Materials and Metallurgy - March 24, 1999

UNITED STATES OF AMERICA
NUCLEAR REGULATORY COMMISSION
ADVISORY COMMITTEE ON REACTOR SAFEGUARDS
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MEETING: MATERIALS AND METALLURGY
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USNRC, ACRS/ACNW
11545 Rockville Pike, Room T-2B1
Rockville, Maryland

Wednesday, March 24, 1999

The subcommittee met pursuant to notice, at 8:30 a.m.

MEMBERS PRESENT:
WILLIAM SHACK, Chairman, ACRS
MARIO H. FONTANA, Member, ACRS
THOMAS S. KRESS, Member, ACRS
ROBERT SEALE, Member, ACRS
. P R O C E E D I N G S
[8:31 a.m.]
DR. SHACK: The meeting now come to order. This is a
meeting of the ACRS Subcommittee on Materials and Metallurgy. I am
William Shack, Chairman of the subcommittee. The ACRS members in
attendance are Robert Seale, Mario Fontana, and Thomas Kress.
The purpose of this meeting is to meet with representatives
of the NRC staff, the Nuclear Energy Institute, the Boiling Water
Reactor Vessel Internals Project, and the Pressurized Water Reactor
Materials Reliability Project, to discuss industry and NRC activities
related to steam generator tube integrity, the BWRVIP, the PWRMRP,
reactor pressure vessel integrity, status of resolution of the
differences between the staff and ASME regarding the use of the 1994
addenda to the ASME Section 3 code for Class 1, 2 and 3 piping systems,
the proposed revision to 10 CFR 50.55(a), codes and standards, and
regulatory research activities associated with 10 CFR 50.61, the
pressurized thermal shock rule.
The subcommittee will gather information, analyze relevant
issues and facts, and formulate proposed revisions, 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 a part of the notice for this meeting previously published
in the Federal Register, on March 8, 1999. A transcript of the meeting
is being held and will be made available as stated in the Federal
Register notice.
It is requested that speakers first identify themselves and
speak with sufficient clarity and volume so they can be readily heard.
We have received no written comments or requests for time to
make oral statements from members of the public.
The Materials and Metallurgy Subcommittee last met to
discuss steam generator integrity activities in August 1997. Since that
meeting, the staff has changed its approach and the industry has
developed steam generator guidelines.
Similarly, the subcommittee has not been updated recently by
the staff on the other items on the agenda.
At the conclusion of the meeting, we plan to identify those
items which should be brought before the full ACRS at the April 7-10,
1999 meeting for further discussion and review.
I have a conflict of interest related to steam generator
tube integrity activities in the BWRVIP-14 safety evaluation report
because of work performed by Argonne National Laboratory for the NRC.
Dr. Seale will act as the subcommittee chairman during the
discussion of these items.
At this point, I will turn the meeting over to Dr. Seale.
We will proceed with this meeting, and I call upon Emmett Murphy, of the
Office of Nuclear Reactor Regulation, to begin. And while I have a
conflict of interest, I would be very interested to hear whether you
guys have managed to resolve what to do about severe accidents and steam
generator tube integrity.
MR. MURPHY: Risk considerations are on the menu for today.
DR. SEALE: Let me clarify. Your conflict is that you will
not participate in any decisions that the subcommittee may make
regarding what it takes to the full committee and so on, but you're more
than -- you are encouraged to let us know of any comments you might have
as we go along.
DR. KRESS: Clarifying comments.
MR. MURPHY: Am I on?
DR. SEALE: You're on.
MR. MURPHY: All right. Well, this morning we'll be
discussing issues relating to steam generator tube integrity and we'll
have four different presentations this morning under this particular
topic.
I will kick things off with an introduction that will
briefly describe the background, centering around the last time we met
on this particular issue, what has transpired since that time.
This will be followed by an NEI presentation to discuss the
current industry initiatives pertaining to steam generator tube
integrity. This will be followed by a discussion of NRC activities
relating to interactions with NEI and the industry in general on how
best to proceed with development of SG programs and perhaps a new
regulatory framework dealing with steam generators.
And, finally, Steve Long of NRC will make a presentation on
risk considerations as they pertain to integrity.
DR. SHACK: So it's that third bullet that's going to tell
us how the NEI approach is going to be folded into the regulatory
system.
MR. MURPHY: Yes. My first discussion this morning will be
kind of an introductory presentation. Hopefully, it will run short and
allow more time for what follows later.
DR. KRESS: What is the status of the differing professional
opinions?
MR. MURPHY: That will be covered. Now, we met with this
subcommittee back I August of '97 to discuss a proposed draft GL and
accompanying draft regulatory guide, DG-1074, entitled SG tube
integrity. The draft GL was intended to advise utilities that simple
implementation of existing regulatory requirements, particularly tech
spec inspections, would not, in and of themselves, ensure tube
integrity; that actions beyond normal tech spec requirements would be
necessary, is necessary to ensure tube integrity, and requested that
utilities submit proposed upgrades to their tech specs as necessary to
ensure tube integrity.
The enclosed draft regulatory guide defined one acceptable
approach to doing this. It was a performance-based or
quasi-performance-based approach defined in the draft guide.
We also reviewed the regulatory bases behind this proposal
and the status of the DPO resolution at that time, which had been
categorized administratively as Generic Safety Issue 163.
We met in September of that year with the full ACRS to
discuss the draft GL and DG. The ACRS subsequently endorsed issuance of
the draft GL and DG for public comment. On October 2nd of '97, we had a
separate meeting with the -- I think it was the full ACRS at that time
to discuss the DPO concerns and the staff's proposed resolution of these
concerns. And ACRS endorsed issuance of the proposed resolution in
October.
And I seem to have a bit of a problem here.
DR. SEALE: You're missing your ladder?
MR. MURPHY: I'm sorry?
DR. SEALE: You're missing your ladder?
MR. MURPHY: I'm missing some pages here. I'm mistaken.
I'm not missing anything. Subsequent to the fall '97 meetings with
ACRS, NEI informed the NRC by letter that the NEI Nuclear Strategic
Issues Advisory Committee had voted to adopt the following formal
industry position; namely, that licensees would evaluate their existing
programs and, where necessary, revise and strengthen program attributes
to meet guidance of NEI 97-06, which they entitled steam generator
program guidelines, and that this action would be initiated no later
than the first refueling outage, starting January 1st, 1999.
It's our understanding that, in fact, utilities are, in
fact, proceeding with this initiative. I think the protocol of
agreements of this kind are that once this kind of position has been
adopted, that all utilities are obliged to commit to these actions.
NEI 97-06 is programmatically similar to DG-1074 in terms of
general program elements and strategy. This next viewgraph is one that
has been presented to this committee before, but it was presented to
explain the general strategy behind the DG-1074 approach.
But it also is a fair summary of how the NEI program would
work, at least at the top level; namely, it's centered around a set of
performance criteria, covering structural integrity, operational leak
integrity, and accident leakage integrity. One performs a look-ahead
assessment over the next operating cycle, something we call an
operational assessment, to ensure that whatever actions they've taken in
this particular outage are sufficient to ensure the performance criteria
will be met throughout the cycle or until the next SG inspection is
scheduled.
In addition, they do a look-behind assessment, which we term
a condition monitoring assessment, to confirm that, in fact, that tube
integrity was maintained consistent with the performance criteria during
the past operating cycle.
So, again, all the --
DR. KRESS: Could you refresh my memory on what these
performance criteria were, related to leakage and detection of so many
cracks?
MR. MURPHY: The performance criteria basically -- the
structural criterion, two types of structural criteria had been
discussed. One is the traditional deterministic type criterion, which
were developed consistent with the stressfulness of Section 3 of the
code; in other words, we're trying to maintain a factor of three with
respect to burst under normal operating conditions, a factor of 1.4
under faulty conditions.
DR. KRESS: Based on detected cracks, the depth or --
MR. MURPHY: No, this is your goal. You are attempting to
manage the steam generators through inspections and the like in such a
way as to ensure that all tubes --
DR. KRESS: I see. That's the top level.
MR. MURPHY: That all tubes will retain these margins. So
we have structural criterion and we have leakage criterion. In other
words, immediately prior to an SG inspection, the steam generator should
not be degraded to the point where leakage would, under -- leakage
induced by a postulated accident would not exceed what you've assumed in
your licensing basis accident analyses or leak at a level that might
pose a potential risk concern.
DR. SHACK: Suppose you hit the Ano@ on that. You know, you
do the condition monitoring and you find out that you've had one tube --
I guess Farley had an example like that, where you didn't meet the
performance criteria. Now, is that a violation or what happens when you
bing the no?
MR. MURPHY: It's not, in and of itself, a violation. You
will -- well, first off, we haven't talked about in what regulatory
context this kind of program is going to exist. We have proposed a reg
guide defining this kind of approach as an acceptable method. We also
recommended in the GL that there be tech specs that would incorporate
these program elements.
But no matter -- even with the approach that we were
proposing under the GL approach, exceeding the performance criteria
would not, in and of itself, constitute -- it would not be a tech spec
violation, for example. But it is a flag. If you exceeded these
criteria or failed to meet the criteria, it suggests potentially that
your program isn't as effective as it should be and you should be going
back and trying to see how it came about that the performance criteria
were exceeded, and you should be taking appropriate corrective actions,
as well as informing NRC that you have this situation.
And what you most want to see is that something like this
does happen. You don't want to see it happen again and again and again.
A chronic situation, where risk would be much more sensitive to a
chronic situation of this type than to a one-time exceedence due to
something unexpected.
Now, while we look at the program strategy and program
elements at a top level and there's a great similarity here, of course,
in terms of the details, there are a number of differences.
DR. KRESS: Before you leave that, I was more or less
halfway assuming that the corrective actions were plug and repair, but I
see you have a separate box for plug and repair after you've already
satisfied the performance criteria.
So what sort of corrective actions are you talking about
here?
MR. MURPHY: The one common causal factor that may cause you
to exceed performance criteria when you look back and see how well you
did is inadequate eddy current inspection. So one common thing one does
is take a hard look at its eddy current inspection program and upgrade
it as necessary.
One may determine that it's not that the inspections were so
bad, but that the crack growth rates were so high, and one might adjust
his inspection accordingly.
DR. KRESS: I got it.
DR. SHACK: Now, people have been doing this sort of
voluntarily. How have they been doing? When they do the conditioning
monitoring, are they, by and large, everybody is coming up with --
they've met all the performance requirements?
MR. MURPHY: Everybody is doing these assessments. There
have been two recent examples we'll be talking about in the next
presentation where performance criteria have been exceeded. We'll be
receiving their operational assessments that describe basically how they
plan to avoid getting to the situation during the current period of
operation.
There are technical issues outstanding as to how one should
-- the predictive technology -- the predictive approaches one applies.
Industry guidance in this area is not fully developed. We have DG
guidance, but it has no status. It has no regulatory status. It's just
a comment.
One of the points I was going to make later on is assuming
this framework is in place, industry is committed to it and so forth, a
big part of the success of this approach and ensuring tube integrity
will be the commitment on the part of utilities and seeing to it that
they do what they have to do to ensure those performance criteria are
met. Commitment is going to be a big part of it.
And NRC, in its oversight capacity, certainly, to the extent
that there is a chronic problem out there with a plant or utility, it's
going to take a certain commitment on NRC's part, as well. That's the
best I can answer you for now, Bill.
We do have a plant out there that has failed to meet these
performance criteria several times over since 1992 and I'll be talking
about that plant a little bit later on.
Where we want to go is away from a situation where we're,
every operating cycle or every other operating cycle, finding that we
fail to meet performance criteria. It suggest that we're not doing
things as well -- the utility may not be doing things as well as they
should be doing.
In February '98, we responded to NEI by letter. We had not
been requested by NEI to review their guidelines, but we did take a
look. We viewed this industry initiative as a positive step. Of
course, we were very encouraged by a lot of the similarities in the
general approach, as compared to how we were proposing to proceed.
We also informed them at that time that we were, at that
time, proceeding with our plans to issue the draft GL and DG-1074 for
public comment. Very importantly, though, and this was a major reason
we wanted to get this letter out to NEI, was that NEI 97-06 contained
two performance criteria which, to our thinking, may not ensure
compliance with current regulations and that licensees should carefully
assess these guidelines before their implementation to ensure
consistency with 10 CFR 50.59.
The performance criteria I'm referring to are the structural
performance criteria and the accident leakage criteria. The DG-1074 had
proposed structural criterion, the deterministic criterion I just
described a few moments ago, which we believed to be consistent with how
the plant is licensed and these safety factors were the basis for the
plugging limits in the plant tech specs.
However, the NEI guidelines were suggesting that as an
alternative, licensees might employ probabilistic criteria for purposes
of -- as performance goals for managing their steam generators.
These probabilistic criteria were geared toward
demonstrating that the conditional probability of rupture during
postulated accidents was less than a certain number,
five-times-ten-to-the-minus-two per event. So we did not -- it was our
intention with this letter then to alert NEI and the industry that there
was a regulatory issue here; that blinded limitation of the NEI
guidelines, in our opinion, may not be consistent with the regulations.
DR. KRESS: Was your problem with just the value of that
conditional probability?
MR. MURPHY: We think that if one is going to manage the
steam generators to anything other than the safety factors that are
currently in the licensing basis or based on ASME Section 3, then he is
obliged to -- that serves as a basis for tech specs, he's obliged to
come in for our review and approval before he actively manages his steam
generators relative to that criteria.
DR. KRESS: If they were to do something to 97-06 to make
you feel that it met your requirements, would you endorse it in that
Guide 10-74?
MR. MURPHY: I'm heading there, but I was going to -- where
this is all going is the mutual activity between us and the industry to
see if we can come to some mutually agreeable approach. That's where
this discussion is heading.
DR. KRESS: It just seems to me like some level of
conditional probability on that failure would be equivalent to the
margins.
MR. MURPHY: Certainly, one could define probabilistic
criteria that are equivalent and one could define criteria that maybe
are not equivalent, but one might argue are still adequate from the
standpoint of defense-in-depth and risk.
But we would argue that that needs to be -- such a proposal
needs to be submitted for our review.
DR. SHACK: So your argument wasn't against the
probabilistic criteria, because you had it in 10-74.
MR. MURPHY: Right.
DR. SHACK: It was just that they couldn't implement it
under a 50.59 argument.
MR. MURPHY: That's correct.
DR. KRESS: I see. That's sort of a different tact.
DR. SEALE: And this is the 50.59 as it used to be, the
50.59 as the patch we hope to put on it in the short term, or the 50.59
when it truly becomes a risk-informed tool?
DR. KRESS: I think you have to live with what you have.
You probably have to live with what you have, which is rather
frustrating.
DR. SEALE: Okay. Fine. I can live with that. They might
not be able to, but I can.
MR. MURPHY: However, after a number of meetings with the
industry and a lot of internal discussion, there was a bit of a change
in direction in the NRC initiative and we informed the Commission I
October of 1998 that unless otherwise directed by the Commission, that
we would delay issuance of the draft GL, but we'd work with industry to
resolve issues relating to the NEI guidelines.
Technical differences still remain between the staff and
industry, including the appropriate framework for implementing the
guidelines, but it's our objective to see if we can't endorse industry
initiative for ensuring SG tube integrity in lieu of issuing a GL.
DR. KRESS: What exactly does endorse mean here?
MR. MURPHY: Well, I think that it, in this context, doesn't
have an exact meaning. I think what we're suggesting here is we're
going to work with industry to see if the -- as I indicated, there are
some differences with NEI 97-06 that need to be resolved and perhaps the
industry initiative can be revised somewhat, which is -- in some
mutually agreeable fashion, and be in a form that would be -- that we
could endorse either directly or through some change in the regulatory
framework that recognizes the existence of the NEI guidelines.
DR. KRESS: So it would have the force of regulation.
MR. MURPHY: That was going to be part of what I was going
to be discussing after the NEI presentation. NEI, of course, will be
discussing what their proposals are and one of the big issues then is if
the industry initiative is kind of the benchmark, if you will, then what
is the regulatory animal that it becomes part of.
DR. KRESS: As part of that framework you're talking about.
DR. SEALE: Yes, that's a real interesting point, because
after all, as I understand it, once the industry buys into an NEI
whatever it is, that that is a prima facie commitment on the part of
everybody to comply with that.
MR. MURPHY: To themselves.
DR. SEALE: To themselves, but nevertheless. On the other
hand, a regulatory guide is a recipe. It's not the only recipe.
MR. MURPHY: Just to jump ahead a little bit, I'll say it
now. It's the feeling on the part of a number of us on the staff, this
is not the official NRC position, but it's hard to see how this is going
to be made to work without some sort of tech spec or code, but the code
approach does not appear to be practical in the foreseeable future. It
takes time to rework the code. But some sort of tech spec change would
be necessary to accommodate this.
DR. SEALE: You need an enforcement hook.
MR. MURPHY: Yes.
DR. SEALE: Okay.
MR. MURPHY: We also informed the Commission that we would
proceed with issuance of the DG, the draft DPO resolution that we had
discussed with ACRS, and a subsequent DPO memo to the Commission dated
September 25, '98, which reiterated the concerns regarding our
recommended approach and the draft GL and DG-1074.
The Commission made no objection to our proposed approach,
so these three documents, the draft guide, the proposed DPO resolution,
and the DPO author's memo to the Commission were released for public
comment in January of this year. Comments have been requested by June
30th of this year.
The Commission noted that we should be careful and provide
guidance to the regions that DG-1074 is out for public comment and it is
not to be used as guidance for inspecting licensee SG programs. It has
no regulatory status at this point.
DR. SEALE: It really doesn't have any regulatory status
until you have reconciled those comments and reissued it formally, does
it?
MR. MURPHY: There was a concern. Industry had this concern
that inspectors -- they got this document, regardless of its status, and
--
DR. SEALE: You don't understand. My comment is, it's not
-- while it's out for public comment, it has to complete the cycle and
become issued as a formal document before it becomes a basis for
inspection, doesn't it? What I'm saying --
MR. REED: You're absolutely right.
DR. SEALE: June the 30th, this doesn't become in force.
You've got to do something with the public comment and other things
before it can have any elevation in its status.
MR. MURPHY: I understand. But people can frame their
thinking and be guided by even unofficial documents when evaluating
utility programs.
MR. REED: We're responding to a Commission and industry
concern there.
DR. SHACK: They're just reinforcing that point, that's all.
MR. REED: The inspectors say, look, this is not -- you
don't use this to inspect.
DR. SEALE: Yes, but June 30th is not a magic date.
MR. REED: It's not. Yes.
MR. MURPHY: Okay. That concludes this introductory
presentation and I think NEI, at this point, the representatives have
the floor.
MR. REILY: I'm Jim Reily, from NEI. I've got a couple of
folks with me here today in case some questions come up that they can
answer as utility representatives. Mike Short, from SONGS, and Rick
Mullins, from Southern Company.
Did everybody get a copy of the presentation? In some
respects, this is going to look a little redundant to Emmett's, which is
probably a good sign and even indicates that we might have been talking
a little bit prior to this meeting. Hopefully, well continue to.
So this is kind of our perspective on what's going on. What
I'd like to be going over this morning is the initiative, Emmett has
already talked about that a little bit, where we are right now from a
status perspective, and a brief outline of what we see the be the
issues. I'm going to be going over the issues in a general sense.
We've got, obviously, a lot more details than this, but the more major
broader perspective type issues is what I'd like to bring up.
This is something you've seen before this morning. Same
statement. As Emmett indicated, the inference here is that we have made
an internal commitment that we will implement the requirements in NEI
97-06, as detailed in the EPRI guideline documents that are referenced
by it, by the first refueling outage after January 1st, 1999.
The feedback we've gotten to this point, as indicated,
nobody there is not going to be implementing it in accordance with this
commitment.
DR. KRESS: Could you give us little bit of perspective on
the general feeling in industry of internal commitments due to their
initiative versus something required by regulation? How do you view
those two things? Would you much rather have the internal commitment
and does that give you advantages and flexibility and save you money?
MR. REILY: I would answer that in the affirmative, but I
think probably, if I can call on Mike or on Rick, they'd probably be
better to answer that question than I would.
DR. KRESS: They can comment from the utilities.
MR. REILY: They can comment from the utilities themselves.
MR. MULLINS: I'm Rick Mullins, from Southern Company. I
spent a number of years working with Farley nuclear plant, on their
steam generators.
I believe the industry preference would be to keep the
commitment internal, because it does give us a lot more flexibility.
Steam generators are an ever-changing task to manage and to respond in a
regulatory arena or in an ASME code, as Emmett said, is very difficult
to do in a timely fashion.
We feel better with those internal commitments.
MR. SHORT: My name is Michael Short, and I'm a manager
responsible for steam generators and other activities for San Onofre
Nuclear Generating Station. My comments are similar to Rick's. It's
basically principally from the standpoint that there is quite a bit of
evolution occurring in the technology of steam generator inspections and
repairs and the industry would prefer some process that enables us to
continue to grow with that technology and apply it on an ongoing basis.
The concern is that if we regulate in detail through, for
example, the code or other similar document, we'll freeze the
technology, at least portions of that technology.
It's our belief that by maintaining some flexibility, we
actually, in the long run, enhance plant safety and enhance the
economics.
DR. KRESS: How do you feel about the inspectability and
enforcement aspect of that? Do you think it's just as enforceable and
just as inspectable?
MR. SHORT: I have to admit that I think from an enforcement
standpoint, the situation is rather confused right now, and our
commitments don't readily solve the staff's problems in the enforcement
and inspectability.
I think the inspectability can be handled with whatever
guideline you use, but what do you do if you find a deviation? What is
the staff's action and authority to take action? Right now it's that
they're confused and that is a weakness in the industry initiative
approach, just how to do that. Rick, do you have anything else?
MR. MULLINS: No. Just one thing to add is that staff has
never, in my past, had problems with finding some regulatory enforcement
--
DR. KRESS: Somebody can.
MR. MULLINS: Somebody can find something that they could
use, the maintenance rule, Appendix B or something.
DR. SEALE: If they look out there, they can find it.
DR. KRESS: They have a big enough stick.
MR. MULLINS: Yes, sir.
DR. KRESS: Thank you. Appreciate that perspective.
MR. REILY: So what is this NEI 97-06 that we're talking
about? It's a guidance document, first of all. It describes the
program that will be followed, and there is an outline here that I will
talk about in a minute that generally tells you what's in this document.
It gets its details by way of the EPRI guidelines that are
referenced by it, and there is a series of EPRI guidelines that are
associated with this initiative, everything from primary and secondary
water chemistry through NDE-type guidance and tube integrity assessment,
et cetera.
So NEI 97-06, in general, contains the performance criteria.
Emmett has already mentioned these. We have three. There's structural
integrity performance criteria within it that's tied to
deterministically 3 delta P and 1.4 main steam line break. In addition,
there is a probabilistic criteria on structural integrity, also, that's
tied to the probability of the steam generator tube rupture. The value
we have in our guideline right now is five-times-ten-to-the-minus-two.
There is an accident-induced leakage criteria. We tie it to
10 CFR 100 and GDC-19 requirements. And there is an operational leakage
criteria of 150 gallons per day per steam generator.
So those are the three performance criteria, some of which
we are actively discussing with the NRC because of some differences in
approach and there will be slides later in this presentation on those
issues.
In addition, there is guidance on the steam generator
program, what's it going to look like in a given utility. It requires
an assessment of potential degradation mechanisms prior to an outage.
You take a look at what's going on in your steam generator, where is it
occurring, what kind of equipment do I need to use to make sure that I'm
finding any degradation mechanisms.
You plan the inspection ahead of time, again, and where am I
going to inspect, how am I going to inspect, what kind of things am I
going to do to make sure I'm catching what's going on inside the
generator.
It talks about the assessment itself, NDE, et cetera,
maintenance and repair requirements, plugging, sleeving, whatever
happens to be appropriate. It also talks about what requirements do we
have for primary and secondary leakage, primary and secondary leakage
monitoring, primary and secondary side water chemistry.
Again, remember, these are, at this level, in this NEI
97-06, a very general description, again, with reference to the EPRI
guidelines that govern.
Foreign material exclusion, maintenance of steam generator
secondary side integrity, not only tubes, but, in general, the secondary
side of the steam generator, and what self-assessments need to be
accomplished, especially in cases, as Emmett indicated, where you go and
inspect the steam generator and find that you haven't met your condition
monitoring requirements, your performance criteria. What are you going
to do about correcting that situation so you don't have a recurring
problem?
Then, finally, it talks about what kind of reporting
requirements have to be sent in to the NRC.
So where are we right now? What's our objective? Well,
right now, we are trying to get a generic license package together for
NRC approval prior to the end of this year and that license package
would include technical specifications, any UFSAR changes that may be
required, and any documentation that might be necessary to support the
license change.
At the same time, we're at least considering the possibility
of whether a pilot plant approach may be a better way go to about this.
We haven't made up our minds about that yet.
There are certain advantages to using a pilot plant approach
because of the fact that some of these issues are difficult to tackle
from a generic perspective and may be a little bit easier to put your
arms around if you're dealing with one licensing basis, not an industry
full.
But that's what we're working toward by the end of this
year. What are we doing to get there? Well, we're having frequent
meetings with the staff on specific issues and monthly summary meetings
with the staff and management. The last time we did this was the end of
February. We had a February 10th meeting with the staff and a February
24th meeting with senior management. We have another meeting set up for
April 1st and my intention is to continue these meetings at least on a
monthly basis.
We are also trying to get more frequent meetings on focused
issues with the staff as we're able to get the time together to do that,
so that we can make some progress on specific issues. Senior management
will continue to meet on a regular basis. Their next one is scheduled
for the middle of May.
The point with the senior management meetings is to provide
a way to break the logjams. If we're stuck on an issue, we want to make
sure we've got those folks a little bit higher up maybe more in the
decision process and able to move things along, and it also, of course,
serves as an incentive to all of us to keep pushing on this thing, so
we're able to get these guys together and show that we're doing
something.
