems that needed to be reviewed, and that is
basically what this slide is identifying.
The list of mechanical components subject to aging
management review, a list was provided in the application to identify
those components.
Here are the results of the scoping, all the systems at
Oconee that were included or that meet the scoping criteria, and you
have got Oconee systems that are with the plant proper, the safe
shutdown facility -- or standby shutdown facility systems, and then the
systems at Keowee, which is the hydroelectric plant supplying emergency
power, but this is a list of all the systems that meet the scoping
criteria.
An example here is given next on how the components were
screened. You have got the systems listed here and these are the
different materials that might be part of the system and this gives
remarks on the materials and where the information came from. This is
what shows up in the station calculation that identifies the components
within a system, the materials.
Now we are on to electrical. The electrical scoping and
screening methodology as basically laid out is a little bit different
from the mechanical approach. Except for specific components that are
scoped out or screened out, all plant electrical components are included
in the aging management review. To explain that a different way and
contrast it to the mechanical approach, for mechanical the systems were
defined and everything was scoped to determine exactly what was
in-scope. In electrical it turned out to be more efficient for Oconee
to start with the whole plant and only screen or scope out a few pieces
of equipment for particular reasons but leaving the rest of the
components in, thereby having an encompassing review of components that
are both in-scope and some that are not within scope but not trying to
differentiate exactly which ones meet which criteria.
It does include everything that is in-scope but it does also
include components that do not really meet the criteria.
So the way that breaks out in the scoping and screening
criteria, 54.4(a), the scoping, basically everything is scoped in but a
few specific commodity groups of electrical components are scoped out.
Evaluation is done to scope them out. The screening criteria for the
active-passive components was actually applied to all electrical
component commodity groups, so this was done for all of them.
The screening criteria for the replacement criteria was only
applied to a few groups of components but was not applied to everything.
The basic evaluations for electrical did not break it down into systems
to start out with, it broke all the electrical components into
components in commodity groups to start out the review.
This chart shows the basic process -- identify electrical
component commodity groups installed at Oconee along with their intended
functions, and then applying the scoping or screening criteria. These
were not done as it shows here really in a sequence. They were all done
sort of as independent steps, and then what came out of the scoping and
screening were a list of electrical components that were included in the
review.
Here we have a table that shows all the electrical component
commodity groups. This basically describes all the electrical commodity
groups that are installed at Oconee.
Some of the commodity groups are broader than others, but
basically that includes everything in the plant.
This table gives the results of the application of the
screening criteria, the passive-active screening of components. It was
done to all the components. Most of the determinations were made
elsewhere or documented elsewhere to start out with in the rule. You
have the reference documents. The rule says that these particular
components are subject to or do meet the criteria, the passive criteria,
and these particular components do not meet the criteria.
The working draft of the SRP in NEI 95-10, which has the
same tables, say that these particular components do not meet the
criteria. There is a September 19 letter from the NRC to NEI that
particularly speaks to these particular components as not meeting the
criteria, and at the time this table was made, what Oconee did in the
application was address these particular sets of components, some of
which did meet the criteria and some of which didn't.
Since then in particular there's been an NRC letter which
addressed fuses that probably should be added to this table, but for
Oconee really it's just these determinations that really should be of
discussion in the application.
This gives the results of all the electrical components that
are included in the aging management review. Here you have the
component commodity groups that had components that met the scoping and
screening criteria, and this describes in words the groups of components
that meet the criteria, giving exclusions where necessary, and this
lists the intended functions that were used for the components, but that
is the complete set.
Now I will go on to the integrated plant assessment aging
management review for structural, mechanical and electrical components.
Although the scoping and screening was done slightly
differently for each discipline, when you get to the aging management
review it is done, really addressed the same for all three disciplines.
The reason is that at a high level you have got component
materials and you add in component environments or stressors that could
affect those materials and also you look at potential aging effects --
what sort of aging effects can happen to those materials, and then
basically you are looking at determining whether those aging effects are
applicable to those materials in those environments, and applicable also
meaning having a time limit is going to cause the loss of intended
function if unmanaged for the period of extended operation.
The TLAA reviews that were performed I will discuss next.
The TLAAs involved plant-specific design analyses, focused on boundary
conditions or assumptions based on the 40-year operating term, and the
action is to assure that the analyses are valid for the extended period
of operation or that the effects of aging will be adequately managed for
60 years.
Oconee-specific time limit aging analyses have been
identified by reviewing the Oconee UFSAR documented correspondence and
other topical reports. The resultant list includes EQ fatigue, tension
loss and pre-stress, reactor vessel embrittlement, just as some
examples, and no Oconee exemptions were based on a time limit aging
analysis.
The TLAA process is consistent with the guidance provided in
NEI 95-10, the process that was used by Duke, and provides reasonable
assurance that we found them all and evaluated them.
The last area that I will cover is programs and activities
credit for license renewal.
This chart gives an overview of all the programs that are
credited for license renewal, a total of 50; 28 are existing programs or
activities that are going to require no change at all. There are 11
existing programs or activities that need to be enhanced in some way or
other, and then there are 11 new programs or activities that need to be
instituted at the station.
This is a list of the 28 existing programs that do not
require any changes for license renewal, this is the list of the
existing programs to be enhanced, programs and activities, and a listing
of the new programs and activities. Most of these new programs, from
here on down, are inspections, one-time inspections.
CHAIRMAN BONACA: Before you change that --
MR. COLAIANNI: Yes?
CHAIRMAN BONACA: -- just could you give me an example of an
enhancement in one of them, just to get a feeling for --
MR. COLAIANNI: Okay. Mike, can you give us an example?
Maybe the Keowee oil sampling?
MR. SUMNER: My name is Mike Sumner. The Keowee oil
sampling program at the hydro station has been there since 1970 and they
take oil samples on a periodic basis for years and have them analyzed,
but it wasn't formalized. The results were very hard to come by. They
just did it. It was done by the fossil hydro department.
We enhanced that program by making it very formalized and
having a bonafide frequency and documenting results and keeping track of
stuff like that. That is a particular enhancement.
CHAIRMAN BONACA: Okay, thank you.
MR. COLAIANNI: All right. Talking about the safety
evaluation report, it was recently issued. There are 43 open items and
six confirmatory items; 28 of the 49 are relatively straightforward to
address. We don't see any real complications coming in for those.
Three of the 49 items are related to the UFSAR supplement. Eighteen of
the 49 in five different topic areas will require meetings. The topic
areas are scoping process and results, complex assembly boundaries,
consumables, CASS components, and reactor vessel internals.
To end up -- some observations on implementing the license
renewal rule. These are rather broad but basically we saw a need to
develop clear definitions of terms so that we as an industry and the NRC
can be always talking from the same page. That would help streamline
the process.
Document scoping and screening processes -- in a lot of
respects that is talking about the electrical process which wasn't
represented in the NRC guidance and/or in the inspection plans, and just
basically it would make the process easier if that were included, to
broaden the ability of the utilities to use efficient means to get
things done.
Also, develop a technically sound process for handing
emerging issues -- GSIs is an example. That sort of thing. But these
are just some broad topics, observations that we have had that would
help the process.
That ends my presentation, unless there are any questions on
any parts?
CHAIRMAN BONACA: Just looking at the programs you had to
institute, you have the 11 new programs and activities. This seems to
be a significant fraction of the overall programs that you are talking
about. I mean you had 28, 11 are enhanced and 11 are new, but --
MR. ROBINSON: This is Greg Robinson, if I may, a little
explanation of the programs.
If you will note, there are two new programs, and both of
them were discussed or mentioned, at least the Alloy 600 was mentioned
in this morning's discussions. Those are really the only true new
programs. A point on the inspections below that, the nine inspections
below that. In many cases when we could not characterize an aging
phenomena, we just did not feel comfortable technically to say a
phenomena was not occurring. We said why don't we go look, and so the
one-time inspections are aimed at doing that aging characterization.
If there is aging present, we will continue on and the
process will allow us to implement some programmatic action. If there
is not any aging present or we cannot determine that there is any, we
will then be able to form a better technical conclusion and those will
drop off, and so there's only two that we plan to carry forward, so the
percentages change when you look at it from that perspective.
MR. TUCKMAN: Mike Tuckman. If you look at it from the
perspective of work hours expended in the year, there is not a
relationship to the number of programs. Most of the programs that are
in place are very heavy usage programs. These one-time inspections are
relatively small in comparison.
