Protecting People and the EnvironmentUNITED STATES NUCLEAR REGULATORY COMMISSION
UNITED STATES OF AMERICA
NUCLEAR REGULATORY COMMISSION
***
ADVISORY COMMITTEE ON REACTOR SAFEGUARDS
***
MEETING: PLANT LICENSE RENEWAL
U.S. Nuclear Regulatory Commission
11545 Rockville Pike
Room T-2B3
Rockville, Maryland
Thursday, April 29, 1999
The subcommittee met, pursuant to notice, at 8:30 a.m.
MEMBERS PRESENT:
MARIO H. FONTANA, Chairman, ACRS
MARIO V. BONACA, Member, ACRS
THOMAS KRESS, Member, ACRS
DON W. MILLER, Member, ACRS
ROBERT L. SEALE, Member, ACRS
WILLIAM J. SHACK, Member, ACRS
ROBERT E. UHRIG, Member, ACRS. P R O C E E D I N G S
[8:30 a.m.]
DR. FONTANA: The meeting will now come to order. This is
the second day of the meeting of the ACRS Subcommittee on Plant License
Renewal.
I am Mario Fontana, Chairman of the Subcommittee for Plant
License Renewal. The ACRS members in attendance are Mario Bonaca,
Thomas Kress, Don Miller, Robert Seale, William Shack, Robert Uhrig.
The purpose of the meeting is for the subcommittee to review
the NRC staff's safety evaluation report concerning Calvert Cliffs'
plant license renewal application 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.
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 April 5, 1999. A transcript of the meeting is
being kept and will be made available as stated in the Federal Register
notice.
It is requested that the speakers first identify themselves
and speak with sufficient clarity and volume so that they can be readily
heard.
We have received no written comments or requests for time to
make oral statements from members of the public.
Today, we're going to hear from staff on a presentation of
their safety evaluation report. Now, Noel has given the ACRS members a
list of the SER chapters and a list of issues, with member assignments.
Please get your comments to Noel, who will collect them. These are
needed by the full meeting next week so that we can incorporate them
into the interim letter.
Also, if you have any questions from the staff regarding the
sections that are assigned to you or any additional areas of interest,
raise them before the end of the day so that we can receive their
replies in time for drafting of our letter next week.
We will proceed with the meeting and I call upon Mr.
Christopher Gratton.
MR. GRATTON: Yes.
DR. FONTANA: To proceed.
MR. GRATTON: Thank you. I'm not quite sure whether or not
I can speak loudly enough or clearly enough to be heard, but my name is
Chris Gratton. I'm the divisional coordinator for license renewal
activities in the Division of Systems Safety Analysis, and I was also a
reviewer for the Calvert Cliffs license renewal project.
My presentation will be on the scoping and screening portion
of the safety evaluation report. During my presentation, I'm going to
cover the implementation of scoping requirements, the implementation of
the screening requirements, how we handle structures and commodities,
open items pertaining to scoping and screening, confirmatory items
pertaining to scoping and screening, and the license renewal issues
pertaining to scoping and screening.
The staff's goal was to have reasonable assurance that the
applicant identified all the structures and components subject to aging
management review. In order to get this reasonable assurance, we
performed the following reviews to scope the systems, structures and
components.
The first thing that we did was we took a complete list of
the systems and structures at Calvert Cliffs from Table 3.1 in the
application and identified those systems and structures that had license
renewal application reports contained in the application.
From those systems and structures, without reports of
application, we sampled several systems to determine whether they had
intended functions, then we've included them within the scope of license
renewal. We've used the FSAR to determine whether the systems had any
intended functions.
So our focus was on those systems that were not included in
the license renewal application, since the other ones were already in
and evaluated.
We did identify some systems and structures that did not
have reports in the application, but upon further investigation and
through the RAI process, we have satisfactory responses from the
licensee that the components that perform intended functions were, in
fact, in the license renewal applications in other sections, such as the
commodities sections.
From this review, the staff obtained reasonable assurance
that all of the systems and the structures with intended functions were
identified in the license renewal application.
The second review that we performed, we asked ourselves what
portion of the within-scope systems and structures are required to
perform intended functions. For each of the -- I believe there were 66
systems and structures in the application, 35 of which are broken out
into individual SERs in our safety evaluation report.
We compared the simplified drawings that were provided by
the applicant to the flow diagrams in the FSAR or other docketed
diagrams or drawings of the system. We focused on those portions of the
system that were not within the scope of license renewal, to ensure that
they did not have any intended functions to complete system level
intended functions. We used the FSAR to identify the intended functions
along with the list of intended functions provided by the application.
Special consideration was given to the boundary valves or
boundary points to ensure that they were properly accounted for within
the scope of license renewal.
Next, we identified the within-scope components that were in
those portions of the systems that were within the scope of license
renewal. For each system and structure within scope, Calvert Cliffs
provided a list of these components that were within the scope of
license renewal. Using the flow diagrams, we validated those lists
component by component. We found some emissions, but in interaction
with the licensee, we clarified those emissions as either not required
to be within the scope of license renewal or the applicant agreed that
the characterization of the system boundaries was incorrect and they
included those components within the scope of license renewal.
At this point, we had boundaries for our systems and we had
a list of components that we had reasonable assurance constituted the
entire group of components that were within the scope of license renewal
and we went on to our screening portion.
This consisted of an active/passive determination and a
long-lived/short-lived determination. The staff compared the list of
components within the scope of license renewal to those subject to an
aging management review and focused on the applicant's justification for
removing items from the second list. The applicant actually provided
two lists; one within the scope of license renewal, and a second subject
to an aging management review.
The difference between those two lists were removed for one
of two reasons, either an active/passive determination or a
long-lived/short-lived determination. That's what the staff focused on,
to see whether or not that determination was made properly.
What remained from this second -- from this screening
process was a list of structures and components subject to an aging
management review. Now, I sort of mixed components and structures
together and that's because the evaluations were done similarly,
although a structure is not a system. The structures were identified
individually and broken down into their components and the same process
was performed as it was within the system. We identified those portions
that perform intended functions. We focused on any portions of a
building or a structure that was -- and if it is not within the scope of
license renewal, to see if it performed any intended function.
Then we ensured that the list of components was complete and
that the components, subject to an aging management review, was also
complete. For commodity groups, the structures and components were
assembled in a different manner. The commodity groups, being several
different systems, and the staff performed a review of the following
type.
The applicant stated that the commodities associated with
the within-scope portions of the system were also within scope. In the
commodities section, the applicant listed the systems contained in that
commodity and the staff verified that the list was accurate by sampling
the systems not included on the commodity list.
So in the commodities section, a table was provided of those
systems that contained that particular commodity. If it was electrical
equipment, it was electrical equipment. If the commodity group was
component supports, it was component supports.
Using the boundaries that we had validated in the systems
portion, if, say, the feedwater system was listed on there as having a
component support, those portions that were within scope, including any
piping and structural components that extended beyond the last boundary
valve, that were used for structural support for seismic considerations,
weren't within scope.
This was true for the commodity groups. This is the same
way that we evaluated this. The commodity groups were instrument lines
and cables. Cranes and fuel handling was reviewed in an individual
section. It didn't span different groups and fire protection system was
evaluated as a single system.
As far as open and confirmatory items, we still have four
open items. The first one has to do with the station blackout diesel
building. It was not included within the scope of license renewal and
it was erected in close proximity of the seismic Category 1 EDG
building, and there were questions in the staff about whether or not the
design of the building brings it within the scope of license renewal.
The words in the final safety evaluation report, final safety analysis
report, that say that its failure could impact the ability of the EDG
building to perform its safety-related function, but the staff is
considering, as you will see in the portion on license renewal issues,
cascading issues, and that is how far out and what sort of boundaries do
we place on scoping and items that do not itself perform safety-related
functions or non-safety-related functions whose failure can affect a
safety-related piece of equipment.
The second open item. There are several nozzles in the
charcoal filter beds that were not scoped within the scope of license
renewal. The licensee had indicated that up to the isolation valve for
these nozzles, there's a short section of piping and then a spray
nozzle. The fire protection staff in DSSA believes that this section of
piping, these nozzles are required by 10 CFR 50.48, and we're trying to
address that with the licensee staff.
The third issue also is a cascading sort of issue. It has
to do with the ductwork that provides cooling to certain rooms within
the containment that provide the basis for environmental qualification
calculations. Without this ductwork or failure of this ductwork, the EQ
requirements may not be maintained. The assumptions that were made in
the calculations would not be maintained, and the staff is trying to
address how to handle these secondary issues, failure of a
non-safety-related piece of equipment and its effect on a piece of
safety-related equipment.
The final open item is just sort of an editorial type of
thing. We noticed that there were some inconsistencies between the
referencing of individual system electrical commodities and the
electrical commodity list. So an open item was issued to make sure that
those two sections -- well, not those two sections -- the electrical
commodities list, which contains the table of all the systems that have
electrical commodities in them and the systems themselves, that they
cross-reference each properly, because right now we've found several
errors in that relationship.
As far as the confirmatory items go, we have two. Staff has
been talking with the licensee about the tendon galleries and their
exclusion and we're waiting for resolution on that issue, as well as
certain solenoid valves in the containment spray. The information I had
on these valves is that they're air-operated valves and they do not
contact process systems.
So it's just a matter of identifying the type of valve to
see whether or not they would be within scope or not.
Finally, the license renewal issues, there were three in the
DSSA section. They covered consumables, which was not addressed in the
BG&E application. Consumables, the staff just issued a position on the
20th of April covering structural steel and grease, component filters,
system filters, fire hoses, fire extinguishers and air packs.
Staff plans to use that position. It's calling for comments
at this time.
Fuses, there was a -- staff put out a position that fuses
were active components and BG&E countered that the fuses were, in fact,
passive and the -- I'm sorry. Just the opposite.
The staff believed that the fuses were passive and BG&E
thought they were active.
The final one is this cascading issue that I addressed
earlier, and that is systems that are non-safety-related or relied upon
in calculations; you know, should their failures be considered within
the scope of license renewal when performing your scoping.
Thank you.
DR. FONTANA: The cascading failures, how do you go about
analyzing those? Do you track them from first principles or does it go
back to the PRA or something like that?
MR. GRATTON: It was pre-deterministic. For this SBO
failure, it was in the FSAR for another reason and the description of
the failure was in the FSAR itself and 10 CFR 54.4, the B criteria,
non-safety-related, whose failure could affect a safety-related piece of
equipment, the EDG structure being the safety-related piece of
equipment, it was a direct deterministic evaluation.
DR. FONTANA: Okay. Thank you. Ready to move on?
MR. GRATTON: Yes.
DR. SEALE: When you did these deterministic calculations,
were they, in some cases, replications of the calculations that you had
done or had been done back when the license was first granted, the
bounding kind of calculation that is used in the licensing basis?
MR. GRATTON: No calculations were actually done. The
current licensing basis actually carried forward into the license
renewal period. That was one of the bases for performing this review.
This was a scoping review, where we tried to bring the design basis
events onto the systems and determine which portion of the systems were
actually performing the system level intended functions that were
described in the FSAR.
DR. SEALE: So you made no attempt to confirm that you could
replicate those calculations.
MR. GRATTON: No.
DR. SEALE: The laws of physics haven't changed, but --
MR. GRATTON: Not that I know of.
DR. SEALE: -- there may be other things that have changed
in the interval that would make that calculation somewhat difficult at
this point, I'm afraid.
DR. FONTANA: Anything else?
MR. GRATTON: Thank you.
DR. FONTANA: Who is next here?
MR. GRIMES: Dr. Seale, this is Chris Grimes, Chief of the
License Renewal and Standardization Branch.
I would like to point out that it is our expectation that we
may end up going back and looking at the structural analysis for the
non-safety-related station blackout diesel building and, using that
assessment, to make a determination about whether or not failure of that
building and its impact on the safety-related diesel generator building
is an appropriate failure to consider for this purpose.
So we may end up going back into that analysis and looking
at the conservatisms or the nature of the failure modes.
DR. SEALE: That analysis wasn't in the original licensing
basis, was it?
MR. GRIMES: When the station blackout -- no, not in the
original licensing basis, but when the station blackout diesel was
added, it became a part of the licensing basis.
DR. SEALE: Yes. And you may confirm that.
MR. GRIMES: I expect that we will end up reviewing that
analysis to make a final determination on this particular open item.
DR. SEALE: I think we'd be interested in what you find out
there.
DR. FONTANA: Okay.
MR. MUNSON: My name is Cliff Munson. I put together
Section 3.1, common aging management programs, of the SER. These are
programs that appear throughout the -- that are used in the different
structures and systems, in a variety of structures and systems.
The first one is the fatigue monitoring program, the second
one is the chemistry program, and then the third is structure and system
walkdowns, boric acid inspection program, corrective actions program,
and the age-related degradation inspection program, ARDI.
So we'll start with the fatigue monitoring program. This
program monitors and tracks low cycle fatigue usage caused by pressure
or thermal transients for components in the nuclear steam supply system
and steam generator welds, and the cumulative usage factor is used to
quantify the fatigue damage resulting from each transient.
The design limit for the CUF is one and corrective actions
are to be implemented before this CUF reaches one.
DR. KRESS: It's easy to measure the pressure variations,
but thermal variations, you need thermocouples stuck around everywhere.
MR. FAIR: I'm John Fair, the reviewer on this. What they
mean by that is they're measuring process temperatures as heat-ups and
cool-downs occur.
DR. KRESS: Okay. And then they --
MR. FAIR: In some cases, they do have some more detailed
thermal measurements in certain locations.
DR. KRESS: But they just measure the temperature of the
fluid.
MR. FAIR: Right.
MR. MUNSON: The fatigue monitoring program is applied to
these different systems that I've listed here. As of right now, there
are no open items or confirmatory items or license renewal issues for
the fatigue monitoring program.
DR. SHACK: How does that handle GSI-190?
MR. FAIR: We separated, in the SER, the monitoring program
by itself as a program that just tracks the fatigue from the issues
related to fatigue in the other sections, and we discussed the GSI-190
in Section 3.2.
MR. MUNSON: The next common aging management program is the
chemistry program. The chemistry programs primarily manage the
corrosive action of water for systems containing primary, secondary
water, component cooling, and service water. The ARDMS managed by the
water chemistry programs include various types of corrosion, from
crevice corrosion, galvanic, to general corrosion, pitting,
intergranular attack, stress corrosion cracking, intergranular stress
corrosion cracking, primary water stress corrosion cracking,
microbiologically-induced corrosion, selective leaching, and degradation
of elastomers.
For the systems containing primary water, these are a list
of the systems containing primary water, and the aging effects that
apply to these systems that are managed by the chemistry program.
These are the secondary -- systems that contain secondary
water, excuse me, and a list of their aging effects.
DR. SHACK: I assume that this really works -- I mean, they
reference EPRI guidelines for primary and secondary water chemistry.
What is the commitment, that if EPRI revises those guidelines, what does
Calvert Cliffs do?
MR. PARCZEWSKI: Usually, the plants keep abreast of any
changes which are made in the guidelines.
DR. FONTANA: Please identify yourself for the transcript.
MR. PARCZEWSKI: Kris Parczewski, from Material Engineering
Branch, NRR.
DR. SHACK: But there is no commitment then to --
MR. PARCZEWSKI: There is no specific commitment in the
submittal.
DR. MILLER: A question. Several of those systems do
involve -- have some radiation. Is there synergistic effects between
the chemistry and the radiation effects? Is that addressed in the
guidelines? I'm not familiar with the guidelines.
MR. PARCZEWSKI: Those guidelines don't address any
radiation effects.
DR. MILLER: Is there any -- I don't know. Bill, do you
know about that? Is there synergistic effect from those chemistry --
I'm not a chemist, so I don't know, but some of the systems do involve
some level of radiation.
MR. MEDOFF: I'm Jim Medoff, with the Materials and Chemical
Engineering Branch. I've done chemistry inspections of plants in Region
I. Calvert Cliffs has been one of the plants I have inspected.
Typically, these plants do monitor both the cold chemistry
of the reactor coolant system and the radioactive nuclides in their
reactor coolant system. In addition to meeting the EPRI guidelines, the
plants typically set administrative limits that are more conservative
than the EPRI guidelines, because they typically don't want to get to
the levels or the limits set by the EPRI guidelines.
So the chemistry departments typically try to maintain the
water chemistry to levels that would be consistent or better than would
be dictated by the limits set by EPRI.
So from what I have found from my chemistry inspections, the
industry has been implementing their chemistry control programs in
accordance with the guidelines and, actually, they've been doing such a
good job of it, this was one of the reasons they took the chemistry
inspections out of the core curriculum.
So I think that the licensees do address chemistry quite
well.
DR. KRESS: The answer to the question that he asked is no,
that the radiation levels in the cooling system are so small, that it
doesn't enter into the chemistry very much.
DR. MILLER: What's the limits on the radiation for that?
DR. KRESS: It's the iodine.
DR. SEALE: Your other question, I mean, the radiation
certainly does affect the water chemistry. That's basically why you
have a hydrogen over-pressure, to make sure that you don't generate
undesirable species because of the radiolysis. You suppress that as
part of the water chemistry.
DR. KRESS: Yes, but it's so low that it wouldn't matter
anyway.
DR. SEALE: Not the radiolysis product you generate in the core. When
you're in a BWR and you're not suppressing, you get a very different
chemistry. Not in your concern, but in the corrosion person's concern,
it generates a very different corrosive environment, depending on
whether he can or cannot suppress those radiolysis products in a PWR.
DR. MILLER: So in a PWR, it's not a concern. In a BWR, it
might be a different situation.
MR. PARCZEWSKI: Actually, the iodine, radioactive iodine,
which is dissolved in the sump, can be controlled by keeping pH in the
sump water about seven, because then the iodine is kept in ionic state
and, of course, then it's not released. So there is a control of
iodine, radioactive iodine in the water.
DR. KRESS: Yes. But that has little to do with the
corrosion issue.
DR. SEALE: It's a different issue.
DR. KRESS: It's a different issue.
MR. MUNSON: Continuing with chemistry programs for
component cooling and service water systems. These are the aging
effects listed here. For the chemistry programs, there are no open
items, no confirmatory items or license renewal issues.
DR. SHACK: Can I just go back to the fatigue program for a
second? When they're monitoring fatigue, they're monitoring these
components for some sort of bounding. I mean, they're not monitoring
every location, obviously, so they pick bounding locations.
Are these bounding locations for the things that were
considered in their original design analysis or have they incorporated
industry experience that you're getting fatigue, for example, in
feedwater lines that you really didn't anticipate in the original
fatigue analysis? Are you bounding those, also?
MR. FAIR: Both are handled. The answer is correct. Most
of the locations are based on the original fatigue analysis. However,
there were some additional items added, one of them being steam
generator nozzles that were a product of industry experience, and they
did some fairly detailed monitoring at the plant to come up with their
analysis of those nozzles.
DR. SHACK: So they think they've bounded all those
locations then with the components.
MR. FAIR: Yes. They think they've bounded the worst case.
The monitoring program, as you say, is a sampling program and it relies
on picking the worst cases for the sampling.
DR. SEALE: Let me make sure I understand what we're saying
and the code words that we're using and all.
I recognize this may not be within the narrow scope of the
review of the BG&E application. But nonetheless, there are pilot
studies that have been ongoing having to do with in-service inspection
that are related to fatigue problems in piping and stress corrosion.