So, again, we expect to have a generic license change
package by the end of July in order to support the NRC's review and
approval by the end of the year.
And where does NEI 97-06 stand? It was issued initially in
December of 1997. We have gotten comments from the NRC on NEI 97-06,
and Emmett went over some of them in his discussion with you.
We responded to those comments in a letter dated December
17th. There were, I believe, 21 issues that we responded to in that
letter, and the NRC has gotten back to us on two separate occasions with
their response to those comments. And from my counting, I had about 50
percent of the comments basically being accepted by our letter of
December 17th and about 50 percent of them still need to be resolved.
The February 4th letter was more of a generic kind of an
approach. There was agreement that we were making progress with the NEI
97-06 and that we would continue to work together to get to a final
product.
There were a couple of specific issues that were mentioned
that were of concern to the NRC that had to do with incorporation of
some of the criteria in the technical specifications and approval of
alternate repair criteria and those kinds of things.
The February meeting handout went into significantly more
detail on each of the comments and it talked about specific issues that
exists with them.
As I mentioned already, we have been serving the plants and
haven't heard anybody say that they will not be incorporating this by
the first refueling outage after January 1st. We did issue a letter
specifically addressing Emmett's concern, the NRC's concern that Emmett
talked about just a little while ago, and that is that some of what is
being proposed in NEI 97-06 is under discussion and may or may not be in
accordance with a plant's licensing basis, and we caution everybody to
ensure that when you're implementing this, you don't do anything that
isn't in accordance with the plant's design and licensing basis in the
process of putting these requirements in your plant procedures.
We intend to issue a Rev. 1 and the idea is to issue that
about the same time that we send out the generic license change package.
Of course, we're going to have changes to it. We already have some
changes to NEI 97-06 identified. We'll put out a Rev. 1 that
incorporates all those discussions at that time.
So what are the issues? We have broken them into three
categories; technical, licensing and regulatory, and those associated
with risk. We have broken up -- this whole effort within the industry
is being spearheaded by a task force within NEI and we've broken the
task force down into subgroups, too, to try and assist the resolution of
some of these things, so we can put a little bit more focused attention
on them.
So the issues. Technical. Operating assumptions for 3-NO,
normal operating DP. We need a better definition of what is the normal
operating differential pressure, what kinds of transients need to be
included when you come up with this differential pressure.
We believe there is regulatory and code precedents that
would allow us to limit the transients that need to be considered here.
We're working on a definition now, we'll be working with Emmett and
others to make sure we come to agreement on specifically what is this
differential pressure that we're testing against, what transients need
to be included. It's still an open issue.
DR. KRESS: And are those transients spelled out in Chapter
15 of the SAR?
MR. REILY: I don't believe -- no, I don't believe they are.
DR. SHACK: Can somebody give me a specific example of where
the problems are on this? I always thought normal operating pressure
was something we understood.
MR. REILY: The question is during startup, what transients
during startup might have to be included, at what point in startup do
you have to start being worried about these pressure transients that you
might encounter.
MR. MURPHY: Shutdown, during shutdown, for example, the
tubes go into tension during shutdown.
DR. SHACK: Do you flip-flop back and forth between the 1.4
main steam line break and the 3 delta P? The 3 delta P is always the
limiting quantity?
MR. MURPHY: Typically, it's the limiting quantity.
MR. REILY: There are things to consider here. Do you
really need to be concerned about these transients if the reactor is not
critical? We don't know the answers to those questions yet. We're
trying to come up with some suggestions, some definitions that might be
acceptable to both sides.
MR. REED: We search around and try to find the worst normal
upset and condition you can find and it increases the delta P by like a
hundred or more, versus like a normal typical. Take that times three
and --
MR. REILY: It starts getting pretty significant, or even
more than that.
MR. SHORT: We're currently testing our tubes to pressures
in the range of four to -- 4,000 pounds to upwards of 5,500 pounds
against a current definition of three times full power operation delta
P. That results and you then multiply it by three, the results in the
test pressure, and you have a plant, anywhere from 4,000 pounds to as
much as 5,400 pounds. To encompass all of the elements of the staff's
proposal could raise that pressure three times -- these are in-plant
tests.
Now, the tube is retired after it's tested, but that's
pushing the technology and the equipment, pressurized to that. So
that's one of the questions that we're trying to work through, is what's
an appropriate test pressure.
DR. KRESS: Is this a good place for risk-based arguments?
MR. SHORT: That's one of the approaches. One of the things
we're considering is can we limit this to transients that are present in
modes one and two, for example, and we do reduce the range of pressures.
MR. REED: And they're typically pretty short duration.
DR. KRESS: And that's important to risk-based.
MR. REILY: That's one. Another is the accident-induced
leakage. Our contention has been that the ultimate licensee basis is 10
CFR 100 and GDC-19. The NRC has pointed out that one gpm appears in
many places in a lot of plants', most plants' licensing basis, and feels
one gpm is probably a better limit to use.
However, I believe I'm not misrepresenting when I hear that
there may be margin beyond one gpm, but nobody really knows what the
correct value will be, in the NRC or, for that matter, right now, us; so
what is a good defensible value beyond one gpm, somehow related to 10
CFR 100 and GDC-19.
A problem we see with one gpm, for example, is that even
though that's huge in the accident analysis as the leakage rate that
determines your off-site doses, you also, in many places, have that as a
tech spec limit, too.
So that means that you're operating keeping it to less than
one gpm or if you have an accident, is that not going to -- is it
realistic to assume that it won't get worse, and, if so, what does that
mean with respect to consistency on the accident analysis.
So I don't know what one gpm is a really good number either
and part of what we're trying to do here is come up with something that
will work and be acceptable on both sides. The previous comment, is
this the kind of thing that you'd use a risk-informed type approach,
yes, it is, and that's something to consider, too, in how do you tie
this thing down a little in a way that makes sense, from a risk
perspective.
Steve Long has told us in other discussions that he likes
the long-term. One gpm has some significance in terms of severe
accident space and, therefore, there is some resistance to going beyond
it, because it turns out that it's a sensitive type program when it
comes to performance under those conditions.
Tube burst and tube rupture, I don't see this as a big
issue, but it is one that needs to get resolved. Really, the difference
-- see, the whole issue here is how do we differentiate between leakage
and failure, because what we're trying to do in structural integrity is
to prevent tube burst. But when there is tube leakage, tube burst, how
do we tie that down in a way that we make sure that we're both in
agreement with and that you can ultimately test your tubes to make sure
that you're meeting the requirements.
So we're developing definitions, definitions that will
hopefully address both the NRC's concerns, as well as our concerns. I
don't see this as a big issue. It's just something that needs to get
worked out.
And I don't know whether I'd call this an issue as much as
some information that's needed. I believe Emmett made a comment earlier
about some of the guidelines not being finalized. Maybe that's my
inference out of what your statement was. But we have two that we are
-- we still have in draft form that we're trying to get all the
issues/comments resolved and it is our belief that it isn't wise to
release those things to the NRC for their information until we get the
industry comments worked out and kind of test them in the field a little
bit to make sure they really make sense.
Those two right now are pressure testing and steam generator
integrity assessment. We have a goal to get those out in Rev. 0 form,
at which point NRC will be given a copy by the middle of the year, and
actually in situ pressure testing we're hoping to have before that.
Steam generator integrity assessment we're looking for, like
I said, by the middle of the year. And that should complete the picture
from the standpoint of NEI 97-06, because all of the EPRI guidelines
that implement the requirements will be available for the NRC to take a
look at to see what it is we're trying to say we're doing when we have
the steam generator program.
Licensing, regulatory issues, what are we going to do about
technical specifications is probably the biggest question here. As I
mentioned, in the February 4th letter, the NRC stated that they would
like to see the performance criteria in the technical specifications.
We are actively considering that and trying to decide how is the best
way to put those into the technical specifications.
Reporting requirements, the way I understand it, within NEI
97-06, that are pretty similar to DG-1074, are acceptable and need
somehow to be tied into the technical specifications that we're
developing, so that it's explicit on what reporting requirements are
necessary.
We would tie surveillance requirements to the steam
generator program and describe the program itself in the administrative
session of the technical specifications. We have some straw men we've
been bouncing around on our side of the fence. I know the NRC has been
doing the same thing on theirs.
I believe that we'll get there as soon as we have a chance
to bang these around enough times to come up with some technical
specifications of both parties can believe in. It's obviously an
important issue.
Repair criteria and tube repair methods. The issue here, I
think, in general, is that we agree with, first of all, what they are,
at least in terms of definition, and that the NRC approval is required
for first-time use of either of these.
I believe the question that resides on both sides is how do
we go about providing the means to have the NRC review and approval of
either an ultimate repair criteria or a tube repair method the first
time and then subsequently allow other plants to use them with a 10 CFR
50.59 type approach. Both of us are struggling with, legally, how do
you manage this thing in order to make sure that's done properly.
DR. FONTANA: When you say other plants, you mean if they
approve it for one, then all the others -- all of the other plants can
use it.
MR. REILY: They can do a 50.59 evaluation to ensure that
they -- that what's been done bounds the conditions at their plant.
DR. KRESS: Is this the voltage-based repair criteria?
MR. REILY: That's one right now. There may be others in
the future, but, yes, it's the Generic Letter 95-05 and two repair
methods, sleeving, et cetera.
DR. KRESS: Sleeving.
MR. REILY: Yes. Okay. Risk issues. I believe the thing
is here how do you deal with severe accident concerns and this kind of
plays into the subsequent bullets or the subsequent pages that are
coming after this. How do you address severe accident concerns, when do
you address them, what's the acceptance criteria for saying that your
results are okay in severe accident space?
We trip across this when we talk about exceeding one gpm.
We trip across this when we talk about using a probabilistic criteria
for structural integrity. So it's all kind of new to all of us, to both
of us, I think, and we're trying to get our arms around exactly what are
these things, how do you do them, and what's acceptable when you do.
DR. SHACK: But you do agree they have to be considered.
They're not beyond the licensing basis.
MR. REILY: Oh, no, I don't think anybody is saying that
severe accidents aren't beyond the licensing basis. That's part of the
problem. We think they are. They are. I don't think there's -- but
the fact is that we're being told that if you're going to go beyond
these licensing values, you've got to look at it from the severe
accident perspective and we're not quite sure how to do that.
What are the risk issues? Probabilistic, structural
integrity. The information we've gotten from the NRC so far is this
value is -- well, it's questionable from two points of view, and I think
you've already heard these two. How does it related to the
deterministic criteria and -- I'll think about the second one, what's
the second one, my mind just went blank on me -- how does it relate to
deterministic --
MR. REED: Both the value to be used -- 2.5-times-ten --
MR. REILY: Yes. The specific value to use, how it relates,
I don't know, my mind's drawing a blank on the second one. But we've
been told that it's okay to use it for operational assessments, but not
for condition monitoring. One thing I didn't mention in the tech specs
is we intend the tech specs to capture the requirements for condition
monitoring, not operational assessment.
Now, operational assessment is, in essence, the same kinds
of concerns extrapolated out to the end of the next cycle. The only
thing you have to take into consideration in addition is growth rates,
of course, to be able to come up with values at the end of the next
cycle.
And the position is it's okay to use probabilistic
structural integrity for operational assessment, but if it comes around
to the end of the next cycle and you don't meet your condition
monitoring requirements, you've got to be taking a look at why you
didn't. Of course, why you didn't can be tied to your operational
assessments you used the last time.
So even though the use for probabilistic operational
assessments is being not challenged right now, the fact is it's
something you're going to have to be very careful with to make sure that
you end up with results you can live with.
We would like to use it for condition monitoring, also. But
in order to do so, we're going to have to work a justification for using
it. Right now, we've got EPRI taking a look at how that might be done
to allow us to use this probabilistic limit for condition monitoring,
also.
DR. SHACK: Can you tell why there is this dichotomy between
the condition monitoring and the operational assessment? I mean, I can
understand it under current regulations, but if you had a tech spec
amendment, wouldn't that get around that problem?
MR. MURPHY: The reason is right now we're looking at the
status quo. There is no regulatory requirement to perform operational
assessment. So these assessments are voluntary actions on the part of
the utilities. So if they do these assessments, they can evaluate --
they can do these assessments relative to any criteria they want.
However, we would argue, though, that they can't have --
they shouldn't be maintained on the steam generators relative to those
criteria. Rather, the licensing basis says these tubes should have a
factor of three. So people are assessing the condition of the
generators. Their expectations should be -- what we're trying to
demonstrate is that we have the conditional safety factors,
deterministic safety factors retained.
MR. REED: Actually, in the recent discussions we've had
with industry, the staff has been more of the mind that you guys go do
your operational assessment, do it however you see fit. You're going to
hold the bag there. When you shut down, here is what -- so if you guys
want to use a probabilistic approach, well, you're putting your neck out
there. When you shut down, you're going to have to show you meet the
traditional --
MR. MURPHY: What we're shooting for is a performance-based
approach. The important thing is that you maintain the safety margin
goals that you set out for yourself, what actions you take to ensure you
meet that goal isn't something that we necessarily have to pin down in
our requirements.
MR. REED: We give them more flexibility, however you can
skin the cat.
MR. MURPHY: However, it would seem, as just pointed out, it
would seem that if you're doing your operational assessments relative to
a probabilistic criteria, that it's not going to be too surprising that
you don't meet your deterministic criteria at the end of the cycle.
MR. REILY: Obviously, it depends on how you set your
probabilistic criteria up.
DR. KRESS: That's the nature of it. That's why you call it
probabilities.
MR. MURPHY: The probabilistic criteria that are being
proposed are criteria based on the conditional likelihood of failing
during an accident, during a steam line break, for example, whereas
typically the most limiting criteria we have to do with deterministic
space is the factor of three criteria relative to normal operating
pressure.
So there's not just deterministic versus probabilistic, it's
one set of criteria that is, in most instances, based on normal
operating pressure and the other criterion is based on accidents.
DR. KRESS: Calculated accident pressure and temperature.
MR. REED: Actually, it goes from something like was
mentioned before, like a number like over 4,000, 3 delta P, if you get
higher than 5,000, down to this is typically at 2,600. It's a safety
set point plus accumulation plus uncertainties, it's about 2,600, at a
probability of failure of about five percent.
So you're coming down in delta P given the probability.
There's no probability assigned to the deterministic, never has been, so
that's kind of been a known thing there. So that's what you're looking
at, different delta P and then assigned probability. Staff used that as
a relaxation and that's where our concern is.
We need to look at that and it should be risk-informed.
DR. KRESS: Basically, if you accept that, you're basically
saying margin of three was not an appropriate margin in the first place.
MR. REED: Or we're saying that this also ensures the
defense-in-depth. I'd like to put it that way.
DR. KRESS: You're changing what your acceptance of
defense-in-depth would be.
MR. REED: We would have to determine it still retains
defense-in-depth and the risk is acceptable.
DR. KRESS: If you do that, let me know how, because I've
been trying to figure out how one determines an acceptable
defense-in-depth under any circumstances.
Let me know what you come up with.
DR. SEALE: Once you open up the question.
DR. KRESS: Yes.
MR. REED: We'll take that one off the table.
MR. REILY: And we've already talked about this, too.
Accident-induced leakage obviously has risk inferences. What do we do
to justify exceeding one gpm? We're working on that, also, and, as I
mentioned, that's something we're taking off with EPRI to see if we
can't come up with a technical approach together to get something
greater than one gpm.
So that's it as far as where we're heading with this. As I
mentioned, there was some redundancy with them that we've been talking
frequently and expect to continue to do so.
Questions?
DR. SEALE: I have a general question and I'd like to get
the reaction from any of you on this.
I think it's important that we try to keep things in
perspective with each other and as you may or may not know, we've been
looking at a lot of related interwoven concerns having to do with
potential for making Part 50 risk-informed. There's a thing on the
table now about Appendix K. We've been beating our brains out with
50.59 and with other things like that.
And there was recently a change which I understand has
implicit in it the potential for considerable regulatory relief, namely
that the change in the status of level four violations, whether or not a
notice of violation would be issued.
In the world of steam generators, where you have had a
problem, what level are those violations?
MR. REED: I can only say that we're starting to think about
where we do this whole -- if we do this new framework, this
performance-based framework, in looking at that gigantic mission paper,
it's 007, the ideas in there about how they lay out different color
codes, what you're talking about and what threshold, we started looking
at where we would be on that and you go through these exceeding
performance criteria, like 3 delta P, that's still safe and that's why
we established that criteria.
Where it becomes significant is at 2,600, it's a tube
rupture, we start thinking about that, but we're not there, to be honest
with you. So my answer is we don't know yet.
DR. SEALE: But there's a history. There is a history,
though.
MR. REED: Yes, there is.
DR. SEALE: There have been some problems and when that's
been -- those have happened, where are they? Are they level fours, or
are they level threes, level twos, where are they?
DR. KRESS: You mean what were the past --
DR. SEALE: Yes. What's the experience?
MR. RUSH: Well, based on my inspection experience, most of
the time --
DR. SEALE: Could you identify yourself?
MR. RUSH: Bill Rush, from the Materials and Chemical
Engineering Branch. I've been on several inspections over the past
several years relative to steam generators and have been involved in a
number of enforcement issues with the steam generator tube integrity
programs.
And most of the concerns that we've identified in the field
are Appendix B concerns, which generally fall into severity level four
violations or of lesser significance. I guess about two years ago, two
or three years ago, the Office of Enforcement issued an enforcement
guidance memorandum on steam generators and how inspectors were
declassifying the various findings that they made during inspections.
And considering what's going on with the revision to the
regulatory framework, you could potentially see things as high as
severity level three, in my judgment, because the changes that are being
discussed here are programmatic.
If I recall, the enforcement guidance memorandum says if you
make programmatic mistakes or errors which result in a significant
number of tubes being significantly degraded, then you, I think, cross
the threshold from a severity level four to three.
But hopefully that will be prevented by whatever the
framework is that is agreed upon.
DR. SEALE: Could we try to find out a better, a more
organized answer to that question? You know, maybe getting rid of AEOD
is another way of hiding the answer. I'm not sure. I would hope not.
That's one of the things we're worried about.
But could we try to -- maybe Steve Long knows? What is the
experience with past steam generator problems in terms of the category
of the level of violation? Was it four, three, what? Overall.
MR. MURPHY: We've never issued a severity level three, to
my knowledge.
DR. SEALE: Never issued a --
DR. KRESS: I think he said it's four, at most.
MR. MURPHY: Yes. It's only severity level four or lesser.
DR. SEALE: I would agree with you, in looking at where
you're going, certainly you need to ask yourself whether you're talking
about red, green, blue, purple, whatever the colors may be, or things in
the future. I think that's a very --
MR. MURPHY: We agree. One thing to emphasize, though, it's
not been our thinking that an instance where somebody finds he doesn't
meet the performance criteria under condition monitoring, that wouldn't
necessarily translate to a situation which needs to be cited according
to whatever the standards are.
DR. SEALE: I understand.
MR. MURPHY: A big part of what goes into that is the
circumstances under which the situation occurred.
DR. SEALE: I understand, and that's certainly in the spirit
of what risk-informed regulation is all about, and that's an important
aspect to recognize as you move forward, I think.
MR. REED: I guess you guys probably are familiar with that
whole policy, when things go to level three or whatever, than I am. I
assume you've been briefed on it. But I'm hearing we've never done a
level three to date. We've had seven tube ruptures and it's pretty hard
for them to get into level --
DR. SEALE: But that's something I think we need to know.
We've heard about these levels in the abstract, in a way, but in the
real world of steam generator tube performance, what are we talking
about? And I appreciate your answer.
MR. RUSH: I think what you really need to cross that
boundary into a severity level three violation is where the NRC or
whoever decides that that steam generator may not have been able to
perform its safety function.
DR. SEALE: Yes.
MR. RUSH: Because of some mistake somewhere. Not
necessarily because of a degradation problem, but it had to involve an
error on the licensee's part.
DR. SEALE: Degradation plus lack of appropriate remedial
action or something of that sort. Sure. Anybody else have any other
questions?
DR. SHACK: I'm still confused. I'm reading page 17 here of
the draft reg guide. As I read it, the probabilistic criteria are a
full alternative to deterministic criteria.
MR. MURPHY: The what?
DR. SHACK: The full alternative to the deterministic
criteria, although it represents a change to the licensing basis, and I
do have to come in and get NRC review and approval. Are you saying the
answer would be no?
MR. MURPHY: The idea was that -- well, the staff had
concluded, when preparing the draft guide, that if risk could be
demonstrated to be low, that those particular performance criteria, the
values given in the draft regulatory guide do meet the other engineering
elements of Reg Guide 1.174 in terms of defense-in-depth and that kind
of thing. We think it would be consistent with the GEC, all the other
governing regulations.
In other words, maintaining the official probability of
rupture during accidents to the sort of numbers that were talked about
in the DG is consistent with the defense-in-depth that the original
design basis had in mind.
DR. SHACK: So it is an alternative and it meets all the
requirements.
MR. MURPHY: But there may be risk implications and those
risk implications need to be assessed on an accident basis. Just
looking at it from an engineering standpoint --
MR. REED: We would suggest a risk-informed submittal.
DR. SHACK: Which gets him off into severe accident space.
DR. KRESS: It gets him into plant-specifics, also.
MR. MURPHY: I think for most plants, it would be largely a
severe accident assessment that they'd want to look at. But there are a
couple situations, depending upon the application of the criteria, where
even some design basis scenarios within the design basis envelope should
be looked at.
For example, B&W units have a high frequency of secondary
side depressurizations that have nothing to do with main steam line
break, stuck open safety valves, and what has to be sure is that the
probabilistic criteria that are being proposed are an adequate surrogate
for the spectrum of accidents that you're concerned with.
So a risk assessment, in part, is demonstrating that your
criteria, your proposed criteria, presumably which address one or two
operating situations or accidents, are an adequate surrogate for all
scenarios and ensuring that you don't have a significant risk impact.
DR. SEALE: Could I suggest that perhaps another way to look
at this would be, I think, first of all, the committee has, on occasion,
in the past, tried to make the point that the deterministic evaluation
is the step zero or step one in preparing the case for a probabilistic
assessment. That is, you really have to go through the deterministic --
most of the deterministic steps, anyway, in order to set the boundary
conditions for doing a probabilistic assessment.
And Tom has made the point repeatedly in the past that he
doesn't know how to handle defense-in-depth in a risk-informed
regulatory process. Well, in a sense, these deterministic limits are
the risk -- are the defense-in-depth aspects that you'd have to -- that
you'd want to address after you've done -- or as a part of wrapping up
the package, if you will, in a risk assessment which is based on
probabilistic considerations.
DR. KRESS: But the problem with that is they're
incompatible sometimes and you're changing these deterministic
requirements. That' what you're actually doing.
DR. SEALE: Sure.
DR. KRESS: You want to change those things.
DR. SEALE: Sure you do.
DR. KRESS: And the question is how much change is
acceptable --
DR. SEALE: Yes, exactly.
DR. KRESS: -- in a defense-in-depth --
DR. SEALE: But that's where that question has to be
answered. What I'm saying is that the whole package would include the
consideration of what the defense-in-depth elements are and whether or
not they changed or whether it's appropriate to change them.
DR. KRESS: My objective with the defense-in-depth stuff is
to not mix deterministic standard criteria in with probabilistic.
Defense-in-depth needs to be defined in terms of probabilistic sense and
the deterministic stuff should stand on its own.
The defense-in-depth should be part of your definition of it
and your limits on it, should be part of your probabilistic setup, and
that's the way I'm approaching it. Therefore, I would not go along with
what you said, although they are -- they can be removed.
DR. SEALE: You're really making it hard.
DR. KRESS: Yes, I'm making it hard.
MR. REILY: I read somewhere that the defense-in-depth
aspect of the probabilistic approach is sometimes handled through the
treatment of uncertainties.
DR. KRESS: Absolutely.
DR. SEALE: Exactly.
DR. KRESS: It has to be related to the uncertainties. The
trouble is how to make that relationship and how to put limits on it.
That's the problem. But that's the way you do it in the probabilistic
world and you're exactly right. That's the way I'm approaching it.
We're working on an ACRS position on this and I'm supposed to be taking
the lead and that's the approach I'm taking.
DR. SHACK: Except there are some uncertainties you can deal
with and some you can't.
DR. SEALE: Yes.
DR. KRESS: That's part of the problem.
DR. SEALE: And you're a victim of the fact that we're
trying to pick as many brains on this thing as we can.
DR. KRESS: That's why we asked them strange questions.
DR. SEALE: As a matter of fact, I think it's very
reassuring to hear a person with -- that's in your position and with
your background and so on come up with this probabilistic point or
uncertainties point with regard to defense-in-depth, because that's very
helpful, I think, in terms of -- you know, we are not off the wall
completely, anyway.
DR. KRESS: The biggest uncertainty in all of this is how to
deal with George Apostolakis and --
DR. SEALE: There is that, and that is a very uncertain
question. Well, are there any other questions or comments?
[No response.]
DR. SEALE: I guess you're back in the barrel, Emmett, after
we have our break. But what I wanted to say before we break is I hope
you gentlemen will not only stay around for the rest of the
presentation, but if you have any comments that you would like to help
us with as we go along, we would very much appreciate your saving them
for us and being willing to respond and we ask for -- or if you have
something that's appropriate at the moment, we might even be able to
break in a little bit. But we do want your input and your help.
We'll break until 10:15 and then you'll be back in the
barrel.
[Recess.]
DR. SEALE: We are back in session now and we'll see what
Emmett's got.
MR. MURPHY: In my first presentation, I sort of discussed
where we had been, and now this discussion will focus on where we're
trying to go and also briefly describe some recent operating experience
at a couple of units that relate to -- that have some relationship to
where we're trying to go with the regulatory framework and the industry
initiative.
It updates you as to where we are with the responses to GL
95-05 and GL 97-06, dealing with inspection methodologies and
degradation of the internals.
Now, as was indicated by Mr. Reily, there has been extensive
interaction, he's already discussed these interactions, but I think the
point to be made is that this has been -- that this is something that
both sides are serious about and we're working intensively on and
pursuing.