DR. KRESS: When you look at the fact that you did add a
couple of new programs, and you may add more depending on these
inspections, is that a lessons learned for operating plants that aren't
yet thinking about license renewal? Should those programs be there?
MR. GRIMES: This is Chris Grimes. I will tackle that one.
We would not expect individual license renewal applicants to
reflect on the generic implications of these findings. We have
identified half a dozen to a dozen issues that have come up as the
guidance for license renewal has formulated. We refer to the panel that
reviews events and determines what things warrant further action. Some
of these things have evolved in bizarre and unusual ways, but they do
get fed back into the operating reactor program.
DR. KRESS: That was basically my question.
MR. GRIMES: We feed back this experience into the normal,
into the regulatory process because license renewal is predicated on the
regulatory process carries forward through the period of extended
operation in order for us to focus on just this small set, and I would
like to provide a different perspective on the statistics.
That is, irrespective of whether or not the inspections are
done every day or they are done once in a 60-year period, they lend to
the public credibility of our knowledge, understanding and ability to
address whether or not those aging effects will have an impact on the
intended function in the unlikely event that a design-basis accident
should ever occur, and so from our perspective on the statistics, we
essentially weigh things that occur routinely almost the same way that
things that we want to just verify we never need to anything more about
it.
CHAIRMAN BONACA: I had a question. These are
inspections -- the ones on the right side, my right side. I see that
pressurizer examinations, but this morning I asked a question because I
saw a program that covered that and I was told that the program provides
for examinations to be stepped up in case you have in fact findings from
those inspections.
MR. GRIMES: Right.
CHAIRMAN BONACA: So these are not just one-time inspections
outside of some kind of programmatic requirement. You have some
programs under which you are going to put those?
MR. GILL: This is Bob Gill. Let me clarify. These are
different pressurizer components than the ones we talked about this
morning. This is in fact the heater bundle and actually the interior
cladding and spray nozzle, not the Alloy 600 parts.
CHAIRMAN BONACA: Okay.
MR. GILL: And in fact the pressurizer cladding was a
concern from an operating experience event about 10 years ago. We are
going to go in and look to see if there is any indication of iron oxides
on the cladding and then go further, the pressurizer heater bundles, the
stress corrosion cracking of a weld which might lead, and so that is
different than the Alloy 600 big program we were talking about, which is
up there at the top. There is overlap on some of these. It's just the
way they got binned and when they were born and that type of thing.
DR. SHACK: A similar question on the small bore piping in
the sense that you have had problems with small bore piping --
MR. GILL: Right.
DR. SHACK: -- and you are looking for now a particular in
this inspection.
MR. GILL: This would be different piping. If you flip up
the other overhead with the existing programs, let's touch on that
briefly.
The existing programs that we have had operating experience
on is the program to inspect the high pressure injection connections
throughout the cooling system. We had the event a couple of years ago.
Many years ago the B&W Owners had an event, created a program. There
was a generic letter and all that. We had some problems on implementing
that program, but that is an existing program that covers that specific
location, its unique thermal phenomena, its situation there. We do
RT/UT, all kinds of examinations on that. Many inspections are done on
those nozzles. Those are HPI makeup nozzles.
To flip back to the small bore piping, that is different.
That's events in drains and impulse lines and other things that are less
than four inches, not the HPI nozzles per se.
CHAIRMAN BONACA: All right. We would like to get a sense
from the Staff when we have a presentation of how this compares with the
BG&E application.
MR. GRIMES: We are going to cover that during the separate
discussion tomorrow on the credit for existing programs.
CHAIRMAN BONACA: Okay.
MR. GRIMES: In a general way -- and we will try to show you
the contrast.
CHAIRMAN BONACA: From our perspective it is very hard to
compare. It seems almost apples and oranges in that BG&E have
approximately 400 programs and here we are talking about 50. They are
different things, I understand that, but I would like to put them in the
same context so we understand.
MR. GRIMES: We are going to cover that during tomorrow's
session.
MR. TUCKMAN: Dr. Bonaca and Dr. Shack, this is Mike
Tuckman.
It is interesting to note, since you asked the question
about small bore piping, that is not a program that we had identified as
something needed to be done. We believe the ASME code was sufficient to
and does require various visuals, et cetera, of small bore piping. This
was something that came out in the NRC's SER on reactor coolant system
piping and when you talk later about credit for existing programs, one
of the concerns of the industry has been the accretion of requirements
from existing programs, and that would be an example of one that we
added as a result of the review process from the NRC but I don't know
that we would necessarily agree it should have been added.
Did I do that right, Chris?
MR. GRIMES: Yes, sir. We twisted his arm. It's just a
question of whether we twisted it fairly.
[Laughter.]
DR. SHACK: Would that be true also of the reactor vessel
internals aging management program?
MR. TUCKMAN: I don't think so.
DR. KRESS: Does Oconee deal with design basis hydrogen by
using recombiners?
MR. TUCKMAN: Yes.
DR. KRESS: Is there not a program associated with those
that -- I didn't see it on your existing programs. It seems like it is
a component needed to mitigate the design-basis event.
MR. COLAIANNI: And it is included in the review.
DR. KRESS: It is part of the review?
MR. TUCKMAN: Yes.
DR. KRESS: Gets screened out for some reason?
MR. SUMNER: This is Mike Sumner again. We evaluated and it
had no aging effects because it is stored in the warehouse. It is a
portable piece of equipment.
DR. KRESS: Oh, I see. It's not in there --
MR. SUMNER: It is not in the reactor building, no, sir.
DR. KRESS: I see, I see, so there wouldn't be any aging --
MR. SUMNER: Right. We keep it out in the warehouse and
keep it warm.
DR. KRESS: -- because it is in a controlled environment.
MR. SUMNER: Yes, sir.
MR. COLAIANNI: It has a heater that we keep it up at about
200 degrees to keep it warm and dry.
DR. KRESS: Okay.
MR. COLAIANNI: Any other questions on any aspect of it?
[No response.]
CHAIRMAN BONACA: If none, I want to thank you for a really
informative presentation. Thank you.
MR. COLAIANNI: Okay. Thanks for the chance.
CHAIRMAN BONACA: Now we are moving to Staff presentations.
MR. LATTA: Good afternoon, gentlemen. My name is Robert
Latta. I work in the Quality Assurance, Vendor Inspection, and
Maintenance Branch within NRR. My function was to review the aspects --
the application related to scoping and screening.
Section 2.2 of Exhibit A of the application described the
methodology used by Duke to identify the mechanical systems and
components to meet the requirements of 54.4(a)(1) and (a)(2), that being
safety-related and non-safety-related components. These requirements
state in part that the plant systems -- excuse me, the plant -- I'd
better have that light on, I can't read -- these requirements state in
part that the plant systems, structures, and components that are within
the scope of this part are safety-related SSE's that are those relied
upon to maintain functional during and following design basis events as
described in 50.49(b)(1).
However, as described in the application, the design
criteria to which Oconee Nuclear Station was originally built did not
include all of the systems, structures, or components that needed to be
included under the safety-related criteria defined under 54.4(a)(1) or
the non-safety-related criteria defined under 54.4(a)(2). Therefore,
Duke relied on the results of a design study that identified the systems
and components that are needed to fulfill the safety-related criteria
defined in 54.4(a)(1).
Since the design study conducted by Duke only validated
those functions required for the successful mitigation of Oconee design
basis events identified in chapter 15 of the FSAR, it was unclear to us
whether or not all of the functions required for the successful
mitigation of these DBE's set forth in the Oconee current licensing
basis have been identified as required under the rule. Further, since
Duke's methodology had not identified all of the SSC's required under
54.4(a)(1), the potential existed that these conditions also existed for
components addressed under 54.4(a)(2), non-safety-related SSC's.
During the staff's most recent meeting with Duke
representatives on May 11, 1999, involving Oconee's license renewal
application scoping issues, RAI 2.2-6, the staff identified two action
items that needed to be resolved within the confines of the SER. And
those are described on my first slide here, that is, that the applicant
is to review their response to RAI 2.2-6 to include a description of the
processes used to identify the events for Oconee Nuclear Station's
license renewal scoping and expansion as to how these -- and an
explanation as to how these 26 events identified during the May 11
meeting are sufficient to satisfy the requirements of 54.4(a)(1) and
(a)(2).
Subsequent to the development of these slides, we did
receive the letter from Duke that was dated June 22 which provided their
revised response to the RAI. This included a description of the 26
events used for mechanical license renewal scoping relative to the
second bullet there where we were evaluating subsequent to the receipt
the need for future inspection efforts that is an ongoing effort within
our organization.