And there are presently applications before the Commission
to go to a risk-informed inspection program where the sites of the
inspections are picked on the basis of experience with previous problems
with systems.
If I read your comments correctly, I gather that the
positions that you have identified or that the applicant has identified
here as the places where they're doing their fatigue analysis encompass
not only the kinds of fatigue locations that were in their original
in-service inspection, but also at least some selection of the results
of the experience that has been gained over the years of other locations
where fatigue has, in fact, been observed.
Now, that doesn't mean that BG&E is asking to go to a
risk-informed in-service inspection program, but they are using some of
those results in picking the sites for doing their fatigue monitoring.
Is that correct?
MR. FAIR: I believe they're using the experience of past
problems to pick some of their selected sites. I don't know that risk
was factored into any of those decisions.
MR. DOROSHUK: This is Barth Doroshuk, from BGE. We
incorporate operating experience into locations that we have in our
fatigue program either as an ongoing monitoring point or special
analysis. I'm not sure that we care if it's a risk-informed location.
We're more concerned about suspicion that there is damage occurring.
So we do not use a risk-informed type of approach when we
think there is something going wrong. The locations in the fatigue
program would not be removed from the program as a result of using a
risk-informed approach. If there was to be a removal of a point in the
monitoring program, it would have to be reviewed against 50.59
requirements to ensure that the design basis requirements were still
being met.
So even though we are supportive of using risk-informed ISI,
we do not use that type of insight to remove locations from the
monitoring without proper evaluation.
DR. SEALE: If I may make a comment. The obverse of that
coin is that if the ISI -- if the risk-informed ISI programs -- that is,
the programs that are based on some sort of risk analysis -- don't pick
up the, quote, experience identified areas of concern that you have
selected to add to your program, then there is something wrong with that
risk-informed analysis. That's the first point.
The second point is that I assume that whatever we're doing
in no way prejudices your option down the road to come in and request a
modification of your licensing basis to allow you to go to a
risk-informed in-service inspection program.
But that's completely removed from and independent of
whatever the concerns are that we have right here.
MR. DOROSHUK: I agree with you.
DR. SEALE: Okay.
MR. DOROSHUK: Maintaining the configuration and being able
to maintain the flexibility to change as you get insight is an
appropriate thing to do and we would -- we believe the commitments that
are being put in the application as part of the licensing basis would be
modifiable if we did gain the flip-side, which is positive experience,
as well.
So we don't think we're handcuffing ourselves at this point.
DR. SEALE: It isn't your intent to do so.
MR. DOROSHUK: No, sir.
MR. STROSNIDER: This is Jack Strosnider, Director of
Division of Engineering. I'd just like to confirm that, number one, I
agree completely with what you said with regard to risk-informed
inspection programs. Our expectation, as you're aware, we're working
through these pilots now, is that when done properly, they would
identify the more likely locations of failure, that that's part of the
consideration there.
So we would expect that that would be the outcome of a
risk-informed program.
Secondly, yes, but nothing that's happening in this
amendment is going to preclude someone from proposing a risk-informed
inspection program down the road.
The final comment I want to make, which I just think might
help in this -- in understanding this section, is to recognize that
going through a number of programs here and if we talk about a chemistry
program, for example, when you get to a particular system, you may not
be relying solely on that chemistry program to manage degradation.
In this case, this fatigue monitoring is really monitoring
to compare to the design basis, the usage factor type consideration.
For certain systems, there will also be, on top of that, some Section 11
or other inspections that are performed.
So I think it's important to recognize that when you talk
about fatigue monitoring, this is not solely what's being relied on to
manage the aging mechanisms.
Like I said, when you get into the specific systems, you'll
see that, well, yeah, you credit chemistry, you credit perhaps
in-service inspection or whatever the appropriate combinations are that
will effectively manage the mechanism.
MR. MUNSON: The next common aging management program is
entitled structure and system walkdowns. These are walkdowns of
structures and systems and components so that any abnormal or degraded
condition will be identified and documented, with the goal that
corrective actions are to be taken before abnormal or degraded
conditions proceed to the failure of the system or structure.
Corrective actions are taken in accordance with the
licensee's corrective action program, which is QL2, and at a minimum,
these walkdowns should occur at least once every six years for every
structure and system.
The walkdowns are to be performed on these following
structures and systems, component supports, primary containment
structures, all the way through to safety injection systems, instrument
lines. I won't go through the whole list.
DR. SEALE: Here, again, you talk about what's going to
happen in the future. It's the "going to be". What about the "has
been?" I mean, you haven't been boycotting the inside of the plant for
the last 20 years. You've been walking around in there up till now and
if you found any water on the floor or whatever the expression might be,
you've identified the problem and you've taken corrective action.
And I would assume that there would be some corporate memory
so that those actions would show up in this program, too.
MR. HEIBEL: This is Dick Heibel, Baltimore Gas & Electric.
You're exactly correct. After every outage, the system engineers
perform system walkdowns to ensure that the systems are ready to start
up. There's also PMs that require walkdowns at this six-year frequency
specifically to look at degradation of the system. But all of these
systems will get a walkdown by the system engineer at least every two
years.
Additionally, the operators have to perform valve lineups
after every outage and which valve lineups they do and don't perform is
controlled by a procedure that we require them, at a minimum, every two
cycles, to do an entire valve lineup.
DR. SEALE: But in addition to that, if you've had any
experience in the past, I would assume that somehow you've factored that
into your assessment.
MR. HEIBEL: Exactly correct.
MR. STROSNIDER: This is Jack Strosnider. Just to add,
again, part of the staff's review is to look at operating experience.
We asked questions in that area and the submittal included information
on prior experience. So that is taken into consideration with regard to
what you might expect in the future or what corrective actions have been
taken that might need to continue. So that is a specific part of the
review.
DR. UHRIG: In other words, that's just a continuation of
the existing program as far as walkdowns are concerned.
MR. GRIMES: This is Chris Grimes. Except to the extent
that we look at whether or not the walkdown is addressing a particular
aging effect of concern. I think some of the walkdowns have increased
their scope or increased -- or changed the guidance to the plant
personnel who are going to be looking for particular kinds of
degradation.
DR. SHACK: That's the 101 modified procedures we saw
yesterday or something like that.
MR. STROSNIDER: In the broader context, the question is
what's the operating experience not just for this unit, but even
industry-wide, and does your program, whether it's a walkdown program or
whatever, does it have the right attributes in it to address that
experience.
Part of this gets into identifying what are the plausible
aging mechanisms based on looking at experience.
DR. FONTANA: How many walkdowns have been done on six-year
intervals so far? The question that I'm getting at is, does six years
appear to be a good number.
MR. DOROSHUK: This is Barth Doroshuk, from BGE. The six
years is for structures only. As Dick Heibel pointed out, these
walkdowns occur when you get down at a system level. Each system
engineer is required to walk down all or part of his system on a monthly
basis, unless it's negotiated differently with his supervisor.
So this is a much more frequent activity than is represented
here, from a detail standpoint. In addition, these activities -- these
walkdowns have been formally in place for over ten years, that these
procedures or guidelines have been in place and have been, of course,
maturing with the results of the inspections.
So the short answer is yes, we do think it's effective, and,
of course, we'll continue to refine the program as we conduct the
walkdowns. And it has been refined for license renewal in particular,
as Mr. Grimes pointed out.
DR. BONACA: Just a question. Operating experience is also
used to reduce the number of components which are within the aging
management program, correct? For example, I was looking at the
instrument lines, where an evaluation of the failures that have occurred
over 25 years, and because of the categorization that these are due to
poor, inadequate maintenance, a lot of this lining is removed from the
list because we haven't seen aging issues affecting the lines. Is it
correct?
MR. GRIMES: This is Chris Grimes. I believe that the
characterization is in terms of whether or not there is a reason to
believe that there is an aging effect that needs to be managed for those
lines.
DR. BONACA: I understand that.
MR. GRIMES: As opposed to removing it, it was more is there
a class of instrument line that requires particular attention and an
aging management program.
DR. BONACA: Exactly. So I understood that correctly. The
question I had is that clearly we -- this is projecting that the future
will be like has been for the past 25 years. There may be some
incipient aging effect we haven't seen yet, either because we go to
extended life or because there are some phenomena that don't manifest
themselves -- haven't manifest themselves yet.
How do we -- how do the programs address these issues?
Where you don't have -- when looking at certain areas because your
program doesn't lead you to do that, you're waiting for the failure of
the component or -- I'm trying to understand how does this get done.
MR. STROSNIDER: Operating experience is one part of the
review, but it is not considered, in and of itself, sufficient to define
whether you need a program in the future.
You also look, based from your knowledge of the type of
degradation mechanisms that might be anticipated, you look at research
results and then you -- so you look at the potential basically, I guess,
just from an engineering or scientific basis of what potential
mechanisms might show up and you look for programs to address those.
But there are things that are covered in these programs that
have not been observed in operating reactors, but there is an
anticipation they could come about. So you look at them.
So I think the important point is, yes, operating experience
is considered, but it's not the sole basis for defining the program.
DR. BONACA: Since we're not looking at risk issues or risk
importance of components in this program, so there could be some
component there that because we haven't seen any aging effect, is not
being inspected specifically or looked at. Yet, it is risk significant.
Is it possible that we have the combination there?
MR. GRIMES: We went back to look to see whether or not
there were any risk-significant components that were passive that
weren't otherwise captured by the deterministic basis. So that's a
feature of the review, is to determine whether or not the aging
management programs are sufficiently comprehensive.
I'd also like to add to what Jack said, that you mentioned
the potential that there might be incipient aging effects that have not
yet been manifest. The concept about having the current licensing basis
and the existing regulatory process carry over is a recognition that as
we learn things in the future and if we identify a new aging effect, and
we would like to think that's unlikely because we did a -- we've got
about 15 years worth of research that's looked at what are plausible
aging effects, what are applicable aging effects, and we've been
reasonably conservative and the applicant has been reasonably
conservative about attaching aging effects to things for which, as Jack
mentioned, haven't been observed yet, but in anticipation, they might
occur, we'll make sure that inspection and maintenance are appropriate.
DR. BONACA: But you see what I was going at. So you have
comfort in your review that the programs they have implemented will
allow for early detection of degradation in certain components which are
passive, but are not part of what is recognized today as being under an
aging program.
MR. STROSNIDER: Correct. And I think we have to
acknowledge, we don't have a crystal ball, there's been a lot of
research done. We're addressing those issues that we consider
plausible, things that could happen that we need to look at.
But the other important thing is that these walkdowns and
the plant programs, you heard the sort of frequency, there are
indicators of -- if new problems show up, these program walkdowns and
other inspection activities and stuff will show that that's occurring.
Then we do gain through operating experience and we'd have
to factor that in as new issues show up.
So when you go into the renewal period, some of the same
programs and mechanisms that you use today for identifying unexpected
problems will carry forward into the renewal period.
But the attempt here is to address as much of what you think
is plausible as you can.
DR. BONACA: I had a question yesterday. I said that once
the license is granted, it's a process that continues. There is no
further review, and then they accept that.
The only question I had on the part of the staff is how is
the staff planning to monitor, in the next 15 years, not only for this
plant, but for the other plants, and see if what they thought was a
sufficient basis for the license ten years from now is still going to be
good, what have we learned from this process.
I'm trying to understand how you guys are going to do that.
MR. GRIMES: We would intend to do it better than we have in
the past, actually, in terms of the programs that we have to change the
oversight process, that looks at plant performance relative to its
licensing basis on a day-to-day basis, and to constantly challenge
whether or not the licensing basis is adequately addressing safety.
We have now developed a program that's going to look at
plant performance indicators relative to our expectations about plant
performance and that includes program attributes, whether or not the
programs are effective, are the events that are occurring -- do they
indicate that there is some weakness in either the design or the
operation of the facility.
So to get back to your original question, we're working
towards a conclusion that is based on comfort that actions have been or
will be taken, using the language in 54.29, about the Commission's
decision basis, that includes a continuation of feedback mechanism that
learns from experience, adjusts as new information comes along, but is
constantly looking in areas that are risk-significant or materially
significant; that is, like fatigue, looking at potential damage
locations.
So we're confident that the processes will work to carry
forward these conclusions and continually challenge them.
DR. BONACA: And I appreciate that. I'm only saying that
this is a rule which has a special opportunity for being tested before
it really goes into play, and that it will be many years before this
plant achieves its 40-year life and walks into the life extension.
I think because of that, there has to be a sensitivity and
monitoring almost itself as a rule, because certainly ten years from
now, you're going to find that the presumptions which were in the rule
and in this review were pretty much correct. We haven't learned
anything else that said we really didn't have our act together.
So that's an important point, I think, that there should be
some strategy at the NRC level to learn these lessons and monitor.
MR. GRIMES: We agree.
DR. BONACA: And that would give the comfort also to the
public and everybody else that these programs are thorough and have a
foundation. So there is an opportunity.
MR. MUNSON: For the structure and systems walkdown, there
is one confirmatory item. The walkdowns have been amended to detect the
aging effects of reinforced concrete structures. Previously, that was
overlooked.
The next aging management program is the boric acid
inspection program. This program manages the general corrosion of the
carbon and alloy steels exposed to concentrated boric acid. The program
involves periodic walkdowns of borated systems to look for leakage and
subsequent corrective actions to mitigate the effects of the
concentrated boric acid corrosion.
This program also manages general corrosion,
erosion/corrosion, where, and stress corrosion cracking of various
carbon steel reactor pressure vessel components and the program also
manages, in part, primary water stress corrosion cracking of alloy-600
components.
The program is applied to the following list of systems and
structures.
The open item for this boric acid inspection program is it
does not provide for removing interference; thus, some internal portions
of the reactor vessel cooling shroud that harbor pockets of liquid may
be inaccessible for visual inspection.
The confirmatory item is that the inspection scope is to be
expanded to include reactor vessel cooling shroud anchorage to reactor
vessel head and reactor vessel cooling shroud structural support
members.
DR. SEALE: I don't quite understand your open item. You
recognize that some areas are not accessible for inspection as they are
presently configured.
MS. COFFIN: That's right. This is Stephanie Coffin.
DR. SEALE: You're going to live with that or are you doing
something to --
MS. COFFIN: No. It's an open item for the applicant to
address.
DR. SEALE: I see. So they're going to come up with
something which you will then assess for its adequacy to remedy that.
MS. COFFIN: That's right.
DR. SEALE: Okay.
MR. MUNSON: The next common aging management program is the
corrective action program and this corrective action -- the program is
really one of four phases of the maintenance strategy used by BG&E to
manage the effects of aging. The four phases are discovery, assessment
analysis, corrective action, and confirmation document.
The current licensing basis provides for the assessment,
analysis and corrective action and confirmation documentation phases
through the implementation of their corrective action program, which is
the QL2 corrective action program.
The processes and activities encompassed by QL2 are
conducted pursuant to the requirements of Appendix B to 10 CFR Part 50
and cover all structures and components subject to aging management
review, and the staff determined that this approach is acceptable to
address the population of safety-related structures and components
subject to aging management review.
There are no open items for the corrective actions program.
There is a confirmatory item, a description should be
included in the UFSAR supplement and for the applicant's -- and/or the
applicant's quality assurance policy for the Calvert Cliffs nuclear
power plant to confirm that BG&E Appendix B program also applies to
non-safety-related structures and components that are subject to aging
management review for license renewal, so that these programs can be
controlled.
DR. UHRIG: Is this an expansion of QA program?
MR. SOLORIO: This is Dave Solorio. I'm sorry. When you
say expansion of the QA program. This is an existing program. It's a
very mature program that BG&E has had.
DR. UHRIG: But it's going out to new components, is it not?
MR. SOLORIO: Well, you're shaking your head, Barth, but
before I -- so correct me if I'm wrong, but there are certain components
that BG&E has said are subject to an AMR that were not safety-related
and I believe BG&E will say that some of those components have always
been part of their QL2 program.
But the staff's concern was that the documentation, either
the QL2 program or the UFSAR, did not specifically call out those
components, non-safety-related components, to be within the scope of the
QL2 program. Therefore, the staff is just asking for that to be
committed to.
MR. DOROSHUK: This is Barth Doroshuk, from Baltimore Gas &
Electric. This is not an expansion of the quality assurance program.
All the components on-site, whether they be safety-related or
non-safety-related, are subject to the corrective action program and
controls of Appendix B.
What this confirmatory item does -- so in other words, if we
find something wrong, we write an issue report and we walk through the
licensing basis checks to check operability issues, irregardless of its
classification.
But what this is going to do is recognize that there is an
aging dimension that may be needed to be clarified just for -- I guess
we talked here yesterday about the culture and changing behaviors, just
to make sure that that's captured.
DR. UHRIG: Thank you.
MR. HEIBEL: This is Dick Heibel. To put a little more
definition. We would consider it an expansion to the program if it's
being subject to QL2, the corrective action program would change a
component from being non-safety-related to safety-related. We don't
intend to change the designation from non-safety-related to
safety-related. But it will still be subject to the -- the entire plant
is subject to the corrective action program.
MR. MUNSON: The final common aging management program is
the ARDI program. These are one-time inspections to verify that an
age-related degradation mechanism does not need to be managed for the
period of extended operation or to verify the effectiveness of an
existing separate preventive or mitigative type program.
The ARDI is applied to a number of different systems.
DR. SEALE: That's a pretty long list. Basically, you're
hoping that plants don't develop post-40-year geriatric diseases, like
arthritis and some of these other things that some of us have.
MR. DOROSHUK: Yes, sir. We agree with you. This probably
goes right to the question earlier on are we trying -- do we have a
crystal ball.
These aging effects that this program is being employed on
are on the periphery of -- we haven't seen them yet, but, again, we set
the thresholds very low and we're going to go out and do these
confirmations. So hopefully these types of activities do try to take
into account Mr. Bonaca's concern.
DR. SEALE: Well, when you come up with your crystal ball,
maybe someone will come up with a silver bullet to take care of some of
our other problems, too.
MR. MUNSON: The open item for ARDI is the staff has
identified some age-related degradation mechanisms that we feel require
periodic regular inspections and such as for the verification of
acceptable condition of codings and verification that corrosion is not
occurring due to leakage.
So there were some differences that we had with the licensee
with respect to whether ARDI should be applied to different systems.
DR. SEALE: So basically, you moved them into a more
disciplined or scheduled inspection mode, right?
MS. COFFIN: If we thought that a one-time inspection wasn't
enough, then we asked them to do something more regular.
DR. SHACK: How many of these ARDIs are open to question
now?
MS. COFFIN: I don't understand what you mean.
DR. SHACK: I assume that -- it says that they're not
acceptable for some of these.
MS. COFFIN: That probably affects about -- I'd have to
check -- about three to five systems.
DR. SHACK: Three to five.
MS. COFFIN: Out of --
DR. SEALE: That 15.
MS. COFFIN: Yes.
DR. FONTANA: What specifically? Is there one or two that
you can --
MS. COFFIN: You want an example?
DR. FONTANA: Yes.
MS. COFFIN: One example that the staff identified was for
the saltwater system, they are going to rely on ARDI to verify corrosion
of carbon steel components due to leakage through the system and the
staff believes that since leakage can happen anytime throughout the
remainder of the plant's life, doing a one-time inspection really is not
going to work for that aging effect, and that's something that should be
going into the system walkdown kind of a procedure.