The objectives that we are pursuing with this effort I think
are consistent with the objectives that we have been pursuing since the
beginning of the regulatory activities in this area. Namely, we want to
have an approach that is performance-based and risk-informed, that will
be adaptable to new degradation mechanisms as they develop, or advances
in eddy current technology without the difficulty of rendering utility
programs or regulatory requirements obsolete or ineffective.
It would certainly be a desirable objective to provide -- to
allow utilities the flexibility they need to effectively -- to maintain
their generators in a cost-effective fashion, consistent with the
overall objective of ensuring -- providing for this flexibility, by the
way, in a regulatory framework is a very difficult challenge, and I'll
be speaking to that briefly, because there are some kinks, legal kinks
to be dealt with in that regard.
To have a framework -- a known framework within which SGDSM
strategies -- that is, defect-specific management strategies -- should
be developed. I think that framework is pretty well developed as of
now. When one is developing, for example, alternate plugging criteria
to deal with specific degradation mechanisms, he needs to be thinking
programmatically as part of these ARCs, saying what are the inspection
programs surrounding the implementation of these ARCs, how is one going
to perform the operational assessment, condition monitoring and so
forth.
Finally, to have an effective enforcement hook. We believe
substantial progress has been made in resolving technical issues that
exist between the industry initiative and RGL and regulatory guide
initiative. However, some high priority technical issues remain to be
resolved before we can reach agreement with industry on their initiative
and a new regulatory approach can be agreed to.
But I think it's a very important note that these high
priority issues exist irrespective of whether the industry proceeds with
this initiative and whether a technical agreement is reached on that
initiative in the new regulatory framework.
In other words, these issues don't come to the fore because
NRC has an initiative or because industry has an initiative.
These are issues we will have to grapple with regardless.
So these are issues that we have to resolve, but we think there is a
compelling case to be made for proceeding with trying to reach agreement
on developing a new regulatory framework. We think that it has benefits
to the NRC in terms of providing enhanced assurance of tube integrity
and, at the same time, it's highly desirable to provide the industry the
sort of flexibility it needs in dealing with the kinds of problems it
has to manage.
As Mr. Reily noted, the current scheduled goal is to try to
reach agreement on priority technical regulatory framework issues to
support issuance of an industry generic package sometime in the early
summer of this year.
If that can be achieved, then we would think that it may be
possible to turn around this package by the end of the year or shortly
thereafter. We would need to -- when we spoke about how we would
endorse -- what would be the form of an NRC endorsement of the industry
initiative, it's not totally clear at this point, but it would seem that
a staff SE, safety evaluation, of the submitted change package, which
would include a revised version, presumably, of NEI 97-06 and technical
bases accompanying that and generic tech specs, a generic SE may be an
appropriate vehicle. Of course, we'd have to -- we'd be discussing the
draft versions of the SE with you and with CRGR, and then we'd have to
go to the Commission.
MR. REED: I'm not sure yet.
DR. SEALE: Emmett, I have to say I think sometimes we do
the industry a disservice when we state issues like this in a this side
versus that side way. Clearly, they want steam generator tube
integrity, too.
The idea of losing steam generator performance or, in fact,
having to replace a steam generator is not a pleasant thought for the
industry people either and there's a lot more commonality in this goal
than I think we sometimes suggest.
Just a comment.
MR. MURPHY: True. But it is a challenge, nonetheless. If
one thinks in terms of regulatory framework, develop the framework which
does what the regulator wants it to do in terms of it being enforceable
and all that kind of stuff, but, at the same time, give the utilities
what they need, which is flexibility.
DR. SEALE: And I'm sure the most unattractive part of this
whole process is having to sacrifice tubes I order to demonstrate
performance, because you're just eating up the reserves, so to speak,
when you do that. It's not easy, but it's -- the bottom line is a lot
more one of agreement than disagreement, I think.
MR. MURPHY: Just an observation before proceeding. I'm
going to try not to be real repetitive on what Mr. Reily had presented
in the previous hour. But the SG tubes are unique among the ASME class
of components in that in-service inspection and repair requirements are,
to a great extent, governed by the tech specs rather than the ASME code.
I think earlier editions of the ASME code had a much more
complete treatment of the in-service inspection issues and repair of SG
tubes than the current issues do, and I think that the -- it was in
response to the early problems experienced with SG tubing in the >70s
that led the staff to believe that we needed a way to have a set of
requirements that would be more timely implemented to help out with the
problems that were being experienced, and that's why we transfer a lot
of these requirements to the tech specs.
DR. SHACK: The difficulty of changing a tech spec is not
trivial, but changing the code is really --
DR. SEALE: The problem is more plant-specific. That's what
it really says.
MR. MURPHY: It also says something about the times, as
well. I mean, we found it easier in the >70s to install what we called
the time of augmented SG requirements in tech specs. We were able to do
that in a very timely fashion as compared to working with code.
So an issue for us then is that assuming the technical
issues pertaining to the NEI 97-06 can be resolved, what sort of
regulatory framework is appropriate.
Now, this next viewgraph is a bit dated. In the fall of
'98, the initial industry thinking on this particular subject was that
perhaps that many of the tech spec requirements dealing with steam
generator tube integrity, particularly those dealing with tube
inspections and tube repairs, could be eliminated from the tech specs.
SG programs would be developed consistent with the industry
guidelines and incorporated into licensee controlled documents, such as
the FSAR procedures. I think as Mr. Reily noted, we seem to be working
in the same direction, that perhaps some tech specs may be appropriate.
Industry had -- even back then, though, there was
acknowledgment of the need to submit first-of-a-kind ARCs and to prepare
methodologies for NRC review and approval.
Two observations about the implications of the leading
existing tech spec requirements and not putting in anything that would
-- to accompany the industry initiative. What we noted about that is
that existing code, the existing code is not in a condition right at the
present time, Section 11, to pick up the slack. The ASME code
requirements in Section 11 have big gaps in terms of what appropriate
tube surveillances should be, tube plugging limits and repair methods.
These would need to be substantially upgraded and included
-- that's not something that is likely to happen in a relatively short
period of time.
Also, we think we would essentially, in effect, be
eliminating the traditional deterministic safety factors as part of the
licensing basis and that if one is relying solely on an industry
program, that is, licensee controlled documents, safety factors that
they're maintaining the plant to can be modified under a 50.59 process.
So we think that this option of eliminating current requirements in the
tech specs does nothing to better focus regulatory requirements or
enforcement for maintaining tube integrity. In fact, it would seem to
me to be a big step backward.
So we think, and I think the industry agrees to a certain
extent, at this point, that we need to be taking a look at what sort of
tech specs are appropriate.
MR. REILY: Emmett, clarify. When you made that last
statement, were you still referring back to the earlier position that
the tech specs were going to go away and the FSAR was going to carry all
the requirements?
DR. SHACK: Could you come up to the table so we can get
this on the record?
MR. REILY: I'm sorry. This is Jim Reily. Just a
clarification on that last statement. Were you, by saying that you felt
that we were taking a big step backward, referring to the previous
position --
MR. MURPHY: Yes.
MR. REILY: -- to not --
MR. MURPHY: I thought you -- I liked your presentation
today very much. I was not referring to where we are, but this was a
option that had been discussed and put on the table last fall.
MR. REILY: You're still referring to the earlier
discussion.
MR. MURPHY: Yes. So we think we'll need tech specs to
accompany whatever initiative is finally agreed to. One possible
approach; not necessarily the only approach, but one possible approach
would be to replace existing tech spec tube surveillance and repair
requirements with something like the following; namely, licensees shall
implement a program to ensure that the following performance criteria
are met.
These would be your default performance criteria that we
discussed this morning and Jim Reily discussed this morning. One might
propose different criteria, to the extent that risk issues are
appropriately dealt with.
The tech specs would state that such a program would include
-- should include condition monitoring assessment with respect to the
performance criteria and that corrective actions, of course, should be
implemented if the criteria are not met. The tech specs would need to
address plugging limits and repair methods, and include reporting
requirements.
We believe that this kind of approach is consistent with 10
CFR 50.36 in terms of performance-based approach and the performance
criteria that relate to the functional -- ensuring the functional
capability of the tubing to accomplish its safety function.
We think the tech specs of the sort that we just described
would certainly better focus regulatory requirements and enforcement on
maintaining tube integrity rather than how to get there.
It would also allow the staff to ensure that risk issues
associated with new ARCs, repair methods and alternate performance
criteria are evaluated.
DR. KRESS: How does it do that, give you that assurance?
MR. MURPHY: Well, exactly how we write up or exactly how
the tech specs treat ARCs, repair methods, even performance criteria, I
think those details need to be worked out. For example, if these
criteria are explicitly stated in the tech specs, then if one wants to
implement something different, one must amend the tech specs, and, of
course, we're involved in that process.
However, that kind of process has the disadvantage of -- it
reduces -- it greatly reduces licensee flexibility and we're also trying
to develop an approach here that enhances, as much as possible, their
flexibility.
And so we are engaged in a bit of creative thinking here in
terms of how we might construct these tech specs, such as to ensure that
new repair limit or new repair methodologies, ensuring that we're in the
loop in terms of review and approval when these things are first
developed, but once these things have been looked at on a first time
basis, you might say that it should not be necessary for others to amend
their tech specs, if they wish to implement some other criterion within
the context of the applicability of the staff's approval of the initial
submittal.
And we have been actively talking with OGC about how to do
this and it's not straightforward. There's a lot of hand-wringing, but
it's something -- OGC is working with us on this and the idea -- so the
objective is to build as much flexibility into this tech specs as can be
done, while still ensuring that the staff would be involved in the
review and approval mode on first time applications of ARCs, repair
methods, and that possibly, possibly performance criteria themselves.
So the wording of a tech spec or a proposed tech spec
doesn't exist yet. There's a big legal component to how those words
should look. But it is something that we're actually looking at and
working very hard on.
DR. KRESS: But the idea is probably that if you put wording
in the tech specs that says we're changing the alternative repair
criteria or the repair methods, that they have to come to you for review
and approval, and that almost always eliminates 50.59, because if it's
in the tech specs, it's a violation of 50.59.
If you don't put that in there, then how are you going to
know -- how are you going to tell them to come to you the first time
anyway?
MR. MURPHY: That's exactly right.
DR. KRESS: That's the problem.
MR. MURPHY: That's right.
DR. KRESS: So you're going to have to be creative on how
you work that.
MR. MURPHY: One easy way one might write this is to say one
may implement ARCs that have been reviewed and approved by NRC.
DR. KRESS: That would be a creative way. That might work.
That might work.
MR. MURPHY: Exactly how we're going to deal with this is
something that we are working actively with OGC on to make it acceptable
to them and we at the technical staff here at the NRC and the industry.
DR. SHACK: What's wrong that? Sounds like a simple answer
to me.
DR. KRESS: That sounds like a good idea to me.
MR. MURPHY: Our lawyers balked at that.
MR. REED: And we're inclined to write into the tech spec a
little more explicitly the change process, exactly what you've got to do
and what you have to document and that kind of thing, to make sure that
it's addressed.
DR. SEALE: Why did I have this feeling that that would be
the case?
DR. SHACK: That's reasonable enough. I think industry
would still like it if they can get the flexibility.
MR. REED: I think the legal weasel words, if you will, in
there, you can get the flexibility -- they'll implement approved repair
methods and approved performance criteria.
DR. SEALE: That's the real advantage right there.
MR. MURPHY: Yes, in the middle of the page.
DR. SEALE: No, no. The bottom one. A new idea is not dead
on arrival because it's not covered in the process that's available to
get the approval. That's the real threat.
MR. MURPHY: I'm sorry.
DR. SEALE: A new idea is not dead on arrival because it
defies the process available to get approval. You see what I'm saying?
This allows you to have other ways of doing it and have a process for
you to review it and approve it and so on.
MR. MURPHY: Yes.
DR. SEALE: And that's the biggest -- that's the most
important thing, really.
MR. MURPHY: Yes. Yes.
Jim Reily noted that much of the detail of the industry
initiative is contained in sub-tier documents to the NEI guidelines.
Some of these documents, including the tube integrity assessment
guidelines, are still being finalized.
And there are a number of -- when you get down to that level
of detail, there have been a number of issues, technical issues that
have existed for years as to how one should be doing these assessments.
We're likely to continue to have certain issues in this area for years
to come.
This level of detail, of course, would be beyond the level
of detail addressed by tech specs and it would be beyond the level of
detail addressed in any NEI top tier document that would be endorsed by
NRC. But one additional benefit to being involved in the review and
approval process of criteria and processes and so forth is it allows us
to continue to interact with the industry on the -- as the tube
integrity assessment methodologies are refined and inspection
qualification issues are dealt with.
DR. SEALE: One of the tests you might want to ask yourself
is -- you've had some remarkable advances on non-destructive evaluation
technology over the last five, eight years. It seems to me you don't
want to write anything into these tech specs that would impede the
application of those advances to the resolution of your problem.
MR. MURPHY: Yes, that's correct.
DR. SEALE: That's kind of a test as to whether or not
you're building a barrier that you don't want.
MR. MURPHY: And it's a big argument for going to
performance-based as much as we can.
DR. SHACK: I was just thinking about that. I looked at
SONGS' assessment there and I looked at that POD curve they had for the
bust point. I suspect you could debate that for months on end. But if
you take the notion that the operation assessment is theirs and the
performance criteria is yours, so you don't get hung up over all those
details --
DR. SEALE: Yes.
MR. MURPHY: With regard to technical issues, in the
meetings that we've had to date, we appear to have reached a resolution
on quite a number of these issues, roughly half, as Jim has said, in
terms of issues pertaining to the top tier document.
As I just noted, we're going -- there are additional issues
that have existed for a long time, say, with respect to the EPRI tube
examination guidelines and no doubt there will be issues, technical
issues that exist relative to guidelines that haven't been finalized
yet. There are some very tough technical issues to address when one is
developing tube integrity guidelines.
How do you deal with uncertainties and how conservative do
we need to be and all this kind of stuff. But with the sort of tech
spec that we're talking about here, one that incorporates performance
criteria, and with agreement on what the top tier document should look
like, which would serve as a basis for developing industry programs, it
shouldn't really be necessary for us to -- for NRC to have to endorse
the lower tier guidelines.
The important thing is that the utilities successfully
maintain tube integrity relative to the performance criteria and that
they demonstrate this and that industry is zealous about taking the
appropriate corrective action and if they should not meet the criteria,
then NRC needs to exercise the appropriate oversight in assuring that
this is, in fact, being done.
High priority technical issues, these are issues that have
to be resolved before we can have technical agreement on what the tech
spec should look like and an addressable set of industry guidelines
should look like -- are the same ones basically that Jim Reily discussed
and I won't go through those again.
Some of these issues are closely related to how one deals
with the risk issue and Steve Long will be talking about these during
the next presentation.
I'm going to skip the next viewgraph, unless somebody wants
to discuss it, and move on then to Farley Unit 1. Farley, of course, is
a Westinghouse steam generator. I think they have 51 steam generators,
if I'm correct. This unit is going to replace their generators at the
end of the current operating cycle, which has just begun.
Right before their last refueling outage in October, they
shut down to SG leakage, which was, I think, peaked out at around 90
gpd, leakage spike.
An in situ pressure test was performed on the leaking tube
and the in situ pressure test results, in conjunction with assessment or
analysis of the eddy current data, indicated a burst pressure of
somewhere around 2,600 psi. There were a number of different numbers
floating around, but they were generally in the 2,500 to 2,800 psi
range, I believe. I'm not sure what the official number is anymore.
But this is -- steam line break pressure is 2,560 psi. If
one is trying to achieve a margin of 1.4 with respect to main steam line
break limit, you're looking for a burst pressure on the order of 3,600
and 3 delta P takes you above 4,000.
The leaking tube -- an assessment was done on the previous eddy current
examination of this tube the last time it was inspected. It was found
to have exhibited an indication of a previous refueling outage
inspection, which was missed by the analysts.
Data analysis procedures at that time then were revised,
data reanalyzed, some additional sample inspections performed during the
unscheduled outage and the tubes were plugged and the plant was
restarted and operated through its scheduled refueling outage in October
'98. During that period of time, the plant experienced minor leakage,
around 20 gallons per day.
DR. SEALE: Could I ask you, is this a plant that was doing
100 percent tube inspection in the previous outage?
MR. MURPHY: Rick Mullins I think is going to address that.
MR. MULLINS: This is Rick Mullins, from Southern Nuclear.
We've been doing 100 percent inspection for eight to ten years.
MR. MURPHY: I understand that was running 150 gallons per
day leakage.
MR. MULLINS: The tech spec limit for that unit is 140
gallons per day.
MR. MURPHY: So they didn't exceed the tech spec limit
before they shut down.
DR. FONTANA: They shut down due to the leakage, it says
here.
MR. MULLINS: Right. We got concerned when it spiked to 90
gallons per day and decided the proper thing to do was shut down.
MR. MURPHY: An in situ pressure test -- okay. During the
October refueling outage inspection, while they were doing the eddy
current inspections of the tubing, they also did some in situ pressure
testing and one of these tubes, I believe it was the leaking tube, the
one that leaked a small rate during operation, was in situ pressure
tested and failed at 3,600 psi cold.
There is some debate as to whether the failure was, in fact,
a burst or something maybe a little less than a burst. I think this is
-- the fact that these kinds of questions exist are a big part of the
reason why we need to resolve the definition of burst.
DR. SHACK: What's the current definition of burst?
MR. MURPHY: There is no -- DG-1074 has a suggested
definition.
DR. SEALE: Did it burst or did it unzip?
MR. MURPHY: I made some backup slides which included a
proposed definition of burst, but it looks like I left it behind. But
basically it's a definition that one can utilize either in analytical
space or in experimental space.
In analytical space, it would correspond to predicted
failure, at plastic collapse, particularly if they're using limit load
analysis; in experimental space, if you can't retain -- if the tube
opens up to release the bladder, it can't hold a bladder anymore, we
would consider that to be a burst.
I believe that's pretty much the differentiation that was
made between burst and non-burst of tubes in the construction of the
95-05, in the voltage-based database on burst strength.
MR. MULLINS: If I could add one thing. One of the problems
with this tube is that we could not put a bladder on that. If this tube
-- excuse me -- wrong tube. That was the August tube. I'm sorry.
MR. MURPHY: Yes, because you have the sleeve in the way.
MR. MULLINS: That's right.
DR. SEALE: We're going to need to move along here.
MR. MURPHY: All right. Again, this -- when you go back and
look at the old data on this tube, again, with the benefit of hindsight,
you could see a quick burst of signals, so this caused a further
revision of the data analysis procedures which were implemented during
the outage. The plant was restarted in December '98 and is scheduled to
operate for 15 months to the next refueling outage, in the spring of
2000, at which time they'll replace the generators.
The licensee is performing an operational assessment to
demonstrate that the SG tubes will retain adequate integrity for the
duration of the cycle. Now, of course, he did the preliminary
assessment before he started up to demonstrate that he had a little time
to do a more careful assessment or a more detailed assessment that would
look beyond the immediate future to the end of the cycle.
And were going to be taking -- I think this will be a very
-- from our standpoint, a very interesting assessment to look at. The
licensee has agreed to send this assessment next month, I April. He did
-- apparently he's completed an assessment relative to the deterministic
performance criteria and demonstrated that he can operate for ten and a
half months into the 15 months cycle, he can operate for ten and a half
months and still meet the factor of three, and it's my understanding
that you're going to propose operation for the full cycle based on an
assessment performed against the probabilistic criteria.
MR. MULLINS: We're still doing the review of the
probabilistic assessment and I won't -- depending on the results are
will determine what we come in here with. It is not finished yet.
MR. MURPHY: Okay. We had two situations, in August and
October, where tubes were found not to have the appropriate margins.
One of the problems has to do with eddy current limitations and although
corrective actions were implemented, it's very difficult to get the
probability of detection of these small amplitude signals, precursor
signals up to one. It always -- it always seemed to me you're always
going to miss some percentage.
So that needs to be folded into the operational assessment.
Also, it's quite apparent that these cracks which were
occurring at Farley are going quite -- would appear to be going quite
quickly. So there is a high growth rate issue to be also considered in
this operational assessment.
DR. FONTANA: I'm a little confused here. You pressure
tested a leaking tube and it burst at 3,600 psi.
MR. MURPHY: Yes.
DR. FONTANA: So you've got to put that tube out of service.
MR. MURPHY: Yes.
DR. FONTANA: So what does that tell you relative to the --
presumably it tells you something relative to the other tubes. If
you've got a flaw of a certain size, is that a potential failure?
MR. MURPHY: This is a tube and the other tube had failed a
couple months earlier. This is a tube which, at the previous
inspection, had exhibited very, very minor signals and, of course, at
this outage in October, you have other tubes now that are exhibiting
very small signals, many of which you're detecting, some of which
perhaps you're not.
And you have two tubes that had evolved from having very
minor indications to being tubes that didn't have adequate strength in
less than operating cycle.
DR. FONTANA: So what do you do about the other tubes, then,
the ones that now show this kind of fault?
MR. MURPHY: The question -- I think the issue that comes --
that these test results raise is how do we know that more tubes won't
degrade to the point where they don't meet 3 delta P before the end of
the next cycle.
DR. FONTANA: Well, you don't and part of the problem is
3,600 is only ten percent less than 4,000. If you had a big -- a large
number of samples, you could do a probability distribution and you could
say, well, gee, that's just the end of a tail and that's not really
representative of the others, but you don't. You don't have a big
sample.
MR. MURPHY: It's not only that, but we are worried about
the worst tube. It's always the worst tube is the one that's going to
rupture. So you are trying to predict the behavior of the worst tube.
DR. FONTANA: But you have to make a decision with respect
to the tubes that are still out there that shows these kind of flaws and
that will be able to withstand the three times delta P over the next
cycle.
DR. SEALE: Your second bullet says that the data analysis
procedures were further revised. Is there a third bullet which is
between the lines there that would have said on the basis of that, X
additional tubes were plugged?
MR. MURPHY: Yes.
MR. MULLINS: Yes, sir. Everything we detected, we plugged.
MR. MURPHY: I think the -- it's one thing to be developing
a new program for the industry, an issue that talks about a new program
strategy that's performance-based and taking corrective actions as
necessary to achieve the goals.
NRC, we're thinking along the same lines and the licensee is
doing an operational assessment, but I think part of whether this is
truly going to enhance tube integrity performance is going to depend
upon the commitment on the part of the industry to --
DR. SEALE: Clearly this is not what you would normally do
in the sense that you've already made the commitment to retire this
steam generator at the next cycle. So now the question is if you plug
all of those tubes that are showing a problem, do you still have enough
steam generator to get the performance you want out of the plant.
If you do, it's almost a non-brainer, although you don't
want to commit yourself to plugging criteria that are so conservative
that you may influence what happens down the road.
MR. MURPHY: I don't think that was the issue. I don't
think there was an issue as to which tubes with indications they were
going to plug. I think the issue is really twofold, very small
amplitude signals are difficult to detect. You may not detecting every
one.
The second thing is the high growth rates we appear to have
with this phenomena and the effectiveness of the new regulatory approach
that the industry and the staff are exploring here is to lead to a large
measure a function of the commitment on the part of utilities to be
trying to ensure that their program is adequate to ensure those
performance criteria are met.
Staff has as responsibility in this area, too. We should be
expecting utility performance -- or industry performance relative to the
performance criteria to be good.
DR. SEALE: I would imagine that the guys in research, if
they don't run out of money completely, are pretty hot to get a hold of
some of these tubes to do some assessments after they become available.
MR. MURPHY: The second unit --
DR. SEALE: You don't have to comment on that, though.
MR. MURPHY: The second unit is Arkansas Nuclear 1, Unit 1
-- Unit 2, I guess that's correct. It's Unit 2. That's incorrect.
It's a combustion generator. In situ pressure tests during
the scheduled refueling outage in January '99 caused a tube burst at
3,900 psi cold. Again, this is less than the 3 delta P criteria.
The tube had exhibited an indication, at a previous
mid-cycle inspection, that as dispositioned as NDD by the analysts, one
analyst had called it, I believe, another analyst had not called it.
The resolution was no indication.
Data analysis procedures were revised. Licensee plans to
perform a mid-cycle inspection. He's been in a mid-cycle inspection
mode for the past several cycles because, unfortunately, I think this is
the fourth incident since 1992 where tubes are believed not to have met
the performance criteria.
The licensee is in the process now of performing an operational
assessment to demonstrate that he can meet the period of operation for
the mid-cycle inspection. The licensee is performing this assessment
relative to the 3 delta P criterion. This licensee also plans to
replace his generators in the next scheduled refueling outage
inspection, which is in the year 2000.
The licensee is doing operational assessments. He's doing
them relative to performance criteria. He sees that the tubes that are
failing to meet the criteria, indications were missed, and so he tries
to figure out why they were missed and revises the procedures. But this
is not the first time. This has been a repetitive thing through the
years.
So I think that this raised -- you know, one -- one -- I
think this illustrates a situation that we're trying to improve upon
and, again, this is -- and this is going to take commitment on the part
of the utilities and I think NRC -- an issue for the NRC is what kind of
-- how much oversight involvement do we want to take, where is that
threshold.
DR. SEALE: It seems to me that these two events and the
ultimate disposition of them and so on might be something that maybe
we'd be interested in hearing about in more detail on down the road.
Emmett, I'm going to have to tell you, we're going to have
to move along pretty quick. I'd like for you to show us your slides,
but let's move through them.
DR. SHACK: Let me ask a question. You sort of indicated,
at Farley, that the problem seemed to be that the growth rates were
unexpectedly high. At Arkansas, are they just missing indications or is
this, again, you can attribute it to an unexpectedly high growth rate?
MR. MURPHY: I think it's a combination.
DR. KRESS: Regardless of whether you're using a
probabilistic analysis or a deterministic analysis, that would be a
problem in either one of them, because you have to use a growth rate.
DR. SEALE: Right.