Questions related to the open item or --
MR. GRIMES: Is that all for 2.1, Bob?
MR. LATTA: Yes, sir.
MR. GRIMES: This is the way that the scoping issue that you
referred to, Mr. Bonaca, this is the way it's characterized in the
safety evaluation, and we have received a response from Duke concerning
how they identified the 26 events, and as I mentioned before, our
objective in this review is to make sure that we're satisfied that all
of the intended functions associated with the current licensing basis
have been identified and that the associated systems, structures, and
components that are relied upon to perform those functions have been
properly screened or have been subject to an aging-management review.
And so we're going to, as Bob mentioned, we're going to proceed to
pursue the information supplied in the letter from Duke. Copies of that
should have been provided to the ACRS, but I'll make sure that Noel --
DR. SHACK: We have it.
MR. GRIMES: Okay.
CHAIRMAN BONACA: Okay. So right now this remains an open
item.
MR. GRIMES: Yes, that's correct.
DR. KRESS: Does the staff have any plans to use something
like a risk-importance measure, components that end up -- to see if the
design basis actually captures all of the ones that you might -- risk
important?
MR. GRIMES: We used risk-importance measures in order to
focus the scope of our inspection activities. As I mentioned before,
we're consciously avoiding trying to challenge the adequacy of the
current licensing basis to --
DR. KRESS: I recognized that was your marching orders.
MR. GRIMES: But that doesn't -- as I also mentioned before
also, the process provides that we try and do smart samples that we look
at things that have risk importance in terms of the processes, the
methodology, and the aging-management program. So we're going to look
in areas that if there are questions, you know, concerning whether or
not the intended functions are really doing the right things relative to
plant risk, we find something and we'll pass it on back to folks to
think about in terms of the current licensing basis.
DR. KRESS: So you really don't -- oh, you think that might
ought to be incorporated into the licensing basis?
MR. GRIMES: If we find something that's risk-significant
for which there is some question about whether or not the current
licensing basis is the right current licensing basis.
DR. KRESS: Would that have to be subject to a backfit?
MR. GRIMES: Yes, it would. We put it into the appropriate
process for making decisions about changing the current licensing basis.
MR. NEWBERRY: Dr. Kress, let me follow up. A week before
last we got our staff requirements memo from the Commission on
risk-informing Part 50, and in that SRM they tasked us to go look at the
definitions of "safety related" and "important to safety." And, you
know, Bob just mentioned (a)(1) of the rule in terms of scope of license
renewal used the term "safety related."
So even though the SRM is directed at Part 50, we've talked
about it with the industry at our first kickoff meeting, and I think
we're trying to figure out to what extent that project is going to draw
in Part 54. And I think we're going to end up tackling that issue that
you just raised in the context of that effort.
DR. KRESS: Once you approve a license renewal like this,
though, what's going to come, particularly for Oconee, before you ever
get to that.
MR. NEWBERRY: Yes, that's true.
DR. KRESS: You wouldn't go back and grandfather.
MR. NEWBERRY: Mike's going to shake his head no on that. I
don't think so.
MR. GRIMES: Like I said, we're trying to proceed along
this, you know, walking that very careful line, recognizing that the
state of the art will continue to evolve, and we don't necessarily like
being on the cutting edge of technology in terms of fixing the
regulatory process, but we keep being driven there for, you know, a
variety of things.
But in this case, we're just going to try and -- we need to
satisfy ourselves that the suite of events -- as a matter of fact, we
ought to define the term, what is a design basis event. We'll clarify
what we understand the current licensing basis to be, and then we'll
proceed from there to make sure that we've got all the functions.
DR. KRESS: The nature of my question was that clearly
design basis events incorporate risk-significant or else we wouldn't do
them. But my question was are you really limiting yourself to that or
are you making some other sort of overall risk evaluation so that you
assure yourself that you're not really missing something that might be
risk-significant, and in my mind even if it were not captured by the
design basis event, you might want to make it part of the license
renewal. If it's really risk-significant you want to capture it in the
scope of an aging-management program, only to be sure you weren't
limiting yourself.
MR. GRIMES: On the 14th when you talk about policy issues
you can consider that, because we specifically took the language in the
statements of consideration to be an admonition that we should -- the
current licensing basis carries over. But, like I said, if we find
something we think is important, whether it's a plant-specific question
related to the current licensing basis and the state of the current
licensing basis, or whether there's a generic implication, you know,
we'll refer those to the appropriate processes.
MR. TUCKMAN: Dr. Kress, this is Mike Tuckman. I'm from
Duke.
One of the interesting things about this rule is that it is
not a risk-informed rule, it is a very prescriptive rule. I think in
reality we are covering everything, and if an improvement were to be
made in the rule sometime in the future, the scope of things that you
look at in the license renewal would be greatly reduced.
DR. KRESS: You're probably right. I looked at a lot of
things in here that might not have to be in the scope if you did it
really risk-informed. It would probably go that direction.
MR. TUCKMAN: As Greg talked about, we use the maintenance
rule as a kind of a tool to look and see how it matched up with license
renewal, and of course in the maintenance rule we do look at
risk-significant systems and pay more attention to those as we do in
license renewal. But as far as the actual rule went thus far, it was
very prescriptive and you treat everything the same.
DR. KRESS: I recognize it's strictly a design basis
concept.
MR. TUCKMAN: Yes, sir. I think it's very unlikely that we
will have missed it.
CHAIRMAN BONACA: Although everything is captured in the
discussion, but does it mean that you have to do something about it?
All you have to do is to address the need. And so even within the
context of a prescriptive rule, I think that it is a way to soften the
blow, I mean, you can say hey, this is justification for not doing
further inspection. And I think that it's only fair to say that that
should be allowed by the rule.
But I think the only place where it is important is where,
you know, you may have a component out there because of some insights
and it may be from looking at a broader set of initiators, either
through PRA or through deterministic approach, or by one component there
is important and we may have missed it. And that was the thrust of I
guess my question, and I'm sure that that's really what the staff is
doing and will bring to closure. And I don't expect to see surprises, I
mean, to the question I had on the feedwater system, I got an answer
that said we already included it. That's the answer. So -- okay, with
that, any other questions?
DR. SHACK: Well, just on a general, I mean, does the
license renewal give you a way around backfitting in the sense that you
get a chance to look at the degradation of a passive component and have
it addressed whether it's safety-significant or not?
MR. GRIMES: We had one example that was just mentioned in
terms of twisting the applicant's arm to address the lack of an
inspection activity associated with small bore piping, and, you know, we
get into at least do one inspection, check and see whether or not the QA
program needs to pick something up. And in the course of resolving
questions and comments on the standard review plan, there are other
areas like that that have come up where the utilities have said they
don't think that it's worth it, and we've said prove it, and we've, you
know, we'll march through those. Those are the 108, you know, things to
do when we have spare time.
If we can embarrass the industry enough into going out and
checking some of these gaps, then eventually we will have a full
program, but even then by the time we get that cleaned up then operating
experience will say there is something else we ought to go check -- you
just have to follow up there, getting back to Dr. Shack's comment.
These inspections and programs are solely focused on 40 to 60 years, so
the licensee is not obligated unless there is a relationship there to go
look today. The focus is on aging from 40 to 60, so we are not
talking -- remember Chris's comment, to feed it back in -- that is
another process.
DR. KRESS: After 60 years has gone by, can we expect
license renewal renewal?
MR. GRIMES: I'm sorry, what was the question?
DR. KRESS: Can we expect a license renewal renewal after 60
years?
MR. GRIMES: I would want to answer that question in two
ways. The first way is that in this question of credit for existing
programs, we were reminded to point out that we have not even completed
the first two applications yet, and so it may be expected that the
license renewal rule needs to be renewed here in the very near future
based on the experience from the first few applications, and we'll
constantly revisit whether or not this is the right thing at the right
job associated with license renewal, but then the second part of the
answer is we specifically point out that 20 years from now Oconee can
come back and apply to renew the renewed license for another 20 years on
a presumption that the maintenance activities are going to take
sufficient care of the plant so that they could justify continuing
operation, so long as it is economically viable.
MR. TUCKMAN: This is Mike Tuckman. I am going to let
somebody else worry about that problem.
[Laughter.]
DR. KRESS: You are going to be retired by then.
MR. GRIMES: Thank you, Bob. Mr. Gratton and Mr. Shemanski
are going to start with the next section, but I do want to ask this.