Actually, the applicant has decided that that's how they're
going to do it and that's more of a confirmatory item for that
particular system that I gave you an example.
DR. SHACK: How about the service water? That's like a
long-shot for a one-shot inspection.
MS. COFFIN: I'd have to look at the application to look at
specifically what kind of aging effect they're particularly addressing.
A lot of these things, the applicant gave us a lot of information on the
design and the environment. That made the staff feel very comfortable
that if there is an aging effect, it's going to be very minimal, and
they planned on doing these inspections to verify that assumption, and,
of course, if that assumption is incorrect, they're going to be
implementing their corrective action program.
MR. MUNSON: That's the conclusion of Section 3.1.
DR. FONTANA: Thank you. Any additional questions on this
section?
[No response.]
DR. FONTANA: We'll go on to the next one.
DR. SHACK: John, just before you leave. Have you decided
what happens if, in fact, they can't manage to keep something below the
line?
MR. FAIR: I'm not leaving. But if you were excusing me,
I'll be glad to go.
DR. SEALE: No. In a word.
MR. FAIR: Yes. They would have to write a problem
identification report and we had a discussion of this, which they
haven't -- there is no specific action they can determine ahead of time,
other than it would probably require a look at an expanded scope of
components, since this is a sampling procedure, and they have several
options for corrective actions; either do some more analyses, propose
some additional inspections, or maybe go as far as replacement of the
component.
MS. COFFIN: I just want to point out that all these common
programs that Cliff just went over today, you're going to be seeing them
again and again throughout the presentations, and I don't think most of
the presenters are planning to spend a lot of time on all those common
programs, since we already went over them.
MR. ELLIOT: My name is Barry Elliot. I'm with the
Materials and Chemical Engineering Branch of NRR, Division of
Engineering. I'm going to be discussing our review of the reactor
vessel, the internals and the reactor coolant system.
The applicant has 19 programs to manage the aging effects of
the reactor vessel, the internals and the reactor coolant system. Nine
are existing programs, five are modified -- are existing programs that
have been modified, and five are new programs.
I don't intend to go through all 19 programs. I'm just
going to take and highlight what I consider the most important ones.
Some of them I just listened to and I heard a lot of discussion. So
you're going to only hear a brief description of the program.
The first program is the water chemistry program. For the
reactor coolant system, it established limits on impurities, such as
fluorides, chlorides, hydrogen and dissolved oxygen. It measures
primary coolant parameters, such as conductivity and pH.
The water chemistry program is used to assure the reactor
coolant system will not be subject to corrosion. It's an existing
program and will continue into the license renewal term.
The next program is the eddy current examination program for
the steam generator tubing. It's an existing program and also will
continue into the license renewal stage. It's used to detect denting,
where stress corrosion cracking and pitting.
The third program is the in-service inspection program and
it picked -- the inspection is a non-destructive examination and a
pressure test to determine critical locations and components to manage
the effects or where erosion, corrosion and cracking.
This is an existing program. However, as part of our
review, based on operating experience, based on knowledge of aging
mechanisms, we have recommended additions to these programs and
modifications to these programs.
I'll be talking about, later on, the modifications to the
ISI program for the internals and the open issues, in particular, there
is a series of modifications we are recommending be included or at least
right now are open items that might need -- we might need to make
adjustments to the ISI program.
DR. SEALE: Barry, just out of curiosity, are all the cooper
components gone or copper alloy components gone from their secondary
system, so they can truly optimize their water chemistry?
MR. ELLIOT: I don't have an answer to that.
MS. COLLINS: Especially as it affects steam generator
tubes.
MR. ELLIOT: The next program I'm going to talk about is the
reactor vessel material surveillance program. This program is an
interesting one for Calvert Cliffs, because they have one of the best
programs in the United States.
In this program, generally, materials are removed from
capsules and periodically tested to monitor the effect of neutron
radiation in the environment. In the case of Calvert Cliffs, they
started with six capsules in their vessel. They've tested -- each
vessel. They have tested two from each vessel. So they have four
capsules remaining from their original program.
They have gone out and added to this program. They have
added supplementary capsules that they got material from Shoreham. It
turns out Shoreham welds were some of the critical welds in Calvert
Cliffs Unit 1, also.
In addition, it turns out that McGuire also has material
that is related to Calvert Cliffs, so that using the McGuire data to
monitor and calculate the neutron irradiation embrittlement for the
Calvert Cliffs vessel.
As far as the license renewal -- that's the existing
program. We are concerned about two things, generically, in license
renewal for vessel surveillance programs. First, that the data bound
the neutron fluence for the license renewal period and the second thing
is that the data that is gathered, and, in many cases, it could be
gathered before the license renewal period ever begins, that it be
applicable to the operation of the plant during the license renewal
period.
In this case, I don't think it will be a problem for
Calvert, because although we've explained this to them, that if they
take -- there are two things they have to do. They have to modify their
program.
First, they have to extend the surveillance schedule to include capsules
out to the neutron fluence at the end of the license renewal period.
Second, if they have early withdrawal of capsules, they must establish
limits on their operations as far as temperature, flux, spectrum --
that's about all I can think of right now -- that they must operate the
plant to and that the surveillance data is useful for.
If they go outside that bound, then they would have to come
back to us and either restart the surveillance program, make adjustments
to the surveillance program, or tell us how they're going to adjust
their irradiation embrittlement estimates.
But I don't think this will be a problem for Calvert. They
have a lot of capsules and they should be able to monitor the radiation.
That's neutron irradiation embrittlement.
The next is thermal embrittlement, cast stainless steel
components.
DR. SHACK: Just a quick question. On that one, do they
have lots of margin on their PTS?
MR. ELLIOT: Yes. Well, it's not that they have -- they
have -- but I could tell you, the PTS values, they're below the
screening criteria at end of license and they're committed, as part of
the regulations, to monitor this. In fact, six months ago, they
submitted a new estimate and they're still -- and their estimate
included the license renewal period and they're significantly below the
screening criteria for both units.
DR. SHACK: I take it that they're even still at 50 foot
pounds for the --
MR. ELLIOT: Fifty foot pounds upper shelf energy. They did
an analysis that shows that at the end of the license renewal period,
they'll be just above 50 foot pounds, like 51 or something like that.
This will be monitored as part of the vessel surveillance program.
The thermal embrittlement portion is a new program, the cast
austenitic stainless steel program, and this program is to identify cast
stainless steel materials that are susceptible to thermal embrittlement
based on the percentage of ferrite, the amount of molibnimum, and the
casting methodology.
The criterion-associated analyses are documented in EPRI
topical report 106-092. The criteria was developed using measured and
saturation lower bound JR curves. The saturation lower bound curves
were developed by Argonne Laboratory from tests on age, cast stainless
steel material. In all cases, the Argonne prediction curves were
equivalent or conservative compared to the measured values.
Staff reviewed the topical report and submitted an
evaluation, I think, to NEI and we've discussed it with Calvert Cliffs.
There are some modifications that are necessary to the program. A few
of the -- one criteria has to be changed. The method of calculating
ferrite has to be a particular way and the inspection method of --
should we be recommending that it be qualified to Appendix 8, if they
can develop techniques that can qualify this.
This materially is very hard to ultrasonically inspect, but
we're hoping that the industry will put an effort here and be able to
qualify an inspection procedure for this type of material.
DR. SHACK: I'm curious about that, because it had comments
about niobium in the stainless.
MR. ELLIOT: Yes. One of the things we said is that if
there's any niobium in the cast stainless -- these are part of the
limits. We modified the limit on -- we modify a ferrite limit for high
molibnimum, but if there is any niobium in the cast stainless steel,
then this criteria would not apply, and the material would have to be
inspected.
DR. SHACK: Did they really have enough foresight to analyze
for niobium in their cast stainless?
MR. ELLIOT: They said they're going to look into it.
MR. BALDWIN: Marvin Baldwin, with Baltimore Gas & Electric.
Cast was one of the areas we looked at very closely. We reviewed the
certified material test reports that we got from Combustion Engineering,
from fabrication, and determined that we have no niobium. Niobium was
neither specified in the fabrication of any of the cast components that
are in the RCS pressure boundary.
DR. SHACK: I'm sure it wasn't specified, but was it
analyzed to find out if it got in some other way?
MR. BALDWIN: I recall seeing niobium on the data sheets for
some of the CMTRs. I can't say that I saw them for all, but what I did
was I -- I'm not a metallurgist, but I know how to look at documentation
to see what's there, and I did see NB or, I think it was called
something different before, I forget what it was, and I did see those on
some, where there were blanks or no numbers.
DR. SEALE: I'm not sure I understand where this niobium is
supposed to be. What if you went to a different cladding material?
MR. ELLIOT: Excuse me. This is not cladding. This is cast
austenitic stainless steel.
DR. SEALE: That's what I said. I didn't know where the
niobium was supposed to be. So you've answered my question.
MR. ELLIOT: Okay.
DR. SHACK: It's not supposed to be there.
MR. ELLIOT: Yes, it's not supposed to be there.
DR. SEALE: I know, but if we talk about high burn-up fuels and the
possibility of modifying cladding.
MR. ELLIOT: This issue, you could -- I mean, Bill knows a
lot about this.
DR. SEALE: I'm sure he does.
MR. ELLIOT: I think the French reactors, I think, specified
niobium.
DR. SHACK: No, they didn't, but they got it.
MR. ELLIOT: They got it. And so that's why this was a
concern that was raised and specifically if there is niobium, then all
the criteria don't apply and the materials would have to be inspected.
The next program is a modification to the ISI program. It's
the internals inspection. It's the internals program. I was listening
before about here is a case where the licensee says really there is no
problem, but the staff has decided that there is a potential problem in
the future.
In this case, the internals are subject to high radiation
and what we're concerned about here is radiation-assisted stress
corrosion cracking as well as just general embrittlement of the
stainless steel.
Another part of this is that we also have the cast stainless
components also in this internals. So not only are they going to have
the neutron embrittlement, but they're also going to have the thermal
embrittlement of those components.
At the moment, there is very limited data available for
neutron embrittlement of stainless steel. The applicant is
participating in an industry program to develop that data.
However, until that data has gotten analyzed, we have
decided that the ISI program needs to be enhanced. The current program
is to do a VT-3. Our experience with boiling water reactors is that a
VT-3 will not discover the type of cracks that you can get from IASEC
and, therefore, an enhanced VT-1 examination is going to be required for
the limiting component or limiting locations in the internals.
The licensee has taken this to heart, finally, and they have
identified the inside surface of the re-entrant corners of the core
barrel as a location that is going to be VT-1 -- enhanced VT-1
inspected. That has the highest combination of stresses, because it's a
welded corner. It's the closest to the core and it also has high
temperatures. On one side, it has the hot leg temperature; the other
side, the cold leg temperature.
That takes care -- that's the stainless steel and welds.
Now, we're also concerned about the cast stainless steel components.
There are two cast stainless steel components. The CE shroud assembly
tubes and the core support columns.
In this case, we are concerned about two things; thermal
embrittlement, like I said, and the neutron embrittlement. There is no
data available for this type of problem. So, again, we asked the
licensee to do an analysis or to do the VT-1 inspection, enhanced VT-1
inspection of these components.
Now, the analysis is -- this is how we're running the --
this is how we're doing -- we asked them to do the analysis. We
established criteria for neutron fluents; that is, ten to the 17th
neutrons per centimeter squared.
If the fluents receive, at the end of the license period,
for any of these components, are above that criteria, it would be
considered a high radiation area for the program and the only way the
components would not be inspected would be if VT-3 -- would return to a
VT-3 -- is if they could demonstrate that the loads on this thing during
all ASME -- all accident conditions is either compressive or very low.
Otherwise, if it has a high fluence, it would get an enhanced VT-1
examination.
The second part of the criteria is for low fluents
components. If it turns out they have low fluents; that is, lower than
ten to the 17th. In that case, we would think that the neutron
irradiation embrittlement would not be a factor. The only factor to be
considered then would be the thermal embrittlement.
There, they can go -- they would have to show that they meet
the thermal embrittlement criteria we talked about and we modified for
the cast austenitic stainless steels. If they could show that, then the
inspection could be reduced to a VT-3.
That's our modification there.
The next program is the alloy-600 program. This is for the
primary system. The alloy-600 program is a program to manage primary
water stress corrosion cracking for pressure boundary components and it
looks like the most susceptible, most safety-significant components.
This is an existing program. It basically ranks the
alloy-600 components based upon the residual and operating stresses,
operating time, and material heat treatment. It turned out, as part of
this review, that in Unit 1, the most susceptible component is the vapor
space instrument nozzle in the pressurizer -- four vapor space
instrument nozzles in the pressurizer heads, and they will be replaced
during the -- with alloy-690 during the 2000-year outage.
In Unit 2, it turned out that the limiting, most susceptible
material was the pressurizer heater sleeves, and these materials were
replaced with 690 in the 1989-1990.
The alloy-600 program has not identified any other -- at
this time, any other materials that need replacement. The alloy-600
program, we use VT-1 and VT-2 to detect leakage and to determine whether
there is a problem with the alloy-600 -- the other alloy-600 components.
The fourth, the last program I was going to talk about,
which we discussed already, was the fatigue management program for the
primary system. The fatigue monitoring program tracks the low cycle
fatigue usage of critical reactor coolant system components.
The program has been modified to include reactor coolant
pumps, motor-operated valves, some pressurizer components, control of
drive mechanisms, reactor vessel level monitoring system components.
DR. SHACK: The other slide said there were no open issues.
MR. ELLIOT: I know. That's not true.
MR. FAIR: Could I help you with that? It's just the way
that the -- we constructed the SE. As far as the program itself, we
didn't have a problem with the way it was being implemented, and that
is, tracking the worst components and taking corrective actions.
In terms of the open items in this section, they haven't
completely evaluated all the components to determine if there were other
locations that needed to be monitored. So that's one of the open items.
MR. ELLIOT: We have several open items. Some of these may
require modifications to the in-service inspection program. The first
one is that -- this is not a modification, but that the applicant should
credit tech spec limits of steam generator leakage as part of its aging
management program. That's just we think that that should be done.
We think there is a program needed to manage stress
corrosion cracking of the reactor pressure vessel head closure seal
leakage detection line. This line has had, in the past, stress
corrosion cracking.
We think there is a program needed to manage the cracking of
pressurizer heads and shelves, in particular, the cladding. We've had
cracking in the cladding that has gone through the cladding into the
base metal in Haddam Neck, around the -- and the area that needs to be
looked at is the cladding around the surge nozzle and the heater welds.
Those are areas that have high thermal fatigue.
DR. SHACK: When we say this, does this mean you want them
to add to this to the fatigue monitoring program?
MR. ELLIOT: No.
DR. SHACK: Is that what is implied here?
MR. ELLIOT: No. In this case, we were negotiating what
kind of inspection they can do to look and see whether or not we get any
of the stress corrosion cracking of the clad in this region or thermal
fatigue cracking of the clad in these regions.
The program that might need modification would be the ISI
program.
Again, an ISI program is needed to manage cracking on the
inside surface of small bore piping, including Inconel material. The
applicant must document their inspection methods to detect where, before
it begins to compromise the function of the hold-down rings.
DR. SHACK: Again, the small bore piping, that's piping that
now escapes Section 11 because of its size. Is that the --
MR. ELLIOT: It doesn't escape it. It has just a surface
examination. It doesn't have a volumetric, and so we don't see the
inside surface. So we need something more.
We have a few confirmatory items. The applicant is to
revise the cast austenitic stainless steel program to include the
criteria and methods of examination recommended by the staff. The
applicant is to revise the RPV materials surveillance program to include
data and establish operating conditions for a period of extended
operation, as I discussed.
The applicant is to confirm the applicability of the
alloy-600 CEDM program through the period of extended operation. They
have done the analysis for 40 years and now they have to confirm that
the analysis is bounded for the 60 years.
The applicant should document their conclusion that the
control element shroud bolts do not perform a safety function, as
described in 10 CFR 50.4, and, therefore, not subject to aging
management review. And the applicant is to document the operating
stress for hold-down ring, to demonstrate that the hold-down ring is not
subject to stress relaxation.
The final thing is you talked about fatigue. We have this
as a confirmatory item. This is the environmental effects as related to
GSI-190 and the applicant must resolve the environmental fatigue issue
for the period of extended operation, if the issue is not resolved
generically prior to the end of the current license term.
To summarize the license renewal issues that are critical
for the vessel internals and reactor coolant system or internals
embrittlement, which I discussed. Thermal aging of cast austenitic
stainless steel, which I discussed. Vessel surveillance, which I
discussed, the materials surveillance program, and fatigue is the
fatigue monitoring program.
That concludes my discussion.
DR. FONTANA: Thank you.
DR. SHACK: I guess I didn't quite -- is the implication of
the bullet on the fatigue really that that one can stay open for a long
time yet and you don't really need to resolve it until the end of the
current license?
MR. FAIR: Yes, that's correct. What we're relying on in
that is we did the evaluation for current operating license, the 40-year
evaluation, and we presented a finding that we didn't think we needed to
backfit anything for the current operating license.
The open issue was whether we could extend that conclusion
into the renewed period of operation and we thought we needed additional
work in order to make some safety conclusion in the renewed period.
MR. GRIMES: I'd like to add. The treatment of this generic
safety issue is the same approach that was used during the operating
license stage in terms of the treatment of generic safety issues and
recognizing that we weren't making a licensing decision at this point,
with a pending issue unresolved.
It is our expectation that the work that the Office of
Research is doing is going to identify a resolution of this issue well
before the plant reaches the end of the 40 years.
It is a unique generic safety issue in that respect because
we didn't have any other generic safety issues that bifurcated between
40 years and the period of extended operation.
But we've also recognized that we could tackle it on a
plant-specific basis in much the same way that Barry described the way
that we addressed these generic renewal issues for embrittlement and
CASS and other things, on a plant-specific basis.
But at this point, we're just trying to reconcile what it's
going to take to resolve the generic safety issue is where the NRC staff
thinks it ought to be expending its energy rather than trying to resolve
it on a plant-by-plant basis.
DR. FONTANA: Any additional questions, comments?
[No response.]
DR. FONTANA: Well, we're scheduled for a break now. Thank
you very much. Let's be back here at 10:20.
[Recess.]
DR. FONTANA: We will resume the meeting. You had a
20-minute break instead of a 15-minute break, so we're going to make it
up later.
MS. COFFIN: Bill, I just wanted to get back to you; later
today, when we go over the cooling systems, you're going to hear a lot
more about the aging management programs, for example, for the service
water system. You'll see that ARDI is actually a very small component
of the programs in effect for that system.
My name is Stephanie Coffin. I will be going over with you
the engineered safety feature systems, which consist of the following
three systems; the containment isolation group, the containment spray
system, and the safety injection system.
Just very quickly, the containment isolation group functions
to prevent uncontrolled or unmonitored releases. The containment spray
system limits pressure -- the primary function is to limit pressure and
temperature in the containment following an accident. The safety
injection system, the primary function is to supply emergency core
cooling following a LOCA.
Most of these programs you've seen before, because they are
the common aging management programs that Cliff went over today. But
very briefly, all three systems have some carbon steel, no alloy steel
components, and because they're located in containment, they could
potentially be exposed to concentrated boric acid. So to mitigate
general corrosion of those components, and this is -- the applicant
relies on its boric acid corrosion inspection program and we went over
that earlier today.