DR. KRESS: It just means there is something wrong with that
growth rate.
MR. MURPHY: I'm going to finish up quickly here. Standards
on Generic Letter 97-05 inspection methods. Its intention was to ensure
that qualified NDE was being used for depth sizing. We have reviewed
almost all of the licensee responses at this point and issued our
findings to the utilities and, in general, we find that, in fact,
licensees are inspecting the tubing, the sizing indications using
techniques called for by the EPRI guidelines.
With respect to cracking, what this means is that people
typically are plugging on detection. Pitting and cold leg fitting are
generally the only corrosion related flaws that industry is implementing
or relying on depth measurements in comparing the 40 percent plugging
limit for determining how they're going to disposition the tube.
Finally, Generic Letter 1106, which dealt with degradation
of SG internals, that GL was issued in response to reported damage at
foreign and domestic units. Most of this experience was foreign
related, which involved erosion of the carbon steel egg crate and
drilled hole support plates, cracking of drilled hole support plates,
and failed wrapper welds at one foreign unit, leading to a drop of the
steam generator wrapper and wrapper cracking.
The status review of the licensee and owners group responses
indicates that erosion of carbon steel drilled and broached hole tube
support plates is not an issue due to their robust design; namely, these
kind of plates are very thick and not susceptible to -- by virtue of
their thickness, not susceptible to the significant degradation like the
egg crate supports.
The erosion of the carbon steel egg crates is possible and
has been observed and the CE owners group has recommended inspections
for these types of support plates which would be implemented depending
upon circumstances.
DR. SHACK: And you literally mean erosion here, I mean,
velocity and flow that pass this thing plays a role in corrosion of the
support plate.
MR. MURPHY: Yes.
DR. SHACK: What are these velocities?
MR. MURPHY: I don't have that number offhand. Cracking of
carbon steel drilled support plates has been identified through eddy
current inspections. These kinds of problems are believed to have
occurred either during the initial application of the generators or
during the first operating cycle and do not appear to be active
mechanisms.
Finally, our review of the owners group reports indicates
that the wrapper damage is not an issue for our domestic SGs due to
design differences relative to the foreign unit that experienced the
problem in this regard.
The more robust, well designed, and coupled with larger
tolerances for thermal expansion, such that we didn't lock up the top of
the wrapper against the shell and place unanticipated thermal stresses
on these welds.
So we expect to be closing out this GL by the end of this
fiscal year. We expect that we'll be -- you know, we're heading in the
direction of concluding that licensee programs are adequate to ensure
that the internals at domestic units are adequately maintained.
DR. KRESS: Is Checkworks used anywhere here to predict
erosion?
MR. MURPHY: I don't think so. I don't think so.
DR. KRESS: I didn't think it was.
DR. SEALE: Any questions for Emmett? We've beat you to
death, I guess, pretty much. Emmett, thank you very much. It's been
very helpful.
Steve, I guess you're in the barrel.
MR. LONG: Have we dispensed with microphones today?
DR. KRESS: We've got them.
MR. LONG: I mean in terms of something I wear.
DR. KRESS: You don't need to wear one. We'll pick you up
right here.
MR. LONG: Actually, I think you've all been distributed
copies of slides that are virtually identical to these. So this is more
a matter of going through and discussing them and I can be as brief or
as long as you'd like to be.
DR. SEALE: Well, why don't you move along and if we have a
problem, you know us, we're not bashful.
MR. LONG: I'll try not to read the slides to you, but I
just came from another presentation and I'm going to need them to remind
me of what I intended to say at this presentation. First of all, I want
to talk about the cover page.
We're talking about when and why they consider risk
associated with steam generator tube degradation and relaxation of
requirements on structural -- on tube structural integrity. It doesn't
say how. The genesis of this white paper that I'm discussing today is
meetings with industry, where industry has been asking for some guidance
on use of risk assessments in trying to modify the tube requirements.
When we -- we try to do that. I've written several pieces
of guidance and the problem with getting them out the door is not so
much the how, which I think we've documented some work on NUREG-1570 and
EPRI had done some work which we have looked at and BG&E has carried
that work along further, and we think we got a fairly good handle on the
how.
But when we tried to write it down and move it, we seem
internally to have a lot of problems with the when and why are we doing
this.
So the white paper is really, at this point, a decision
focused in full within the staffs. It's moving up through the staff to
try to get everybody to understand at least the basic principals and
come to an agreement on and when and why.
You don't have a copy of the draft white paper at this point
because we didn't get it far enough up the concurrence chain to get it
over to you. So that's still a process that's ongoing to get this
consensus.
I will stick, therefore, mostly to the technical part of it
today. First of all, because this is an explanation, what I've done is
just tried to very much condense what's in the white paper with only
slides, and some of this is going to be preaching to the choir, I
suppose.
We're pointing out that the steam generator tubes are
important because they're really two of the three physical barriers
between the fission products and the public. We're also pointing out
that the design basis requirements on those different barriers are
really different per barrier.
In other words, the requirements on the RCS boundary on the
fuel clad and on the containment are not identical in each case. As a
matter of fact, when you get to the containment, you're really putting
up a design basis that assumes you failed to meet the design basis of
the first two barriers.
So when we talk about design basis issues, that often gets
confused and we try to explain that to some degree in the white paper.
We also are pointing out that the existing requirements, as
they are now imposed, really all the way down to the tech spec level, we
believe are adequately controlling the risk. So we're really talking
about changing the things that we now think are controlling risk.
DR. KRESS: When you say two of the three barriers, you're
talking about the RCS and containment.
MR. LONG: The RCS pressure boundary and the containment,
yes. There's a table on the next slide that tries to summarize which
requirements give us control of risk in some way. We can refer back to
this from time to time as we go through, but the --
DR. KRESS: Before you go on, Steve, can you go back to the
previous slide just a second? Is that bottom bullet -- there are no
bullets there, but the bottom one, is that an expression of faith or do
you know this from some assessment?
MR. LONG: The assessments we've tried to do -- I think the
most complete one we've done so far is in NUREG-1570.
DR. KRESS: The first thing I will ask you is what did you
mean by adequate, how did you define adequate protection for this
bullet?
MR. LONG: Okay. Quantitatively, as best we could. The
most direct answer to your question is we tried to bring together all of
the accident sequences that we thought would be --
DR. KRESS: Would be relevant
MR. LONG: -- affected by cracked tubes. And then addressed
the level of containment bypass we thought would occur due to those
cracks. We did this in NUREG-1570 and we did it for a condition that
was anticipated to be somewhat worse than the condition that we now
think we have; that is, we were looking at a proposal from industry to
allow a certain level of probability for rupture of steam generator
tubes given a main steam line break type transient and trying to infer
how they would behave in all the other transients quantitatively, given
the quantification for that one transient.
We think that that level of degradation was somewhat worse
than is really occurring right now in most of the plants, at least if
they're successful in meeting the plugging requirements at the end of
cycle.
DR. KRESS: But your -- what criteria are you saying you're
trying to meet, though?
MR. LONG: Numerically, when we did this, we came up with,
for a Surry-like plant design that had not replaced generators, so it
had a level of degradation near what was proposed. We came up with a
conditional -- we came up with a large early release frequency, maybe
it's not quite the right definition, so maybe we should call it a
containment bypass frequency given the timing issue.
It looked like it was about one-times-ten-to-the-minus-five
per reactor year. Now, that's something I can't generalize very far
from one plant with one set of numbers on it, but it gave us some faith
that what we're doing now should probably keep most of the plants in a
range that we would consider to be consistent with Reg Guide 1.174
criteria, for instance, for total LERF.
DR. KRESS: Now, in doing that, I see what you're doing and
I agree with you, did you ask yourself any questions about
defense-in-depth associated with those?
MR. LONG: We'll get to those. Yes, we did. Matter of
fact, that's going to be in a few slides here.
DR. KRESS: Okay. Thank you. Go ahead.
MR. LONG: The intent here is really to point out that
there's a couple of things that are really helpful in limiting risk, but
in an indirect way, and there are a couple of things that really aren't
that helpful, even in an indirect way.
In the structural integrity area, the requirement to have a
strength that will handle three times the normal operating delta
pressure at normal operating temperatures or usually that's dominant
over the 1.4 four times the DBA pressure differential at normal
operating temperatures, does have a fair amount of benefit when you get
into the severe accident cases and you start asking what will happen if
I have some pressure differential that may be like the DBA pressure
differential or may be less than that, but the temperatures are a lot
higher.
There's actually not any margin at that point if you meet
the margin requirements for normal temperatures. But because you're
trying not to get past that margin, the net effect is you're really
decreasing the probability of having a flaw that that's weak if you do
have an accident. So the target is helpful.
Similarly, we've now talked about an accident leakage, and
I'll get a little bit more into the genesis of that, but I think you all
already know it. The accident -- the design basis accidents have an
input value of one gpm for assumed leak rate in an accident being the
maximum leak rate that we thought we would allow during an operational
condition and there was no real thought that that leak rate might
increase due to the accident back when the design basis analyses were
developed.
So the idea that if there isn't any leakage, it will be
pretty low, and the idea that there really shouldn't be any leakage,
because if we can find a flaw, it shouldn't be more than 40 percent
through wall, according to the plugging requirements in most tech specs,
helps a lot with regard to how much leakage of highly radioactive
material might escape the RCS into the environment if you really do have
a severe core damage accident.
DR. KRESS: You really mean that and that, you have to have
both of these things.
MR. LONG: Not really. I think if you only have one gpm
leakage, and we'll get to whether one gpm will stay one gpm during an
accident.
DR. KRESS: That's what I was getting at.
MR. LONG: But if you really set accident leakage as one
gpm, that helps a lot in reducing the amount of effect on the public.
DR. KRESS: But you're really counting on the 40 percent
through-wall criteria there.
MR. LONG: Again, we'll get into some slides and we'll get
into this much more deeply.
DR. KRESS: Okay.
MR. LONG: The other main point of the slide, though, is as
far as operational leakage is concerned, we've actually lowered it as
we've gone through upgrading tech specs. But it really doesn't tell you
much about what will happen during the accident. If you are operating
low leakage or 20 gallons per day leakage, that's not telling you if
crack-like flaws in the tubes will continue to leak at approximately
that rate if you change the pressure differential or increase the
temperature or if some flaw will fail and actually burst or give you a
lot larger leakage.
So you've heard the DPO issues that Joe Hopenfeld has been
before you on a couple of times and this is related to that. You do get
a little benefit from the operational leakage in the sense that if there
is any leak before break benefit, this is capitalizing on that and
finding things that might be incipient failures because they reveal
themselves by leakage. But there is no real guarantee that a large
fraction of leakers will reveal themselves that way in normal operation.
The other one is the containment design basis accident right
now that we compare to Part 100 dose guidelines. If that's separated
from all the other calculations and you just look at the way you would
calculate dose and assume that the one gpm isn't an input, but that
instead it is a variable that can be derived from the design basis
analyses, the other flexible variable is the amount of iodine
concentration you allow during normal reactor operation to be your
coolant.
And if you force that down, you can allow the leakage rate
from primary to secondary to go up and still meet your Part 100 dose
requirements for this very specific steam line break accident.
DR. KRESS: The source term of this accident is the level of
iodine already in the coolant.
MR. LONG: Spiking factor. There is a potential that if you
do the analysis, you'll depart from boiling on the fuel and have to take
some penalty in source term by adding some sort of fuel clad damage and
gap release, but typically they can avoid that in the calculation, so
it's just a matter of showing off the normal iodine concentration.
And the difficulty with that is you can let -- if you --
there is the ability to push the normal iodine concentration limit up
that you can, in fact, get very large leak rates that will still meet
that particular dose calculation as long as the source term is only a
very low concentration of iodine compared to what you'd have if the fuel
was really severely damaged.
DR. KRESS: Part of that calculation involves the fact that
the iodine is in the water and it has to partition in the gas space
before it goes to Part 100 dose.
MR. LONG: There is some partitioning in that, but I'm not
sure that buys you the biggest factor there. The biggest deal is that
you pretty much have --
DR. KRESS: I would agree that this is a low efficacy and
minimum risk. I think I would agree with that.
MR. LONG: That was my only point.
DR. SHACK: What makes it an operational leakage, though?
I'm not sure that that's -- it may not be limiting in the sense that
you've got the 3 delta P, that may be a more limiting criteria, but I'm
not sure that it's -- that does tell me the population or the size of
through-wall cracks that I have. I can either have one crack of about
half an inch or I can have X cracks at a quarter of an inch, but it
certainly does limit the flaw population to --
MR. LONG: You could have a three inch long crack that was
-- what is it -- 89 percent through-wall and it wouldn't leak at all,
but it would burst if you increased the delta P.
DR. SHACK: How is that different? Oh, the 40 percent
through-wall is what saves you.
MR. LONG: Right.
DR. SHACK: So any leak criterion is always subject to that,
that you can have these cracks that are just about to go and you'll
never know.
MR. LONG: Yes. So I'm saying there is some benefit,
because we have seen leakers that they've shut down and plugged that
probably would not have withstood a main steam line break, much less a
severe accident.
DR. SHACK: So it's really not cracks that leak at this
level. It's cracks that don't leak at this level under normal delta P
could pop.
MR. LONG: Right. But the real point is what you're trying
to do is protect yourself by lowering the operational leakage. There is
only so much benefit you can get there. There is still a population of
flaws you don't address with operational leakage.
The proposed modification, I think it's NEI and others.
Maybe it should have said industry.
But there's a couple of types of things that have been
proposed here. One is to replace the 40 percent through-wall criterion
with a criterion that would somehow allow through-wall cracks to remain
in service. An example of that, which we have approved, is the ODSEC
under the tube support plates and the reason for the approval there is
that the support plates are credited for constraining its burst and also
for reduction of the actual leak rate.
But to carry that approval into the free span brings up a
lot of issues that you can't count on getting the additional support
from that drilled hole support plate or down on the tube sheet. We've
also made the same kind of relaxation.
The other type of relaxation that's associated is to
increase the accident leakage, as we just discussed, and base that
allowable increase only on the main steam line break design basis
accident, with reduction of the iodine concentration being at the
discretion of the plant owner, the operator.
There's a program called the flex program that I think
you've heard about before that's been proposed where they would not have
to put in a tech spec amendment. They would simply get approval to do
this themselves and the difficulty is it doesn't address some of the
issues we mentioned before.
Then the final one that's been proposed is to substitute for
the SME structural margins the three times normal operation pressure,
instead of a probability that you will burst at a lower pressure and the
probability proposed was five percent.
So each of these, as we just discussed, doesn't address some
of the risk issues, some of the risk sequences that we found there would
be important contributors when we tabulated where risk came from.
Now, to get into the leakage issue a little more fully, I think I've
mainly said this. Let's just make sure there aren't any big questions
on it. Here is the defense-in-depth issue for you.
The one gpm wasn't a derived parameter initially. It was a
given parameter and my understanding is it was essentially something
that had to be above zero because people aren't perfect, they aren't
going to make something that clearly will never leak. But it had to be
detectable, so that once it did leak, you had to be able to go in and
find it and fix it.
So a nominal number 20-30 years ago was one gpm and it's
been used pretty much ever since, although it's been split among
generators over years and recently we've actually reduced operational
leakage. But most DBA calcs are nominally around one gpm leakage.
If we tried to risk inform that number, there's some
additional work that could be done and really is ongoing in research
right now, because we requested that they do this. What we're trying to
do is ask if the leak rate is, from primary to secondary during severe
accidents is X gpm, please define the consequences to the public as far
as potential for acute fatalities, potential cancers at different
ranges, doses, a variety of different measures of risk, as a function of
this leakage rate from the primary to the secondary system.
And make it very realistic. Take into account the fact that
the pressure will go down between the primary and secondary when the RCS
fails inside containment and see if we can find enough information about
that to risk-inform what this leak rate ought to be.
There may be some change we ought to make there and maybe it
will benefit the industry if we try to be risk-informed. So that's in
progress.
That's really the defense-in-depth issue, because we're
really asking at what point do you start negating the performance of the
containment and some of the holes you would produce under the main steam
line break analysis as being acceptable, even after you have
depressurized the RCS into containment, the hole that's assumed in the
containment that will meet tech spec requirements is smaller than the
hole that's in the tube and you would still get more leakage from the
tube than from the containment.
So we need to make sure we understand both paths and how
primary and secondary leakage really affects the public.
DR. KRESS: Doesn't this get convoluted with the frequency
of your steam generator tube rupture accidents, so that it would be
plant-specific?
MR. LONG: At this point, we're really asking a
defense-in-depth question. We tried to back it away from a frequency.
We will be looking at the frequency in terms of risk as well, but --
DR. KRESS: I was thinking about your point about when does
it compromise the containment. It would be a compromise based on that
frequency, I would think.
MR. LONG: No, not really. I guess what I'm trying to draw
a distinction between here is that to do a risk assessment, I'm trying
to get to the bottom line in consequences and say am I comfortable with
the combination of frequency and effects on the public, no matter how I
got there, whether I'm getting the frequency of affecting the public
down by a low frequency of reaching each of the barriers and they stack
up together to give you a very low frequency, or if I have a pretty high
frequency for two barriers and then I'm counting on a real low frequency
for only one, it comes out the same in a risk assessment.
The defense-in-depth is another look at it that says am I
really counting on only one barrier or am I counting on several. What
I'm really trying to do with this analysis is look at when I start
increasing the effect on the public enough that it matters I the sense
that I'm really starting to lose that last barrier of the containment.
So I'm just looking for a shape in the response curve to the leakage and
trying to see if there is any benefit to a decision-making process from
that knowledge.
We're not going to disregard risk here, but we're trying to
address the other part, which I call defense-in-depth.
Okay. There is one more leakage issue that you heard about
before, and that is if we can decide that a certain amount of leakage
from primary to secondary, let's just say it's five gpm, as an example
to talk about, would not really be an unacceptable level of degradation
for this final containment barrier.
The next question comes, what will that leak rate really be
during the accident. If you have a crack that, because of the delta P
and the softening of a tail maybe at high temperature, will open up and
in itself, one crack give you give gpm, would that flow rate through
that crack be so high that you would actually start eroding open the
crack during the accident, would it create a jet of hot gas that would
shoot across the gap to the next tube and actually cut open the next
tube during the accident.
It's fairly short time periods during the accident. We're
not very comfortable with what the cutting rates are. So this is a
question more than a statement of an issue or a known problem.
But we need to get some information on that in order to make
sure that we really can just talk about the total leak rate and not have
to talk about the maximum leakage through an individual flaw. We really
don't know where we are on that right now.
But that issue has been discussed with you all before more
than once. I believe the staff has said to you that we do not intend to
increase the leakage limits from free span leakers until we're capable
of addressing those.
That's pretty much all I want to say about leakage. Ready
to go to burst. The industry proposal to replace the ASME structural
integrity requirements with a probabilistic requirement that really is a
twofold issue. One of them is probabilistic and that seems to be the
thing that people keep talking about. That's not really our problem,
though.
If we were going to talk about the probability of meeting
the ASME code requirements as opposed to the main steam line break
pressure, then we pretty much have to talk probability, because we're
doing eddy current testing, we're getting an indirect measure of the
size of the flaws. You have to interpret those probabilistically.

Our issue is not the probabilistic part of that. Our issue
is that we're talking now about decreasing the pressure at which we're
setting our standard for not failing and that standard would go from
somewhere around 4,000 psi down to nominally 25 to 2,600 psi, quite a
proposal, and at the lower pressure, based on what was done in
NUREG-0844, the proposal was about a five percent failure rate.
And it was that, in fact, that we put into the NUREG-1570
calculation, that's the best we could do it, to see what the total
effect would be. And the total effect was that looked like about as far
as you'd want to go. But we also found it was extremely sensitive to a
lot of things, including it was very plant-specific.
So we really found that the ASME code requirements for 3
delta P were just about at the zero margin for being able to handle a
severe accident. If you met the ASME code, for some plants, severe
accidents would quite frequently fail to flaw anyway, if it was just at
the ASME limit.
For other plants, it looked like you would be able to
survive some or maybe nearly all of the steam generator, out of the
severe accidents, if the steam generator had a flaw rated in the ASME
code requirements.
It's very plant specific. We think you can analyze it in a
plant-specific way, but you've heard the discussions about whether or
not the thermal hydraulics should really be done this way or that way.
It's open for debate and because you're right on the cusp, the best
thing we can say is we think we're getting some benefit by trying to
meet that standard, but it's no guarantee.
But we feel if we're going to entertain relaxations like
that, we really need to go through and understand the plant-specific
situation.
I mentioned at the beginning that we feel that risk
assessments are feasible, but they're pretty onerous. It's not the
staff's intent to require licensees to just start performing risk
assessments. What they're trying to do is continue to plug on detection
or otherwise repair tubes with the best technology that they can expect
to realistically use in normal commercial operations.
We also point out in the white paper that we think risk
assessments have limits. We think they're useful for demonstrating when
something is really clearly safe enough. We think they're useful for
demonstrating when something is pretty clearly not safe enough. But
they have a very large uncertainty and there is quite a gap between
being able to make one of those demonstrations and being able to make
the other one.
We don't feel that risk assessments are very good for
defining a very precise level for regulatory purposes to say you can go
this far and not this far, whether it be in strength or time or
whatever.
We do then they're very useful in showing what parameters
the risk is very sensitive to and we try to capitalize upon that for
this particular set of commercial issues, but reducing or changing the
requirements on tubes.
What we think we really need to do is set some sort of a
deterministic requirement. The ASME code is one. There may be others
that we choose to change to. And then be able to show that that
requirement does fairly clearly put you in a safe area, and that's where
we think we are today with the existing requirements.
Then we can allow that -- we can allow commercial operations
to sometimes get past the requirement and not quite meet it and the key
to controlling risk under those circumstances is to make sure you detect
those situations and you correct them. You don't stay in that situation
and you don't repetitively enter that situation.
We think that that's usually possible today, although I
think Emmett has been telling you where that was difficult in a couple
of cases just before I got up.
DR. KRESS: I like the phrase on the end of that, and limit
the amount of time the plant fails to meet these margins. Have some
criteria on that.
MR. LONG: As I said, I can't, with a risk assessment, tell
you if it's a third of the year you're fine and if it's half a year
you're not fine. Risk assessments are just not that good.
DR. KRESS: I gather that's going to be an issue, because
people are wanting to operate suspect steam generators for a limited
amount of time till they get to the point where they're going to replace
the whole steam generator. And you have to make a judgement as to
whether that time is appropriate or not.
I don't know how you're going to make that without relying
on a risk -- I mean, that has to be a risk assessment issue.
MR. LONG: We can certainly give you risk insights that are
related to the decision, but I don't think you can really be risk-based
in the decision and say solely that we calculated the number and if
Farley is going to have a crack that is susceptible to rupture under a
severe accident that starts in August, that's too soon, but if it starts
in September, it's not too soon.
First of all, we can't predict their growth rates that well,
neither can they. Secondly, even if we knew the growth rates that well,
we don't know the rest of the thermal hydraulics and the other things
going into the risk equation well enough to be that precise.
DR. KRESS: So pretty uncertain calculations.
DR. FONTANA: The alternative is to fall back on totally
conservative decisions, isn't it?
MR. LONG: Well, I think there is some judgment in here and
as you look at the level of degradation, and this isn't on the slides,
but if you think about some measure of strength, and the one that
technically works is the stress magnification factor, the size of your
flaw, its depth and its length is increasing, and, therefore, the
susceptibility of the failure is increasing.
The first thing that's going to happen is it will get down
near the ASME code limits, at which point it will be susceptible to core
damage accidents that occur not because of the flaw failure, but because
of some other reason like station blackout. The frequency will either
challenge that flaw in the ten-to-the-minus-fifth per reactor range, we
think. Maybe lower, but around there.
You might be able to argue you can take the year of exposure
to that if you're pretty sure that the fix at the end is they're going
to replace the steam generators. It's not going to be there the next
year.
On the other hand, if their argument is, well, we might be
there and if we are there, we're going to do something that may not
really be very effective and then try to run for the next cycle and the
next cycle and the next cycle.
The support of it is how often are you really going to
terminate the condition. Another one is how big could a degradation be,
if you start getting down to where you think you're going to rupture the
tube in normal operation or under fairly insignificant transients,
you're jacking up the risk a lot more.
DR. KRESS: You're jacking up the frequency.
MR. LONG: You're getting yourself susceptible to much more
frequent transients.
DR. KRESS: I gather from what you said that it probably
would include the absolute level of core damage frequency in your
thinking, because you talk about this ten-to-the-minus-five over a given
time period. That incorporates the core damage frequency. So you would
do some sort of a basic risk assessment based on probabilities.
MR. LONG: I think we could give some insights into it.
What I'm really saying is I don't think we can give you a single linear
measure that's -- or a threshold that if you get to here, it's too far.
DR. KRESS: For the plant that had
five-times-ten-to-the-minus-four CDF, you would look at it differently
than one that had ten-to-the-minus-six.
MR. LONG: If we believe those CDF values were realistic,
yes.
DR. KRESS: You always have to assess the numbers, to some
extent.
MR. LONG: To try to assess two of them, they might be ready
to replace generators by the time we got finished with the first one,
I'm afraid.
DR. KRESS: That may be the problem right there. If they're
going to replace it at the end of the next cycle, by the time they got
there --
MR. LONG: We'd be doing somebody's IPE in sufficient depth
to understand if you can really use it quantitatively for this issue is
difficult, because most of them were not produced with a good
understanding of this issue and even when we go through NUREG-1150,
which tried to address the issue, we found that we had to make
substantial changes to the quantification in order to properly address
the effect of flaws.
DR. KRESS: That may be the real -- you'll have time to do a
true risk assessment over a period and you want to address these
particular problems.
MR. LONG: Part of it's time and part of it's that we don't
have precise inputs, even if we had the time.
What we're talking about here is trying to set some sort of
deterministic criteria that you can measure performance against and if
you fail to meet them a little bit, you're not a very severe risk to the
public at that condition. Now, if you fail to meet them by a huge
margin, you may still be under risk, but you're setting the criteria
back far enough that it isn't an occasional non-repeated entry into the
non-compliance, let's call it, space that would create the risk. Then
you try to measure performance against that standard.