The Staff's presentation was set up on a streamlined format based on
some feedback we got from you on the Calvert Cliffs presentation. We
are going through each chapter and we are going talk about the open
items, the confirmatory items and anything the Staff thought constituted
a particularly important or noteworthy thing to pass on to the
Committee, but at the same time, we are here to answer any questions
that you might have about the Staff's evaluation basis, so don't
hesitate to take us in a different direction if you need to.
CHAIRMAN BONACA: Before we start the presentation, the
discussion we just had, one thing that I would like to state is that it
is impressive to see how many programs exist already in the units and
also the insights provided by the maintenance rule, and the existence of
corrective action programs.
I mean on the positive side of it, there has been tremendous
progress in the industry in the past 10 years and it is pretty
impressive to see how ready the industry is to move to license renewal.
I mean there is a lot of stuff in place there that is pretty impressive.
MR. GRIMES: Mr. Bonaca, I would like to emphasize that
although we talk about disputes over what is necessary for license
renewal, we agree that almost all or nearly all of the existing programs
deserve the credit that we are going to give them for managing aging
effects and the area where these disputes probably should continue is a
struggle between the plant operators and the regulators to constantly
challenge these areas where there are programs that don't get a whole
lot of visibility, that don't get challenged often enough in order to be
readily understood as being an effective aging management program.
But we are only talking about out of those 49 open and
confirmatory items there are like five areas of controversy, and
regardless of whether or not you count individual procedures and come up
with a number between 400 and 500, or whole programs and come up with a
number that is like 50, having five things to argue about in order to
come to a conclusion about granting a 20-year license I think is
remarkable in terms of credit to the regulatory process that we have set
up over the last, what? -- four years.
CHAIRMAN BONACA: With that, are we ready?
MR. GRATTON: Thank you very much and good afternoon. My
name is Chris Gratton and I am the Divisional Coordinator from the
Division of System Safety Analysis for the License Renewal Activities,
and what I am going to be discussing today are the scoping and screening
activities performed by the Staff.
Since Chris already took my thunder, this is a streamlined
presentation that will not focus on the process that we use but rather
the results of those activities.
What I am going to cover today are the open items that the
Staff identified during the review, the confirmatory items -- which is
actually only one, so confirmatory item. We will discuss how the Staff
addressed license renewal issues, the Priority 1 issues that were in our
area of concern, and I will discuss one item of interest, the difference
between the BG&E review and the Oconee review that we have just
completed.
As you can see on the slide, the first two open items have
to do with systems that the Staff considered were within the scope of
license renewal yet the licensee did not determine to be within the
scope of license renewal so questions were asked of the licensee to
justify the exclusion of the recirculated cooling water system and the
chilled water system.
The RCW system is a closed cooling water system that removes
decay heat from the spent fuel pool cooling system and transfers it to
the CCW system. The chilled water system provides air conditioning or
cooling air to the control room. Both of these systems we felt met the
regulations to be within the scope of license renewal and we are
pursuing justification for their exclusion.
The third open item is identified here as skid-mounted
equipment. The real clarification is that for an emergency diesel
generator supporting the SSF, the licensee identified the skid as being
within the scope of license renewal but excluded the components on the
skid as being subject to an aging management review under a provision in
Part 54.21 and the Staff believes that it was inappropriately applied in
that certain components on the skid were excluded without consideration
for aging management review. It was just sort of a blank exclusion, so
there are clarifications in NEI 95-10 that we believe they should have
applied and reviewed those components on the skid and we are pursuing
that also.
DR. KRESS: What sort of components are they? Starting the
diesel or --
MR. GRATTON: There are some components associated with the
fuel oil system. This is piping up to the diesel generator, cooling
water to the cylinder cooling jackets, and portions of the air starting
system.
The fourth open item has to do with structural sealants in
general. The issue came about in questions regarding water stops that
were cast in place for the auxiliary building. The Staff identified
them as not being identified as within scope of license renewal at all.
When the question was brought up the Applicant stated that they did not
meet any intended functions that would require them per 54.4.
When that was brought up there is a Staff position on
consumables. We consider these to be consumables, and they should have
been addressed as such, but because they are passive and long-lived, we
felt that they did meet some scoping requirements to maintain the
integrity of the auxiliary building, protecting safety-related equipment
that may be in the spaces from either flooding or intrusion of water, so
we believe they should be within scope and we are still discussing their
inclusion within the scope of license renewal.
The fifth open item has to do with staged equipment, and
this is Appendix R equipment. It includes items such as pumps and
switchgear and cables that would normally not be considered within the
scope of license renewal but because this equipment is staged in a
warehouse and not continually in operation, the Staff believes that some
provision should be made to monitor its again because the rule assumes
that active equipment such as pumps and switchgear are continually in
use, monitored and tested, and this equipment is available in the event
that there is a design basis fire and as such it is not being used.
The last three open items are similar in nature in that the
Applicant identified them as being within the scope of license renewal
but did not provide justification for its exclusion from an aging
management review. They provided a condition monitoring or performance
monitoring as the reason why they are not subject to aging management
review, but the rule requires that -- or maybe the statements of
consideration identify that a site-specific justification that the
condition monitoring program that they are referring to should be
described in adequate detail, and those provisions were not included.
The three systems that we are talking about or the three
components that we are talking about are the Keowee and turbine building
roof structures. These were identified as being monitored by the
Applicant and replaced based on their condition. Ventilation sealants,
which includes sealing material like tapes for the ventilation ducting
for the control room pressurization and filtration system, that again
would be monitored but replaced on the basis of their condition.
The final one was some fire detection cabling. The Staff
feels that more information about how the performance or condition
monitoring is taking place is needed so that we will be assured that the
components will be replaced prior to their failure.
Those were the open items. The one confirmatory item that
we had involved piping segments that provide structural support in
particular for boundary points. In the BG&E review, there was a
specific section that was written on the identification of these piping
segments and the anchors that are included with them.
There was some confusion over the Oconee application
identifying these segments and the Staff got together with the licensee
and the issue was resolved. We are just waiting for written
confirmation that -- and docketed information that will close this item.
As far as license renewal issues, three issues came within
the area of the DSSA review for scoping and screening. I have mentioned
some of the consumables that we had issue with, specifically the
structural sealants. There was a letter issued by the Staff that
identified our position on structural sealants, and they mostly include
areas such as packing and O-rings, which are excluded from license
renewal, structural sealants -- which the Staff considers included
because they are long-lived and passive, oils and greases were excluded
and filters, fire extinguishers and hoses and other fire protection
equipment were excluded but they are subject to certain justifications
that are required by the licensee to ensure that their exclusion is
appropriate, and the Staff addressed those as they were performing their
review.
Cascading -- there were a few issues identified for
cascading in the BG&E review, but they did not seem to carry forward in
the Oconee. There were not as many instances where hypothetical
failures had brought systems that we felt or components that we felt
should be within the scope, and it just was a matter of site-specific,
so there were no good cascading examples that we could think of for the
Oconee review.
As far as the heat exchanger function, the heat exchangers
that perform safety-related intended functions for license renewal were
identified as having an intended function that included the transfer of
heat. I believe in the BG&E review that was not identified, so the
industry picked up on that and they did include that intended function
for this review.
As far as items of interest, the one that I did want to
identify was the difference in the methodology that the Applicant used
for identifying the systems, structures and components that were in the
scope of license renewal. Two different methods were used -- two
different approaches, I should say, were used.
The BG&E used simplified diagrams to identify the bounds of
the review, where Oconee provided a voluminous number of flow diagrams
that were computer-generated and they were very robust with respect to
identifying the ends of -- the boundaries of license renewal. They were
very helpful to the Staff because they provided a lot of information
about and beyond what BG&E had provided, but BG&E, because they provided
simplified diagrams, they tended to have more emphasis on the written
text, so there was a lot more description of where the bounds were and
tables and charts associated with a number of components, which was
helpful in their review.
In the Oconee review, they were sort of sparse, and they
provided a lot of flow diagrams and then the final result of the
components and structures that were subject to aging management review,
but our review is a two-step process, which structures and components
are within the scope of license renewal, and of those which ones are
subject to aging management review.
We didn't have that first group. We had to pull them off of
sometimes as many as 28 diagrams to try and figure out which ones were
subject to aging management review.
Neither of them were wrong or in my own personal opinion,
since I did a number of these, I felt the Oconee was easier because I
could read the diagrams and see them, but that was a large difference,
and I believe that I had more success reviewing the latter ones, so I
just wanted to highlight that and maybe give Oconee some kudos in
choosing that methodology for the Staff to review.