With regard to the internals of these components, the
containment isolation group has a variety of internal environments,
including treated water, well water and gaseous waste, and because of
the design of the system and the internal environments, the applicant
presented information that the corrosion effects are expected to be
minimal and they're relying on ARDI and supplemented by some local leak
rate testing of some valves in their programs to verify that, for the
management of aging effects. That would be crevice corrosion pitting,
general corrosion.
DR. SHACK: What size is this piping that we're talking
about here?
MS. COFFIN: I would have to look at the application. It
probably varies. For the containment spray system, it's exposed
internally to treated water and we're relying primarily on the
applicant's chemistry program to mitigate the corrosive effects of that
environment.
Because there are some stagnant conditions in the system, because it's
in a standby mode most of the time, the applicant has committed also to
doing some age-related degradation inspection, the ARDI inspections, to
check specifically in those areas.
For the safety injection system, again, this system is
exposed internally to treated water, and we're relying primarily on
their chemistry controls to prevent corrosion of the internal services.
There are some local leak rate tests and pumps and valves in
their IST program that they also rely on to detect any degradation
that's going on, supplemented by ARDI in some various portions of the
system.
One aging effect that's actually not on this chart is elastomer
degradation and that's for a perimeter seal on their refueling water
tank, and the -- because it's exposed to the element, the applicant
identified some degradation that is possible for that seal and they're
relying on their structure and system walkdowns to identify that.
There are some modifications that they need to make to that
program that I'm going to talk about in the next slide, because those
are confirmatory items.
For the safety injection system, there is something unique
in that system in that they have experienced, at this plant, stress
corrosion cracking of the refueling water tank penetrations at the
penetration welds and they've discovered that through their walkdowns.
They plan on continuing that program to monitor -- manage that aging
effect, although they're going to do some additional engineering
evaluation, that, again, I'm going to put off just for a moment, because
it's part of our confirmatory items with respect to that aging effect.
Lastly, fatigue, this system is included in their fatigue
monitoring program and, once again, there is going to be a modification
to that. The applicant is going to be doing some additional information
relative to fatigue that I will talk to right now.
DR. SHACK: Would this thing see cycles or is this some sort
of leakage kind of induced fatigue?
MR. FAIR: What they're monitoring right now is the safety
injection nozzle, which does see thermal cycles during shutdown cooling
initiation. They're also taking a look further in the line, certain
sections of the line for potential stratification effects, which they
haven't completed yet.
MS. COFFIN: There aren't any open items with respect to
these three systems and the confirmatory items are, one, to modify the
structure and system walkdowns and specifically what they're planning to
do is explicitly add to the scope the inspections of the refueling water
tank for the safety injection system. They're also going to add into
the procedure inspection criteria for the perimeter seal for the RWT and
for the RWT penetrations, penetration welds.
The applicant committed to doing an engineering evaluation
of stress corrosion cracking at their RWT penetrations and they want to
reach the conclusion that they feel satisfied that the walkdowns are
sufficient to detect stress corrosion cracking before there is a loss of
intended function. If they can't reach that conclusion to their
satisfaction, then they're going to implement an ARDI-type inspection
program for that particular aging effect.
Do you want to add something Barth?
MR. DOROSHUK: I want to make one comment. This is Barth
Doroshuk, from BGE. Yesterday I referred to this engineering evaluation
of SEC as a leak-before-break analysis, and I misspoke. That is an
engineering evaluation, not a leak-before-break. So for the record.
MS. COFFIN: And the last confirmatory item, John spoke to
this a minute ago, is that the applicant is right now reviewing industry
reports, particularly with respect to thermal stratification for some
portion of this system and to see if and how the fatigue monitoring
program needs to be modified, particularly for this system, to ensure
that fatigue is managed for the safety injection system.
With that, that takes care of these systems.
DR. UHRIG: Could you expand a little bit on -- I think it's
called thermal fatigue.
MS. COFFIN: I would love to. John?
MR. FAIR: What did you want me to explain?
DR. UHRIG: The thing that I'm most familiar with is stress.
MR. FAIR: Yes, and that's what is being monitored.
DR. UHRIG: This is just basically thermal cycling reduces
stress, but now you're talking about thermal stratification, and this
has got me confused.
MR. FAIR: Well, there's an issue that came up with
potential stratification in lines due to leakage through check valves
and there was a bulletin issued on it, it was Bulletin 88-08.
A lot of licensees have gone back to look and see if they
have this problem in any of the systems in their plant and the
stratification problem is a combination of stratified flow and cycling
flow due to leakage and circulation in certain parts of these systems.
They do cause alternating stresses, quite a number of cycles
of these alternating stresses and can result in cracking and eventual
leakage.
DR. UHRIG: I had an associated stratification fatigue.
MR. FAIR: It oscillates.
DR. UHRIG: I see. All right.
MR. FAIR: The stratification can cause other problems.
MR. PATNAIK: I'm Pat Patnaik. In answer to your question,
Bill, about the size of injection containment spray piping, they're all
six inches. They're over four inches and they're up to 12 inches
diameter, stainless steel.
DR. FONTANA: Okay. Anymore questions, comments?
[No response.]
DR. FONTANA: Thank you.
MR. HOU: My name is Shou-Nein Hou, NRR. I'm the reviewer
on Section 3.4. That covers three areas; the chemical boron control
system, the compressed air system, and fire protection.
For the chemical and boron control systems, the major
component consists of piping, accumulator, strainer, tank, flow,
temperature, heat exchanger, and various kinds of valves.
The material, essentially it's stainless steel inside; on
the inside. That means the contact of process flow. Outside, they do
have carbon steel, alloy or stainless steel.
Another is compressed air. The material, it's carbon steel,
and inside is the compressed air. That is enclosed instrument air,
plant air, and standby saltwater air.
The major components, as you can see, are piping,
accumulator, air compressor, and various valves. Now, another area is
about fire protection. In the license review, there are 66 systems and
components, and 42 of them relate to the fire protection function.
In these 42 systems, 26 are safety-related structures and
systems, such as the pressure boundary system and the structures to
perform the fire barrier functions, and also some electrical equipment.
So in this section, we're only talking about the remaining
16 systems. Now, in these 16 remaining systems, nine -- part is
safety-related and part is non-safety-related. But for safety-related,
there is also another 26 I just mentioned, all be addressed separately
in other sections about the aging management.
So for this particular review, only those non-safety-related
portions of these 16 systems.
First, we talk about the chemical boron control system. Not
because we have that operated as it inside the component, so there is a
generic corrosion concern. So water chemistry program is very
essential. I think that's one of the common improvements that we have
discussed this morning and that essentially is just a program to
identify the perimeters need to be monitored and also the frequency and
also what's the acceptance limit. If you're beyond the limit and what
kind of action need to be taken.
So that would take care of that generic corrosion inside
those components, contact with the borated acid.
Now, in case if there is a leak, because the fastener is --
it's carbon steel and alloy, which are subject to corrosion effects to
the borated acid. In that, they have borated acid corrosion inspection
program. That's also been discussed in this morning.
Now, the plant also -- this system also has a unique concern
is about using the heat trace to maintain the temperature of the systems
above their limit to avoid saturation of the borated acid. That's about
the stress corrosion cracking, stress corrosion cracking caused by the
heat tracing. Because it contains hydrogen, which is a corrosive
element.
Now, the licensee have a plant modification to remove this.
That program being started in '91 to replace it with a non-corrosive
one, and the program is still ongoing, and we were told that it would be
completed by the end of the current licensing period.
I think that will take care of the stress corrosion cracking
concerns.
Now, there are various valves. The valve seat and the disk
is subject to wear, because it's normal operation. For that, they have
a leak rate testing and that's a part of the plant surveillance test
procedure.
So attention to all this. Now, they also supplement by an
ARDI program. The ARDI program for these particular system, it try to
verify no severe previous corrosion impeding internals of the components
contacting the boric water and the shear side of the heat exchanger.
That essentially is kind of walkdown process and it's been discussed in
the morning.
Another is no significant vibration fatigue. That, I had to
go back to the slide in here, talk about CVCS fatigue, the problem.
Now, we know fatigue is a problem. It has two kind of concerns. One is
low cycle fatigue, one is the high cycle fatigue.
The low cycle fatigue is about the thermal transients and
the cause of stress, fluctuation, and they have the fatigue monitoring
program and we know this program, as present earlier, and that program
is not complete yet. The place, the location for the monitoring,
critical locations, has not been finalized.
Also, there are generic concerns also being discussed, the
GSI-190, how to categorically qualify operating plant for the 60 years.
Use the statistical approach, not risk-informed, to pick up sample from
five PWR and the two BWR plants and perform an analysis using the
modified curve generated by Argonne.
Now, besides that, now, there is a concern about the
charging pump. The charging pump has created the operational vibration
and that caused the cracking of the pump or block and also the suction
side of the piping, as well. That has been -- that problem is being
identified and also they have plant modifications in the design and also
improve the pump operating practice. So the problem essentially is
resolved and we're told about all this resolution and we agree with it,
except for that information not yet being shown in the application.
So the application needs to be modified to incorporate that
information. That essentially covers one of the confirmatory items.
DR. MILLER: When you say that problem is resolved, how do
you reach that conclusion?
MR. FAIR: This is John Fair, again. What occurred on the
CVCS system is early in operation, they had some vibration problems on
the suction side that led to some failures. They went in and corrected
the design, changed the design, changed the thickness of the piping, did
some monitoring of the system, determined that they had an adequate fix
for the --
DR. MILLER: How did they determine that?
MR. FAIR: That they didn't have significant vibration.
DR. MILLER: Do they have on-line vibration monitoring now?
MR. DOROSHUK: This is Barth Doroshuk, from BGE. We do have
a maintenance condition monitoring program. That is a vibration
monitoring program. It monitors systems throughout the plant. That
program was most likely used in the verification corrective action
follow-up after these modifications were done to the supports and to the
piping to make sure that vibration was insignificant, as well as
understanding or not seeing any additional failures or degradation in
the system. We concluded that vibration was not plausible for this
system.
DR. MILLER: How did you determine it was not plausible?
MR. DOROSHUK: Vibration, we believed that vibration is a
result of an installation or design defect and the design defect or
installation defect was corrected here through a plant modification and
then verified through follow-up monitoring.
DR. MILLER: Okay.
MR. DOROSHUK: So in this particular location, vibration, we
believe, is not an aging effect.
DR. MILLER: When was this done? I've looked at your SER,
but it doesn't tell me a timeframe.
MR. DOROSHUK: Fifteen to 20 years ago.
DR. MILLER: So you've got that much experience.
MR. DOROSHUK: Yes, sir.
MR. FAIR: Just to clarify what the issue was on this.
Originally, they proposed to do an ARDI on this piping to verify they
had no vibration fatigue damage. There was a question as to how an ARDI
was going to verify this and after some discussions, it was determined
that since they had so much operating experience on the system as
modified, that it really wasn't plausible at this time.
DR. MILLER: Part of this is response to Generic Letter
88-14. Is that what I'm reading here?
MR. FAIR: I don't believe so. Where are you reading?
DR. MILLER: I'm just reading the SER, on the overall
problem that came up.
MR. HOU: You mean Generic Letter 88-14?
DR. MILLER: Right, Generic Letter 88-14.
MR. HOU: I'm going to talk about that later.
DR. MILLER: You're going to talk about that one.
MR. HOU: Yes, right.
DR. MILLER: That relates to instrument air, which
apparently --
MR. HOU: That's right.
DR. MILLER: -- stimulated -- did that stimulate the
vibrations?
MR. HOU: That is not a vibration problem.
DR. MILLER: Okay.
MR. HOU: Not a vibration problem. That's a -- well, I'm
going to talk about it. Are you finished?
MR. FAIR: Yes.
MR. HOU: About the compressed air system, the inside is
compressed air. Now, the material is carbon steel. That carbon steel
can only cause corrosion concern if the air has some problems; for
instance, it contains the moisture. So they have a preventive
maintenance program. That program is going to check the air quality.
But that program is later on being in place after it caused the piping
failure problem and the failure is caused by the corrosion.
Because of that -- well, this is not only the plant problem,
it also is the industry-wide problem. So the NRC issued Generic Letter
88-14. Because of this letter, they modified the plant and also changed
the maintenance procedures and also they put in place the checklist to
ensure that the air quality inside the instrumentation is dry and free
of oil, free of the particulates, particles.
DR. MILLER: So there is a monitoring system for that.
MR. HOU: A monitoring system.
DR. MILLER: Generic Letter 88-14 spoke to that.
MR. HOU: 88-14 probably -- it's asking for some actions,
but also providing information. This is an information letter. But
with that, they performed a corrective action to try to resolve the
problem, and this is what they do. So the problem no more exists.
And as for the plant air, and others, like saltwater, they
do not have the air quality control, but, however, due to their
preventive maintenance procedures, they look at more frequently and also
they do have certain filters, dryers, to make the air quality good. But
-- except they do not have to monitor it. Quality monitor the
instrument air.
But recently they have looked on those plants and see how
the condition look like and find out those lines are in very good shape.
So it look like it's not much a concern.
Now, talk about fire protection. Now, the fire protection,
they actually -- they perform a certain way procedures, try to manage
the aging problem. The first, in the updated FSAR, it has to be
reviewed by the staff and we accept that, there is a fire protection
program in there.
That contains certain systems and the components to ensure
they have -- maintain its function and for the fire-fighting -- for the
fire protection purpose.
And if -- for the non-safety-related components of the 16
systems fell into this category and there is not a problem. Now, in
particular, what -- for example, that includes the feedwater, auxiliary
feedwater and also the plant drain and also something, I guess,
sprinklers and also hose stations.
Now, another screening, there's about a structural system,
actually it's a monitoring the operating conditions of the system and
component and that's by walkdown, periodic walkdown, and also by
monitoring their performance during the plant operations.
So if have this covered, we know there is no problem because
the operating condition for those system and components actually -- the
fire-fighting capability, because in the safety-related components, we
have -- now, there are other concerns, like LOCA, like seismic, but for
this non-safety-related, they do not have -- for the operating loading
is already large enough.
So if the operating condition is good, we know their
fire-fighting capability is maintained.
Now, that kind system, for example, component cooling and
compressed air system. Now, another approach they're taking is those
systems -- now, they have part of it is safety-related, but also another
portion is non-safety-related. Now, for safety-related, we know they
have aging management programs defined, but in a non-safety-related,
they have the same material, subject to the same environment.
So if they apply the safety-related aging management, the
program, to this non-safety-related portion, that will take care of the
aging concern. So this is that their third approach.
Now, with all of these three approaches, they also, they
have supplemented by an ARDI. The ARDI program is one-time inspection,
just to verify those fire protection non-safety-related portions, there
is no significant general corrosion.
Now, with all these three approaches taken, that covers the
15 of the 16 remaining issues just mentioned, the non-safety issue, but
there is one remaining one. It's the condensate system. The condensate
system, the non-safety-related portion, the makeup line is downstream of
a normally closed manual isolation valve. But that can take care of by
the ARDI.
Now, talk about open items. Now, earlier, in my discussion
on the component -- the CVCS, I mentioned about there is a concern on
the stress corrosion cracking and the caused by the heat trace adhesive
and they going to replace it with a new material.
But this replacement, it is started in 1991 and they said
they're going to conclude it by end of the current licensing period.
That means more than ten years away. If we know this is a concern and
also we know that there is a way to fix it and also it's being started,
so why take so long to finish, and that's one of our open items. We
want to have reasons.
Another one of concern is within -- for this program,
because it takes so long, and also because of the replacement, but we
have to know what is the situation of the piping, would it already have
a crack or they may generate cracks during the ten years period of time.
So we'd like the program also to consider the inspections to
ensure that the condition of the piping. That's another open item.
Now, the third open item is about the fatigue. The fatigue,
about in the -- in the low cycle fatigue, they have some -- they monitor
the thermal transient and they perform analysis based on monitor of the
results. But the analysis, the evaluation scope, it also include heat
exchanger and thermal, is what they indicate in application. But in the
application does not provide a detail about the process how to conduct
this evaluation. So this is the third open item.
That concludes my presentation.
DR. FONTANA: Any comments? I guess one question for BG&E,
which I guess they don't really need to answer, is when you get asked
for what's taking you so long, what kind of answer do you give?
MR. HEIBEL: This is Dick Heibel, from Baltimore Gas &
Electric. What we were doing with the installation on the boric -- the
heat tracing on the boric acid, we're replacing it as components are
pulled out for maintenance and on a catch-as-catch-can basis. It's a
type of modification that, quite frankly, on its face, did not merit a
-- it's very expensive program to undertake.
So what we have is stocks of this different type of heat
tracing and when we pull pumps, valves, and do work on sections of pipe,
replace it on a catch-as-catch-can basis, or if the heat tracing fails.
DR. FONTANA: All right. Thank you.
MR. HOU: Do you have anything to say about it?
MS. COFFIN: I would just add the comment that the
application has seen stress corrosion cracking of these tanks due to the
heat and that's why identified the problem, and I'm sure they have an
engineering evaluation of why they can wait, but the staff hasn't seen
that yet.
DR. FONTANA: Okay. Who's next?
DR. SEALE: Dr. Powers will probably be here the next time
you talk about fire protection, so you may have a few questions to come
up at that time. You're not off the hook.
MR. GEORGIEV: Good morning. My name is George Georgiev,
and I'm with the Materials and Chemical Engineering Branch, with the
Division of Engineering, and I will be doing the presentation of Section
3.5.
Section 3.5 includes four systems; component cooling
systems, saltwater system, service water system, and the spent fuel pool
cooling system. All these systems have in common, in general, the low
temperature and as the name implies, they provide cooling to various
equipment components within the plant.
The license application reported that several operating
problems have occurred with those systems and with all fairness, they
are all normal kind of problems that have been in other plants. An
example of those problems, they had a leaky valve, valves in the
component cooling system, they got some degradation of cement in the
saltwater system, some high cycle fatigue in the spent fuel systems, and
all these problems have been addressed and the repaired and there
haven't been any other problems.
The materials of all this system are various because they
all operate under various conditions. They include carbon steel,
stainless steel, carbon-nickel, you've got various type of linings,
rubber linings, cement lining, and all this is necessary to do the
operation.
To address the problems and to take care of various
degradation mechanisms, the application reports aging effects and for
the purpose of this presentation, if you see here in the first where it
says corrosion, that includes various type of corrosion. It includes
crevice corrosion, pitting corrosion, galvanic corrosion, general
corrosion, and the microbiological induced corrosion.
Also, there are other specific for these systems,
degradation mechanism like wear, selective leaching, elastomer and
rubber degradation, mortar, cement lining degradation, and sulfur.
DR. SHACK: A question. I thought yesterday they said they
had rubber-lined systems, and you say cement.
MR. GEORGIEV: Yes, they do have both. They do have
above-ground piping, cement lined. In fact, they have reported some
leakage with this. I believe it has been replaced. But one has to
address all these effects, the licensee has identified aging management
program and most of them are existing programs. They are either site
director procedures, programs to -- maintenance program items, and in
some cases, they had to modify to address the aging effects.
And the only problem for this particular four system is the
ARDI program, which is the inspection program that they'll do to look
specifically for aging degradation, for these systems.
And as far as having open items, we don't have any open
items and we don't have any licensing issues.
That concludes my presentation.
DR. FONTANA: Any questions, comments?
[No response.]