I think I've just said what's on the slide. One of the
problems with what we had said in DG-1074 as a proposal here for the
operability assessment for the steam generator tubes; in other words, as
you look forward to your cycle, you try to make a quantitative
statistical projection of your confidence of a high probability of not
violating this ASME standard, if that's what it is, at the end of the
cycle, and industry has explained to us, quite forcibly, that that's a
very difficult thing to do, given all the uncertainties in growth rate
and so on, that there may be plants especially that have just started to
find they're having a problem.
It may not be a severe problem yet, but the knowledge of it
is very poor, and they could not make such a showing, even though when
they got there, they would be able to demonstrate that they really
hadn't violated the requirements.
So we took another look at it. We basically talk about the
solution that I had mentioned on the previous slide. However, one of
the industry proposals that you've heard in a previous presentation was
to just back off the probability, but do the same kind of operability
assessment. They were proposing a high confidence, a 95 percent
confidence, but only 50 percent probability of not violating the ASME
code requirement.
The difficulty with that is it makes a very unwieldy
regulatory tool. If you actually tried to apply it, when you got to the
end of reactor cycles and measured where you were, you'd be meeting this
requirement if half the time you were violating the ASME standards at
the end of the cycle, because that's what you're doing. You're looking
for a 50/50 probability of meeting the ASME requirement.
Plus, there is nothing really that says how big the failure
is going to be. Your uncertainty is almost irrelevant to that
prediction. So it may be you could have a50/50 probability of meeting
the ASME requirement at the end of cycle, but you'd be real confident it
was within 100 psi of the requirement. That might not be too bad, but
on the other hand, the same process might allow you to be very confident
that you were within 2000 psi.
DR. KRESS: Let your statistician look at that, because your
height of cycles is 50/50, is a 50 percent confidence at a 50 percent
level. Your height of the fuel cycles. You won't have a height of time
at 95 percent confidence.
MR. LONG: You're really saying a 95 percent confidence that
my --
DR. KRESS: Your expected value will not be 50/50.
MR. LONG: I agree with you, but what I'm really trying to
say is it could go to that level, depending on how big that uncertainty
was, trying to bring in the idea that the uncertainty isn't addressed by
this and that it might be okay or it might not be okay.
DR. FONTANA: I don't understand this, but why require such
high confidence for just 50/50?
MR. LONG: Because it's cheap. It's just how many times you
run the computer for the Monte Carlo cycles. That's why. It sounded
good, but it's not giving you much.
DR. KRESS: If you required 100 percent confidence and this
50 percent --
MR. LONG: Then you'd drive it to --
DR. KRESS: You would drive it to a really low level. So
clearly it's not half the time.
MR. LONG: All I'm saying is that you really wouldn't be
able to say it was wrong until it was substantially more than half the
time, because you're dealing with small statistics on the interpretation
of the results.
DR. KRESS: You'd never be able to verify it, that's the
problem. The statistics aren't there.
MR. LONG: As I said, I was thinking about something else
before I got here. I'm not even sure I have these slides in the right
order.
I think we just said this. The final thought at the bottom
is what I need to add. The corrective actions that we want to see at
the end of a cycle where you fail to meet the deterministic criterion
need to consider two possible reasons that you didn't meet the
criterion. One of them is that you were not able to detect flaws at the
beginning of the cycle, that already you didn't meet the criterion, and
the other one is that the flaws all met the criterion at the beginning
of the cycle, but they're growing fast enough, so that some of them
didn't at the end.
And it may be difficult to separate those two out.
Guessing, I think that in a couple of cases we just talked about it's a
combination of the two, but because there is not a real tight
correlation between the signal strength and the flaw size, you don't
really know if, when the signals grew, the flaw was growing at the same
time or there is just some minor change in flaw strength that gave you a
stronger signal. I think you've heard all the details of how those
could come about.
So the idea is to make this work, you really need to have, I
think, a commitment from the licensees that they will come up with a way
of -- if they think they have a detection problem, trying to provide
some additional precision in the technology they use, maybe a different
technique or whatever.
If they think they really have a growth problem, then we may
need shorter cycles and at that point, you need to get back into
assuring yourself that you've developed a corrective action program, so
you're not just repetitively staying in the situation where either
you're unable to detect the flaws that can't meet the requirements and
they're there the whole cycle or they build in early and they're there
for the second half of the cycle.
DR. KRESS: Let me tell you the problem I have with this.
If I were to take my flaw detections on all the flaws I've got and what
size they are and take my growth rate equation that I have and
extrapolate to the end of my cycle and calculate whether I still meet
the requirements at the end of the cycle and then I sit down and operate
and then at the end of the cycle we go in and do our test and find out I
really didn't meet the requirements.
There must have been something wrong with my detection of
the flaws or the growth rate and I need to look at them and do something
about them and take corrective action.
Now, let's, for the sake of argument, say I have a 95
percent probability on the 50 percent, too. In order to arrive at that
number --
MR. LONG: I'm losing you here, but go ahead.
DR. KRESS: Let's say I allow the probabilistic criteria
that they want. It's 95 percent probability that the confidence there
is a 50 percent probability of meeting the thing. I do exactly the same
thing. I take a flaw detection device and put a probability on it. I
take the growth rate and I put a probability on it and I assess what my
condition is going to be at the end of the cycle and put a probability
on it.
If I don't make it, there's something wrong with my
probability distribution on the detection or my growth rate. It seems
to me like they're entirely equivalent. I don't understand your
reluctance to go with one versus the other.
MR. LONG: I don't agree they're equivalent. Let me see if
I can explain it this way. If you did that for one cycle, the -- say
the two -- you found a tube that had a burst pressure of 2,700 psi.
From a standpoint of saying were you in compliance with the high
confidence that half the time you wouldn't exceed the requirements,
well, it could have been, because now you've exceeded it once at one
time.
DR. KRESS: You have a question of deciding whether you're
in compliance or not.
MR. LONG: So then the next cycle, let's say you don't. Now,
there is one out of two. You didn't the first cycle -- you did the
first cycle, you didn't the second cycle, but I at least have to wait
till the second cycle to even start answering the question.
DR. KRESS: I see your problem. You have no way of knowing
whether they -- just because they burst a tube, you don't know whether
they're in compliance or not. The other way, you automatically say
that's out of compliance the other way.
MR. LONG: So what you're looking for is something that
really invokes a change to your process once you've crossed the
threshold and trying to figure out what the change really ought to be is
difficult.
DR. KRESS: If I were the licensee, I would probably use
some sort of probability process to do this.
MR. LONG: Sure.
DR. KRESS: I would end up -- you would end up being --
well, I probably wouldn't because I would just use conservative values
on the flaw in my growth, but those conservative values would be based
on probability.
MR. LONG: One of the things that's on the street now is
draft 1074 and it has in it a proposal for the licensees to use a
specific statistical technique with statistical requirements on the
output of that technique in order to show that they can start operating
from the beginning of the cycle. And that would be something that
apparently the industry would find pretty onerous and might be very,
very conservative in terms of the fraction of the time -- when they got
to the end, they actually didn't meet the standard.
So what we were putting up as an option, and as I said,
these options have not made it through the concurrence chain yet, is to
back away from specifying what the industry has to do in order to
restart the plant, but allow them to go until they have demonstrated at
the end that they're not meeting the deterministic requirement for
strength.
Then at that point, get into a corrective type mode and
trying to make sure you don't repeat it.
DR. KRESS: And your assessment of the correction action
mode could be based on probabilities, you're saying.
MR. LONG: They may have to think about that. I'm sure they
would get much more probabilistic about it if they started failing the
requirements. Again, we may not want to try to define for them exactly
what that probability method or success criterion has to be, but the
point of the white paper is to say we think we can go to a process like
that where you're not precluding on a very high probability ever
crossing the ASME or whatever integrity requirement, because we think as
long as you stay close to it and you don't go over it very often, that
the risk will be adequately small.
DR. KRESS: Can we get a copy of that white paper at some
point?
MR. LONG: I'm trying. We still need to get some
concurrence before we can get out of that level of the staff. The
intent was to have it here for this meeting. We didn't make that.
DR. SEALE: I think it's pretty clear that all of the
discussion won't be over when you get the staff concurrence.
MR. LONG: I'm sure and one of the reasons for bringing it
here was we're looking for input and trying to refine this, because it
is a judgment process. You're just not going to get the answer
precisely out of a risk assessment. It's going to require a lot of
people to think about it and concur on it.
I think we said all the conclusions. I'd read them to you,
but you've already got them in your hands. Are there anymore questions?
DR. SEALE: Anyone?
DR. FONTANA: The third one, that's the different
professional observation.
DR. KRESS: The third bullet.
MR. LONG: The cutting. The third bullet on this list.
DR. KRESS: The third non-bullet.
MR. LONG: Yes.
DR. FONTANA: This says it should be studied, all right.
MR. LONG: I guess one thing I should say there is the -- we
-- unlike the other issue I said should be studied, the NRC is not
actively studying this issue. There is a program that Bill is familiar
with that may start getting us some data on this issue a little bit, in
a couple of years maybe, Bill. But it's not designed to do that.
DR. SHACK: Talk to Joe.
MR. LONG: It's really not designed to do that. We have
talked to the industry about data that they may have. In part, we know
that there's cutting problems in plants that -- fossil fuel plants that
are super-critical boilers that are operate around 4,000 psi and at
fairly high temperatures. We have examples in the next building of
things that have been fairly severely cut under those conditions fairly
quickly.
On the other hand, there are two other code levels. There
is the 2,500 psi level that is more like the PWR. Matter of fact,
that's the reason PWRs are built to that standard, because of a
preexisting value. And there is also an 1,800 psi value that a lot of
plants are built to.
And I think the reputation of the 1,800 psi plants is there
is not much cutting problem with them. So we're hoping that the
industry can bring some data to bear on this that we don't really have
in our hands here. Just experience on how badly things cut at different
pressures and temperatures.
Because the materials are there. There's carbon steel,
there's stainless steel, and there's inconel welds in the plants that
we're talking about, the fossil fuel.
DR. SEALE: The DPO is still hanging out there.
MR. LONG: Still hanging out there.
DR. SEALE: Okay. Are there any other questions or
comments?
DR. FONTANA: One that's not directly relevant. If you
wanted to buy a new steam generator, what's the lead time?
MR. LONG: There is a man that can probably answer that
question.
MR. MULLINS: On the order of two and a half to three years.
DR. SEALE: That's the lead time for one or for a set of
four?
MR. MULLINS: That was for a set of three.
DR. SEALE: A set of three. Do the industry people have
anything else to say or any comments to make about the white paper or
anything like that?
Any other comments?
[No response.]
DR. SEALE: It's always a pleasure to hear from you. We'll
now recess until ten minutes after one.
[Whereupon, at 12:10 p.m., the meeting was recessed, to
reconvene at 1:10 p.m., this same day.]. A F T E R N O O N S E S S I O N
[1:10 p.m.]
MR. SEALE: We will resume now. We are going to be talking
about the activities of the BWR vessel and internals program, and I
guess, Mr. Carpenter?
MR. CARPENTER: Yes?
MR. SEALE: Are you the first guy out of the box here?
MR. CARPENTER: I believe I am, sir.
Good afternoon. My name is Gene Carpenter. I am the lead
project manager for NRR on the BWR internals issues, and I am here to
talk to you a little bit about some of the things that we have been
doing over the past couple of years with BWR internals.
Today, I will be giving you an overview of the BWR issues, a
little history of the BWR internals cracking; some of the inspection
results and safety significance of this cracking; the voluntary industry
initiatives that have arisen for this. Then, I will be going over to
the BWR vessel internals project, which is one of the voluntary industry
initiatives, and I will be talking about some of the submittals that
they have given to the staff to review. We will be going through a
little bit of a schedule and scope of that; the inspections and fall
evaluation strategies; the mitigative strategies; the crack growth
evaluations as part of the mitigative strategies. I will also talk a
little bit about the repair and replacement strategies and also about
license renewal.
Finally, I will sum up with the research initiatives and the
conclusions there.
The pre-review of the BWR internals issues; the NRC staff
has been concerned with materials time limit and aging for operating
reactors for over a decade now, specifically in intergranular stress
collision cracking of BWR internal stainless steel components, and it
has been observed both domestically and foreign since 1999. The most
significant one was the USBWR core shroud cracking that was first
observed in 1993. That was found at Brunswick Nuclear Power Plant.
In 1994, the staff put out generic letter 9403, which
requested that BWR licensees -- let me see if my handy dandy little
pointer here actually works -- performed timely inspections and/or
repairs of core shrouds and provide information to the staff regarding
their compliance with structural integrity regulatory requirements of
the core shrouds. Now, this was based on the provided information by
the industry. The NRC staff then concluded that BWRs could safely
operate until inspections and/or repairs had been completed, and they
closed out generic letter 9403.
Subsequent inspections of other BWR internals has identified
IGSCC in other stainless steel components, and we have been addressing
that issue also.
Can I go on? Some of the safety assessments performed for
significance -- pardon me; safety assessments were performed to
determine the significance and for inspections, and the internals that
have been inspected have included core shroud; core spring piping; core
plate pop guides; standby liquid control to some degree; pump riser
assemblies; low-pressure cooling injection; vessel ID attachments, et
cetera. There have been quite a bit of inspections performed to date,
and some significant cracking has been found in the core shrouds, the
core spray piping and jet pump riser assemblies.
However, and this is most important, no cracking to date has
presented any immediate or near-term safety concerns, and we are
continuing to look at that to ensure that that continues to be the case.
Now, voluntary industry initiatives; the industry, the BWR
owners' group, formed in 1994 the BWR vessel and internals project,
BWRVIP, now, which was formed to address material degradation issues in
BWRs, specifically the BWRs core shroud issue that was identified in
generic letter 9403. The VIP was instrumental in addressing generic
letter 9403 and did help the staff very much in getting to a timely
completion of that letter.
The BWRVIP is composed of five main committees, which are
integration, the assessment, inspection, repair and mitigation
committees. They have determined some of the generic activities that
the VIP has followed since the core shroud issue was resolved
satisfactorily, including the assessments of various cracking issues;
guidelines for performing followup inspections and initial inspections;
flaw evaluations of the various components that have been cracked and
repair and replacement guidelines. This generic activities strategy
that has been in place now, plant-specific AS cracking has been
determined has saved incredible amounts of resources for both the staff
and the industry, and it is a model for the DSI-13 voluntary industry
initiatives program.
Basically, the VIP program has a three-pronged approach:
the inspection of core evaluation guideline strategies; mitigative
strategies and repair or replacement strategies. We will talk a little
bit about the inspection guidelines now. To date, the VIP has submitted
some 13 flaw evaluation I&E guidelines for staff reviews, including the
reactor pressure vessel shell welds, the BWRVIP 05 which this committee
reviewed last year; core shrouds; core spray internal guidance; top guy
core plate standby liquid control; the list goes on, as you can read.
To date, the NRC has reviewed and found the guidance of --
it says three here, but it should be four -- four of these I&E
guidelines acceptable, and we have an additional five in-house right now
that are about to be signed out hopefully in the next couple of days
with the remaining in various stages of concurrence or review.
Going on to mitigative strategies, the vendors have
developed several mitigative strategies that have included hydrogen
water chemistry and noble metal addition techniques. That noble metal
one, specifically, is the GE one. The staff has reviewed and approved
plant-specific uses of noble metal addition, and we expect the industry
to make widespread use of noble metal addition over the coming years.
The industrial research is underway by both the industry and the staff
into further mitigative strategies.
Continuing one, we'll talk a little bit about some of the
mitigative strategies: the cracked growth evaluations. Right at the
present time, the staff is reviewing two cracked growth rate models:
the BWRVIP 14, which is the evaluation of cracked growth and BWR
stainless steel racked pressure vessel internals, and that one has been
initially reviewed, and an initial IC has been written. We are in the
process of reviewing the comments back from the BWRVIP on that for
closing out that one.
The other one that is being reviewed for the staff is the GE
PLEDGE model, and that one is based more on first principles as opposed
to the inspection experience that the VIP is based on. The staff has
given conditional approval, as I said, to the 14 report, and three
approaches have been found acceptable for use in that. These three
bullets here talk about the main criteria that we have found in our
acceptance; that is that the repairs are considered in evaluating
residual stresses; components operated in accordance with the EPRI BWR
water chemistry guidelines and that the stress intensity factor is
explicitly determined to be less than 25 Ksi root interest.
Additionally, the staff is going to need to review
licensees' crack growth evaluations, including an evaluation of the flag
and residual stresses to determine acceptability of cracked growth
rates; the residual stress determinations must also include any repairs
and/or other factors for that location. Cracking and welds that have
been irradiated at greater than 5 E to the 20th neutrons per square
centimeter with energy levels greater than 1 MeV is outside the scope of
this review and needs a case basis to be approved.
Research, who is heading the review on the PLEDGE model,
tells me that the safety evaluation on that will be done sometime this
spring.
Repair and replacement strategies that have been used to
date have included mechanical clamps and fixtures. Core shroud and core
spray are the two most prevalent examples of that. Now, these have
required large resource exposures on a plant-specific basis by the
utilities, and mechanical clamps and fixtures have been utilized
domestically for core shroud repairs, core spray and jet pump riser
elbow cracks.
MR. SHACK: Gene, what kind of inspection schedule are they
on for these components? Is there an accelerated inspection, what you
did for the piping, or is this still basically just an Aspen code type
inspection?
MR. CARPENTER: Well, for the inspections that have been
done to date, they are using the BWRVIP -- I didn't bring the number
with me. I believe that is 41, Keith. Do you have the -- I have a
little cheat sheet right here. Forty-one jet pumps. They are also
doing inspections, just running down the list here, of the VIP -- pardon
me; all of the BWRs are doing inspections based on the core shroud,
based on the BWRVIP 07 document, which was status approved. Also,
hearing inspections on a core spray piping based on the initial approval
of the AT. BWRVIP 25 and 26 are for the top guide and core plate
respectively. They are inspecting to that.
MR. SHACK: Okay; I envisioned those guidelines as more how
to do it, but this includes the whole inspection package.
MR. CARPENTER: Right.
MR. SHACK: The schedule?
MR. CARPENTER: Schedule; schedule of reviews; how to do the
reviews; that sort of thing.
MR. SHACK: So this, in fact, supersedes the Aspen code
requirements or it's --
MR. CARPENTER: To some degree, these components are not
covered by the Aspen code.
MR. SHACK: Okay.
MR. WHITMAN: The only component inside the BWR reactor that
is covered by the code is the core shroud, the core support structure.
All of the rest of these items are not.
MR. CARPENTER: Any additional?
[No response.]
MR. CARPENTER: Continuing on on repair and replacement
strategies --
MR. SHACK: Excuse me; does that include the jet pumps also?
MR. WHITMAN: Yes; again, the only component, if you will,
inside the reactor that is explicitly included under the code is the
core shroud and its core support structure. That is it.
MR. CARPENTER: Motor repairs have successfully been
performed at various locations in the reactor vessel, including the
steam dryer; the feed water and the core spray T-box. Now, one of the
major advantages of this is not needing a plant-specific fabrication or
maintaining costly hardware in stock for emergency repairs during
outages. One of the major disadvantages of this is something that we
are doing a review on now, and that is at high fluence areas, the area's
potential for helium-induced cracking of the components that have been
exposed to high fluences. Here again, low fluences have had successful
weld repairs. We have not seen a lot of experience with high fluence
areas having successful repairs.
Now, replacement has been an option when mechanical or
welded repairs have not been economically feasible. This has been most
often done with the core spray piping. However, two form utilities have
replaced core shrouds, and that has not yet been done here in this
country.
MR. SHACK: Do we have a limit on fluence for these cracking
people below that --
MR. CARPENTER: Right now, we're looking at 5 E to the 20th
for the upper end. However, part of our research is to find out where
that high end is, and I'll be discussing that in just a moment.
Part of the VIP program is also to take care of license
renewal space, what happens after the 40-year initial license has gone
into effect. Long-term degradation of this has been a concern for the
staff, and it is being addressed at this present time. We have
approximately 12 submittals in-house right now dealing with license
renewal space. We expect to be completing those toward the end of this
year.
MR. SEALE: Are these 14 the nature or the individual
reports that would be part of the basis for -- and I say incorporated in
any specific plant proposal for license renewal?
MR. CARPENTER: My understanding is that specific plants,
for instance Plant Hatch, if they're the ones who had the first BWR,
would come in, and again, that's just a supposition.
MR. SEALE: Yes.
MR. CARPENTER: When they come in with their submittal, they
will reference --
MR. SEALE: Yes, that's what I mean.
MR. CARPENTER: -- the BWRVIP document.
MR. SEALE: These are essentially technical backup reports
that will be much like they're doing with the --
MR. CARPENTER: Right.
MR. SEALE: Okay.
MR. CARPENTER: As I mentioned a moment before, some of the
research initiatives that we have ongoing, two of them in particular
that I would like to bring to your attention is the evaluation of
cost-related cracking failures, and what this is is what happens if you
have cracking that leads to a component failure in one location? How
can it possibly affect other components in the neighboring area?
Cascading effects, basically.
That one is ongoing at this time, and we hope to have some
preliminary results toward the end of this year. The other one is the
weldability of highly irradiated materials. This is research that is
going on with both EPRI and the staff, and basically what it is is
trying to confirm or evaluate the feasibility of welding
highly-irradiated stainless steels in BWRs. The program is basically
trying to determine which locations, which fluences, which components
repairs are feasible, and one of the things that we have to look at most
specifically are the levels of boron and fluences to see if we can
determine if that will eliminate welding as a repair option for some of
these areas. Now --
MR. SEALE: These are things that are susceptible to this
helium-induced cracking also.
MR. CARPENTER: Correct; basically, boron is converted over
into helium bubbles when it has high irradiation levels.
MR. SHACK: It all runs and gets heated up and --
MR. SEALE: Yes, jacks it apart.
MR. SHACK: Yes.
MR. CARPENTER: Makes it a little more interesting.
Well, the near-term benefit to this is to determine if we
can find and predict boron concentrations in locations that will require
repairs and hopefully be able to make those repairs and put a staff to
find those repairs acceptable. Additional program benefits will be to
corroborate predictive flex model results with actual fill-in material
samples.
MR. FONTANA: What took you so long to do some research on
that first bullet? It seems like that is the first thing you would want
to know.
MR. CARPENTER: I'm sorry; you're talking about the
cascading failures?
MR. FONTANA: Yes; it seems that's the first thing you would
want to know. Do these failures cascade into -- propagate into worse
accidents.
MR. CARPENTER: Traditionally, we've believed in single
failures, and over the years, we've talked about this, but as to why it
hasn't occurred before on my watch, I really don't have an answer for
it.
MR. FONTANA: Because this was first discovered about 6
years ago maybe, 1993.
MR. CARPENTER: Well, the core shroud cracking was first
discovered back in 1993.
MR. FONTANA: Yes.
MR. CARPENTER: But this is talking about basically
cascading failures for any reason.
MR. FONTANA: Yes; thank you.
MR. CARPENTER: In conclusion, the issue of BWR time
dependent material degradation is being addressed in a comprehensive
manner by both the staff and the industry. We're evaluating the
submittals from the voluntary industry initiative, and we are also
engaged in confirmatory research into determining if we need more data
in some of these areas. The BWRVIP's voluntary initiative has provided
the industry with some generic guidance on performing inspections for
tears and mitigation, and at this time, we consider it to be a success.
And that concludes my comments. Any questions?
MR. SHACK: You have like a voluntary initiative for the
inspection guidelines.
MR. CARPENTER: Yes.
MR. SHACK: How do you handle that in the regulatory space?
I mean, are they inspected against those guidelines?
MR. CARPENTER: Basically, the BWR industry has committed to
following all of the BWRVIP guidelines as they are processed and
approved by the staff. What we are saying when we approve these is that
this is in accordance with appendix B of 10 CFR --
MR. SHACK: Okay; that's the --
MR. SEALE: So you've got a compliance with appendix B to
set if you have a problem.
MR. CARPENTER: Yes, not that we've had a problem.
MR. SEALE: I understand that.
MR. SHACK: Which of the guidelines has been approved?
MR. CARPENTER: To date, we have approved BWRVIP 05 for the
certain approach for shell welds; 07 for the core shroud reinspections;
VIP-18 for the core spray inspections; BWRVIP 06 for safety assessment;
BWRVIP 14 has been initially approved. That's the crack growth and
stills.
We have also approved BWRVIP 16 and 17 for core spray piping
replacement and repairs, pardon me, 16 and 19 for replacement and repair
respectively; BWRVIP 08 and 46 was the BWRVIP's response to generic
letter 9201, and we have approved that. We have also denied BWRVIP 17,
which was their request to perform role expansion of CRDM and vessel
bottom penetrations, basically performing repairs by rolling the bottom
--
MR. SEALE: You're on number 48 in there. That suggests
that there are a rather large number of them in the works somewhere.
MR. CARPENTER: We're up to 66 at this time.
MR. SHACK: Where does it stop?
MR. CARPENTER: Well, the BWRVIP has decided to take on some
additional efforts into new reg 0313 space, so I'm expecting some more
submittals. Where does it stop? Well, I have about 20 more years to go
until retirement.
[Laughter.]
MR. SEALE: So are we going to propose changes to the recert
piping inspection guidelines?
MR. SHACK: That's 0313?
MR. CARPENTER: Yes.
MR. SHACK: Any other questions?
[No response.]
MR. CARPENTER: Thank you, gentlemen.
MR. SHACK: Well, let's see. Now, we have Mr. Terry. There
he is.
MR. TERRY: I could almost say what he said as far as the
presentation, because I am going to cover a lot of the same subject
areas in reviewing the program, et cetera, but I would like to try to
give you a little bit of the perspective from our side as I go through a
lot of it. It is the same program, of course.