That is the end of my presentation. Paul Shemanski is
sitting next to me. The majority of the review was done in DSSA but the
electrical portion was done in the Division of Engineering and Paul up
here is from DE, and if there were any questions on how that was done,
he could also answer those questions.
CHAIRMAN BONACA: Questions?
DR. KRESS: Would you prefer a combination of the Oconee and
the BG&E?
MR. GRATTON: I would prefer a combination of the two. The
written text tended to eliminate some of the questions. I had an
example of areas where we became sort of tube-locked in our trying to
find answers. The seismic anchoring I think was one of the areas of
concern. If there was a written text on how they approached that, the
questions wouldn't have come out when you looked at the boundaries.
They went up to the safety-related, nonsafety-related interface and
stopped.
They called that a boundary position when in fact the
boundary went beyond that and included the pipe segment and a seismic
anchor. That was one example.
Another one was the method that they used to identify
components. They used almost like commodity groups to say, for an
example, in the intake structure, they used steel beams, columns, plates
and supports, and since there weren't any that really fit in there, the
trash rack rails, the rails that the trash rack rolls on, was considered
a steel column.
DR. KRESS: That is confusing.
MR. GRATTON: It is. When you read that, you are -- you
know, there's no steel column there, but when in fact it was made of the
same material, it ages the same way, you know, it really belongs in
there, but there was no explanation that went with that. It was just,
you know, say a diagram and a table, so maybe a little bit more text
would have helped.
DR. KRESS: Is this a message that might be transmitted to,
say, ANO?
MR. GRATTON: Well, to tell you the truth, Mr. Grimes -- we
are currently working that.
MR. GRIMES: We are trying to gather this experience and
then fold it back through the process as we settle on a standard
content.
DR. KRESS: That makes your job easier.
MR. GRIMES: Yes, and the delicate balance is we want to
make our job easier but one of our four principles is that we also want
to reduce unnecessary burdens, so we are going to try and find a nice
middle ground and then fold that back into either a revision to 95.10 on
the contents of the application, or review guidance in the Standard
Review Plan.
DR. KRESS: Is 95-10 still a living document that is going
to be changed?
MR. GRIMES: Yes. They haven't talked about changing it,
but we have said that some of this experience is more appropriate there.
MR. TUCKMAN: Mr. Kress, this is Mike Tuckman. I have the
distinction of chairing the NEI Working Group on this also, and our
intent is to take the lessons learned from both BG&E as well as Duke, as
well as the various issues that we are getting resolution papers from
the NRC on, fold those into a revised NEI 95-10.
DR. KRESS: That would be a great way to handle it.
MR. TUCKMAN: Yes, and also just to provide further
assurance to you that the industry is working together, Gary Young is
here from Entergy and they have been very actively involved in this
process too, so they are getting lessons learned to make theirs work a
little better than ours.
DR. KRESS: Great. I am glad to hear that.
DR. SHACK: Since they are going to get charged for it.
[Laughter.]
CHAIRMAN BONACA: With that, let's take a 15-plus minute
break. We'll start again at a quarter of three.
[Recess.]
CHAIRMAN BONACA: Okay. Let's resume the meeting with
presentations by the NRC staff.
MR. GEORGIEV: Good afternoon. My name is George Georgiev.
I am with materials engineering in Chemical Engineering Branch, Division
of Engineering.
I am here to make a presentation on aging effects. What is
different for this application as compared to the BG&E application is
that Duke has grouped various systems and identified common mechanisms
which cause certain aging effects and have evaluated them in section
3.52 of the application. And section 3.1 is the result of our review of
this application.
Basically the section involves only identification of aging
effects, and our review consisted of what are the identified materials
in the applications, what are the aging effects, and what is the
environment. And we tried to find out whether we can identify over and
above what the applicant has done. And with all fairness, after we did
our review, we didn't find anything different than what they have found.
So consequently Duke has done a good job about it.
However, we do have two open items, and all this question
is, if Duke did such a good job, how do you have two open items? And I
will attempt to answer that.
[Laughter.]
Okay. The answer is that those are imported open items from
other sections of our review, because when you do this general lumped
together review that is not so much system-specific. It is conceivable
that something could be missed when you do a system review. And we ran
it through our individual system reviewers, and doing so we came up with
the first open item, which is the aging effects discussed and accepted
by the staff are not consistently applied by the applicant of the
system, specific discussion of aging effects. And we list in section
3.1 which systems these open items relate to.
The second open items relate to buried components, and
basically in our review we couldn't get a feel how much buried piping is
involved in these facilities. And with all fairness again, the
applicant has provided flow diagrams. We went and reviewed the flow
diagrams, we took out what was buried, identified, and we more or less
we can say what is involved. But then one of that piping is a very
large diameter piping. It's 137 inches. And the aging program that
they proposed to manage the effects on this buried pipe is such that
it is really responsive to this large pipe. It doesn't address the
small pipe because the examination would be done from the ID of the
pipe. And if it is a smaller-diameter pipe, it cannot do it. So that
is the background information of this open item.
DR. KRESS: Are these pipes buried in concrete?
MR. GEORGIEV: They're buried in soil, in soil, yes. They
too address buried in concrete. Today is no problem with the buried in
concrete.
DR. UHRIG: What are they, discharge pipes, 137 inches?
MR. GEORGIEV: I think intake pipes.
MR. ROBINSON: This is Greg Robinson. The intake piping is
11-foot diameter coming in from the lake, and I believe it's a 9-foot
diameter discharge piping. And the piping is coated and wrapped, and
was buried at the initial construction.
MR. GEORGIEV: Basically so what these open items is
intended to do is seek information, find out what other piping is
involved. And another problem was like they do have notes in the flow
diagrams which allow that anything, treat waters of an inch up to 6
inch, you can put -- you could use stainless steel. But it is a maze,
not shell. So we really don't know what is stainless, what is carbon,
what is cast iron. And that is the purpose of this open item, so when
we get this information, we can evaluate it and determine, you know,
what are the problems.
DR. SEALE: You say that the QA records were not such that
you could ascertain what these particular pipes were?
MR. GEORGIEV: We don't have the QA records. Those are side
documents. But we do have with the application the flow diagrams, and
with all fairness, those are very good flow diagrams. They have more
information than typical flow diagrams, construction flow diagrams,
because they were made for license renewal. But it is not that detailed
for us to really determine how much is exempt, so to speak, by what they
are proposing to do. Maybe very small, but maybe miles-long piping. We
don't know. And that is the purpose of that.
Other than that, we have an item of interest. The applicant
has performed an extensive review of aging effects and an exhaustive
identification of aging effects, which is a compliment that they did a
good job identifying the aging effects.
That concludes my presentation and that of panel member Miss
Stephanie Coffin, and she did detailed system reviews. So if you have
some question concerning the open items, she will be more than happy to
give you the specifics.
CHAIRMAN BONACA: Any questions?
DR. SEALE: This is an item that's still to be resolved in
the --
MR. GEORGIEV: Yes, sir. We'll receive the information, and
when we receive it, we'll have a fuller picture as to determining
whether what has been proposed is adequate.
CHAIRMAN BONACA: Okay.
MR. ROBINSON: This is Greg Robinson. If I might add just a
thought here, I think one of the things that you're seeing is not
availability of QA records, but it's the level of detail we provided in
the application to address the problem at hand versus say the piping
drawings or construction drawings that we certainly have on site, but we
can go and measure off the miles of piping or what not, and we will be
providing that information. So I think we're just seeing the comparing
and contrasting of the available information set with that provided in
the application.
DR. SEALE: Sometimes they're curioser than they are other
times.
MR. HOU: My name is Shou-Nien Hou, Material and Chemical
Engineering Branch, Division of Engineering.
Now, the common aging management program consists of 13
individual programs. So to make a long story short, I will just go to
the open items, unless you have specific questions so I can explain to
you.
Now the first open item is related to the Duke quality
control program. That program set the requirements of the corrective
actions, document controls, confirmation process. Especially it sets
the control process and responsibility and activities for initiating the
corrective actions for responding to the nonconforming conditions. And
the program generally is in conformance with 10 CFR Part 50, Appendix B.
So it is quite acceptable, except that it's only covered safety-related
components. But we know in the license renewal review it covers safety
and nonsafety both.
So after interaction with the licensee, we come out with an
agreement that they're going to expand a similar requirement to the
nonsafety-related components. But we do need an official commitment
either in the updated FSAR or toward the quality assurance program, like
documents of Duke-18. And that's our open item.