DR. FONTANA: Very good. Let's move on then to --
MR. GEORGIEV: Give my time for somebody else.
DR. SEALE: That's generous.
DR. FONTANA: Get out the heating ventilation and air
conditioning systems.
MR. CHENG: My name is Tom Cheng, with the Mechanical and
Civil Engineering Branch. Today I'm going to discuss something about
Section 3.6, the HVAC systems.
My presentation is going to cover three systems, which are
the auxiliary building heating and ventilation system, primary
containment heating and ventilation system, and the control room HVAC
system.
Before I start my presentation, I would like to highlight
some operating experience identified at the site. Some cracking has
been discovered at the HVAC ducting due to vibration-induced fatigue.
Some losing fasteners has been experienced because of the dynamic
loading. The control room air conditioning unit was placed out of
service to repair the broken damper linkages. Also, during the
performance period, the elastomer degradation being identified.
BG&E, based on their operating experience and the review of
industry documents, so identified those five aging-related degradations
can cause possible aging effects, which is corrosion and elastomer
degradation, effect of dynamic loads, and the wear of valves and
radiation damages to the non-metallic material.
BG&E uses five aging management programs, as are listed in
my viewgraphs. The first one is the structure and system walkdown
procedures. I think that Dr. Munson already presented. Also, the ARDI,
and he presented also.
Structure and system walkdown procedures, which is existing,
the ARDI is a new one. In addition to those, BG&E also uses containment
leakage rate testing program. This program would be used to discover
and manage the leakage of surface wear and also the leakage of crevice
corrosion, due to crevice corrosion, general corrosion, degradation.
Also, preventive maintenance program, which is existing
program, to be used to discover and manage the effect of corrosion
problem.
The third -- the fourth one is the administrative procedure
-- I'm sorry. Excuse me. The chemistry program procedure, CP-206, to
be used to identify the corrosion. I have to apologize. I forgot to
list this one on my viewgraph.
BG&E has demonstrated in their application that the
combination application of this aging management programs can provide a
reasonable approach to inspect and assess the condition of the systems
such that any degradation condition will be identified and documented
and corrective action can be taken before the degradation proceeds to
failure to perform the intended function.
The staff who reviewed BG&E's application drew the following
conclusions. BG&E's approach for determination of possible aging effect
and approach to identify possible aging effect are reasonable and
acceptable.
The combination application of this aging effect program,
management program, meets the ten elements of the SRP. I did not
identify any open items, except one confirmatory item.
According to the application, the two new diesel generator
buildings and also associated HVAC are placed into operating in 1995.
Because the aging of the existing control room HVAC system equipment is
some 20 years ahead of the aging of those located in the diesel
generator building and also because the new equipment is just at the
beginning of its design life and the system have the design life of 45
years, BG&E concludes that the aging management of the new equipment can
be deferred.
BG&E's conclusion is acceptable, providing BG&E needs to
confirm that, the environmental conditions such that the moisture
contents in the air, temperatures and so forth in the two diesel
generator buildings are similar to the conditions in the control room
and that the material and hardware configuration of the HVAC system
located in the new building are similar to those in the control room.
This concludes my presentation.
DR. SHACK: What's the nature of the dynamic loading? This
is the vibration-induced?
MR. CHENG: That's just, for example, like accumulators in a
location and create a vibration, like a fan, those things.
DR. UHRIG: Imbalance.
MR. CHENG: Imbalance, correct.
DR. FONTANA: Any additional comments?
[No response.]
DR. FONTANA: Thank you very much. We'll move on to
emergency diesel generator systems.
MR. GEORGIEV: Hello again. Since we are formally
introduced already, I'll skip the first slide and go to the second one.
The emergency diesel generator system actually includes two systems, the
diesel generator itself and the diesel fuel oil system.
In general, the diesel has been operating adequately and
several problems have been reported, but all of them have been addressed
and resolved by BG&E.
The operating condition for the diesel basically is external
environment, which is plant quality type of air, and internal
environment, it's either water, tritiated water, or oil, or exhaust
gases coming when the diesel is operated.
To address the degradation mechanism associated with diesel
fuel oil, the application basically divide the problem into external
piping and buried piping, and materials involve the carbon steel
materials and for the buried piping, the buried piping has been wrapped
with protective coating and they also use cathodic protections to
protect the buried piping.
For the external service of the piping, they are protected
by paint. In essence, what BG&E reports to do to address the
degradation mechanisms, which are corrosion, weathering, fatigue, and
wear, they have existing plant programs and also are creating four other
new programs, which are a program which is catching all type of problem,
the program to inspect the buried pipe, and a program to inspect the
balance for the fuel oil storage tanks and they also have created a new
program for caulking around the storage fuel oil tank. The reason being
to prevent water and other material to seeps and effect the metal.
We have, in essence, agreed with BG&E's proposal to manage
the aging effects. However, we do identify one open item and this open
item pertains to BG&E has classified the cathodic protection as not
being needed for aging management of buried piping. The staff disagrees
with this. We believe that they do need both. They do need the
protective wrapping measures and also the cathodic protections.
License renewal issues, we don't have any. We have no
confirmatory items.
That, in essence, concludes my presentations.
DR. FONTANA: Any comments?
DR. UHRIG: Does the cathodic protection --
MR. DAVIS: It's a compressed current system, but it acts
the same way.
DR. FONTANA: Thank you. I guess we can go on to the next
item before lunch. It looks like it's fairly long, but we scheduled 20
minutes for it.
Moving on to the steam and power conversion systems.
MR. PARCZEWSKI: My name is Kris Parczewski. I am a member
of staff of Material and Chemical Engineering staff, in the Division of
Engineering.
I'm going to present to you a review, staff's review of
steam and power conversion systems. The steam and power conversion
systems included in the license application, license renewal application
consist of six systems; auxiliary feedwater system, feedwater system,
main steam system, steam generator blowdown system, extraction steam
system, which, by the way, is inoperable, and nitrogen/hydrogen systems.
Now, the system, the material, the materials of the system
are mainly carbon steel, but some of the systems have some additional
material. For auxiliary feedwater system has, in addition to carbon
steel, alloy steel, bronze, brass, cast iron, and elastomers. It is
exposed to an environment of chemically treated water at temperatures
just below 200 degrees Fahrenheit.
DR. FONTANA: Excuse me. Could you push that other
microphone out of the way? Thank you.
MR. PARCZEWSKI: The feedwater system, in addition of carbon
steel, has chrome alloy steel. It is exposed to an environment of
chemically treated water, the secondary water, basically, at a higher
temperature, up to 475 degrees Fahrenheit.
Main steam system, in addition to carbon, has alloy steel
and some stainless steel, and the orifice is made out of stainless
steel. It's exposed to an environment of wet steel and two-phase fluid
in the drain line when the condensation occurs.
The steam generator blowdown system has, in addition to
carbon steel, stainless steel, brass and cast iron. It is exposed to an
environment, two-phase fluid on the side of the heat exchanger and the
component cooling water on the tube side of the heat exchanger.
The extraction of steel is made strictly from carbon steel
and it's exposed to the moist air. It's empty, because it's not being
used presently. The nitrogen and hydrogen system is made out of carbon
steel and it is exposed to an environment of very, very dry gases, with
dew point minus 40 degrees Fahrenheit, which is extremely dry. But
still it might have some corrosion, so the applicant included it in the
review.
There are several different aging mechanisms, aging effects.
The most prevalent definitely is the corrosion and there are several
managing -- aging management programs for different systems, depending
on the operating conditions and the type of material and so on.
There are really two types of aging management programs.
One is a preventive program and the other one is monitoring. The
preventive program, in most cases, as you can see here, is controlled
with secondary water, there's pH, oxygen consideration, some iron,
boron, if there is boron in the system, and so on.
DR. SHACK: What do they use for their pH control agent?
MR. PARCZEWSKI: They use -- for pH control, they use the
hydrogen, which, of course, is composed in the heat exchanger, the high
temperature. You generate some ammonia, which keeps pH.
In the auxiliary feedwater system, in addition to secondary
water, there is a buried pipe inspection program, which is -- pipe are
exposed to MIC, microbiologically influenced corrosion, and there is no
way to control it. The only way to prevent it, the only way is just
inspecting it.
The second one is, of course, preventing maintenance.
Corrosion inspection, this is a new program, ARDI program, they do
corrosion inspection.
In feedwater, again, there is a corrosion inspection
program, which is the new ARDI program. In water, main steam line, main
steam system, the secondary water, to some extent, prevents some
corrosion. This is the only way we can do it.
DR. SHACK: In the feedwater system, what is the ARDI
looking for here?
MR. PARCZEWSKI: The ARDI is looking for damage due to
corrosion, inspection.
DR. SHACK: So there is no regular erosion/corrosion
checkmate type program.
MR. PARCZEWSKI: There will be another point in my
presentation on erosion/corrosion. It's a specific type of corrosion,
which is not included in the corrosion. We did it separately because
there is slightly different control of this particular mechanism. It's
the next slide.
In the steam generator blowdown system, we have already
secondary water chemistry. Then there is, of course, another component,
cooling water, which controls the chemistry of the cooling water in the
heat exchanger, the one which goes through the tubes, and there is an
additional corrosion inspection ARDI program.
In extraction steam, there is an ARDI program for control --
for inspecting the corrosion in this extraction system, which I
indicated really has only moist air. In nitrogen/hydrogen system, you
have motion control, which is really inspecting, but if there is any
corrosion, it's extremely small, because the gases are kept in a very,
very dry condition.
Now, erosion/corrosion. Erosion/corrosion is a very, very
significant aging mechanism and this is why we looked at it as a
separate item. It is, to some extent, controlled -- prevented by
controlling secondary water. However, there is a problem there.
Usually to reduce corrosion, you keep oxygen down as much as you can.
It is not true erosion/corrosion.
To optimize, you have to go up to a certain point. You
cannot go completely -- usually, you should keep above about 40 ppb. Of
course, you cannot do this. So really, in order to control corrosion,
you cannot optimize erosion/corrosion system. Therefore, prevention
using secondary water is somehow limited.
So we have, in addition to inspection programs, monitoring
programs. One of them -- we have the chemistry -- we have a monitoring
program which uses a program developed by EPRI and they have a check --
I have experience with that, an excellent program, and what it does, it
predicts which components are susceptible to corrosion and in addition,
it predicts when they're going to fail.
The program has to be, so to speak, calibrated, which means
some of the components have to be measured, the effect of
erosion/corrosion, by using the either ultrasonics or radiography, and
then input into the code. This calibrated code then can predict some
other components which are not measured, when they're going to fail,
when they have to be replaced.
It's being used by practically all the licensees, because it
does a very good job.
In addition, there is an ARDI program for inspection which
basically is an extension of this monitoring program, using the same
program, but it adds additional components which originally were not
included in the program. So basically, it's an extension of the E/C
program.
This is for -- in main steam line, again, you have secondary
water chemistry monitoring, basically the same programs as for water --
in feedwater.
The same applies to steam generator blowdown. Again, you
have the same program. So all those three systems have the same
program.
In addition, cavitation is another mechanism which, of
course, is not a chemical. It doesn't involve corrosion. It's
hydrodynamic phenomenon, and there is an -- there is going to be
established an ARDI program for inspecting cavitation damage. There is
no way to mitigate -- to prevent it. Just the only thing is to inspect
it.
This same applies to the wear program. ARDI inspects the
control of seats and plugs of steam atmospheric valves and sterite
carbon steel borders and MSIVs. So this program will be limited to
those components.
Now, the steam generator blowdown system would have a
leaching mechanism. There are some components made out of cast iron or
made out of brass. In those components, the environment, corrosive
environment removes selectively materials in case of cast iron to remove
the ferrite phase. In the case of brass, it removes zinc. So this is
the corrosion mechanism.
Again, there is no -- you can control, to some degree,
through secondary chemistry, but it still needs to be inspected and
there is inspection program, ARDI inspection that is going to take care
of it.
Now, elastomers, there are two programs addressing the
elastomer degradation. One program, which is the sealant inspection
program, will take care -- again, you cannot prevent the program. The
only thing is to inspect it.
The sealant inspection program, which inspects the sealant
around the condensate storage tank, which might be affected by the
environment. ARDI elastomer program, which will address the inspection
of solenoid operated valve made of ethylene, propylene, and subject to
wear. So that's the programs.
The final is fatigue. In some of the piping in feedwater,
you have stratification of fluid in the pipe and this stratification
would produce thermal stresses which will obviously produce some fatigue
of the piping. So this is the final program I will be discussing here.
DR. SHACK: John, just a question on that fatigue. You need
a horizontal run of piping to have that problem, don't you?
MR. FAIR: Yes. As a matter of fact, that's why they
selected this section of the pipe, right near the nozzle. We asked a
question as to why it wasn't a concern anywhere else and it was because
there is a vertical riser coming up to that horizontal run of pipe.
DR. SHACK: So there's just one sort of small segment of
horizontal piping here.
MR. FAIR: Yes, and this is an area where they have a fairly
detailed monitoring of the thermal temperatures in the area to do a
detailed fatigue analysis.
DR. FONTANA: Any additional comments?
[No response.]
DR. FONTANA: Thank you very much. I think we'll move on to
the next topic, sampling and monitoring systems.
MR. PATNAIK: I'm Pat Patnaik, from the Division of
Engineering. I've been asked -- I compiled the sampling and monitoring
system Section 3.9. This sampling and monitoring system comprises of
nuclear steam supply sampling system, radiation monitoring system, and
the instrument lines.
Mine is going to be a snapshot of the SER. The nuclear
steam supply, NSSS sampling system provides for sampling of liquids,
steam gases, radioactive and chemical control of plant fluids, and this
has five subsystems, which is reactor coolant sampling, steam generator
blowdown sampling, radioactive waste sampling, gas analyzing sampling,
and post-accident sampling.
The general categories of equipment are accumulators, air
drives, piping, valves, valve operated panels, instruments, sample
vessels, and pumps. The materials for these components are stainless
steel or carbon steel.
These are compatible with the medium inside the pressure
boundary, which is either borated water or chemically treated water.
The components in this NSSS sampling system that we
evaluated had the intended functions of maintaining the pressure
boundary. It provides containment actuation of the nuclear steam supply
sampling system during a LOCA. It also provides capability to sample
gaseous fluid during an accident.
The RMS, which is the release and monitoring system, detects
an increasing radiation level or an abnormal radioactivity concentration
at selected points in the plant. It provides indication of such
conditions to operating personnel and the system monitors also the
discharge of radioactive fluids from the plant and provides a signal to
isolate components in the event of abnormal conditions, to prevent
uncontrolled release to the environment.
Again, the RMS comprises of piping, tubing, pumps, valves,
filters, instrumentation, and the materials are either stainless steel
or carbon steel, and which are compatible with the internal environment
which is either air, borated water, or chemically treated water.
They had intended functions of maintaining the pressure
boundary. It provides containment isolation, radiation signal to the
engineered safety feature actuation system for containment isolation and
radiological release control.
DR. SEALE: Would you help me? I've got a block. What's
the BACI, again?
MR. PATNAIK: That's the boric acid corrosion inspection
program that you heard in the earlier presentation.
DR. SEALE: Okay. I knew I had heard it, but I had
forgotten what it was. Somehow or another, I didn't feel comfortable.
MR. PATNAIK: This is the program that the in-service
inspection personnel perform right after the outage and walk down the
system.
DR. SEALE: Yes, okay.
MR. PATNAIK: Now, moving on. The instrument lines are
associated with all plant systems. Therefore, the applicant evaluated
this as a commodity. And for the purpose of instrument line, the
evaluation is from the -- looks at from the process line down to the
first hand valve or route valve. Then it went line-up to the
instrument. In other words, it's defined as the components located
downstream of the first hand valve off the main process line or the
vessel, which is called the route valve, and the instrument lines are
all piping, tubing, fittings, hand valves.
The materials are stainless steel, carbon steel, copper,
depending on the environment inside, which could be borated water,
chemically treated water, oil, air. The components that we evaluated
had the intended functions of maintaining pressure boundary integrity.
Corrosion manifests as general corrosion of external, which
is due to leakage of borated water from piping or joints. As the
previous speakers well stated, the ARDI program is -- the licensee has
taken credit for the ARDI program and the BACI program, boric acid
corrosion inspection program, on the nuclear steam supply system
sampling lines.
And for radiation monitoring system, also, ARDI program has
been taken credit and on the instrument lines, again, we have ARDI
program. Structures and systems walkdown, which you've heard.
Then there are two other programs that the licensee has
taken credit for, which is control of shift activities and ownership of
plant operating spaces.
I want to walk you through these last two, because you
haven't heard anything of these two.
Under control of shift activities, operators perform the
walkdowns, plant operators. They inspect accessible operating spaces
during each shift and when the containment -- when the -- during an
outage, they also perform these walkdowns inside the containment, once
per shift.
This program provides for discovery of conditions that could
allow general corrosion to progress for the instrument line supports, by
performing visual inspections.
The inspection items related to aging management include
vibrations and effects that may have caused by this age-related
degradation mechanism, such as damaged piping, instrument tubing, or
leakage of fluids.
Also, this program would also detect leakage of fluids,
which is as a result of conditions progressing from the age-related
degradation mechanism. And the licensee also has the corrective actions
program which will take care of any of these aging effects noticed
during the inspections.
The other program is the ownership of plant operating
spaces. Under this program, the plant operating spaces, they have
owners identified within each space who would provide a point of contact
for any individual who finds deficiencies or any concern with the space,
and the responsible individuals are required to periodically inspect
their assigned spaces for housekeeping, cleanliness, material
conditions, and radiological deficiencies.
This program provides for discovery of general corrosion of
the instrument line supports by performing visual inspection in plant
operating areas.
Again, the inspection items related with this aging
management include items related to specific age-related degradation
mechanisms, such as corrosion; item two is effects that may have been
caused by age-related degradation mechanisms, such as loose lines or
loose fasteners, because of fluids, and the conditions of pipes, loose
fasteners, conditions that would allow progression of age-related
degradation mechanisms, such as unbracketed lines and pipes.
Again, they have the corrective action program which takes
care of any deficiencies that they identify.
That's the general corrosion.
Next, we have this crevice corrosion and pitting. For the
nuclear steam system, we have the ARDI program and then we have the
other programs like specification and surveillance of the system,
component cooling, service water, secondary chemistry program.
These are all the chemistry programs, which the licensee is
taking credit for, as mitigation. Then the third is the local leak rate
test of penetrations. Actual, this local leak rate test of penetrations
is identifying where in the control valves, but the staff didn't
evaluate aging management on the valve internals because the valve
internals perform their intended function with moving parts and changes
in the configuration, which is not subject to aging management review.
DR. SHACK: Would this local leak rate give you a thermal
cycling problem and a fatigue problem?
MR. PATNAIK: Local leak rate --
DR. SHACK: Through the valve. Is this a hot/cold -- hot
fluid going to a cold fluid kind of thing?
MR. PATNAIK: No. I'm talking about Appendix C test -- I
mean, Appendix J, Type C test.
DR. SEALE: Okay. Which is --
MR. PATNAIK: Which is different.
I guess I have one more slide. Lastly, the low cycle
thermal fatigue is one of the possible plausible age-related degradation
mechanisms on the nuclear steam supply sampling system. Anytime you
draw a sample, you go through a thermal cycling, and what the licensee
has used fatigue monitoring program.