First off, just by way of introduction, I'm Carl Terry. I'm
currently the chairman of the executive committee for the BWRVIP. I've
been in that role for several years, and I've been on the executive
committee since we formed the vessel internals project in 1994. At that
time, I was also involved in the BWR owners' group executive committee,
and in fact, it was a group of us really that got together and formed
this group.
By way of background, it was modeled after work that had
been previously done with EPRI as part of the steam generator project,
and so, we modeled, for instance, the use of EPRI as program manager in
that effort and also the heavy involvement by executives from the
utilities as part of that, and I'll talk a little bit more on that, but
that is key to the question that came up on how we handle commitments
and why we think there is a lot of credibility behind implementation of
the program and talk a little bit about that process.
With me today, I should say, are a number of the executives
who are also involved and have been involved from the committee, and
let's see who all is here. Maybe you could just step up. George Jones
is here from Pennsylvania Power and Light and Jim Pelletier, Joe Hagan
from KeyCo and Harry Salmon from the Power Authority. Did I miss
anybody?
But that really has been what we're about is heavy executive
involvement, and I'll talk a little bit about that in terms of how we're
structured.
As you can see, there has been a lot that has been produced
since we were formed in 1994, and frankly, we use the term proactively,
and we use that not just because it sounds like a good term but because
we wanted to get out of the situation that we were in in 1994 when we
were not ahead of the game in terms of how to deal with core shroud
issues. At that time, we really weren't sure what the right way was to
inspect; what the right way was to evaluate the indications that we
have, the extent of the condition, what does that mean, what options we
have available for repair, and that has changed dramatically since that
point in time.
And we are right now completing our initial program scope in
terms of what we wanted to do, which was really to get at both the
reactor vessel and internals, with the main focus being on intergranular
stress corrosion cracking as the mechanism but fundamentally to assess
those components and establish a sound basis not only as to why we were
safe to operate but also as issues arose be prepared to address them
ahead of time. So we knew cracking was going to occur in a number of
areas and be prepared to address it.
But at this point, this year, we are looking at completing
what we had originally planned to do and transitioning into what we call
a maintenance model. That does not mean that the efforts are going to
go away and that all of the information, documentation and support is
gone as well, and in fact, we will be talking with staff later this year
on our more specific plans in that regard. We are formulating that now
among the executives in terms of exactly what that transition will be.
Maybe taking a little bit different cut than Gene went
through, we're really covering all the same territory. We look at this
as really the documents we generate more than anything else as a
reference library that is available for both us and the NRC to use as
part of evaluating what to do on our reactor internals and the RPV
itself. We laid out, before we even started down this path,
particularly beyond the core shroud, we knew we had to do something
there right off the bat, we took a look at, very carefully, what are the
right priorities; what are the kinds of failure mechanisms we have?
What kinds of consequences can be associated with those failure modes on
all of the internals, and as a result of that, prioritized each and
every one of the components and went at our submittals in that way.
We reviewed those priorities with the NRC to make sure there
was agreement on that and then moved forward from there. Additionally,
you'll see that for each of the components, there are assessment,
inspection, repair and mitigation guidelines that are established. That
is the way that we are structured as well in terms of the vessel
internals project, and just to describe that very briefly, one of the
things that is unique on this project as opposed to, say, how we do
things on the owner's group when it comes up with an issue, each and
every one of those columns is a committee on the BWR owners' group or
VIP rather, and it has an in-charge executive, and it is not an
executive sponsor, which is something we have used on the owners' group;
it is truly the in-charge executive.
That executive follows closely what is going on; I'm not
talking about so much reviewing the technical details, although they do
participate in the meetings, but being aware of what's there and what
issues are there, and when they come down and talk to staff, it's really
the combination of the executives as well as the technical committee
chairmen that handle the presentation and understand it.
That is also important because, speaking for a minute on how
we handle these things, these go through the normal review process for
any submittal to the staff, including issuance of a safety evaluation
report when all is done. Once we resolve comments at the VIP level on
those, we then get a consensus. I specifically get consensus of the
executives on which utilities, for each utility, that they will indeed
follow that guidance or, if they want, and there are some special
circumstances; I've never had a case where somebody didn't do it because
they didn't want to, but there are differences in time configurations
and situations. They then explicitly go to the NRC with a separate
submittal indicating that they will be following other guidelines.
That was an important concern to staff as we went through
that, because there isn't the same kind of regulatory hook when you go
through the process on a generic basis, and as Gene pointed out, we've
also indicated that these programs are implemented through the quality
assurance programs and procedures that go along with that and can be
inspected by NRC resident inspector or others as part of implementation,
and I think it has worked very well in terms of that, and so, it's been
a good process.
As you can see on the chart, basically, we have completed
our efforts and those other documents as Gene went through, but this
really covers the heavy hitters in terms of --
MR. SHACK: In your view, would these constitute an aging
management plan for these components, so we would expect to see these
things cited in license renewal reports?
MR. TERRY: Yes; as Gene pointed out, we have a separate
appendix with each of our assessments that deals with the renewal
aspects of that component. In general, it involves explaining why
continuing the program as we have established it will serve well not
just through the 40-year plant life but beyond that, because that is
really the key behind this program is identifying what components need
to be looked at; what aspects need to be looked at and then, from there,
assess what needs to be done, and it really is set up -- you know, as
part of this, there is a lot more behind this, I should point out, that
goes along with it.
In addition to paper, if you will, say, for instance, on
inspection guidelines, we do an extensive amount of work in developing
inspection methods. We have ways of inspecting portions of the reactor
internals today that simply were not available several years ago, both
in terms of the ability to deliver a transducer to a well location but
also and perhaps even more important, our ability to really determine
what the real condition of that component is. Once we get a transducer
on a well, we have a high degree of confidence that we're getting the
right answer.
Some of the things that I wanted to point out that, from our
standpoint we think are either particularly important or point to some
particular successes that we've had in the program that perhaps go
beyond just a matter of providing an adequate level of assurance that
the BWRs are operating safely, and this first one, crack growth
evaluations, my initial executive assignment on the BWRVIP was as chair
of the assessment committee, and one of the things that I laid out early
on was frankly, as a general objective, getting to the point where we
could both inspect and evaluate components and avoid unnecessary
repairs.
One of the things that we have learned in the course of
implementing these things, I guess it's just like any other change you
try to implement. When you go out and particularly when we do
mechanical repairs, you add a level of complexity that can cause
additional issues. By doing the right thing in areas such as crack
growth, and in this case, Gene talked about VIP 14 where we think we get
crack growth assessments down to a reasonable level, that is actually a
very positive thing from a safety standpoint, because you do the right
assessment, and you don't go in and do repairs that might otherwise not
be required, and we are seeing, particularly in the core shrouds, now
that we're starting to get some second round inspections, that as are
predicted by our analytical models as the stress regime reduces
effectively to a compressive or very low condition, this crack growth
does stop.
And given that situation and given the margin we have got in
required ligament, things like the core shroud, we have ample safety
margin and can avoid unnecessary repairs and the right evaluations.
We had a similar success on the RPV shell well inspections.
In that case, you've seen it; I don't think we need to go through that,
but that is just an opportunity where, frankly, in developing that, we
really weren't looking to eliminate any well inspections. We were just
trying to, in terms of what we wound up with, which is eliminating
completely the circumferential well inspections; our real objective when
we started down the path was how the heck are we going to meet the
regulatory requirements of doing nearly 100 percent inspection against
the backdrop of what we knew were going to be access problems within the
vessel? That's how we started down it.
But when we did the probabilistic fracture mechanics work
and saw what happened in terms of probability of cracking and failure on
RPVs, it just provided a very strong case to look for relief in shell
well inspections.
Welding of irradiated materials; as I indicated earlier, we
are certainly getting better, but mechanical repairs 60 feet underwater
are real buggers. So is welding, for that matter, so I am not trying to
minimize that, but I've got to tell you, in terms of maintaining it and
retaining it, if we can really get -- if we can get to success in terms
of being able to do more weld repairs, I think there is a lot to be
gained there, not just from the economic standpoint; in fact, I think it
is just a far better and far superior fix to the problems.
The key there, though, is obviously irradiated materials and
what happens, and by the way, this just happens to be an example of
something we're looking at the entire area, as Gene touched on earlier,
of really what happens on welding of or on irradiated materials in
general is something that we're trying to put a box around in terms of
what's the right way to attack that.
Right now, the 5 E to the 20th is kind of like the 5 E to
the minus 6th crack growth rate; it's a number that's out there. Maybe
a better example is, you know, you don't have IGSCC over 200 degrees.
Well, reality is it's none of the above in terms of an absolute number,
and it's really getting more understanding of really what the right
thing to do is; when don't you have margin, and when do you have margin
and take advantage of it.
Noble metal; that's true. That's a vendor initiative, but
-- and GE owns the process, but frankly, without the VIP, GE would not
have continued with the process. We actually had to work with General
Electric to support the actual pilot applications and some of the work
in that, and that's why there is noble metal chemical available, and in
fact, we have got three plants that have done already and another four
or five that are planning on doing it near-term, and I feel that the
majority of the fleet, before it's done, will implement it.
MR. KRESS: You put that in the water?
MR. TERRY: Yes; it's in solution --
MR. KRESS: And it latches all into the chlorine?
MR. TERRY: Latches -- yes, I didn't know that; somebody
else could probably speak more about the deposition process itself, but
essentially yes, it's in solution, and then, it latches on.
MR. KRESS: Get onto the metal and then protects it, a
sacrificial --
MR. TERRY: Right.
It's actually a catalyst for the reaction.
In the -- as far as cost-beneficial emerging issues, right
now, we are addressing for the RPV itself inspection evaluation
guidelines for it. Another thing that I think is a win all the way
around is the integrated BWR surveillance program, but this involves
ensuring the surveillance capsules among all of the BWR provides for,
frankly, some money saving on the part of the owners, but perhaps more
important, it also substantially expands the single database that we've
got and the consistency of testing and evaluating those specimens as
they come out.
So I think, you know, in followup to some of the issues that
we ran into on the generic level and trying to draw together a story on
that, this will go a long way for future evaluation in really assuring
that that is done right and provides an excellent database for all of
us.
Then, as we talked about on the research piping, this was a
little bit of an anomaly from the standpoint of the VIP, because
obviously, they're outside of the reactor vessel and internals, and Gene
knows that initially, I kind of said why the VIP is part of this when he
called me and asked about doing it, but actually, it makes sense to put
it on the VIP because of the nature of the people that we have out at
not just EPRI but also some of the other folks who have been involved in
looking at this, and our plan is, working with staff, and they have
committed to get this issue resolved this year so we can still move
ahead with the efforts that we want in terms of getting the VIP into a
maintenance.
And to that point, we are focusing on closure of the base
program by the end of 1999. This in no way means that we are going to
stop working on internals and that nobody is going to be available to
support the BWR fleet in implementing this program, but it is important
at this point to make a transition to get it into some of our more
routine programs and processes, and we're looking at this point at using
the BWR owners' group umbrella to handle that but maintaining things
such as EPRI involvement; keeping the right configuration control and
updates on the documents that are used and being available if we need to
if an issue comes up to remobilize the issue and react to a problem
should that rearise.
So we will be reviewing that with staff later this year, and
it is a key discussion point in our executive committee meeting in May,
and we will have a good transmission plan finalized by the end of the
year.
The other thing, license renewal; we touched on that. From
the standpoint of the BWRs, this actually is something that, because the
BWR owners group also has a license renewal committee, and we have
worked closely with the owners' group on this, but fundamentally, this
does lay the groundwork not just for how we want to assess the reactor
vessel and internals but really the BWR approach in looking at license
renewal and ongoing condition assessment as a matter of process.
I have personally always felt that, you know, whatever we do
as part of the license renewal effort has to be reflected back upon in
some way; at least we have to be prepared to answer the question, well,
what does that mean to the clients who are operating in their 38th and
39th year? There just isn't any difference fundamentally between that,
and we believe this approach addresses that in a very comprehensive way.
We are going to, with the transition, there will still be a
vessel internals project. We still will be able to stay in front of
developing issues as they occur. I'll tell you -- in addition to
executive involvement, the other thing that has been key is
communication to the success of this program, and we know that. And it
is our intention to continue that communication on into the future. We
have routine venues to do that as part of the owners' group activities
that are established, and this will continue to be among those that we
look at as we do complete the transition into the maintenance mode.
MR. SEALE: Any questions?
MR. SHACK: Are all of the BWR utilities in VIP?
MR. TERRY: Yes, all domestic.
MR. SHACK: All domestic.
MR. TERRY: And most in the world.
MR. SEALE: Any other comments or questions?
I must say I guess I came on the ACRS about the time the
first cracks showed up, and we've heard two or three briefings now on
this, and this is a personal comment. I have been always impressed by
the way in which the problem was handled. There was -- has been a mix
of the attitude of fix it and understand it, and if you think about
that, usually, it's the lack of balance between those two things that
gets you in trouble when you have a set of problems.
And the way you attack the problem of the shrouds on the one
hand and the crack growth on the other hand, that's a real demonstration
of the balance in those two parts of the approach. Whether you learn
something from the steam generator guys and their woes or not in
organizing this, whoever you learned it from, I think you learned it
very well, and it's a very impressive program. It's amazing, really.
MR. TERRY: Thank you. I think the key was laying out up
front what was really important.
MR. SEALE: But you know how people are. They get fixated
on the, well, I don't really understand it yet; am I going to cause more
problems than I am going to resolve and so on; the ability to go to the
issue and work on it, I think, has been very impressive.
MR. TERRY: Thank you.
MR. SEALE: Well, we're a little bit ahead of schedule. Any
problem? Okay; well, speaking of BWR guys and so on, I guess we're
going to hear about the BWR materials reliability project.
MR. SHORT: We're going to move from a very mature program
to one that's just beginning.
I'm going to speak about the PWR materials reliability
project. I'll use the term MRP for short through the presentation.
My name is Mike Short, I'm with Southern California Edison,
and I am chairman of something we call the Issues Integration Group of
the MRP, and I'll explain what that is in just a moment.
Again, this is a new program. It was implemented by the
industry last year with the direct involvement and assistance of EPRI
and NEI.
DR. SHACK: This came out of the work on the control rod
drive penetration cracking; is that right? Or not really?
MR. SHORT: A whole bunch of issues are beginning to
crystallize within the PWR group, and as the PWR owners started to look
at those last year, we were faced with a choice to make. Most of our
issues outside of steam generators have been managed by individual
owners group, so each owners group had their own program for addressing
the issue. And as particularly some of the utilities with multiple
NSSS' began to see differences in approach amongst the owners group, not
necessarily incorrect differences, you know, technically incorrect, it's
just that there was some redundancies and overlaps beginning to occur,
and we felt that it was time on that basis to pull all of our efforts
together into a single integrated activity. That was one reason.
The second reason was we felt our plants had reached a point
in their life cycle where aging-related issues were also going to begin
to occur, had started to occur, things like head cracking. A lot of
these issues were occurring in overseas plants, so the industry needed a
way to take the overseas information and fold it into their own plants.
So that was a second reason for doing this.
Then I think the third reason had to do with issues like
license renewal. We didn't really have a formal aging management
program on the books anywhere. It was having to be created by license
renewal activities. We felt it best to get ahead of those issues and
pull everything we could into a single project.
Those were the things that were going on that drove the
executives to approach this effort in the way they have.
I've in a sense covered what's on my second slide, the
objectives. What we were looking for was a method to proactively
address materials issues in PWRs. We -- as was mentioned by the BWR VIP
folks, they looked to the steam generator management program, which was
an EPRI program, as a model. Well, we looked at that program -- most of
us were key members of that program -- but we also looked at BWR VIP as
a model to follow. So you'll see a lot of the same features about this
program as are present in BWR VIP.
We had three specific objectives. I could add identify,
resolve both existing and emerging materials issues, and as a result of
that achieve improvements in reliability, operational and regulatory
performance. And we have a set of specific screening criteria which
I'll go over in just a minute that helps us define what issues really
belong under the purview of this.
We also want to serve as a single point of contact for the
industry on materials issues. We do that through NEI. NEI is here
today. Dave Modeen and Kirk Cousins of NEI are here in the back of the
room if you have any questions for them. And then as I mentioned, we
want -- within the domestic utilities, we have three NSSS owners groups.
We wanted to integrate their activities and reduce the potential for
overlap and inconsistency. And that makes us more efficient, it makes
us easier for the staff to deal with issues that cut across all three
NSSS's, and frankly, in the long run, it's better for the industry as a
whole.
Now, I mentioned we had -- we have criteria to help us
select issues for involvement by the MRP process. We have three primary
areas that we selected for work last year, and a fourth area that we've
added on the basis of input from the NRC staff, and I'll speak to those
in a summary level in just a minute.
These are the criteria. I'm not going to read them. You
can I think get the basic picture of the criteria. They have to do with
significant issues that cut across all three NSSS designs, may involve
industry experience or industry activities that we would like to get
involved with, and/or they're very difficult technically. It's hard to
reach a consensus amongst the various owners as to what the right
approach is.
DR. SEALE: I assume that if all of the owners groups are
involved, at least by implication, all of the PWR owners in this country
are involved.
MR. SHORT: That's our goal. We're not quite there.
DR. SEALE: You're not quite there yet.
MR. SHORT: We have nearly -- we have about 95 percent
participation by domestic utilities right now.
DR. SEALE: What about in the international arena?
MR. SHORT: In the international area, that's something
that's not yet on board. They are not completely on board with us. But
I will mention, getting ahead of myself just a little bit, one of our
key projects has to do with vessel internals, much like BWR VIP, and we
have joined with an international effort who is a very large
international effort primarily focused in Europe to look into internals
issues.
DR. SEALE: Okay.
MR. SHORT: We have joined with that effort through EPRI in
now have access to that information and they will have access to ours.
So there will be a complete sharing of data there.
Now, organizationally, we look very much like the SGMP, and
in fact, we've borrowed a number of features of the SGMP. We have a
shared executive group of about 15 executives that manage the activities
of both the SGMP and the MRP. Each utility which is a member of the MRP
provides a senior manager to the effort, and that's what's known as the
senior reps. They provide the agreement to proceed on a commitment, for
example.
Then the SGMP as well as the MRP have something called the
issues integration group, which is a utility group, and it also includes
members from each of the owners groups, and that's the activity that I'm
chair of. I'm chair of this committee right here. And then reporting
to the issues integration groups are a series of task-related groups.
In the SGMP, there are a number of those. In the MRP, there are five.
I show four here; we've added a fifth just recently. These are formed
to address individual issues. It's a little different then the VIP
structure that you were just presented where they broke their committees
down into issues like mitigation or repair. We have not done that.
Each of these committees is limited to the issue, and then within that
issue, they will address inspection, mitigation, and repair
technologies. So it's not either from structure or VIP, but basically
the same general concept, areas of responsibility.
TSS is short for technical support, and what they provide is
they are our standing committee. As an individual task is completed,
there is always, as you might recognize, some follow on, and the follow
on efforts would role into the TSS.
In addition, the TSS is also managing a couple of smaller
activities. For example, they have the management of a handbook of
material-related issues that is being provided to each utility for the
station or system engineer's use in helping them with issues within the
plant. They're producing that handbook. They're also managing our zinc
addition efforts for the reactor coolant system for the control of
cracking.
I mentioned there are four main areas that the MRP is
pursuing. This is the first two of those. The first of those is
cracking of head penetrations, Alloy 600 in particular, and the status
of that effort is we have prepared an industry -- an integrated industry
program. We've taken individual owners group activities and molded them
into a single program, a fully integrated program. That has been
developed and it was submitted to the NRC staff through NEI late last
year, and you'll get a report of the staff's assessment of that program
later in your agenda today.
In addition, the committee is continuing work on repair
methods and the means to mitigate future cracking, and that's an
in-progress effort.
The next major area that we're pursuing is reactor pressure
vessel integrity, and here we are working with the staff to resolve
issues with aging effects on reactor vessel materials.
DR. SHACK: What's an operating issue with PTS?
MR. SHORT: As you go forward, especially start to look at
things like life extension, the operating window the operators are now
allowed to function in is getting smaller and smaller and smaller, so
we're hoping to find ways to open that window back up and reverse the
trend of removing margin from the operators and providing it in support
of reactor vessel analysis.
MR. HACKETT: I guess I would add --
DR. SEALE: Identify yourself.
MR. HACKETT: I'm sorry about that. I'm Ed Hackett of the
Research Office Staff. The only plant that we think we have an
operating plant PTS issue with, of course, is Palisades, and that's
pretty widely known, what's gone on there technically over the past.
Beyond that, there are no other plants all the way to EOL. I think
Beaver Valley is the next one that flags up right at EOL, and then there
is a potential for some beyond EOL. But, you know, you questioned on
PTS. I think that slide probably goes more towards PT limits and
discussion of the operating constraints with PT limits.
DR. SEALE: Thank you.
MR. SHORT: The last two areas that we're currently pursuing
are on the next slide. I've already mentioned that we have commenced an
effort to look at internals issues with PWRs. You could argue this is
very similar to what the VIP has done. We're attempting to get ahead of
the problems before they occur.
As you know, we're just beginning to see issues with PWR
internals, notably baffle former bolts, but we don't expect it to end
there, so the effort is to get ahead of the problems before they become
an operational restraint.
This is -- as I mentioned as well, we're in the very early
stages of what we expect to be a many-year program to go through those
issues, and as I also mentioned earlier, we're teaming up with the
Europeans in their program to address the same issues.
The last item I wanted to bring up is an example of a new
program. We were asked by the NRC staff last year to take a look at
this issue and determine whether or not it fits the definition of
something that should be addressed under this program. We have done
that and concluded it is appropriate to add it to our list of
activities, and just recently reached that conclusion and we're just
beginning work in this area.
Now, what I've done is quoted basically the general design
criteria. The issue here is recently, several foreign plants have begun
to see cracking that was initiated thermally in piping connected to the
RCS that could not be isolated from it, notably HPSI piping. The
industry has had a couple of issues domestically with that problem in
the past, and the issue is, are the industry's efforts current and up to
date and do they reflect the current state of knowledge? And we
conclude perhaps not, and it's worth the time and the effort to pursue
that.
DR. SHACK: That just seems like such a detailed design
thing, it's hard to see how you attack it generically.
MR. SHORT: Excellent comment. And that was notably the
discussion that went around in our efforts as well. It is very much
plant-specific as each plant design is more or less susceptible to this
problem.
What we conclude is there's some improvement in the models
that are used to help those plants address the issue or in the methods
of deciding whether it's worth modeling the criteria that's used to
decide whether you have a problem or not. Both of those areas could be
improved upon. So that's the primary area of attack.
So I wrap this up with a benefits slide. I think the
benefits are fairly evident. We certainly expect through this process
to identify and deal with issues before they become operationally
significant, and the idea of a single industry voice for the three PWR
NSSS designs we see has a lot of merit. I think the staff will agree
with us there. Hopefully, as our plants age, we'll get ahead of
problems through this process. Lastly, of course, is license renewal is
now a more important issue than perhaps it was several years ago. This
program would enable us to provide rigorous support for the license
renewal process.
That's what I have. Can I answer any other questions?
DR. SHACK: When did this start?
MR. SHORT: It started last year. In earnest, it began in
the Fall. Most of the first half of the year was formative in nature,
really getting the three owners groups together to decide what to give
up control of to the MRP, basically what problems to hand off to the
MRP, and how to deal with funding issues, where were the funds to
support this effort kind of thing. So it took us the first six to nine
months of '98 to get through that, and then we've been rolling since
about September.
DR. SEALE: I guess one of the concerns you had was to get
everybody, the different owners groups to decide -- I guess not from the
utility side, but from the NSSS side -- what was what we might call in
the public domain to decide that a shared approach was the appropriate
approach. One of the things that was mentioned in passing that I was
impressed with was the comment that was made about, in the case of the
BWR VIP program, both the confidence with which they felt they could put
a detector, a sensor, where it needed to be in order to assess the state
of repair or disrepair of a component or a part of the vessel and the
--also the confidence they had that they were going to get an answer
that was going to give them a real assessment.
I would imagine there are some things along those lines that
you can inherit from the scattered experience of the individual owners
groups or whoever was doing this up until now. Is that the case?
There's a lot of that kind of technology that you can -- it's just a
question of sharing and so on.
MR. SHORT: I think you're correct with respect to, for
example, all of the underwater tooling --
DR. SEALE: Yes.
MR. SHORT: -- and technologies that the VIP program has
developed are certainly candidates for us to use as well as we find a
need.
DR. SEALE: But there's already, I would think, a body of
experience in the PWR side for some of these things.
MR. SHORT: Yes, there is. For example, in the case of
baffle former bolts, technology has been put together to inspect, remove
and replace those.
DR. SEALE: I see. Okay.
MR. SHORT: So that was a -- principally an owners group's
activity, and a single NSSS vendor put that together.
DR. SEALE: What about this underwater welding thing?
MR. SHORT: I don't know enough about it to comment.
DR. SEALE: I see.
MR. SHORT: I don't know. Bob, do you have any -- I have
not made use of it in my plant, and so my experience with it is
essentially new.
DR. SEALE: Yes. Okay.
Any other questions or comments? Tom?
MR. SHORT: Thank you all.
DR. SEALE: Well, gee, we're getting ahead. Let's take a
little break. I need to make a phone call, anyway. We are making
headway. Why don't we start again at 20 of.
[Recess.]
MR. SEALE: Dr. Shack is no longer in conflict, so it
belongs to him.
DR. SHACK: And Ed Hackett is going to tell us about NRC
research activities on pressure vessels.
MR. HACKETT: And summarizes my first talk. I'm in the
middle of a reorg, so I've been section chief in this area for, I guess,
going on three or four years now. Now I'm going to be an assistant
branch chief, and we're in the mode of probably figuring out exactly
what that means, I guess, over the --
DR. SHACK: Does it mean a pay raise?
MR. HACKETT: No, for sure it doesn't mean that.
DR. SHACK: Oh, sorry.