Any questions?
[No response.]
The next open item relates to the exchanger performance
testing activities. You know, the heat exchanger contains a lot of
tubings and small pipes, and it's subject to the corrosions that reduce
the efficiency of the heat transfer.
So performance testing activity actually is performed,
periodic testing of its heat-transfer capability by measuring the flow
rate and also the temperature difference across the heat exchanger. But
in the standby shutdown facility heat exchangers they only do the flow
rate measurement. You know, that's not enough, because that heat
exchanger includes air-cooled coiling, also water-cooled condenser.
And they also have the fins. If the fins fail, now even the
flow rate's maintained the same, but because of fin failure the flow
patterns change and the heat transfer function changes, and that is
going to degrade heat-transfer capability. So we feel that across the
heat exchanger the temperature difference measurement is essential. And
that's our question.
Another is about the decay heat removal coolers, building
cooling units, and standby shutdown facility heat exchangers. We would
like to know what is acceptance criteria for the performance testing and
what are the bases. And also we know that heat transfer function is
needed for the normal operating conditions and also for the accident
conditions. Can they do that? And we'd like to know the story.
Also, in what condition do we consider that we should
initiate corrective action? On some occasions you mentioned that it's 4
percent above the previous performance testing results, or it's below
certain limits. But we'd like to know the limits for all these three,
the heat exchangers. And this is another open item.
The third one is about surface model piping corrosion
programs. Now we know that certain piping consists of a lot of tubings
and pipes. The material is made out of copper, brass, and cast iron,
and also the carbon steels. And also the environment, it's raw waters.
Now, oh, the makeup of others, degradation mechanism. What, your
inspection, what you did, what the licensee did, is try to use the
carbon steel components sort of as leading indicators.
Now, that immediately raised some questions. How do you
justify to use the carbon steel as a leading indicator and as a result
will bounding or the material conditions and/or the degradation
mechanisms.
And also one question we'd like to ask is another technical
use. It's ultrasonic testing. Now, ultrasonic testing may not be
suitable for tests as you test the localized corrosion and
microbiologically induced corrosions, and those things may happen to
some standard steel, and you may not be able to detect that from the
carbon steel testing results.
And most of all, that program does not cover the inspection
of the Keowee systems. It's only to the Oconee plants, but not Keowee.
Now how to program up all the results from Oconee can bond the Keowee
condition. So that's our question.
We have no license renewal issues.
That concludes my presentation.
CHAIRMAN BONACA: Thank you. Any questions?
DR. SHACK: What's different about the treated water system
stainless steel inspection and this MIC question you're asking. Are
they the same?
MS. COFFIN: That's talking to the service water inspection,
which is raw water environment.
DR. KRESS: Okay.
MS. COFFIN: And the treated water is, well, treated water.
DR. SEALE: In these systems that have mixed piping, have
you had problems with them so far with corrosion?
MR. ROBINSON: This is Greg Robinson. When you say mixed
piping, are you talking about stainless and carbon and --
DR. SEALE: Yes, stainless and carbon and copper especially,
or brass.
MR. ROBINSON: The short answer is no. We've had carbon
steel issues and we've used stainless steel as a replacement material,
and the periodicity of corrosion problems on that stainless is going to
be decades --
DR. SEALE: Yes.
MR. ROBINSON: And so we don't expect to see anything for a
long, long time, if ever.
DR. SEALE: Yes.
MR. ROBINSON: But, no, we've had no problems -- we have had
carbon steel problems, but no problems with the other materials.
MR. GRIMES: This is Chris Grimes. The nature of the open
issue isn't -- wasn't driven so much by a question but that we know
there have been problems with corrosion of copper or cast iron. It's a
reliance on an indicator from findings of carbon steel inspections as --
DR. SEALE: Yes.
MR. GRIMES: Since you're not going to see anything for a
decade, are you going to remember that that's the only thing you're
measuring in order to make sure that you take appropriate corrective
action for these other materials?
DR. SEALE: If it's going to leak, you want to know by how
much.
MR. GRIMES: Right. And where.
DR. SEALE: Yes.
MR. GRIMES: And where.
DR. SHACK: Well, I thought it was more the fact that, you
know, I mean if it's general corrosion, it's true, I mean stainless and
carbon steel are, you know, grossly, but there's nothing that says you
can't pit or have MIC attack on the carbon steel, and it has no relation
to the general corrosion of the carbon.
MS. COFFIN: It's for the other mechanisms. That's why the
question's there.
DR. UHRIG: Have you had any significant problems with the
microbiological induced corrosion?
MR. ROBINSON: No, we have not. This is Greg Robinson. In
fact, to my knowledge we have had no indication of problems with MIC at
all. We're in the foothills of the Appalachian Mountains, and the water
quality is pretty high.
DR. UHRIG: Usually, at least my limited experience has been
in water -- in stagnant water in pipes.
MR. ROBINSON: Yes, that would produce a conducive
environment for that to occur.
DR. SEALE: Everything grows fast in the water in Florida.
[Laughter.]
DR. UHRIG: This is a Tennessee plant, Bob.
DR. KRESS: South Carolina.
DR. UHRIG: The one that had the MIC.
DR. KRESS: Oh, I'm sorry. I thought you were talking about
Oconee.
DR. UHRIG: No, no, it was at the Tennessee plant.
DR. KRESS: Fungus really grows fast.
CHAIRMAN BONACA: Okay. If there are no further questions,
I think we exhausted that agenda for today, and I wonder if you have any
presenters for tomorrow's items that we can continue.
MR. SEBROSKY: The short answer is yes, we have people for
3.3 and 3.4 that we can move from tomorrow to this evening. As a matter
of fact, they're here. So we can go ahead and if you want go ahead and
talk about 3.3 next.
CHAIRMAN BONACA: I think we should, items 3.3 and 3.4.
Yes, 3.3 being containment structures.
MR. SEBROSKY: We don't have -- after we do the presentation
on 3.4, we haven't made any arrangements to bring other people up.
CHAIRMAN BONACA: So we will resume tomorrow after that.
Okay.
MR. ASHAR: I am Hansraj Ashar from Division of Engineering
and I will be making a short presentation on containment structures as
to what the licensee has provided to us in license renewal application.
Yes?
DR. SHACK: I think the answer is if you can read it, we can
read it.
[Laughter.]
MR. ASHAR: I can read from here. You can read from there.
Before I jump to the open items, I think I would like to say
something about what the applicant has provided in the LRA and how the
Staff has reviewed it in a very brief manner.
For containment structures at Oconee, the Applicant has
grouped components of the containment structure in three groups, the
concrete components, the steel components, and the post-tensioning
tendon components. In concrete components it includes the dome and
cylindrical wall, the basemat and the floor. Steel components includes
the liner plate and penetrations including equipment hedge, the access
openings, and the other process, the piping, and post-tensioning tendons
that includes the wires, the tendons, the anchorage components.
Now for all these components, the applicant has identified
the aging effects and based on those aging effects it has provided aging
management programs.
There are three programs which the applicant is counting on
for managing the aging of containment structures. Containment ISI plan,
which is inservice inspection plan for containment, containment program,
and the containment leak rate testing program. All these three programs
has been evaluated by the Staff in accordance with the 10 elements for
evaluating any of the plants or programs which are something like a
scope of the program, the preventative actions, parameters monitored, et
cetera. There are 10 elements against which we evaluate these types of
programs.
One open item -- we believe the application has fulfilled
their requirement for aging management of the containment structure
components.
Now I will explore a little bit on the open item. It talks
about the lack of A&P to manage the aging effects on tendon galleries.
Now tendon galleries, I do not know whether all of you are aware of it,
where they are and what they are, but the tendon galleries are the
bottom of the basemat of the containment structure. They are mainly
used for access to the tendon anchorages, so that during the
installation also they don't need it and during the inservice inspection
they need to go in that area to make sure that they can inspect the
grease caps and the anchorage components in the tendon galleries.
Now what we see in the application is that the applicant is
not telling us how the tendon galleries will be -- the effect of the
degradation on tendon galleries will be managed, and the reason we are
not asking for this, because we consider tendon galleries as pressure
boundary for containment. We consider it is a nonpressure boundary,
however the environment in the tendon galleries does give aging effects
on the tendon anchorage components, and we have seen that in a number of
plants that the bearing place of some of the anchorages had corroded.