We have an open item on this, like many other fatigue items,
items on fatigue, this item involves -- there are 11 locations in the
RCS that are being monitored for fatigue and our staff thought that the
applicant should provide validation to demonstrate that the low cycle
fatigue uses of piping and valves in the RCS hot leg sampling is bounded
by monitoring of those 11 fatigue critical locations. That was the only
open item.
There is one other item, age-related degradation, elastomer degradation.
The internals of check valves in the past, the post-accident sampling
system gas return line tot he containment, and some of the supports in
the instrument line. They contain the elastomer materials that are
susceptible to age-related degradation.
The staff determined that the applicant's ARDI program will
effectively manage this age-related degradation mechanism. So the staff
concluded the applicant has demonstrated that the aging effects
associated with the sampling and monitoring systems are adequately
managed, such that there is reasonable assurance that the systems will
perform their intended functions in accordance with the current
licensing basis.
So this is a nutshell of what we presented of the ACR.
DR. FONTANA: Any additional comments?
[No response.]
DR. FONTANA: Well, thank you very much. The next item is a
fairly long one, so I think we ought to break for lunch now. Since
we're ahead of time, I guess we can show up at 1:00.
MR. GRIMES: That would be acceptable to the staff. As a
matter of fact, we would prefer that, since the folks that are supposed
to be here for the afternoon session might not otherwise know when to
show up. So if we could reconvene at one, that would be our target.
DR. FONTANA: That's fine. Okay. We'll come back at 1:00.
[Whereupon, at 11:53 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
[1:00 p.m.]
DR. FONTANA: The meeting will resume. We'll move into the
presentation on building structures. David Jeng.
MR. JENG: Yes.
MR. GRIMES: Dr. Fontana, before we continue with the staff
presentation, I would like to mention that I just provided a copy of a
staff position that was issued yesterday to NEI on fuses, which
concludes that aging management review for fuses is not necessary.
Assuming that NEI does not object to the conclusion in that
position or that we otherwise don't receive critical comments on the
basis for arriving at that decision, that will address one of the open
items in the Calvert Cliffs review.
That letter also illustrates the process by which we're
going through and defining these generic renewal issues and addressing
the resolution and then documenting the results.
It describes the nature of the guidance that we would add to
the standard review plan. So we offer that also to the subcommittee as
an illustration of how the process is working.
DR. FONTANA: Thank you.
MR. JENG: Good afternoon. My name is David Jeng. I am
with the Mechanical and Chemical Engineering Branch of the Division of
Engineering.
Today, I am going to report to you our review findings of
the building structures, which is covered in the ACR Section 3.10.
Please go to page 75.
Building structures of BG&E include the following five
items; primary containment structure, turbine building, intake
structure, miscellaneous tank involved, auxiliary building, and
safety-related diesel generator building structures.
The basic approach of BG&E in achieving aging effect
management for their structures are as follows. They, first, identified
all the structures and component types, such as the concrete structure
components or steel structure components, and matching these types to
the potential aging-related degradation mechanisms, such as the
corrosion of the steel, cracking of the concrete, and corrosion of the
stainless steel liners in the spent fuel pool.
By matching these two concepts, the component types, with
the potential age degradation mechanisms, they come up with some ten
structure and component types such aging type categories and I am going
to report to you how these ten categories are identified and how their
aging management programs are proposed to be handled.
Going to page 76. The first item is the corrosion of
tendons in pre-stressing losses. BG&E, in this evaluation, determined
that their aging management program for this item should include
mitigation -- periodic tendon surveillance program and implementation of
a long-term corrective action program, which was established after their
discovery of the earlier degradations in the tendons group.
Going to the second item on the same page. Concrete
reinforcing degradations. BG&E determined that the aging effect of
freeze/thaw, leaching, aggressive chemical attack, groundwater, boric
acid, and flow-in water do not apply to their concrete structures,
except for the intake structure, which is submerged into a bay water, a
more aggressive environment type water.
The reason for their judging that these effect do not apply
because the concrete they provided is a very high quality concrete and
their aggregate are tested to standards and also the design is such that
they are consistent with the ACI process and they are going to ensure
such effect would not prevail.
Please go to page 77.
DR. FONTANA: Are they also inspected at some point to make
sure that that kind of construction standard really does -- those kind
of construction standards really does provide concrete that is that
good?
MR. JENG: Yes. As I said in the slide, in the curing,
which covers the good quality construction practices and the
post-construction curing of the concrete.
Going to page 77. Weathering of the caulking, sealants and
expansion joints. BG&E's aging management program items include for the
fire barriers in the auxiliary building and adjacent rooms, they are
going to implement an existing fire barrier program. For the other
caulking and sealants which are non-fire barrier functioning, they are
going to propose a new program to perform inspection.
But BG&E did not adequately cover the potential aging effect
of radiation temperature on the non-metallic portion of the penetration
assemblies, such as the cable installation, sealants for their
penetration, and this item remains open, and this is listed in the open
items later.
Please go to page 78. The corrosion of containment wall and
dome liners. BG&E's evaluation decided that the program should include
use of a protective coating to minimize corrosion effects,
implementation of visual inspections. They are using STP-M-665 1/2 on
the two plants, respectively.
And the last item that BG&E indicated that the -- based on
their past experience, their inspection program has been shown to be
quite effective.
Please go to page 79.
DR. SHACK: What is the nature of the periodic inspection?
MR. JENG: Okay. The most inspection is the type of
inspection -- for instance, the containment liner inspection, which is
based on the ASME IEW/IWL provision, as well as the Reg Guide 1.35, and
they are done on every refueling outage.
DR. SHACK: But is that a visual inspection?
MR. JENG: Basically, visual inspections.
We are on page 79. Corrosion of steel. The aging
management program lists item includes use of protective coatings to
minimize corrosion. Again, implementation of a periodic visual
inspection program. But for the containment emergency sump cover and
screen, which is sort of unique, it was not specifically covered in the
earlier BG&E maintenance program and they are proposing a new inspection
program, number STP-M-661.
Going to the lower part of the page, corrosion of the
refueling spent fuel pool liners and cavity sealing ring, but in 1995,
BG&E did inspect the fuel transfer canal and ensured that there was no
indication of damage or corrosion.
So for this item management, BG&E indicated that the concern
is the potential IGSCC, which may be applicable to the stainless steel
liners and the PCSR and for this item management, BG&E proposes to use a
periodic walkdown, that's MN-1-319, to manage the aging effects.
Please go to page 80. The next item in the category is
degradation of intake structure containing concrete walls, sluice gates,
and steel subject to aggressive chemical attack.
The aging management program proposed by BG&E for this
category include use of a preventive coating to minimize steel
components corrosion, implementation of periodic inspection, and
performance of structure and system walkdowns.
The lower portion of the page, corrosion of steel components
inside miscellaneous tanks involve enclosures. For this particular
category, BG&E proposes to use preventive coating to minimize corrosion,
implementation of periodic walkdowns, and through application of these
programs, they intend to manage the corrosion of CST tank number 12,
FOST tank number 21, and the auxiliary feedwater valve enclosure.
Please go to page 81.
DR. UHRIG: You said they propose to use. They presently
have preventive coating, do they not?
MR. JENG: They do, but they are making it official
commitment for some enhancement of the content of the program.
DR. UHRIG: Thank you.
MR. JENG: Please go to page 81. Weathering of vertical
tendons. BG&E did discover some degradation in the vertical tendons.
For this category, it proposes to include implementation of periodic
inspection and to perform needed engineering evaluation and take
whatever needed corrective actions. The staff finds this to be
acceptable.
Go to the lower portion of the page. The evaluation of
neutron absorbing materials. For this particular consideration, BG&E
proposes to perform periodic sampling of the neutron absorbing materials
and also to implement the EGP 86-03R title, analogies of neutron
absorbing material in spent fuel storage racks.
Please go to page 82. Besides the about ten items I
discussed, BG&E also looked into the potential effect of foundation
settlement and it concluded, and the staff agreed to their conclusion,
that because of the following three reasons, the foundation settlement
is not a plausible concern for the BG&E structural foundations.
The number one basis is the design is such that the building
capacity of the foundation material is so high, with a margin of more
than ten. Secondly, there is the underground drainage system in place
right now which would tend to control groundwater levels. And the third
reason is the -- after all these years, the settlement, if any, should
be mostly in the uniform settlement and the settlement normally do not
effect the structure performance.
For the intake structure, BG&E did also maintain that the
first and third reason alone should be able to justify that there will
be no settlement concerns for intake structures. Incidentally, the
intake structure of the underground drainage system.
I have covered the major, some ten component category aging
effects and the BG&E proposed management programs. The staff did review
all these proposed programs in great details and except for the open
item which we have three items later, we have come to conclusion that
they have done adequate evaluation job and proposed adequate scope of
programs to achieve the needed management of aging effects of BG&E
building structures.
Please go to page 83. There are three open items. The
first one is pertaining to the tendon force trending analysis. Because
of the major difficulties experienced in the tendon areas, and the staff
asked BG&E to show some trending of the existing forces in the tendons
to stay above the minimum requirements called for by the design, at the
end of the 60 years or 20 years extended period, and this is the first
open item.
The second one pertain to the concern of the groundwater
effect on the intake structure from the embedded surface areas and the
BG&E presented some chemical analysis of the groundwater for the plant.
In fact, they provided three reports. One of the three testing show
very high -- concern on the degradation of the concrete surfaces.
So for this reason, the staff asked BG&E to commit to
perform at least some portion of the inspection on the outside exterior
surfaces of the intake structures before the starting of the license
renewal period at least one time, and this is the second open item.
The third open item pertain to the BG&E need to further
address the effect of aging due to irradiation and temperature on the
cover, O-ring and other known metallic materials for the electrical
penetrations.
Please go to page 84. There are two confirmatory items.
The first one pertain to the BG&E commitment to perform inspection
before year 2002 of the containment domes. There have been some
freeze/thaw induced degradation observed on the top of the containment
and BG&E maintains that -- but the staff wants to make sure, you do this
inspect one before year 2002, and they consented.
The second item pertain to the BG&E commitment to further
enhance the guidance on their MN-1-319, which is quite often used in
many of the programs. The enhanced area covers, number one, to provide
much more detailed guidance on how to judge the functionality of the
structures and components.
The second item is to further enhance the guidance on how
they can change -- the authority to change the programs, scoping
decision criteria, and how to change the schedule of inspection.
So these two item BG&E has committed enhance in their
program MN-1-319. There are six -- page 85, please. There are six
license renewal issues. Most of these issues are not germane to BG&E
because they already provided information specific to their plant and
one item -- two items that staff has yet to develop their own position.
So I am reporting to you that the license renewal issue does
not pertain to BG&E application.
With this, I am concluding my presentation and if you have
any questions, I would be pleased to answer your question.
DR. FONTANA: Let me take time to look at these just for a
second here.
DR. UHRIG: These issues will be resolved before -- these
six issues.
MR. JENG: The six issues are not germane to BG&E's
situation.
DR. UHRIG: Okay.
DR. FONTANA: Any comments? Any additional comments?
[No response.]
DR. FONTANA: Well, thank you very much.
MR. JENG: Thank you.
DR. FONTANA: Thank you. We'll move on to component
support, cranes and electrical commodities.
MS. LI: I'm Renee Li, from Mechanical Engineering Branch,
in Division of Engineering. The section I'm going to talk about is
Section 3.11, which covers component supports, cranes and electrical
commodities.
For component support, the component support is defined as
the connection between a system or a component within a system and the
structure member. All component support type that provide support to
system and the components which are within the scope of license renewal
are also considered to be within the license renewal.
The component support including piping supports, cable
raceway support, HVAC ducting support, and equipment support. The
support section also include the piping segments that provide structure
support.
These piping segments include piping segments beyond the
safety and the non-safety-related boundary to the first seismic
restraint and they perform the intended passive function of providing
structure support to the safety-related piping.
The crane section include fuel handling equipment and other
heavy load handling cranes. This section covers the evaluation of, A,
components involved in fuel handling and transfer and, B, cranes that
routinely lift heavy loads over safety-related components that are
associated with fire systems, spent fuel storage, refueling pool,
elevator fuel handling and the cranes.
The last section I'm going to talk about is the electrical
commodity. The electrical commodity include the structure enclosure for
electrical equipment which provides support and protection of the
electrical equipment located within them.
The electrical commodity include miscellaneous panels, motor control
center cabinets, switch gear, disconnected cabinet, bus cabinets,
circuit breaker cabinet, local control station panel, battery terminals,
and the charger cabinet, and inverter cabinet.
The following three slides will show the applicant proposed
aging management program to manage the aging effects and which will also
show which components that -- component support that those aging
management are credited for.
Our review is to ensure that the applicant's proposed aging
management program will manage the aging mechanism and the effects in
such a way that the intended function of the component supports will be
maintained in accordance with the current licensing basis during the
period of extended operation.
As you see, the aging management program for general
corrosion of steel, which has combination of numerous program, and the
most of the program have been addressed earlier. I think the only one
maybe is the snubber visual inspection surveillance program, and that's
the tech spec snubber surveillance program, which has a table that will
determine the frequency and also the sample size of each inspection.
The other have been covered, except addition of baseline
walkdown, which is to pick up those component supports that are not
covered by the original baseline inspection.
Preventive maintenance checklist. Usually, the PM checklist
or the task is for a specific component or component support. For
example, there is a preventive maintenance checklist that's a modified
version of the existing program and it's credited for aging management
of the metal spring isolator and the fixed basis component supports,
such as containment air cooler fan.
The same program for the general corrosion of steel are used
for managing the effects of loading due to hydraulic vibration or water
hammer.
The next slide shows the aging effects of loading due to
some extension of piping and the component, and aging management program
basically are very similar to the previous one. The first one is the
structure and the system walkdown. The second one is the control of
shift activity. The third one is the ownership of plant operating
spaces and also the section 11 ISI program.
The same program is also used to manage the aging effects of
loading due to rotating machinery. The last slide for the component
supports has to do with aging effect of elastomer hardening and the
program -- the aging management program, the three programs we already
discussed, plus the plant modification program, the plant modification
program is a new program and that's credited for the modification of
control room HVAC air handler support to replace elastomer isolator with
the spring-type isolator.
The last aging effect is the stress corrosion cracking of
high strength bolts and the aging management program that is credited
for ISI and addition of baseline walkdown.
And for the piping segment that provides structure support,
in the application, BG&E states that the same aging effect for the
safety-related portion of the piping will apply to these piping segment
beyond the safety and the non-safety-related boundary. Therefore, the
aging management program that credits for managing the aging effects of
safety-related portion of piping are also applicable to those piping
segments.
The next two slides are for fuel handling equipment and
other heavy load handling cranes. Again, our review is to ensure that
the applicant's proposed aging management program will manage the aging
effects in such a way that the intended functions of the components will
be maintained in accordance with the current licensing basis during the
period of extended operation.
BG&E has proposed numerous evaluation programs, procedures,
instructions, and including PM tasks, and those programs have been used
for different combinations of aging effects and the fuel handling
equipment or the heavy load handling crane.
The aging effects they cover has general corrosion,
oxidation, fatigue, and wear.
The next slide will show the mechanical degradation,
distortion, and also corrosion due to boric acid. I will not go into
the detail of the various PM programs.
This is the slide for the mechanical degradation,
distortion, and also corrosion due to the boric acid.
Most of the programs that I just showed, they are existing programs.
Just a few are the modified programs and the programs generally provide
requirements for inspection. Most of the inspections are visual
inspections, but they have some NDE, and each program is credited for
discovery and management of certain aging effects for a specific group
of components.
I think one of the programs, that is the boric acid
corrosion inspection, this morning has been discussed and there are some
specific concerns of that program.
DR. SHACK: Is the snubber considered a passive support or
are you --
MS. LI: The snubber itself is active. But between the
snubber and the structure, the portion we consider as a support to the
snubber, is passive. So that is the one that's inside scope.
DR. SHACK: But the active function of the snubber is
checked.
MS. LI: Is checked per the tech spec.
DR. SHACK: Under the tech spec.
MS. LI: That's right. The next two slides are for the
electrical commodity. The applicant has identified the aging effects of
fatigue and electrical stressor and the wear, also general corrosion and
the dynamic loading on the motor panels.
As far as the aging management program, for the fatigue, the
licensee credits the PM checklist, I think the name is reactor trip
circuit breaker inspection, and that has a requirement of every 48
weeks, they do a visual inspection and also require that if any fatigue
degradation is detected, it should be reported and they evaluate per
site corrective procedures, and operating experience showed that this
has been very effective.
Also, the program, ARDI is also credited for these aging
effects.
For the electrical stressors, the PM procedure, MN-1-102, is
credited and in accordance with the PM procedure, repetitive tasks are
performed, train, inspect, and calibrate the electrical commodity, and
if there is any degradation, it will be reported and they evaluate and
correct action taken. Also, the ARDI program is credited for this aging
effects and I think for the other two, for maintenance procedure and the
ARDI, the dynamic load -- yes. The dynamic loading on the motor control
center panel are the one that nearby the emergency diesel generator and
the concern is the vibration.
The staff's review, we do not identify any open item or
confirmatory item and also there is no license renewal issue in this
area.
Based on the information provided by the applicant, we are
able to conclude that the aging management program will be adequate to
manage the aging effects identified by the applicant and we believe that
there is a reasonable assurance that component support, fuel handling
elements, heavy load handling cranes and the electrical commodity will
perform their intended function in accordance with the current licensing
basis during the period of extended operation.
That concludes my presentation.
DR. FONTANA: Any comments?
[No response.]
DR. FONTANA: Thank you very much.
DR. SEALE: Drinking with a fire hose.
DR. FONTANA: Pardon?
DR. SEALE: Drinking with a fire hose.
DR. FONTANA: The next area -- is it one presenter for the
remaining areas?
MR. SHEMANSKI: Yes. I've got the next four sections.
DR. FONTANA: Okay.
MR. SHEMANSKI: I may need some help, though.
DR. FONTANA: All right.
MR. SHEMANSKI: Good afternoon. My name is Paul Shemanski.
I'm with the Electrical Instrumentation and Control Branch, Division of
Engineering. I will be making presentations on the four remaining
sections; Section 3.12, 3.13, 4.1 and 4.0.
Starting with Section 3.12, which is entitled electrical
components. This section is devoted primarily to not EQ cables.
Electrical cables are long-lived, passive components that are within
scope and subject to an AMR and cables that are associated basically
with every plant system.
At Calvert Cliffs, there are approximately 30,000 cables and
of the 30,000 cables, 29,000 are non-EQ cables and 1,000 are EQ cables.
Again, this section deals primarily with the non-EQ cables.
Because of the large population, BGE decided to treat cables, the non-EQ
cables as a commodity and for efficiency, the 29,000 non-EQ cables, they
were divided up into six groups, as indicated on the slide.
The first two groups are located in the main steam
penetration room. The first group consists of cables and power control
servers routed without maintained spacing, whereas the second group
consists of cables and power servers which are routed with maintained
spacing.
The reason group number two has maintained spacing is that
these cables are designed to carry larger currents, so they have to be
spaced a certain number of cable diameters away from each other, so that
you don't suffer the thermal effects of self-heating, due to ohmic
heating.
DR. MILLER: So the spacing requirements are strictly the
ohmic heating.