MR. HACKETT: I know it means more work, so Mike maybe gets
to do less. Anyway, we'll sort that out in the next couple weeks.
MR. SEALE: One of those lateral arabesques.
MR. HACKETT: This is what I was going to talk about, and I
tried to capture, you know, the focus that Noel had in the agenda. I
guess I won't go down this in any great detail other than one piece
that's -- I guess looked back on this. It's kind of interesting. It's
been over two years since Mayfield did this brief, I think, the last
time, so it's been '97 or '96 or something since we've done it.
In the meantime, we've completed a peer review that took us
awhile, so it's good I'm doing it this year because I think that took us
almost a year to get that in place. Then I was just going to go through
pretty much in the order you see there. The focus in the office and in
the agency in general has been on outcomes rather than products, so I'll
try and point that out as we go along.
This is kind of our motherhood slide, I guess. This is what
we're trying to do, you know, provide the data and the analysis pools
necessary to do these four things here that you see. Sometimes people
think this is in conflict or have accused us that some of these things
are in conflict with pursuit of technical excellence, and sometimes
that's true. The bottom line is what the research office is really
charged to do.
The last one is more interesting for us. Over the last
couple of years is the focus I'm trying to maintain the essential
confidences for NRC, both through the contract effort and at the staff.
As you well know, we lost a lot of highly qualified folks here at NRC,
and we are losing people due to retirement, both and also our budget
declining in the contract effort, so that's been a challenge. I'll talk
some more about that.
In fact, on the next slide you'll see what scared me when I
first put it together because it's a very precipitous --
DR. SHACK: It's a slippery slope.
MR. HACKETT: Yeah, about a million over the last three
years, about a million per. We are closing projects, as it says there,
as warranted.
MR. SEALE: What about when not warranted?
MR. HACKETT: Well, that has happened. In certain cases, we
just haven't had the budget. It's a good question, Bob. When I look
back -- I guess the best way I could answer it, when I looked back at
the past also -- I didn't get it all on the viewgraph, but I think it
peaked in '94 at about $10 million. What's happened during that time
frame is the completion of a lot of the large scale fracture testing,
particularly at Oak Ridge. That was very expensive, the kind of thing
we don't need to repeat, we don't think we need to repeat. We're trying
to do that on a more leveraged basis at this point, but you know, we
have, because of budget impact, not been able to complete some of those
the way we would have liked, so not as warranted also comes into play
here.
More and more, we are looking at this incremental value of
additional research and whether or not we can justify it in the current
environment. In certain cases, we are getting questions answered,
although we -- this program has been going on for a long time now, so
the ABIG has even come to talk to us about, you know, haven't you guys
-- can't you solve this after 30 years, you know. You find yourself on
the defense, but of course as you know well, these problems are of a
class that tend to evolve on you, particularly in the area of
irradiation embrittlement.
DR. SHACK: But the European effort's closing down, too,
right? Did they shut down the spinning cylinder experiment, I heard?
MR. HACKETT: I think the spinning cylinder work is
completed, largely a success story, too, you know, because they actually
-- speaking of Oak Ridge, the Oak Ridge team who did the blind study on
the propagation of the cracks for the simulation PTS scenario in the
spinning cylinder, they came closest to the mark of any of the five or
six teams that were looking at that. You're right. I think the
spinning cylinder facility is being retired as far as I know, so some of
these things are ramping down.
MR. SEALE: One of the things about that budget profile that
you have there too is that with time, your tolerance for pain goes up.
I mean, the thing that was unacceptable at seven mil becomes tolerable
at five, and you know, so not only are you losing money, but you're
nerves are getting deadened.
MR. HACKETT: That's a good point. One of the things we got
into -- I'll bring this up at the risk of some people telling me I
probably shouldn't bring it up, but the core capabilities assessments.
As you guys know, we agonized over that for the better part of the year,
and wrapped up in there was that notion of how far do you go with this
and where do you think, you know, how long do you keep -- a good
example, Randy Nansted down at the Oak Ridge National Lab. At some
point, you're only giving Randy X number of dollars, and his group is
not thriving anymore. You might be able to keep a lower dollar level
and keep some of these experts on some kind of retainer, but they're not
doing the vigorous type of work they want to be doing. In some cases,
you know, we're starting to now run into for that reason, a lot of times
they want to go work for other people. So, we're going to get into, you
know, conflict of interest. We have one several occasions gotten into
the with some of the contract efforts. So, that's just kind of, you
know, where we're living these days.
I think a lot of this is justified because we have finished
a lot of these large scale experiments, and we don't have a continuing
need to redo those. I think for awhile we thought we did because we
were doing an awful lot of it throughout the mid-80's to the early 90's,
but I think by and large, where advanced fracture mechanics is showing
us we don't need to do those anymore to argue the vessel behavior. So,
it's been interesting.
Just as a few examples, for '99, just current examples, we
have a dosimetry effort at Oak Ridge that we're terminating because
we're running out -- that's a case where we're running out of the need
for -- we have three dosimetry programs, and it's been --
DR. KRESS: That wasn't the program intended to make a
direct measurement?
MR. HACKETT: No, no. That program is also finalizing.
That's the second one.
DR. KRESS: Oh, that's the second one.
MR. HACKETT: Yeah. The ND for the RPV effort, we have that
going at NIST, and we are completing that this year as opposed to
terminating it. Completion for us means we've identified some feasible
concepts. Then the idea is to have a workshop and transition that,
transition being the key word, I guess, to the industry, assuming the
industry wants to take that up. That's a relatively high risk path.
For 2000, we're considering at least consolidation of some
of the other efforts at Oak Ridge, which will be kind of a throwback to
what we did before. We had -- historically, there was the HSST program
which started in '67, I believe, and that was broken up in '89 because
it was perceived at that time it was too large to manage it. Now the
two separate pieces have shrunk down to the point that it probably makes
more sense per scale to recombine them. So, we're looking at that for
2000.
The peer review panel -- and you may see someone here that
you know well -- was put together. This was under when Dr. Morrison was
our office director. He had decided it had been awhile since this work
had really been wrung out by an independent panel. He put us on the
path of doing this, and the effort outlived him as office director. The
panel is there listed, as you see. Andy Murphy here coordinated it for
us as sort of impartial leader for the team, and this work was completed
in 1998.
DR. KRESS: I know all them but the fourth one.
MR. HACKETT: Yeah, he's kind of questionable.
By and large, we were happy with the panel conclusions
because they were fairly complimentary. These were their principle
conclusions. I think they pretty much across the board thought we were
doing the right things with the right mix of individuals and
laboratories. What I didn't put on here is the major concern was the
one we talked about before. We spend, I think, a good deal of time at
one of the reviews at the Oak Ridge Lab discussing the idea of the
succession plan, or if there were a succession plan. We didn't have a
good answer for that then, and I have to say we don't now.
Oak Ridge, for instance, just within this year, will
probably retire three key individuals, two who are going to retire this
month, Bill Penel and John Merkel. John Merkel, in specific, has been
with the program since its inception, so he brings a huge amount of
history and basis to what's been done down there.
MR. FONTANA: He's just a young fellow.
MR. HACKETT: John is in his early 60's.
DR. KRESS: They still have Colin and Nansted.
MR. HACKETT: Bill is still there, although he's moved on to
work on the defense side. Randy is still on board with the program, but
it's shrunken down, and not only for us losing budget. It's just, you
know, we're starting to lose some of these folks who've been doing this
for their life's work, and it's a real challenge to keep up with that.
DR. KRESS: This panel, what I gather from reading the
reports, they all went off and wrote their own individual reports.
MR. HACKETT: Right.
DR. KRESS: There wasn't a consensus report.
MR. HACKETT: There wasn't a consensus report.
DR. KRESS: But it was amazing, and I don't know if they
collaborated or not, but there was a lot of consistency.
MR. HACKETT: No, we didn't collaborate.
DR. KRESS: There is a lot of consistency throughout on all
of it.
MR. HACKETT: A lot of the comments were pretty much
mirrored. I thought there was a -- from my read of the thing, for
instance, there was almost an equal fascination on the part of most of
the panel with the vessel flaw evaluation, the characterization of the
flaws in the walls. They had a lot of interest and a lot of discussion
along those lines, and a lot of discussion about the diversity and
holding the group together. You're right. It was pretty remarkable
when you look through it.
Regulatory focus was the next thing I wanted to make sure
that we -- that was another thing that the panel got into extensively,
too. This becomes kind of easy for vessel integrity because there's
only a few issues. I think we basically retired one with the low upper
shelf evaluations. I think we've declared victory there from always
back, and we don't see that coming back to bite us at the moment.
Pressurized thermal shock is there, as it has been for
awhile, which is the Rule 10 CFR 50.61, the regulatory guide, which is
on the plan specific aspects of that. We have a major initiative
underway there in cooperation with the MRP and NEI to re-evaluate PTS
because what we now think -- now, I don't want to steal Mike's thunder.
Mike is going to be talking to you tomorrow -- Mike Mayfield -- about
this re-evaluation project, but a couple of things that have come
together. The flaw characterization effort is now at a level where we
think we know that better than we ever have. The fracture mechanics has
evolved to a point that we haven't utilized it effectively on some of
these analyses.
The third piece is the embrittlement estimates themselves.
We've completed some work, which is the second bullet there. We've
completed some work within the last year, establishing the technical
bases that's still all empirical largely, but there's some physical
basis through Bob Odett for what's going on there. We now have a
database in the embrittlement space of 600 some odd data points instead
of the infamous 177 that went into reg guide Rev. 2. The bottom line is
it's a better trend, more physically and statistically robust. The good
news is that it ends up by and large showing reduced embrittlement for
most situations. There are some exceptions there.
DR. KRESS: What's the status of the thermohydraulics
association? Is that still the same.
MR. HACKETT: The thermohydraulics has been an interesting
aspect of this thing. Mike may get into more detail on that tomorrow,
and there will also be others from our office who can address that
better than I could. One of the show stoppers in thermohydraulics, to
the best of my understanding, was how much money, how much resources it
takes to rerun these codes from scratch.
DR. KRESS: That was my --
MR. HACKETT: And the idea was that we are not going to do
that for this re-evaluation.
DR. KRESS: To the input as it was
MR. HACKETT: It's breaking -- what I hear from that quarter
is that that breaks the bank. They can't afford it with the level of
resources they have. What they're trying to do is leverage that based
on the previous IPTS studies where a lot of that work was done, and then
see if they can do anything in uncertainty space, you know, we less than
a brute force analysis, as Mike would categorize it.
DR. KRESS: Would you go back and re-evaluate the original
IPTS?
MR. HACKETT: Exactly. That's exactly what's being done,
and you can see -- you'll see that in detail from Mike tomorrow. We
just had a major meeting with the industry where we sort of bedded a
plan that was proposed by NRC but then was iterated on by NRC staff and
MRP staff. It's -- I think it's in the kind of shape now that we can go
forward on it, but there's -- we've always had fits and starts with
PTS's, as you know well. You know, we think we have the best shot at it
this time and we have a lot more attention and focus devoted to it. So,
I think, you know, we'll be able to make some real progress this time as
opposed to some of the past efforts.
DR. SHACK: But on PTS, I mean, Palisades is the only one
that's going to see even the screen criteria at 40 years.
MR. HACKETT: Right.
DR. SHACK: How many would see it at 60?
MR. HACKETT: Ah, I came prepared, although I didn't have a
slide. I didn't show this to Keith in advance, either. Somebody had
gotten into this with me previously. We didn't have a real good way of
doing this. The previous thing we had done is who might or might not be
interested in thermal annealing, which is another subject we can
discuss. When I went down this list with the Palisades, which is
obvious, they're right now projected to reach the screen criteria in
2004 or December 2003. Then I thought the answer to this question, with
the level of uncertainty we've dealt with before, I'll go back and look
at Keith's databased, you know, the RVID that they put together or RTD
data that Every put together and go in and look at the plans that right
now are looking at an adjusted RTMDT of 250 or greater. There's enough
uncertainty there that, you know, maybe they could come up on this thing
within the license renewal period.
What I came up with is a list of ten plans that, as I put on
here, may be impacted -- maybe, maybe not. It depends on how things go.
DR. KRESS: That's with the 20 year extension?
MR. HACKETT: That's with the 20 year extension. Then these
could be, obviously, candidates that would benefit from revised criteria
for pressurized thermal shock or embrittlement estimates or possibly
thermal annealing, if people were to reconsider that option, but it was
about ten plans. I think DOE had run a similar exercise where they came
up with eight or nine. I don't know, we never did compare whether it's
the same eight or nine, but it was, you know, something in that
vicinity. It is true to say that, you know, when you look at the
operating license period, it's really Palisades, you know, right now.
DR. KRESS: May I look at that?
MR. HACKETT: The pressure temperature limits, on the other
hand, that affects everybody. Then we have a recent success there that
I'll talk about where we've made some modifications in conjunction with
the ASMI group on PT limits for heat-up and cooldown. Basically what we
did is we changed -- we felt that there was significant technical
justification for changing the basis on the fracture toughness curves
from crack arrest basis to initiation basis, K1A to K1C. So, we've made
some significant progress there.
LTOP is linked to PT limits and standard review plan and
tech specs. Size assumptions and ISI always comes back around. Can we
justify a reduced size? That's always been a question on the table, and
I think the answer is probably yes, but a lot of other implications come
with that. A lot of times, you know, I know when I go to ASME code
meetings, a lot of people ask the question, you know, NRC has us do all
these enhanced ISI's of reactor vessels, but at the end of the day we
don't get credit for that. So, what are we doing in the way of, you
know, trying to get credit for ISI results.
At least in the evaluation Mike will talk about tomorrow,
you're not going to see that, but what you will see is the benefit of
enhanced ISI that was used in a laboratory environment for the PV rough
vessel and then subsequently now is being utilized for Shoreham. We're
doing that work cooperatively with EPRI. What's coming out of that is
the best ever flaw characterization of reactor vessel loads that we've
seen. Up until now, we've been basically using the Marshall
distribution unit, dating all the way back to the late 70's. So, this
is work that's finally bearing fruit.
Joe Escara is in the room, and Joe started a lot of this
work a long time ago, and I think he was foresighted in seeing that this
-- this is the kind of thing, a good example when we were talking about
cuts in resources. This program took five to ten years to bear fruit.
You know, you're putting a lot of money out in a national lab and you're
developing and enhancing ISI techniques, to the point that now you're
getting these accurate characterizations that can come to bear on this
problem. It wasn't -- by no means was it overnight. I mean, how long
ago was that, Joe? Yeah, 80's somewhere.
The technical program has -- I've always looked at it as
having three parts. There's the fracture mechanics analysis
methodologies. I guess I won't go through this line by line, but you
can see what shows up on here. You have analytical and experimental
parts. More and more, we're doing validation of the analyses method of
uses. We used to go through these two pieces and turn to Oak Ridge to
do the validation on a pretty large scale basis. We haven't been able
to afford to do that, nor do we necessarily need to do that anymore.
So, a lot of that validation is being done on a collaborative basis with
-- FALSIRE is fracture analysis of large scale international reference
experiments, I think. In the NIST program, some of you mentions spin
cylinder programs, so a lot of that work's being done there. A lot of
folks may have heard about the master curve. The master curve is
certainly a part of this and is, you know, a controversial part, though
we are devoting some resources to that, as is the industry, for longer
term, I think is the way I'd characterize it.
The second major piece technically is embrittlement
estimates. There we're looking at a continuation of test reactor
irradiations as justified to address property variability. Also looking
at less and less at this point, evaluations for thermal annealing and
reembrittlement trends. This is a lesser piece because right now we
don't have anybody exactly lined up for thermal anneal in their plant,
but the baseline technical work is there.
Mechanisms of embrittlement, this says there's significant
international involvement. There's a group called IGRDM that I think
you're aware of, the International Group of Radiation Damage Mechanisms.
Very active group. They meet typically once a year, and they will --
very stimulating kind of environment for folks who are doing mechanistic
work in these areas. A lot of their focus currently has been on what
happens down the line. If Bob Odette were standing here, he likes to
talk about -- it's kind of a funny phenomenology, but he calls it late
blooming phases, for instance. Right now, so much of the program has
been focused on copper and nickel, matrix damage. Bob is now looking at
things like what about manganese. I think that's the synergistic effect
with manganese and nickel that may not kick in until some high effluence
level. So, we're looking at those kinds of things. That's a
continually evolving picture.
I think we have a really good baseline because we know that
the situation is dominated by copper precipitation. So, copper is a key
driver, nickel is a key driver, and then matrix damage. So, we think we
have a pretty good handle on that, but there are other pieces that may
come into play.
We are doing some limited validation through evaluation
materials removed from shutdown reactors. Currently, we have the Japan
power demonstration reactor project collaborative with Jerry in Japan,
and that's through a bridge where we're evaluating materials that came
out of the JPDR.
The third technical piece --
DR. SHACK: I thought I saw something somewhere about
somebody looking at Trojan.
MR. HACKETT: I think it was on Mike's slide previously. I
left it off this one because we hadn't been able to get anywhere with it
for awhile. Trojan, as you heard, came highly controversial because
they had a huge debate with the Commission over disposal of the vessel
and the internals. As I understand, that was approved, remarkably, but
I don't know. We were negotiating at one point. We're trying to get
some core samples taken from the Trojan vessel, and that I'd probably
defer to Mike.
MR. MAYFIELD: Bill, the situation is -- Mike Mayfield from
the staff -- the situation is if we got agreement -- in fact, some of
the Oak Ridge guys went up and met with the Portland General Electric
representatives and the people at the burial site. The arrangement was
depending on how much stuff they've put in the vessel and how hot it is.
Once the vessel's on its side in the ditch, then we may be able to get
on it and take some core samples, but then again, it gets back to how
hot the interior is because once you pull the core, if the shine's too
high, you can't work with the vessel. So, we just haven't followed up
because the licensee's been real focused on getting the vessel out of
the plant on a barge and on its way to the burial site. I heard
something recently that they've picked the vessel up now, so we're
probably --
DR. SHACK: So it's really starting to move along.
MR. MAYFIELD: Yeah, it's starting to move, so it's time now
to ask Oak Ridge to get back in touch with the licensee and see what the
curie content is and to make that cut, that assessment about whether
this thing is just too hot to handle, meaning once you pull the core,
what do you do with it because what you'd have to do is then put a plug
back in and do a seal wall if the shine's too high. You know, we're not
looking at burning up people unnecessarily. So, if it can be done and
done safely and reasonably, then we'd want to pursue that. If it's just
too much of a radiological hazard, we'll bypass it. The vessel isn't
that interesting because it doesn't have that many neutrons on it. The
chemistry isn't particularly out of whack, so from an embrittlement
standpoint, it's not that interesting, but it was one more data point.
So, if we can get it, get it reasonably conveniently, we'll pursue it.
If not, we're just going to walk away from it.
DR. KRESS: How about the JPDR? Does that have the
effluence and the chemistry --
MR. MAYFIELD: No, that was a demonstration boiler in Japan.
It's only about ten to the eighteenth, and again, the chemistry wasn't
very interesting, but it was the first piece, first shot we really had
at getting some service irradiated material from a real live pressure
vessel. So, it gave us an opportunity to go look at some material that
was representative. It has enough effluence on it to -- we ought to be
seeing something.
MR. HACKETT: We continue to pursue other possibilities.
Bob Hardies is here, and he's Bob's chairman of the MRP, RVI, ITT, if
that's right. Bob, I know you gave me Maine Yankee, for instance. We
have not followed that up, but Maine Yankee is a possibility to follow
through on, is another one out there.
This Trojan thing was fascinating because the curie load on
that package was apparently impressive. It was like I think in excess
of a million curies or something that are active inside the vessel.
This is without the fuel. It's de-fueled, obviously, and just the
internals with some low density concrete they wrapped around the
internals. That was a real controversy, plus shipping the package as a
whole. So, we do continue to try and pursue those.
The third technical piece was debated over exactly what to
call this but really what we're doing with it in vessel integrity is
flaw characterization, and that's what we've been talking about, these
detailed inspections. The report, as you can see, is fairly half a D.C.
phone book thickness on the PV rough evaluation. That was the pressure
vessel research user facility that was at Oak Ridge. It's an older
combustion engineering vessel that we got extensive access to to be able
to conduct very highly qualified staff to UT examinations from the
inside. We got the best ever flaw characterization out of that.
The companion work on destructive verification of those
flaws is almost finished now. We should have that report done by June.
By and large, what it's showing is you don't see big flaws in reactor
vessel wells, and you don't see them on the surface. What you see are a
lot of a relatively high density of very small flaws near the interface
between the cladding and the base material. These are things that are
like on the order of two millimeters, and in a lot of cases are less.
The bottom line is when you run the probablistic fracture mechanics
analyses, these things do not contribute to the vessel failure
frequency.
DR. SHACK: But it does confirm then the high density that
you were seeing with the SAF?
MR. HACKETT: There is a high density of these small -- I'll
call them indications because it's wrong to even call -- they're not --
they're certainly not all crack-like. They also remain to be confirmed
across the board because you're starting to get down to the resolution
in some of the UT scans, but you do see a lot of these things. From a
metallurgical perspective, I don't think that's surprising. What would
be surprising is if you saw a lot of crack-like indications along that
interface and they were larger. They have to get to, you know, we're
probably talking six millimeters and beyond in terms of aspect to be
significant.
DR. KRESS: You still characterize those in terms of per
unit volume?
MR. HACKETT: Yeah, they are characterized in density.
First, we're looking at distribution through the wall.
DR. KRESS: Yeah.
MR. HACKETT: And then you'd see the expectation that you'd
expect. Depending on how the vessel is put together, you see a large
concentration at the interface of the cladding. If it was a single V
well that was back gouged to sound metal on the ID, you might see some
activity there. If it's a double V well, you would tend to see it at
the root of the double V.
DR. KRESS: But that's accounting for your analytical
process.
MR. HACKETT: It is, right, and then Mike will probably go
over some more details on that tomorrow. One of the papers I know we
passed to you guys as background included a revised valuation of PTS
that John Malak was one of the principal authors on. They concluded
largely on the basis of this change in the flaw characterization coming
out of the PV roughed exams. They were able to justify going to a lower
frequency, which would then, you know, logically indicate that that
could justify a lower, or higher rather, PTS screening criteria. That's
all preliminary work at this point, and Mike will go into detail on the
project to flush that out tomorrow, but that's where it's heading.
The other piece that's interesting, and going back to the
peer review, almost everyone in the peer review commented on PRODIGAL.
I think it just fascinates people. What PRODIGAL is is a program that
was developed by Rolls Royce and Associates. We supported this through
subcontract with PNNL, and it was an expert elicitation process where
they got some welders and then some welding engineers. I'm not sure --
they kept the groups separate, I guess, so they wouldn't fight too much
or whatever.
They looked at the kinds of flaws you'd expect in these
multi-task welds. Then Dick Chapman, who had the lead for this, built
this into a Monte Carlo simulation model saying if I have X number of
passes of a submerged arc weld in this type of vessel, here's what I
think we'd likely see. Then when you run PRODIGAL, by and large, it
comes out, you know, within the same scale as what we've been seeing
with Midland, with PB Rough and, you know Shoreham Data is coming along
in cooperation with the industry. So, that's been interesting.
The question then remains can we do this on a generic basis.
You know, Bill, I think you asked that earlier. The answer is I think
it's too soon to tell. We can certainly do it on like a vessel specific
basis or a -- maybe more correctly, a vendor specific basis. You know,
if you know all CE fabrication was such and such a way and you run these
models, you could probably say for CE welds of this type, I can use this
model. I don't know that we're able to generalize it more than that at
this point.
When Mike and I looked at this the other day, it's a shorter
list than it used to be, and it is. We used to have more folks under
contract than this, but the large effort, as you've heard, over many
years the course has been at Oak Ridge, and now in the form of three
programs, the HSSI program, which is heavy section steel irradiation,
which is the irradiations piece and the mechanisms piece. The HSST
program, which is really the fracture methodology validation and
development. There's also a piece there where Claude Pugh and Richard
Bass do a lot of facilitation of the international collaborations that
we have, and Richard, indeed, participates in a lot of that directly
himself.
Those are the three pieces we have there. The Naval Surface
Warfare Center, and as a subset, the U.S. Naval Academy, Professor
Odette at California, Santa Barbara. Mechanisms work, Ernie Eason at
Modeling and Computing Services in Boulder, Colorado, doing also a lot
of work on embrittlement estimates. NIST for two separate activities,
one for the NDE for RPB embrittlement, one also on dosimetry which is
ongoing. Brookhaven on dosimetry, and the University of Illinois is
really a subset also of NSWC, doing a lot of work on constraint effects
and tips. The University of Michigan is where we do the test reactor
irradiations, and a lot of that comes under the HSSI program at Oak
Ridge.
It's smaller, but it's still a fairly, gives you an idea of
the kind of mix we like to keep among the labs that the universities and
the commercial contract effort.
MR. FONTANA: But it's the 4.9 million that's --
MR. HACKETT: The 4.9 million is spread out over that
contract effort right there.
MR. FONTANA: Right.
MR. HACKETT: In terms of, like I said earlier, the office
and the NRC, of course, is a lot more outcome focused these days, so I
tried to cast this as much as possible in terms of outcome. We talked
about this one earlier, development of code case and revision to ASME
appendix G to allow the use of initiation fracture toughness in place of
arrest fracture toughness for developing PT curves.
This is a significant burden reduction. I think it remains
to be seen exactly how much, but it's more than a potential that's in
place and is endorsed by the NRC, nor formally yet but, you know, that
requires an exemption. Currently the process is on a regulatory basis,
but it's a burden reduction for those who are constrained on heat-up and
cooldown, which is a lot of plants.
There's also an increase in safety, we think, based on
reduced challenges to LTOP and -- I probably should have brought one
with curves showing how this thing gets constrained as you go up in
radiation embrittlement space, but basically you're looking at some PWR
operators who are having to do sometimes some tricky things just to get
these plants up and down, and sometimes they're not doing all the right
things in the main interest of safety. So, I think this is a
significant outcome for us just recently.