We have seen quite an infiltration of water at a number of tendon
galleries, and the high humidity in the tendon galleries, and that is
why we believe that the most cost-effective way of ensuring that the
tendon anchorages degradations are managed well, the basic thing that
the applicant has to do is to manage the aging effects on tendon
galleries and make sure the environment in the tendon galleries is not
conducive to corrosion and degradation of the anchorage components.
That is the open item I am talking about.
The license renewal issues -- the license renewal issues on
tendons, this is mainly a discussion of temperature effect on tendons.
Our experience has shown that the pre-stressing tendon forces in
containments have seen more losses than what were estimated at the time
the construction was -- when the design was performed, and that is the
reason this particular issue came as one of the license renewal issues.
Now the Staff feels that the applicant's ISI plan, which I
mentioned earlier, plus an adequate TLAA for tendons, which the
applicant has performed to some extent -- we have some problems but that
will come under the topic on TLAA, but we believe that the ISI plan and
the adequate TLAA would take care of this particular license renewal
issue.
The second issue on 98-0049, inaccessible areas, 10 CFR
50.55(a) has a requirement to look for the degradation in the
inaccessible area if there are symptoms that indicates that there would
be some problems in the inaccessible areas. The basic concern in
98-0049 I believe is related to the other areas which are not being
indicated by the accessible areas. Mainly there's the groundwater
chemistry that might affect the degradation and aging of the below-grade
containment structures.
The applicant response to some of the questions that we
asked has provided us with chemical composition of some of the
contaminants in the groundwater and it amounts to something like less
than 10 ppm of chlorides and close to about 500 ppm or less of sulfates,
which are the basic contaminants we think are detrimental to the
concrete structures, so we believe that that particular issue for
containment has been addressed.
The next license renewal issue is 98-052, which is related
operating experience. The applicant has provided data on what has
happened to pre-stressing tendons and the liner plate corrosion and the
junction of the cylindrical wall and the basemat, that they have seen
some corrosion and they have taken corrective actions on that, so the
vital things that are necessary for operating experience has been
provided in the license renewal application, so we believe it has been
very well covered in that.
The next one, in 98-0057, relation to maintenance rule. I
have not seen much discussion of this particular issue in application
itself, but the way we perceive, the Staff perceives it is that for
maintenance rule, as a matter I had been to a couple of inspections on
maintenance rule baseline inspections, in which the licensees in
general, not this particular applicant but the licensee in general have
taken credit for the ISI plan, which is an implementation of subsection
IWE/IWL of ASME Section 11.
They have taken credit for preventive maintenance for the
maintenance rule, so I think it applies to this particular application
too.
On the subject of the next license renewal issue, 98-0087,
which is related to the temperature, actually shield water temperature
should go into Section 3.8 but I'll talk only about the containment
temperature here.
The applicant has addressed this issue under environmental
assessment and its effect on various parts of the containment
structures, so the Staff believes that it has been addressed well in the
application and we don't have any issue related to that particular
license renewal issue.
Now items of interest, as I mentioned before about the TLAA
for post-tensioning tendon forces, will be discussed probably tomorrow,
in Section 4.22 of this SE.
TLAA for liner and penetration fatigue analysis, that will
be discussed in 4.21 of the SE, probably tomorrow. That ends my
presentation.
DR. SEALE: You mentioned that the experience with tendons
has been less positive than expected, that you have had some relaxations
of tendon tension which were more than you would have anticipated?
MR. ASHAR: Yes. The experience does show that at a number
of plants the pre-stressing tendons were losing their pre-stressing
forces more than what was anticipated or what was estimated during the
design of the plant.
At Ginna, the licensee for Ginna had gone through extensive
investigation of why that happened and what they found, they sent out
the specimen of the wires and tendons to Lehigh University for testing
as to why it happened, and the conclusion was that the steel that is
being used for pre-stressing tendons is going through much higher
relaxation at higher temperatures. In tighter temperatures we are not
talking about very high temperatures, we are talking about in the range
of 95 degrees instead of 72 degrees -- 95 degrees and 100 degree
temperatures.
It was clearly indicated in some of the research that has
been done at Lehigh that relaxation losses are occurring at a higher
rate than would occur at 72 degrees temperature, for example.
DR. KRESS: How did they determine? Did they retorque the
volts or they got crane gauges on it or --
MR. ASHAR: No. What they did was they took the
pre-stressing wires from the plant --
DR. KRESS: Oh, they took it out.
MR. ASHAR: They took it out because they had to take it out
as part of inspection and part of investigation. They took out the
pre-stressing wires. Because they are greased you can take them out if
you want, and as a matter of fact, as part of the inservice inspection
they have to take one wire out of it in order to inspect the material
properties and condition of simple wire. It is part of the inspection
requirement.
So they took those wires out and stressed to various levels
of pre-stressing force and then they left it for 1000 hours and 10,000
hours kind of timing to see how much it relaxes under various
temperature conditions.
DR. KRESS: I see what you are saying. They did it in a
lab.
MR. ASHAR: They did it in a lab, yes.
MR. GILL: Bob Gill, Duke. Just a footnote on this. The
original tech spec requirements for testing our tendons required us to
look at the same tendons periodically specified in the tech specs.
Several years ago Staff was reviewing a report that we had made on that
tendon testing and strongly suggested we convert to Reg Guide 135, just
a random testing sample, and that was about concurrent with the
imposition of IWL, the rulemaking that occurred three or four years ago,
I forget, so we have just recently shifted from specified tendons to
random tendons, and so we really only have one datapoint with the random
testing results, and as we get more data obviously we can do
extrapolations in the future.
We have the projected loss based on the data we do have. We
projected that out and it is well above the prescribed minimum limit at
60 years. That is in a document called Selected Licensee Commitments,
which are a part of our FSAR. We will do the periodic testing and
confirm that our actual datapoints are above that. That is part of the
application. In fact, the FSAR supplement contains those curves in
there and again we are in a transition mode at Oconee from what we had
had for 20 some years to the new random selection process, and which
tendons do you select, do you select some near main steam pipes which
might be a little warmer than others? All that is in the process of
evolution as a Part 50 type issue.
We tried to capture that in the renewal application but the
target is still evolving in some respects.
DR. SEALE: Thank you.
DR. KRESS: What does containment leak testing tell you
about aging of containment? Anything?
MR. ASHAR: Containment leak testing regarding the
prestressing force, you mean?
DR. KRESS: No, about aging in general.
MR. ASHAR: Aging in general. Well, Type A test generally
tells us the overall leak rate into the containment from the containment
structure.
DR. KRESS: Tell you some of the elastomers have --
MR. ASHAR: Elastomers, yes, but that would be more seen in
Type B type of test. Type B tests are the ones --
DR. KRESS: Where you go right to the --
MR. ASHAR: Where you locally --
DR. KRESS: Locally go to the --
MR. ASHAR: Pressurize the particular penetrations.
DR. KRESS: Yes.
MR. ASHAR: And try to find out the leakage rates. And
there are limits on leakage rates. So when they exceed that leakage
rate, then they ought to do something about it, why it's happening. And
many times the seals and gaskets might come off it.
MR. GRIMES: This is Chris Grimes. I'd like to add that
Appendix J also has requirements in it that speak to performing visual
inspections. You basically want to check the condition of the
containment before you pump it up so that you don't, you know,
inadvertently blow a seal out or something or break light bulbs. So to
the extent that Appendix J also provides for a visual inspection and
just the setup and performance of the test causes you to have to go
check on the condition of the structures, it provides you with an
inspection activity that constitutes an opportunity to look for
nonconforming conditions.
CHAIRMAN BONACA: Any other questions on containment
structures?
[No response.]
If not, I think we have one more presentation on reactor
coolant systems.
MS. BANIC: Good afternoon, ladies and gentlemen. My name
is Lee Banic, and it's a pleasure for me to be here to discuss our
safety evaluation of the reactor coolant system. As coordinator of the
review for the Division of Engineering, I'll be making the presentation.
Assisting me is Barry Elliot, who had most of the open issues --
[Laughter.]
And generic license renewal issues.
There were ten reviewers who contributed to this section,
and many of them are here with me to answer any questions you may have.
Duke described its aging management review of the reactor
coolant system in 17 sections of its application. We reviewed these
sections to determine whether the effects of aging on the reactor
coolant system components will be adequately managed. The components
are piping, pressurizer, reactor vessel and internals, steam generators,
reactor coolant pumps, control rod drive, tube motor housings, and
letdown coolers.
The programs we reviewed were the Alloy 600 program,
inspections for the pressurizer, reactor vessel internals, small-bore
piping, control rod drive mechanism, nozzle and other vessel closure
head penetrations, high-pressure injection connections, reactor vessel
integrity, and steam generator tube surveillance.