MR. SHEMANSKI: It's the ohmic heating and the spacing is
determined by the actual -- I guess they go through and do the thermal
calculations and determine how many cable diameters away form each other
they must be spaced. It's a function of the cable loading, the current
it's carrying.
DR. MILLER: Are any of these cables -- are there any in
radiation areas? I notice you have -- I'm looking at the LRA right now
and you have a lot of discussion of cables that are in radiation areas
and how you're going to handle those through calibration and so forth.
MR. SHEMANSKI: These particular cables are located in the
main steam penetration room and I do not believe -- Carl, is that
correct? I think they're only subject to thermal.
DR. MILLER: These probably aren't in radiation areas.
MR. SHEMANSKI: I don't believe these are.
MR. YODER: My name is Carl Yoder. Those cables in the
first two groups are outside containment. They are in the aux building,
not just the main steam pen room, but throughout the aux building.
MR. SHEMANSKI: Now, group three, cables and power servers,
those are located in containment and they are subject to synergistic
thermal and radiation aging and the max temperature in containment is
120 degrees F.
Group four, cables in the four KV power service, those
cables are subject to thermal aging and they are used for the four KV
pump motors in the saltwater system.
Group number five, those cables are located in
instrumentation service and they are subject to thermal aging resulting
from a reduction of insulation resistance.
DR. MILLER: So those are subject to degradation.
MR. SHEMANSKI: Yes, they are. Instrumentation cables tend
to be smaller and more susceptible because of their physical dimensions,
more susceptible to thermal degradation, and those particular ones, they
manage the aging through instrument calibration program. They
periodically calibrate the instrumentation circuitry and they can, in
essence, tell if they're getting degradation due to calibration errors
or whatever -- not calibration errors, but changes in calibration.
DR. MILLER: So the concept -- I'm reading this section
right now in the LRA. The concept there is you have -- starting at
excessive drifting, for example. You're going to attribute those to
cabling or --
MR. SHEMANSKI: You start by doing a root cause analysis and
it may lead you to a determination that the cable insulation may be
degrading, resulting in the increase in -- or I should say reduction in
insulation resistance and that would effect the calibration of the
instrumentation circuits.
DR. MILLER: And all those cables are accessible, so they
can replace them.
MR. SHEMANSKI: I believe so. And the last group are cable
sin the four KV power service. They're also used for the four KV pump
motors in the saltwater system, but they're -- well, they looked to see
if they were susceptible to a degradation mechanisms called treeing.
Treeing is a form -- it's a high voltage induced degradation. It
results in kind of a tree-like pattern in the cable insulation and its
degradation that provides hollow microchannels in the cable to grow.
And as those microchannels grow, I guess, the cable becomes
-- you have changes in the dielectric material, dielectric
characteristics of the insulation. However, they did do an ARDI and
found that there was no evidence of any treeing in those high voltage
cables.
DR. MILLER: And none of those cables -- are those cables in
radiation areas?
MR. SHEMANSKI: No. They're in the -- they're used for the
four KV pump motors. They are subject to thermal degradation.
DR. MILLER: So the only cables really in the radiation
areas are instrumentation cables. Is that right?
MR. SHEMANSKI: No. There are cables in power service in
containment, group three.
DR. MILLER: I'm sorry. You're right.
MR. SHEMANSKI: And those, of course, are subject to
synergistic thermal and radiation aging.
DR. MILLER: So how are -- I can probably read it here and
find it. How are they going to handle those effects in case --
instrumentation, I can see they're going to do surveillance. On the
power service, how are they going to do those, if there is any
degradation? Since we know that degradation of instrumentation cables
-- I mean, there are different insulators and so forth, I'm certain
there are.
MR. SHEMANSKI: Group three was subjected to an ARDI. As a
matter of fact, all six groups were subjected to ARDIs and the ARDIs,
the age-related degradation inspections, have been completed.
Specifically, for group three, BGE is telling us that any power cables
that satisfy the following criteria, if they're inside containment, if
they use EPR, which is ethylene, propylene, rubber or cross-link
polyethylene, if they're not environmentally qualified, which these are
non-EQ cables, they're saying that these are considered to be subject to
plausible synergistic radiation and thermal aging. So they will --
those are plausible aging mechanisms, so they will periodically have to
look and see if they are getting any type of degradation.
DR. MILLER: Is that by visual inspection?
MR. SHEMANSKI: Well, one way. They do have monitors,
radiation temperature monitors. They know what the threshold levels are
of the cable insulation material. Carl, I believe, wants to amplify.
MR. YODER: I just want to clarify. With regard to those
cables we have determined to be subject to plausible aging, except for
the instrumentation cables, which will be subject to loop calibrations
that include the cables, the rest of those, we've committed to replace.
DR. MILLER: So they're all accessible for replacement, in
other words.
MR. YODER: Well, we'll probably end up re-running them. We
won't pull all the cables out.
DR. MILLER: So you pull the old ones out and you'll
re-route them if you can't route them --
MR. YODER: We normally would not pull an old cable out
because it would probably damage surrounding cables. So we'd run new
ones.
DR. MILLER: I see.
MR. SHEMANSKI: This particular slide shows the various
aging effects which cables are subject to, embrittlement, cracking,
reduced mechanical integrity, swelling and so forth, insulation
resistance reduction. And we mentioned the ARDI program, which has been
completed for these cables.
I also talked about the instrument calibration program.
As a result of our review of these non-EQ cables, we did not
identify any open items or license renewal issues.
DR. MILLER: Now, somewhere I saw that, of course, there is
a generic issue 168 on cables. How do we get around that? That's not
been fully reconciled yet.
MR. SHEMANSKI: This particular section is on non-EQ cables.
DR. MILLER: That's non-EQ, you're right. I'll wait for
that.
MR. SHEMANSKI: My last presentation will be on EQ. 168,
GSI-168 is devoted to environmental qualification.
DR. MILLER: We'll wait.
MR. SHEMANSKI: This is not the section, 3.13. This is
confusing. Let me explain how we arrived at putting this section in the
SER.
If you look in the license renewal rule, EQ appears twice.
It appears once under scoping, where the five regulated events are
listed, ATWS, fire protection, PTS, so EQ is listed under scoping. Then
it appears again in the EQ rule -- I mean, in the renewal rule as a
TLAA.
This particular section, when BGE generated their
application, they wanted to address the scoping aspect of EQ, which
requires that you look at passive, long-lived components. So what they
did was they took the EQ master list and they only looked at the
long-lived, passive components on the EQ master list, where there may be
intended functions of these components that are not managed by the EQ
program, and because the EQ program focuses primarily on radiation and
temperature. Those are the main parameters.
However, if you look at some of these components, such as
the containment penetration assembly, that is subject to general
corrosion. Well, that general corrosion is not handled by the EQ
program. So BGE identified four components here, the containment
penetration assemblies, core exit thermocouples, they're subject to
crevice corrosion and pitting, solenoid valves, they're subject to
crevice corrosion and pitting, and the reactor level vessel monitoring
in core assembly, which is subject to crevice corrosion and pitting.
For those particular aging effects, they identified the
following programs. For the specific class of EQ components, the ones I
just mentioned, general corrosion, crevice corrosion and pitting, those
are handled by the chemistry control program in PEG-7, which I believe
is a walkdown type program.
Kapton-unique aging, that one is dealing with the insulated
wires on Valcor solenoid valves. It turns out that Kapton, it's not an
extruded insulation material. It's sort of wrapped and, as such, it's
more susceptible to absorbing moisture and under hot high moisture
conditions, hot temperature and high moisture conditions, the Kapton can
absorb water and then it becomes very brittle.
It really should only be used in an environment less than 40
percent. So that's sort of a unique aging effect for a particular type
of solenoid valve that BGE is using.
There were no open items or confirmatory items or license
renewal issues associated with this subset of EQ components that I just
discussed.
DR. UHRIG: Are any of the Kapton-unique components used in
safety systems?
MR. SHEMANSKI: I believe so. They're used as solenoid
valves and I believe the answer is yes, they are in safety-related
systems. They are on the EQ master list.
DR. UHRIG: So anything that's EQ would be on a safety
system.
MR. SHEMANSKI: Right. Although it is possible, on the EQ
master list, there are some non-safety-related components that may have
to be qualified. But probably 95 percent of the components on the EQ
master list are safety-related electrical components.
DR. MILLER: The idea here is they've already been
qualified.
MR. SHEMANSKI: They've already been qualified.
DR. MILLER: Tested at least.
MR. SHEMANSKI: Right. They've been qualified through LOCA
testing.
DR. MILLER: And somebody has agreed that a short-term LOCA
type test is equivalent to a long-term -- you have the same number of
rads over long-term and it's the same number of a short-term.
MR. SHEMANSKI: Well, basically, you're trying to -- in a
LOCA chamber, you're trying to simulate LOCA and they go through and
make a calculation of what the expected pressure and temperature is.
They try to simulate that in the LOCA chamber and then they add in the
accident dose that you would expect, typically 150 mega-rads. So it's,
in essence, trying to simulate LOCA conditions.
How long you test it in the LOCA chamber is a function of
how long the equipment is required to operate post-LOCA, and that varies
depending on the plant CLV. Some plants have a 30-day operability time,
others go up to, I believe, one year. It's a function of when the plant
was licensed.
DR. MILLER: Of course, that's not a synergistic test.
Temperature and radiation is not the same thing.
MR. SHEMANSKI: Well, you do get a -- there is a synergistic
effect. You get added degradation when you combine radiation and
temperature.
DR. MILLER: They just aren't done at the same time.
MR. SHEMANSKI: Right. Are there any additional questions
on cables? Because the next presentation will be on TLAAs.
DR. MILLER: The generic issue, are you going to address
that here sometime?
MR. SHEMANSKI: Yes. The next presentation --
MR. SOLORIO: Paul, can I interrupt something? Before you
go on, Paul. BG&E pointed out to me something related to an earlier
presentation the staff has made on Section 3.11. With respect to the
electrical commodities, BG&E has changed their commitment to use ARDI as
one of their aging management programs and they're going to use
electrical penetrations. That was a recent change and the staff is
reviewing that against the SER, because it's currently not reflected in
the staff's SER.
However, I don't anticipate there being any significant
changes, because we're really talking about going to -- the nature of
the program probably is going to be very similar and it's probably going
to be even more frequent.
As opposed to a one-time inspection, it's going to be a
periodic type of inspection. So I don't see a significant change in
that area.
MR. SHEMANSKI: Okay. The next section in the SER, Section
4.1, is the identification of time-limited aging analyses, TLAAs. BGE
has identified each TLAA with its aging effect and its disposition,
demonstrating that the analyses either remain valid for the period of
extended operation, the analyses have been projected through the end of
the period of extended operation, or the effects of aging on the
intended functions will be adequately managed for the period of extended
operation.
In my next presentation, I'll go into a little more detail
on EQ, because you haven't heard anything about that yet. However, for
the other TLAAs, which appear on this slide and the next slide, this is
a total list of TLAAs.
Do you have any specific questions on those? You heard most
of the discussion regarding fatigue monitoring program and I believe
most of these, if not all, have been covered by previous speakers. So
if you do have any specific questions on any of these TLAAs, we have
several staff members that probably would be in a better position to
answer them.
Basically, what I've given you here is the list of the TLAAs
that have been identified by BGE. I'll just run through them one by
one. The heat-up and cool-down curves, the aging effect is radiation
embrittlement and the aging management program relies on the G and H, 10
CFR 50 Appendices G and H curves, and data from the surveillance
capsules.
DR. FONTANA: TLAA involves equipment that whose lifetime
originally -- let me see if I understand this properly. It's equipment
whose lifetime originally could have gone past 40 years, but if you're
going to extend a license, it can go -- the equipment will have to
operate beyond what may have been its design life. Is that correct,
basically? And you have to analyze that it's going to be able to
perform its function during this additional time period, is that
correct?
MR. SHEMANSKI: Right.
DR. FONTANA: Now, the analysis then is done, like the
heat-up and cool-down curves on radiation embrittlement, the analysis is
obviously quantitative. You have models and predictions and that sort
of thing.
They're not referenced here. I guess if you look at the
BG&E report and you track the references all the way through, they
should take you to the models and data and uncertainties and everything
else. Is that correct?
MR. SHEMANSKI: Well, they should, yes. Right.
DR. FONTANA: Well, do they?
MR. GRIMES: Dr. Fontana, if I could. The simplest way to
describe time-limited aging analysis is basically a design analysis
that, in some way, incorporates 40 years in the design calculation. So
for example, the PTS analysis has a plant life assumption it. Fatigue
has a certain number of cycles assumed in it.
And this, the aging management aspect of time-limited aging
analysis is either that you show that the -- you state the analysis has
already been updated for a 60-year life, you -- it either already
exists, it has been updated to 60 years, or it will be managed in some
way.
DR. FONTANA: Well, how do you know it's any good?
MR. GRIMES: We review the analysis results. We've either
done it -- as Barry mentioned earlier, we've already done a safety
evaluation related to embrittlement for a 60-year life. In other cases,
there are analyses that we've seen before. So by sampling a typical
analysis, we have confidence that simply redoing the analysis with a
different assumption is all right, or there is an aging management
aspect associated. There is a process aspect that we can refer to.
MR. ELLIOT: I'm Barry Elliot. The pressure temperature
limits curves are developed from the requirements in Appendix G and the
requirements in Appendix H is the surveillance program. That's just to
confirm that the embrittlement we used for the curve is what we think it
is.
Now, the embrittlement -- the non-embrittled portion of the
analysis is in the ASME code. It's a specified way of calculating
pressure temperature limits. The part that's age-related degradation is
the embrittlement portion and that is -- we have regulatory guide, Reg
Guide 1.99, Rev 2, which describes how you are to calculate the amount
of embrittlement which goes into these pressure temperature limits.
What we do is if a new pressure temperature limit comes in, we review
the surveillance data, we review the methodology of calculating the
embrittlement to make sure it complies with what's in the regulatory
guide.
So this is time-limited aging. It happens to be, for this
particular plant, they gave us a 48 effective full power year curve
already and so they've already done -- for the equivalent fluence of 48
effective full power years, for Unit 1. For Unit 2, I think they have
only a 30 effective full power years.
So sometime in the future, before 30 effective full power
years, they have to give us another curve that applies to 48 effective
full power years. But they would be following the guidance in the --
the requirements of Appendices G and H and the regulatory guidance in
Reg Guide 1.99 to calculate those curves.
DR. FONTANA: Okay. Thanks.
MR. SHEMANSKI: Okay. The next two TLAAs involve fatigue
analysis for RCS piping, steam generator pressurizer, pressurizer
auxiliary spray line, and pressurizer surge line. The next one is the
fatigue analysis for main steam supply lines for turbine-driven aux feed
pumps, and those are both managed by the fatigue monitoring program.
In addition, the next TLAA is also managed by the fatigue
monitoring program, fatigue analysis for the containment liner plate.
The next TLAA is the pre-stress loss calculations on containment
tendons. That particular TLAA has been deferred by Baltimore Gas &
Electric to the year 2012.
Another TLAA is the spent fuel pool criticality calculation,
the aging effect is loss of neutron absorption and the coupon
surveillance program is used as the aging management program for that.
DR. FONTANA: I'm just curious. How do you go about
measuring the tension in the tendon?
MR. SHEMANSKI: They've got a lift-off test which is in the
tech specs and I forget the parameter, 2000 KIPS or some -- I don't
recall the exact number, but they have kind of a jack and they're able
to measure the lift-off force with the tendons, and that's really not my
area.
DR. FONTANA: Okay.
MR. SOLORIO: The NRC staff reviewer who evaluated that
isn't here at the moment, but I believe someone from BG&E has some
information they can provide.
DR. FONTANA: I'm sure you know how to do it. I was just
curious.
MR. WARD: I'm Don Ward. It's sort of backing out of the
way they're installed initially. The tendons are installed with shims
under both ends, so that you wind up with stretching the wire in order
to get the tension in there.
When you do the lift-off test, you put a ram back on one end
or a jack, a thousand-ton -- I'm sorry -- a 500-ton jack, pull on it,
and measure the force. There are gauges on the jack that you can
measure the force with.
DR. FONTANA: Five hundred ton jack.
MR. WARD: Yes. They carry about 700,000 pounds each.
DR. FONTANA: Thanks.
DR. SHACK: What does it mean when the program is deferred
to 2012?
MR. PATNAIK: This is Pat Patnaik. What we got from the
applicant, that they would provide us the curves, the loss of stress,
pre-stress loss, on the tendons, calculated to the new values. That
will be covered in the tech specs. Those are in the tech specs.
MR. WARD: Don Ward again. The part that was in the tech
specs, that you will now remember being in the tech specs, was recently
moved to chapter 15 of the FSAR, but it's the same sort of thing. It's
these curves plot on semilog paper as a straight line. We were just
looking to see if there are any nuances and so it's being deferred a
bit, particularly until we decide what we're doing with the vertical
tendons.
MR. SOLORIO: This is Dave Solorio. I just wanted to point
out also that there is an open item associated with this. Page 109.
MR. SHEMANSKI: It's open item 4.1.3-2, deferral of the
re-calculation of loss of pre-stress on containment tendons, to the year
2000. Since we're on open items.
There is also an open item on the addition of the upper
shelf energy evaluation as a TLAA. The staff has concluded that this is
a TLAA and should be treated as such. The third open item is the
addition of metal fatigue of B-31-7 Class 2 and Class 3 piping as a
TLAA. Apparently, BGE did not -- I'm sorry -- BGE did consider the
number of cycles in the evaluation of Class 2 and Class 3 piping.
Therefore, the staff feels that this is a TLAA, should be
treated as a TLAA. There is one confirmatory item regarding
documentation of containment liner plate fatigue analysis. Basically,
BGE needs to document the evaluation which demonstrates that the current
analysis remains valid for the period of extended operation.
We list one license renewal issue, 98-0048, elevated
temperature of pre-stress in tendons. This, I believe, was previously
discussed in Section 3.10 of the staff SER on building structures.
Are there any additional questions regarding TLAAs?
[No response.]
DR. FONTANA: I guess not.
MR. SHEMANSKI: If not, then I'll go to the final TLAA,
which is EQ, environment qualification of electrical equipment. BGE
identified the 10 CFR 50.49 program, that's the EQ rule, 50.49. BGE
identified that as a TLAA for license renewal.
Now, it's important to note that when the staff evaluated
the BGE TLAA for EQ, we focused on the program elements and process, and
I will repeat that again. We focused on the program elements and
process provided by BGE.
They are using standard approved EQ methodology and
acceptance criteria in accordance with the 10 CFR 50.49 EQ rule.
Basically, the way BGE is treating it, for all of the
long-lived active and passive, this TLAA is unique, it includes -- this
is the only TLAA, the only place in the application you'll see where we
have active components in license renewal.
It just so happens that the EQ rule 50.49, when you look the
EQ master list, it consists of active and passive components.
DR. MILLER: Did they do that just for convenience?
MR. SHEMANSKI: No. I mean, that was the way the EQ rule
initially was developed. You had to list or include all of the
electrical components that --
DR. MILLER: All safety-related.
MR. SHEMANSKI: All safety-related electrical components
that are, number one, subjected to a LOCA or main steam line break or
high energy line break; that is, subjected to a harsh environment, and
then required to mitigate that particular DBE.
You look at the list, it includes, as you could see, motors,
transmitters, pressure switches, all of which are active. But for this
particular TLAA, we do include both active and passive long-lived
components.