Duke earlier described its aging management programs for the
reactor coolant system in four Babcock & Wilcox owners' group topical
reports. These reports were on the reactor coolant system piping,
pressurizer, reactor vessel, and reactor vessel internals. We
previously approved reports on the piping and pressurizer. We had a few
open and action items in our safety evaluation for those reports, and we
found that Duke addressed them in its application. We reviewed the
reports on the reactor vessel and internals concurrently with Duke's
application. We had no open items regarding the reactor vessel. We did
have open items for the internals, which we list in our safety
evaluation for the application.
We found that except for the open items shown on the slides
that Duke has shown that the effects of aging on the reactor coolant
system will be adequately managed so that we can make our reasonable
assurance finding.
And now for the open items. We had two open items about
Duke's identification of aging effects. They're shown on the slide.
Duke is to identify that the aging effects for pressurizer spray head
are cracking and reduction in fracture toughness due to the thermal
aging of cast stainless steel and to provide the basis that void
swelling is not an issue for reactor vessel internals or provide an
aging management program for it. The staff is concerned that void
swelling could change the dimensions of a component and thus its ability
to perform its intended function.
We had a number of open items about aging management
programs. This first open item relating to inspection of pressurizer
components exists because they are made of Alloy 600, an alloy
susceptible to primary water stress corrosion cracking.
The next item is open --
DR. SHACK: Is the pressurizer spray head the only internal
component that's cast stainless?
MR. ELLIOT: That's the only one identified, yes, so far, on
the pressurizer. We have cast -- on the internals there is cast
stainless steel.
DR. SHACK: Okay.
MR. ELLIOT: But on the pressurizer -- this is the only one
they've identified.
MR. RINCKEL: This is Mark Rinckel from Framatome. That's
correct. It's the only cast item in the pressurizer.
MR. ELLIOT: The internals have cast stainless. That's a
separate item here.
DR. SHACK: What would be the internals component that would
see high enough fluence that you'd worry about the dimensional changes
from void swelling?
MR. ELLIOT: It would be -- what's the name of it,
whatever's nearest the core.
MR. RINCKEL: It would probably be the baffle plates or
baffle bolts. Those receive the highest fluence, some around 10 to the
22, 10 to the 23.
DR. SHACK: I can see them getting stressed perhaps by
swelling, but, I mean, what --
MR. RINCKEL: I --
DR. SHACK: Requirement?
MR. RINCKEL: Well, I guess there are questions with that
type of fluence. The NRC said that the swelling could be between 4 and
14 percent. I think this is very much a research issue, and, you know,
we're certainly looking at responding to that and looking into it. But
my understanding is that any dimensional changes would really impact the
baffle bolts, and we have a program to look at the baffle bolts, so
that's really going to be the focus of our response.
MR. ELLIOT: That you're inspecting the baffle --
MR. RINCKEL: We will at some time. Right now we just do
visual of those.
MR. ELLIOT: The intent of this question is to make sure
they have a reactor vessel internals program, which you've heard
discussed before. We want to make sure that part of that program that
they address void swelling.
MS. BANIC: The next item is open because Duke did not
identify thermal fatigue as an aging mechanism for the letdown coolers.
However, Duke had thermal fatigue damage on four coolers due to
operating them in an improper manner. Duke repaired them, but we're
asking Duke for information to convince us that the four coolers will
not fail again due to thermal fatigue. We had open items about
stainless steel components. The first one applies to managing thermal
aging of reactor vessel internals, valve bodies, the pressurizer spray
head.
The next item applies to reactor vessel internals. Duke is
to identify and include limiting wrought stainless steel nonbolting
components and welds in internals in its ISI program. This action is
necessary to manage the effect of neutron irradiation embrittlement in
these components.
The next item is to manage the effects of
irradiation-assisted stress corrosion cracking, IASCC, of stainless
steel bolting of reactor vessel internals.
The next open item addresses synergistic effects of thermal
and neutron embrittlement on the fracture toughness of cast stainless
steel internal components.
DR. SHACK: On that one, you seem to have a criterion for
the fluence on the cast stainless. Has that really ever been looked at
independently or do you just assume that if you've got enough ferrite in
it to embrittle it thermally, it's going to embrittle when you irradiate
it too?
MR. ELLIOT: Our approach on -- Barry Elliot -- our approach
on the cast stainless steel internals is to look at both mechanisms
simultaneously. Failure to satisfy either mechanism, whether it be
embrittlement or cast -- whether it be neutron embrittlement or thermal
embrittlement, if you cannot satisfy the criteria we've written into the
safety evaluation, then an augmented or supplementary inspection would
be required. So in this case you have to satisfy both criteria.
Satisfying one is insufficient.
We've established two criteria. We have a thermal
embrittlement criterion in the SER. We have a neutron embrittlement
criterion in the SER. And if they can satisfy both those criteria, then
they don't need to do any supplementary inspection. If they can't
satisfy both criteria, then they would have to do some kind of
supplementary inspection.
DR. SHACK: But the neutron embrittlement criteria is
basically a fluence level --
MR. ELLIOT: Yes.
DR. SHACK: And then a ferrite level that's essentially
equivalent to what you use for the thermal aging. Is that --
MR. ELLIOT: Right. And also we're allowing as part of the
neutron embrittlement and thermal embrittlement, if the stresses are
very low, if they can show the stresses are very low, then we would --
DR. SHACK: You don't really care.
MR. ELLIOT: We don't really care. That may be one way the
spray head can be removed from inspection, for instance, is there's
probably very little stresses on the spray head. You know, that would
be something they have to look at. We just established a criterion.
It's up to them to, once we established a criterion, to convince us that
nothing -- no supplementary inspection is required.
MR. RINCKEL: I had one question. In the B&W owners' group
RCS piping report, BAW 2043(a), that was approved by the NRC in 1996,
you had accepted a different position for the evaluation of CASS valve
bodies, and I guess three years have elapsed and things have happened.
But the position that you have here is different than what was accepted
before. And I wonder if you might just tell us what your thinking is
here and what's transpired in three years to lead to this.
MR. ELLIOT: In the last three years, in fact in the last
year, the industry has come up with a criterion for evaluating CASS
stainless steel. We didn't have that criterion three years ago. We've
reviewed that criterion now. We've adopted it as well as provided
additional criteria we think should be added to it, and we think that
Duke should implement the industrywide criteria at this time.
MR. GRIMES: That raises a good point in terms of all of the
topical report approvals are subject to verification to make sure that
they're still current, and so before we complete the final safety
evaluation we'll make sure that the evaluation basis for all the B&W
topicals is current.
MR. RINCKEL: I think that's the only one so far that I've
seen that there's been a, you know, something -- a different position.
So I just wanted to get clarification.
MS. BANIC: This last open item concerns vent valve and
retaining rings, which are precipitation-hardened stainless steel being
subject to supplemental examination unless Duke can show that loss of
fracture toughness from thermal embrittlement and neutron irradiation
embrittlement is not significant.
We had no confirmatory items. There were three license
renewal issues. As shown on the slide, they are thermal aging of cast
stainless steel, vessel surveillance, and internals embrittlement. We
cover all of these issues in our safety evaluation. As you have heard,
Duke's treatment of the thermal aging of cast stainless steel and
internals embrittlement resulted in open issues. We had no issues with
the vessel surveillance program. And we had no items of interest.
MR. GRIMES: As they're leaving the table, I'll say are
there any questions on section 35?
[Laughter.]
DR. SEALE: We noticed they were pretty slick.
CHAIRMAN BONACA: It was quite a fast move.
Any other questions from any Members here?
[No response.]
There are none, so we thank the staff for the presentations
they've given to this point, and we have gained some time for tomorrow
morning. We will resume the presentations tomorrow morning with I guess
SER Section 3.5, Engineered Safety Features, and also because we gained
some time, we will have time for the subcommittee for our deliberation
and decisions on what we need to bring to the full committee in
September, as well as some topics for the ACRS interim letter.
So with that, we thank the presenters both from Duke and
from the staff, and we'll move on to -- we have one hour here right now
for us to have some brief discussion on what we heard, and again we have
time tomorrow again at midday.
Chris, could you stick around?
MR. GRIMES: Certainly.
CHAIRMAN BONACA: I think for the following discussion we
will go off the record.
[Whereupon, at 3:40 p.m., the meeting was recessed to
reconvene at 8:30 a.m., Thursday, July 1, 1999.]

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