DR. MILLER: But it wasn't required to do that. Is it
required to do that by the rule?
MR. SHEMANSKI: Which rule are you referring to?
DR. MILLER: By the rule, the license renewal rule.
MR. SHEMANSKI: The focus of the Part 54 rule is on
long-lived --
DR. MILLER: Passive.
MR. SHEMANSKI: -- passive components. However, it does
list five regulated events. It lists -- in paragraph 54.3, it lists
fire protection EQ, ATWS, PTS, and station blackout. And by picking up
the EQ rule, you automatically pick up the EQ rule master list, which
has active components.
DR. MILLER: So by including EQ, you automatically pick it
up.
MR. SHEMANSKI: You automatically pick these up. So there
-- and basically the aging management program for EQ is the 50.49
program.
DR. MILLER: In a way, the rule 54 picks up through EQ the
active components.
MR. SHEMANSKI: Right.
DR. MILLER: The EQ program then covers you.
MR. SHEMANSKI: That's correct.
DR. MILLER: That's a simple way to put it.
MR. SHEMANSKI: And the way BGE approaches the qualification
of these particular components is prior to the end of an equipment's
qualified life, the equipment will be replaced, unless it can be --
unless the qualified life can be extended through reevaluation,
primarily re-analysis. So they tell us that sufficiently in advance,
prior to the expiration of a component's qualified life, they will go
through and determine whether or not that component needs to be replaced
or whether or not they could extend the qualified life based on
re-analysis or some type of reevaluation.
Now, we reviewed the methodology that BGE is using in their
current EQ program, and keep in mind that they do have an approved 50.49
program. They've got an SER issued by the staff in the mid '80s which
finds their EQ program in compliance with 50.49. So they're solid for
the first 40 years.
And as equipments on the EQ master list approach the end of
their qualified life, they will be re-assessed ten years from now just
as they are today. They will be using the same methodology.
So we looked at how they extend their component qualified
life and we evaluated or looked at the acceptance criteria they apply,
what type of corrective actions they use, how they go about
refurbishing.
We looked very closely at how they would be applying
re-analysis, how they treat the thermal and radiation environments, and
what effect any plant environmental changes would have on the
qualification status. So we took a pretty in-depth look at their
existing program, basically doing a process type evaluation, and are
satisfied that 50.49 is an acceptable aging management program.
DR. MILLER: So 50.49 covers everything that we've talked
about all day today.
MR. SHEMANSKI: Well, 50.49 focuses primarily on electrical
components in a harsh environment. The key stressors they are subjected
to are thermal and radiation and if they happen to be subject to spray
from the ECCS system, caustic spray, then, of course, they --
DR. MILLER: Boron -- boric spray.
MR. SHEMANSKI: Right, they've got to simulate that in the
LOCA chamber, that is part of the qualification process.
This slide shows the aging effects due to thermal and
radiation primarily, and those aging effects are managed by the
qualification process, which is utilized in the 50.49 program.
DR. MILLER: So were all the things like all the sensors and
so forth excluded and all the rest of the program, now we've got
pressure and flow transmitters all included at this point for these --
if they're EQ.
MR. SHEMANSKI: Right.
DR. MILLER: And we assume an environmental qualification
covers all the issues we talked about.
MR. SHEMANSKI: Well, it does not cover things like crevice
corrosion or general corrosion. It turns out that some of these
components on here, electrical penetration assemblies, solenoid valves,
they have a license renewal intended function, for example, to maintain
pressure boundary and that particular function is really not -- it's not
evaluated in the EQ program. That was why BGE, when I went through
Section 3.13, they looked to see are there -- they went through these --
this entire EQ master list and they said are there any of these
components that have intended functions such as pressure boundary that
are not covered by the EQ program, and they did find four, I believe.
DR. MILLER: Solenoid valves were addressed separately in
there.
MR. SHEMANSKI: Right. So they are subject to general
corrosion or pitting and, of course, those aging effects are not managed
by the EQ program, but they're managed by other programs, I believe the
chemistry control program.
So the bottom line is I think they've got all the -- all of
the plausible aging effects have a management program.
DR. MILLER: In that list, there's, of course, a whole bunch
of passive components. They've already been covered under the other
program, as well as this one.
MR. SHEMANSKI: Right.
DR. MILLER: So the only questionable one would be
components such as flow transmitters and pressure transmitters and level
transmitters. Those might be the only ones that might be falling
through the crack, so to speak.
MR. SHEMANSKI: I don't believe they have fallen through the
crack, because I don't think those particular ones have any license
renewal intended functions that are not being managed by the EQ program.
DR. MILLER: I'm not saying they did. I'm saying they could
have.
MR. SHEMANSKI: They could have. We did look and I don't
believe --
DR. MILLER: Based on the fact that we spent maybe five or
ten hours on this, everybody else has spent many more than that. I just
looked at it from a superficial viewpoint and I would say, gee, did we
cover everything of those active components that weren't covered under
all the other programs, does EQ cover everything under those.
MR. GRIMES: Dr. Miller, I looked at --
DR. MILLER: Am I asking a question that makes any sense?
MR. GRIMES: Yes, and I'd like to attack your question in a
slightly different way.
DR. MILLER: Don't attack it. Address.
MR. GRIMES: Address. Okay. First of all, I want to
clarify, time-limited aging analysis don't care about the license
renewal scope. They're a time-limited aging analysis. There is a
qualified life. EQ just happens to be the biggest qualified life
question we've tackled and for -- to the extent that managing the
environmental qualification time-limited aging analysis relies upon the
50.49 program, regardless of whether or not you've got a piece of
equipment that's active, passive, long-lived, short-lived, whatever it
is, if it's got an EQ qualified life of a year, 40 years or 1,000 years,
the 50.49 process will sort that out.
To get back to your other question about what do we do with
GSI-168, to the extent that information comes out of that research that
challenges the qualified life of any particular cable, then that same
compliance with 50.59 process, about making decisions about replacing,
refurbishing, re-analyzing or re-testing, we rely on that process to
address GSI-168 until the research identifies something different to do.
But to the extent that EQ stuff is also captured as -- in
4.13 of the -- I'm sorry -- 3.13 of the safety evaluation, where we also
look at it from the standpoint of are there other aging effects that are
not explicitly addressed by this qualified life process, like crevice
corrosion or fatigue or other thing, then we address that specifically
for passive components.
For active components, all of those things are excluded for
the same reason we excluded active equipment and that's basically we're
looking at reliability under the maintenance program as the means to
manage aging effects for active components.
DR. MILLER: I think I'm visually seeing everything fitting
together. I'm now seeing the cracks are closing.
MR. GRIMES: The EQ was particularly troublesome for us, as
well, because even though it's a well established and well regulated
program, it's got this overlapping area of responsibility and so that's
why we ended up with one section of the safety evaluation that treats
aging effects and aging management programs and then time-limited aging
analysis also has an aging management aspect of it, as well, but it
really gets back to the process question.
MR. SHEMANSKI: My last slide, there are no open items or no
confirmatory items regarding EQ. However, we did have one license
renewal issue, 98-0014, which basically asked the question whether or
not 10 CFR 50.49 is an adequate aging management program under the
license renewal rule. And basically, the answer is yes, and we
concluded in the BGE SER that 10 CFR 50.49 is an acceptable aging
management program under 10 CFR 54.21.
MR. GRIMES: Paul, if I may. I would like to clarify that
this particular generic renewal issue has now blossomed into what we
call the credit for existing programs issue, which was forwarded to the
Commission and I believe that the ACRS received a copy when we forwarded
the NEI letter.
We're developing a Commission paper that addresses the
extent to which the staff can conduct a license renewal review without
challenging the adequacy of these existing programs.
So you will be hearing more about that, but for the purpose
of this review, we challenged the existing programs. We went digging
into, for example, environmental qualification and compliance with
50.49. The means of compliance as it relates to managing aging.
So you will be hearing some more about that issue, but it's
really more relevant to treating future applications.
DR. FONTANA: The future applications, these license renewal
issues that are resolved now, are they assumed to be resolved for all
future applications?
MR. GRIMES: To the extent that we would add guidance to the
standard review plan or that NEI would add guidance to the NEI 95-10
guide on preparing an application, yes, we consider them resolved for
future applications, too.
DR. FONTANA: We're a little overdue on our break. Any
questions on this area here?
MR. WESSMAN: Before we go on a break. I'm Dick Wessman,
with the staff. A minor housekeeping item. On page 108 of the
viewgraphs, we had an erroneous entry there and I wanted to clarify
that. If you look at that, you will see a couple of entries, one of
them dealing with fatigue analysis for the containment liner and another
one at the bottom dealing with Class 2 and 3 piping.
Those two activities are not covered by the fatigue
monitoring program, per se, but they are addressed by analysis
activities done by the applicant.
DR. FONTANA: Thank you.
MR. WESSMAN: Yes, sir. That's all.
DR. FONTANA: Let's take a break. Let's see. When we come
back, we'd like to discuss what will be presented at the May full ACRS
meeting, some topics for an ACRS interim letter, and possibly what would
be appropriate for additional staff presentations and maybe for future
meetings. So you all may want to be giving some thought to those items.
So let's come back at 20 of.
[Recess.]
DR. FONTANA: The meeting will come back into session. The
first thing that we would like to discuss with you is what should be
included in a presentation for the full ACRS meeting the first week in
May. You have an hour and a half, and that's on the first day, I think,
Wednesday. Will you be making most of the presentation?
MR. GRIMES: Were you addressing me personally or the staff?
DR. FONTANA: You.
MR. GRIMES: We'll do -- actually, we do almost anything you
want. We can do a summary overview. We can just have a very high level
with Dave giving his overview presentation and maybe putting together
some summaries or if there are particular topic areas, Mr. Wessman was
graciously supporting us and we could get particular staff to come talk
about topical interests.
DR. FONTANA: Well, the full committee I don't believe has
received a presentation from you in this area, in my memory at least, I
don't think. So I think it's probably appropriate to start from the top
and give a -- because I'm sure that two or three of them that are not
here and some that are here don't understand the whole philosophy of
this license renewal, which is really rather esoteric, just coming off
the street and listening to it.
So I think an overview of the philosophy basically that you
as the staff are working within the constraints of Part 54 and whereas
we on the committee aren't necessarily. But with regard to what you're
doing, I think you probably should quickly overview what Part 54 is
constraining you to do.
DR. SEALE: How long do we have?
DR. FONTANA: An hour and a half. But I think maybe taking
about ten minutes to get everybody on the same page is probably going to
be worthwhile, because questions that are going to arise are how do you
determine what's in scope and what's not in scope, and the concept of
TLAA is rather esoteric, so you may want to say -- just like you said
about 20 minutes ago, perfect.
Then the area of issues, I'm sure there is going to be some
confusion about what are generic license renewal issues compared to the
other list of GSIs, and you may want to identify what the difference is,
and how you -- the basis for the prioritization of the issues, the fact
we now have 105 of them, when I think there's --
MR. GRIMES: It's 109.
DR. FONTANA: It's 109, and I forget how many are on the
priority one list. In fact, you would allow some issues to go into --
DR. SEALE: Sixty years.
DR. FONTANA: To go beyond the end of the current license,
and I'm sure you're going to get asked about that.
With respect to the SER, I think we'd like an overview of
it, relating most of the key agreements and what the key issues left are
and what the key confirmatory things are. There aren't many of them
left, as far as I could see.
DR. SEALE: Could we get some words from BG&E?
MR. DOROSHUK: Yes, sir, we could support that. Is there
any specific area?
DR. SEALE: Well, in your presentation you made, of course,
there's a lot of it that's background and all, but the material and the
scope, your perception of what the scope is, and then the IPA process
you went through, and then maybe a summary of some sort.
MR. DOROSHUK: Yes, sir.
DR. SEALE: I think that would be very helpful to the
committee, because it -- I won't call it a bottoms-up approach, but it
is the applicant now working with the process as opposed to the
regulator's perception of what the process ought to come up with, and I
think that's very important.
DR. FONTANA: Those two diagrams. You have the IPA flow
diagram, I think that's useful and very valuable.
DR. SEALE: Yes.
MR. GRIMES: You could start about the IPA flow diagram and
end up about the last pie chart, and it's that chunk in the middle
there.
DR. FONTANA: How much time do you think BG&E should have
out of this hour and a half?
DR. UHRIG: Twenty, 30 minutes.
DR. SEALE: Yes. Something like that.
DR. FONTANA: Something like that. And I guess you will
start it, the staff will start it, and you determine between yourselves
where to break into it, I guess.
MR. WESSMAN: I think it would be constructive for the staff
to do that introduction and overview of the philosophy, then go to BG&E
with their discussion of how they did the submittal and then come back
to our SER and we'll pick the specifics that you want us to. That's how
to handle three 30-minute segments, for lack of a better term.
DR. SEALE: Exactly. Recognizing that you're going to get
interruptions.
MR. WESSMAN: Of course. Especially by people who are not
here. At least we know who they are.
DR. FONTANA: Any additional thoughts on what ought to be
covered in the meeting?
DR. SEALE: I could facetiously say that if you don't want
to get too many interruptions, you might not say anything about fire
protection, but I guess that --
DR. FONTANA: Or risk-based.
MR. WESSMAN: That's right, George will be here. We could
use, as a clue from you all, as to the specific areas that you think, as
we try to characterize the SER, that you want us to spend time on. I
think there's been a lot of interest in fatigue and we probably need to
offer that up. But if you could give us some other specific areas that
you think are areas of interest.
DR. MILLER: I'm not certain this -- this is something I
need to look at for my own edification, but I'd like to have more
information on the environmental qualification program and how that all
fits together, the things we hit near the end.
Now, again, that may not be generic enough for the
committee, though.
DR. FONTANA: Well, first of all, you want to get --
DR. SEALE: We're down to an hour here, guys.
DR. MILLER: I know, that's what I say, an hour and a half,
we won't have enough time for any of these specialty areas.
DR. FONTANA: When you get to the SER, an important idea to
get across, whichever way you do it, is the extreme depth. The thing
was actually exhausting to --
DR. SEALE: I think the run-through from the first day
viewgraphs are a good way to state it. Your presentation, basically.
DR. KRESS: David's.
DR. SEALE: Yes. Then the question is do you try to
cherry-pick somewhere through the rest of the 110.
DR. MILLER: Certainly, we've got 30 minutes to go through
the other 110 slides, and which ones are we going to pick.
DR. SHACK: You'll vote for EQ, I'll vote for Barry's part,
and everybody will pick the part that interests them.
DR. KRESS: I would pick the steam generators.
DR. SEALE: I think just to get across the idea that you're
putting a very heavy reliance on inspection, that that's really the tool
that this process, this whole process relies on.
DR. UHRIG: I also think it would be useful to convey the
concept that this is really using existing programs to the maximum
extent possible, with modifications where necessary. Only when this was
not appropriate did you go to new programs.
DR. FONTANA: I guess you ought to do something for common
aging management programs.
DR. SEALE: Yes.
DR. FONTANA: This category. Because I think that's
important.
DR. UHRIG: There were some numbers given about what
percentage of the -- how many new procedures, how many existing
procedures, how many modified procedures. I don't remember the exact
numbers, but it was --
MR. GRIMES: Out of the 430, there were 329 --
DR. UHRIG: Those kind of numbers. I think that gives you a
picture.
MR. GRIMES: Yes, 11 new, 101 modified, something like that.
MR. DOROSHUK: We'll make sure we have those slides for that
particular part of the presentation.
DR. MILLER: I guess we're looking at kind of a condensed
version of what we heard yesterday, right? Mostly.
DR. FONTANA: Bill Shack, do you think one of the things
that should be touched on is the Section 3.2, vessels internals and
reactor coolant system? That's what Barry Elliot covered.
DR. SHACK: Well, after you go through the big overview, I
don't know whether we should -- the 3.1, the aging management review of
the common management programs maybe should be the big sweep. Even
there, I don't think we -- you know, we can't go through it in the
detail that you went here, but somehow you've got to, out of this thing,
grab that chunk out.
I think that will probably chew up --
DR. MILLER: You've got an hour and a half right there.
DR. SHACK: -- most of the time. Between those two
presentations, it's sort of gone.
DR. FONTANA: It sounds like we really can't get into much
of the specific areas.
DR. SHACK: I don't see how we can get into the specific
areas.
DR. FONTANA: Unless the question pops up.
MR. DUDLEY: There is an alternative. For the three people
who are not here, provide them a copy of the slides, where they can see
what programs are or what systems are evaluated in each chapter.
DR. KRESS: Those three people will have also read part of
the SER and they can come prepared to ask questions. So we'll make it
known that if they have an issue with some of that SER, that they need
to ask.
DR. UHRIG: But you could easily send them the slides that
were used today.
MR. SOLORIO: I would like to ask that if you'd let us know
what areas they've read, so we can prepare the staff.
MR. WESSMAN: Yes. I hate to muster 20 people over here,
even though it's only an hour and a half. If there is any way we can
focus it down to a smaller number of key players. They're busy working
on Oconee.
DR. FONTANA: It seems to me that you three guys will be
able to cover it at the level we're talking about.
DR. SEALE: Why don't we ask them who they can best do -- I
mean, the rest of the guys.
MR. GRIMES: I'd also like to suggest you -- we've got a
head start this time. To the extent that two and a half of us anyhow
can try and get through as many of the common programs and the basic
stuff and address broad questions about aging management, as much of
that as we could accomplish in an hour and a half we're going to have
next week, we could do that, and then we've still got open items to
resolve. We could -- we're going to come back to the committee at least
once more.
So we could -- maybe we could get a sense next week about
what particular areas you'd like to explore further and we could just
make a commitment that we'll address those in a future meeting.
To the extent that we can dispose of as much as you can
dispose of and focus down on particular areas of interest.
DR. UHRIG: I think in the preparation of the letter, this
will be brought to a focus.
DR. FONTANA: Will that give you enough to go on?
MR. GRIMES: We're going to -- in the hour and a half, we're
going to devote about 30 minutes to a broad overview of Part 54,
terminology, the basic elements, what are the time-limited aging
analysis, basically a day's presentation in a half an hour for BG&E, and
then a half-hour for the safety evaluation overview, which means three
15-minute prepared presentations. Does that pretty well cover it?
DR. FONTANA: So that the need for additional staff
presentations, I think we're saying we will need them, but what's going
to be included probably will come out of the things that are not going
to be covered next week, right?
MR. GRIMES: Right.
DR. FONTANA: So these guys can work up --
MR. GRIMES: We'll make commitments next week to address
particular questions and basically frame an agenda for a future meeting.
MR. WESSMAN: We can bring a few of the key people. I think
Stephanie Coffin did a lot of work on the ARDI and we'll have her here
and that may eliminate some of that area of questioning. So it isn't
like it will just be the three of us, but I just don't want to muster
all 20.
DR. FONTANA: Any additional ideas, questions? No? If not,
are we done?
DR. SEALE: I think so.
DR. FONTANA: I'd like to thank the staff and BG&E. These
were really well organized response of talks, they were to the point,
good presentations. They reflect a tremendous amount of work and we
appreciate the considerable amount of work you did preparing for this
meeting, which I'm sure is significant, particularly considering all the
other things you've got to do.
So, again, thank you very much, on behalf of the committee,
the subcommittee. We appreciate it, and we'll see you next week.
This meeting is over.
[Whereupon, at 2:58 p.m., the meeting was concluded.]