DR. SHACK: In ongoing work, what would have the biggest
impact on widening the PT limits further?
MR. HACKETT: A couple of things. This one was based on
largely the fracture methodology because we thought that over time that
-- the curves were initially based on arrest toughness, as you know,
because of this concept of a local brittle zone and that we might pop a
crack through. Over time, we've done enough testing and we've
accumulated enough years of experience to say that we don't see that
happening. So, we could see going to an initiation basis. So, a lot of
this has been fracture mechanics. There are those who could argue you
could go further still with things like the master curve. You could
evolve further in the fracture mechanics, but that's -- there's some
tricky aspects of that we could talk about in more detail.
The other piece, the other significant piece, and I think
the two other pieces are going to be the flaw characterization and the
embrittlement estimates. We haven't yet rolled the new embrittlement
estimates into this. That will make this better still for most people.
My understanding is there are some -- the limited population of BWR's
where it may make it worse for awhile, and that's being investigated. I
know Bob is involved with ASTM E900 where they've been looking at that
on an industry basis. The other piece is of course this is done still
on the basis of quarter T flaw. So, you know, that's something that's
been very difficult for us to make progress on.
I sit in on Tim Greasebock's group on ASME 11 which deals
with operating plan criteria. They've been struggling with that one
since I've been on that group since the early 90's, and haven't been
able to get out of that box, to the point that they felt that this was a
way out that was easier, and indeed it was because we got consensus on
this within a year, whereas over seven years now, they haven't been able
to gain consensus on what do we do in place of a quarter T flaw, which
dates back to WRC 175 is where that comes from.
So, there are other areas to make progress on this. This
alone is very significant, but there's room for additional progress.
DR. SHACK: Okay, but the new embrittlement curve won't help
everybody then?
MR. HACKETT: It won't help everyone is my understanding.
Bob, is there --
MR. HARDIES: I'm Bob Hardies from Baltimore Gaslight.
There are some utilities and some plants that will be hurt by it. The
ones with the really low copper and low effluence have a little higher
embrittlement than they did before, at least in the current version of
the correlation.
DR. SHACK: But aren't their estimates so low anyway that --
MR. HARDIES: Where it gets to be an issue is for the BWR's
on their leak test temperature is the one where it cramps them the most
because that's a fairly high temperature they have to get to, and some
of them are looking at the two since the staff has now finally -- I
guess everybody's convinced you can't use nuclear heat to get to the
leak test temperatures. There are some plants that I guess either have
or are looking at installing auxiliary boilers just to get to the leak
test temperatures because they don't have big pumps, so it takes forever
to get there.
DR. SHACK: A few degrees is painful to them.
MR. HARDIES: Yeah. The one other point, I guess, going
back to your question, Bill, about what else, what's the next big piece.
One of the things we'll -- tomorrow when we talk about PTS and this
overall strategy we're going to use, when we met with the industry folks
last week, I guess it was, one of the other questions we put on the
table is can we use some of these same probablistic ideas, risk informed
ideas that we're going to apply to PTS, can we bring some of those same
ideas to the table on PT limits. Maybe there's a way of going away from
the deterministic, highly structured ASME approach and do something
different. I don't know what that something would be, but it's a
subject we've at least put on the table. I think there was general
agreement that we ought to at least consider it.
DR. SHACK: PT limits just seem to affect everybody.
MR. HARDIES: PT limits affect everybody. PTS is going to
affect a relatively small number of plants, and only PWR's. So, PTS is
a much smaller subset in the past, has proven to be a plant killer kind
of issue.
DR. SHACK: It's and plant killer, yes.
MR. HARDIES: But in terms of economics, the PT limits are
probably more troubling to more people than PTS.
DR. KRESS: When you bring risk informed thinking to it, it
will be because of the short time that they're in these things?
MR. HARDIES: That or maybe the -- I just -- I can't really
answer your question because we haven't thought it through. It's
something that we would certainly welcome input from the committee, from
the industry, anybody else that has a notion on this. We know that
staying within the ASME structure, it's going to be hard. There are
only so many knobs you can twist in that analysis. The next big one to
take on, Ed mentioned the embrittlement estimates. The next big one is
the quarter T flaw. If you're going to get away from that and get down
to a -- you have to go to a significantly smaller flaw before you start
seeing much effect. Then you're hung up on well, how good does the
inspection have to be. What level of qualification would the staff want
to see before we really started relying on periodic in service
inspection to justify a reference flaw in the vessel.
So, there are those kinds of questions that suggest just
continuing to tweak with the things that are in the Appendix G analysis
maybe isn't the best success path, so let's try and open our thinking a
bit. We don't have anything to put on the table today, but it's
something we know we'd like to explore. There may not be a success
path, but it's something we know we'd like to explore.
MR. HACKETT: Or it may be that we can get enough
deterministically that that satisfies everyone for the time being. I
think it's some of the line of thinking that we started pursuing based
on the idea of the PTS re-evaluation being a test case for us for risk
informing participants, and there are obviously a lot of elements to
that. We'll see where we go.
This one I talked about. This I consider a real landmark
event for us, this completion of this NUREG here on the characterization
of the clause in the PVR rector vessel. Again, this feeds into --
you'll see the theme of burden reduction here over and over again.
That's basically what we're seeing as we examine this framework and as
we have examined it over the years. There are conservatisms built in at
almost every step of the way, and so it's not surprising that when you
start to really pull the thread on these technologies that have
developed, you start to see that you have some potential for burden
reduction. In this case, it's through PTS and then possibly if we were
to implement this for PT limits and fall characterization for PTS.
This one I guess I talked about also. This is the NUREG on
evaluation of statistical and physical bases for the embrittlement
correlations. That work was completed in 1998. We're now working
internally and also working with folks on the E10 committee. ASTM has a
standard under development called E900 that's being developed, actually
at this point ahead of the NRC Reg Guide 199, Rev. 3. I think that's a
good thing. I think the industry's been very proactive on this.
They've worked closely with us and the contractors on getting out ahead
of the issue, and I think what we're going to see is a better product
than we have by far in 199, Rev. 2.
We've put a lot of resources into development of the
annealing rule, 10 CFR 5066 and associated Reg. Guide. We also
participated in the DOE industry annealing demonstration project. As an
interesting aside, we were even offered by this group to buy the Marble
Hill Plant. The office director turned that one down, but we did get
offered the plant.
The bottom line in terms of outcomes base is we now have a
regulatory framework to do this if the need or the desire arises on
anyone's part. I think that's -- it's down a ways at this point.
Palisades, of course, was going to do this at one point, and they found
they squeezed out some extra neutrons on the dosimetry evaluation that
got on thus far to 2004, and they're not envisioning thermal annealing
at this point, but that framework is there.
DR. SHACK: Excuse me, just to come back.
MR. HACKETT: Sure.
DR. SHACK: Could the industry use E900 in lieu of the Reg.
Guide?
MR. HACKETT: Right now it's not finished, and I guess there
are different points of view on this. We have this -- one of the things
I've taken to heart in discussions and in some of Gil Milman especially
is I deal with the public law and the 1B circulatory 119 on our use of
consensus basis standards, and if you go along that logic path and the
industry develops a product in E900 that we're happy with, we could
endorse that by some regulatory mechanism with maybe appropriate
caveats. A precedent for that is what we did with the low upper shelf
evaluation because ASME took on that piece largely and we endorsed what
they did. It's now an ASME 11 Appendix K. We also put together a Reg
Guide that had some caveats on the kinds of transients. I think
transients and material property guidelines that we felt were -- help
augment that analysis.
So, I could see a path where we do a similar sort of thing,
although the industry is also -- there are a couple of pieces of this
thing. There's the embrittlement trend predictions themselves in the
database that goes along with that. Then there are issues about what to
do with surveillance and credibility, and those are really the purview
of the regulators. So, I think there's always going to be a piece of
something we need to do. The bottom line is if E900 is a document that
the NRC staff is pretty happy with, I think that makes the job that much
easier.
DR. SHACK: Do you have a time line for Rev 3 of 199?
MR. HACKETT: We do. The E900 development I think is keyed
to the end of this calendar year. Is that true, Bob? I think it was at
one point, at any rate.
MR. HARDIES: Yeah, it's still appears that way, but it was
also keyed to the end of last calendar year.
MR. HACKETT: We actually have an operating plan milestone
on this, and I might have to take an action to get it for you. I think
my recollection is that we would have the technical bases -- technical
bases are in evolution at this point, but I think we're about happy with
that. I think the idea was that we would initiate revision of the Reg
Guide in approximately fall of 2000, if what I remember from the
operator. Does that sound about right, Mike? Something on that order.
Then, of course, that's got its two plus years, probably, you know, to
go through it and actually become a regulatory product.
MR. MAYFIELD: It may be worth noting that this
embrittlement correlation comes into the regulatory firmament in two
ways. One is through the traditional use of Reg Guide 199 in estimating
shift in RTNDT. The other place the embrittlement correlations show up
is in the PTS rule. So, while you've got some more flexibility where
folks are just using the Reg Guide -- after all, a guide is just a
guide, so presumably they could seek some other approach with the staff.
For PTS, you'd have to go for an exemption of the rule because those
same embrittlement correlations, the tables are in rule. So, that's
something that we're hoping to find a way of fixing in this revision to
the PTS rule, but it does come up in two ways. So, even if ASTM meets
their schedule and even if the staff put out a Reg Guide to endorse E900
with whatever caveats, you'd still have this wrinkle with the rule that
we're going to have to straighten out.
DR. SHACK: For PTS?
MR. MAYFIELD: For PTS.
MR. HACKETT: Another outcome that's dated for this year is
that we have pursued this task of looking at the use of nondestructive
examination, correct evaluation of reactor vessel embrittlement. I
think it's safe to say this was a high risk path type effort. What our
piece of it was was to look at identification of feasible technologies
for doing this. That's a hard enough part, but then harder still in my
mind is development and then finally implementation of a device of some
sort that can do this, you know, if that ultimately is possible. What
we did through NIST Boulder was develop some technologies that are based
on ultrasound and magnetics that show feasibility for correlation with
different levels of embrittlement in vessel steels. Some of that was
done or prototype or model metallurgical scenarios. So, there's a
feasibility there, and the idea for us always was to get it to some
point like that and then transition that to the industry. That we were
going to do through the mechanism of a public workshop this year, by
8-99. We're actually thinking of doing it sooner if we can get it done,
but that's what we're going to do with that one. Again, it's a high
risk path, but there is feasibility there.
There was also in the product an outcome queue here, a new
regulatory guide on dosimetry and neutron transport calculations which
is slated for completion in 2000. The outcome here, hopefully, would be
an increased regulatory stability for the licensees through more
consistent guidance. So, one of the things we would hear from licensees
is there -- there's really only one person at NRC who does these
reviews, and we have not had specific regulatory guidance in the form of
a Reg Guide. When Mike and others started this activity a number of
years ago, the thought was to provide a more stable framework for some
of these evaluations. So, that one's coming along.
We talked about 199 and the outcomes that that would have,
both for PT limits and for PTS. Mike will talk tomorrow about the PTS
re-evaluation project which we're right now talking about completion in
December of 2001. That completion would be technical bases for
proceeding ahead with the rule change that NRR would then implement.
So, ultimately this goal would get you to probably a rule in 2003
nominally, if this goes along successfully. Mike is going to go into a
lot more detail tomorrow.
Noel also had down on the agenda some discussion of the
international and national activities that we're involved in, and I'll
touch on a number of them here, maybe not all. We do have this joint
effort with EPRI on the RPB distribution and density. This is from the
Shoreham vessel. Again, it's a good thing Bob's here because I keep,
you know, pointing to him on a lot of these things. Bob got us the
material, provided the material basically for free for us to evaluate
the Shoreham vessel welds and also provided the material for EPRI. EPRI
is using different techniques than Steve Doctor at PNNL. For us, he's
doing staff GT exams from the inside diameter, and EPRI is looking at it
from the outside diameter. I think you've got a very complementary,
cooperative program there. Then destructive verification was our piece
to do with Shoreham, which should be commencing later this year. So,
that one, I think, is a very successful example of, you know, hot too
formal collaboration. I think we have an MOU, an addendum to the EPRI
NRC MOU on that, but mostly it's been proceeding informally very well.
Also, we talked about the materials removed from JPDR is
progressing. We also talked about leverage with the collaborative
projects internationally. A lot of this is done through the Oak Ridge
Program with CLaude Piugh and Richard Bass, but we also have
participated directly in a lot of these analyses. Sean Malakas has done
a lot of work in that area on the FALSIRE programs, also on NESC. IAEA
runs a number of cooperative research programs and also collaborative
studies on PTS and other things that we have and continue to participate
in. So, we're involved with all of those, and those, by and large, have
taken the place of a lot of the large scale validation that we used to
have to bear the cost of directly in the program, mostly Oak Ridge.
Also, we talked about the standards development
organizations in both direct participation from the staff and also
probably even greater volume participation, the NRC contractors. ASME
III and IX goes without saying, I guess probably these days as much or
more focused on IX and III, but there is a lot of development with ASME.
ASME has also taken very seriously, I think, over the last year or two,
in my perception, the idea of moving faster on things. They now have I
think a process called fast track that some people might say well, does
that mean they get it done in a decade instead of 50 years.
They're talking in terms of going from meeting to meeting
now instead of -- Mike and Keith will relate to this. When we got into
the low upper shelf criteria development, that took ten years, eleven
years, '81 to '92 or something like that, whereas now you take this
thing that we did last year with implementation of the fracture
toughness -- change in the fracture toughness basis for PT limits was
done inside a year. A thermal anneal encode case was developed inside a
year, so they're moving a lot faster. They figure it's do or die. They
either move faster on these things or the industry's losing interest in
dealing with ASME on these types of issues. So, they're moving a lot
quicker than they used to.
ASTM are involved in this largely through E8, which the
fatigue and fracture people, and then E10, embrittlement correlations
and other things related to irradiation embrittlement dosimetry. The
Pressure Vessel Research Council feeds into ASME basically. ASME uses
them as basically an arm to provide them with information on where they
should go in the future on certain things. A good example of that one
was they had a PVRC task group on the master curve approach to fracture
toughness. They made recommendations to ASME IX and III. The net
result is there's a code case now and implementation of the master curve
approach for an alternate way of determining RTNDT basically. That just
passed, I believe, just passed the committee.
Of course, you know, the previous two talks here today, the
DWR vessel in the terms project and the PWRMRP. It goes without saying
we have a lot involvement with them on an ongoing basis.
The first one has been the real challenge for us, you know,
the reduced budget, because the challenge for us is we've got to do
better than what we do, more efficient utilization of resources. We are
doing more of this. We were overloading Shok, to the point that -- I
hope he doesn't want to court sometime soon, but he's doing a lot -- you
know, a lot of analyses that we used to farm out immediately to Oak
Ridge, that are going to Shok. This is going beyond decimal integrity.
We've done a lot of work in the dry cask area. There's a number of
things that we're doing in house now, compared to previously. We talked
about consolidation of contract efforts, and that's ongoing. And then
we're -- had to increase leverage through the cooperative efforts,
because we just can't afford to do it any other way.
Also, we're anticipating that we're going to complete some
major elements of this project -- program within the next three to five
years, like we've been talking about. If the PTS reevaluation project
is successful, we might be able to declare victory over PTS for a while.
And then we wouldn't have to -- you know, there may not be a need for
funds continually that particular element of work. Maybe other things
will come up that we'll have to deal with, but, you know, there are
completions there. 199 should be revised in that time frame, or at
least underway. And right now, the completion of the revised bases for
the RPV distribution, we anticipate having that completed in that time
frame, too. So, there will be major completions.
However, we certainly have seen that history has shown us
that however many things we seem to complete, you know, it's like the
roots that keep growing back up to the sidewalk, you know, whenever it's
-- you k now, new things are going to come up. The master curve isn't
necessarily new, at this point, but it's certainly highly controversial.
It holds the potential for being able to go directly to fracture
toughness from small specimens. The questions then become: what small
specimen, what types of materials, constraint, loading rates, radiation
effects on the curve shape. There are a lot of details you can go into
there. But there's a world of work to be done here and the industry is
pursuing some of that, and so are we.
But, it's -- my view would be that that's long term, at this
point. We have some of these other things in the pipeline that will
hopefully reduce licensees burden in the near term, and the master curve
might be one that we can implement long term, if we're, you know,
successful working through some of these problems.
Mike mentioned risk informing the RPV regulatory framework,
and we really don't do that right now. The PTS reevaluation project
will be our first cut at that. And, obviously, the evaluation of
embrittlement trends continues. You know, the whole biz that, you know,
we get ever more -- it's like the calculus problem, that we're creeping
up on it to the point that, you know, we've got 80-90 percent of the
picture, but I don't think we have all of it right now. And then maybe,
you know, we want to try and anticipate things, so we don't end up with
surprises in the future.
And then, I guess what I saw when I was sitting down putting
this together, the real major challenge for us in the future is just
being able to maintain the competencies both here entirely in staff and
also in contract effort to deal with the evolution of issues or
emergence of new issues, and that has become a real challenge. The NRC,
as we said, they just go back to these themes. You know, we've lost a
lot of senior people that you really can't effectively replace. And we,
also, unfortunately, have lost an intern program that was developing a
lot of younger talents to the agency that's in abeyance, at the moment.
I, for one, would like to see that reinstated. The contract effort,
we're losing senior folks there. And because of the levels of dollars
that we're at now, they're not one for one replacing these people, even
if they could.
So, those are some real challenges for us and we'll just
have to, again, try and do the best we can with it. But, it certainly
is -- we're in a different -- I think it was the Chairman or -- I'm not
sure if it was the Chairman, but there was somebody, who said that, you
know, we can't continue to do business the same way, and that's
certainly true. So, we're -- you can see where we're struggling with
some things here.
And that's kind of an overview of the whole program. And
when I talked to Noel about setting this up, he said that's what you
guys were looking for. And if there are pieces that we need to come
back and explore -- I know Mike is looking to go into more detail, I
think, with the April 7th meeting of the full committee on the PTS
piece; but, if there are other pieces, just let us know.
Are there any questions now?
MR. KRESS: On that last challenge, are you going to assume
that you have everything documented and archived and all the databases
in good shape, so when everybody disappears, it can all be retrieved in
one point?
MR. HACKETT: I'd like to say, yes. We made a lot of
progress on that I guess is probably be the way I'd answer that. One of
the things that Mike did on one of the other programs that, I think, has
been a very good thing is developed a series of CDROMS on the pipe
fracture database. We're starting to do that and consider doing that
for this vessel area, get all the new regs, get the history of the --
you know, get John Merkle on a CDROM, if you can get it. When Mr.
Taylor was still with us, he challenged us to do that with the annealing
program. His vision came to be true. He said, "No one made me
implement this and those of you who are here who are dealing with this
are going to get older or maybe be gone and when somebody wants to
anneal their vessel in 2012, are we going to have the technology and the
documentation to do that."
So, I think the answer I'd give is we're getting better at
that, but there are some things, I'm sure, that have fallen through the
cracks. But, that's been an initiative for us, too.
MR. MAYFIELD: And I'd add one thing. There's some interest
in that exact subject internationally, as well. We've had some informal
dialogue with both GRS from Germany and EDF in France about, gee, we're
starting to lose some of this information, some of the people that have
sort of been the historians that have retained all this are retiring and
moving on, so what are we going to do about that. So, there is concern
and interest in trying to document, concern with the subject and
interest in trying to do something about it, both nationally and
internationally.
The one other thing I'd like to add that Ed touched on, in
terms of maintaining competencies, and one of the things we're seeing,
as research is looked at providing assistance to some of the other
offices, NMSS, in particular, some of the technology that's been
developed for piping and pressure vessels is finding application in
evaluating dry gas -- dry storage gasses, as one example. And as we're
poking into these things, we're finding other applications. So, this is
something that is -- even as we begin to resolve some of the questions
for rapid pressure vessels, the basic technologies have application in
other parts of the agency. So, it is important that we maintain those
fundamental skills.
MR. SHACK: I have a question. It's not really the research
program, but, if you know, if we're going to extend license renewal, are
we going to have trouble with the surveillance program?
MR. HACKETT: We just -- I laugh, because we've been
debating that a lot. We just put together some guidance on that. I
think the answer is no. I don't think we have major concerns with the
surveillance program, because, by and large, with the lead factors we've
had on some of the capsules, you tend to capture some really long-term
radiation effects.
And the area where I might answer -- you know, qualify that,
is if, you know, we see something in the future we're not anticipating
now. Somebody comes up with some bizarre new core or redesign that gets
to the point of emitting next to no neutrons to the wall or something,
and they do, or maybe they change the moderator characteristics somehow,
things we can't necessarily predict right now, then we might need to
reinstitute some kind of surveillance on a case basis, I think is the
way we wrote the thing up. But, we did just -- in conjunction with NRR
and NCB, we just wrote up some guidance for license renewal for
surveillance. And it kind of goes along those lines. The bottom line
is the first cut, we don't think we have a real problem for most plants.
But, you know, there are these caveats that, if you're looking at some
major change to the way that the core is dealt with, then there might be
a need to examine that further in the future.
MR. SEALE: Or if a late bloomer show up.
MR. HACKETT: Or phases of some sort show up. There's
always a caveat there. It looks like, by and large, it's in pretty good
shape.
MR. KRESS: If my memory serves me right, which it rarely
does, the one time you had a -- for a fundamental theoretical treatment
to establish K1C, is it --
MR. HACKETT: To establish K1C as a basis for the fractured
toughness trends, for instance?
MR. KRESS: Yeah. Did that problem ever go anywhere?
MR. HACKETT: I'm trying to think of the best way to answer
that. K1C, of course, has a long history of development with consensus
codes and standards at ASTM and with ASME. And by and large, I think
that's fairly well understood and kind of wrung out for this kind of
application. And I think the feeling, or maybe more than a feeling, is
that the curves are also lower bound curves for the most part, the ASME
K1C and K1R curves.
One of the interesting aspects of the master curve concept,
which is now departing from that, is to say, let's look at this
statistically. I know Mike kicked off an effort a number of years back
that kind of migrated to become master curve. But, I think when he
envisioned it previously, it was more like, well, how about we
statistically examine K1C data or statistically examine the K1C basis
for some of what we do, and then that evolved more into a master curve
basis.
But, I think the short answer to the question is that the
K1C basis is well understood and is developed. There are iterations on
that that aren't -- they're more risk informed, I guess is probably the
way looking at it, like the master curve. You're looking at directly
measuring fracture toughness and then looking at a best estimate,
instead of a lower bound, and adding uncertainty bounds on that; whereas
the current approach is lower bound, lower bound, lower bound. You
know, you've got a quarter T flaw, you've got a lower bound K1C curve,
and you've got two times the assumed pressure that the vessel would get
to when you do some of these calculations. And the fractured toughness
piece, I think that's -- where the iterations will come in the future is
looking on making that more of a best estimate approach with some kind
of more realistic uncertainty analysis to go along with it. So, that's
where it's heading right now.
And there is an ASTM standard, and that was just completed
last year, on the master curve. And these -- well, there's two co-cases
now that have been approved by ASME that talk about a limited
application of it, not a full-based application.
MR. KRESS: The master curve is just a regression through
the data?
MR. HACKETT: It's more than that. We can have a whole
meeting on the master curve, I suppose, too. But, a couple of key
things: it really relies on the similarity of the transition fracture
curve shape for all faradaic materials in transition and, then, so, it's
going to argue from a common basis. But, then, it is basically going to
consider, you know, statistical variations. It assumes weakest link
statistics are dominating for the traction mechanism. There are a
number of key assumptions that go into it. By and large, it seems to
work pretty well predicting what happens in these materials. And there
are certain exceptions and then there are the caveats for us.
This works really great for the rest of the world, because
they have the material. In a lot of cases what we're stuck with is the
limiting material for that vessel is not in that person's surveillance
program, so what are we testing and how close is that to the vessel
material. And that -- you know, that bedevils the current analyses,
too. It's just that we -- there are enough levels of conservatism in
the current analysis that we think that's captured. When you go to
master curve, then you've got -- have to reexamine the whole thing.
Jack Strosnider, I think, is going to respond to the same.
It has to be examined in an integrated fashion. And I was -- it was a
lot easier to say than do. But, he's right. So, that's where we're
going with toughness.
MR. MAYFIELD: Were you remembering the work that Harold
Etherington had set us off on some years ago, looking at the change and
shape for the low upper shelf materials?
MR. KRESS: Yes, that's exactly right.
MR. HACKETT: That's different.
MR. MAYFIELD: Harold was challenging -- he saw that the
slope of the Sharkey curve laid over for these low upper shelf materials
and he says, why wouldn't that happen in the fractured toughness
behavior and why do you think you can get away with just indexing this
curve and maintaining its shape. We got material from the Midland
plant, the canceled BMW unit, and it had this low upper shelf and one of
the worst actor low upper shelf material. It was a Lindy 80 weld; it's
specifically the WS-70, which is sort of the tail end of these low upper
shelf weld. We put that in the HSSI radiation program. What we find is
that the mean data curve for these radiated low upper shelf materials
doesn't change much. It indexes just like you would expect. What you
see is the lower end of this caravan comes down. So that -- in that
sense, Harold's point was why isn't this curve laying over. Well, the
mean data curve doesn't, but you do see an increased scatter and the
lower values come somewhat lower than you would expect.
We're still bounded easily by the existing K1C curve. But,
you know, we were looking at it, well, one, do you capture -- is there
some safety concern we've got? No, because we're -- there's enough
conservatism in the analysis, we've bounded. But the other piece of it
was fundamentally what's going on. And for reasons, I think we just
finally threw up our hands trying to explain, what you see is this lower
bound tends to come down lower than what we see with the other
materials. But, those Linday 80 welds have a whole history of
surprises. So, we said, well, we're covered, because of the margin we
had elsewhere and covered by a lot. It's not just -- it's not a close
call.
MR. HACKETT: That's another one of John Rickle's legacies.
MR. MAYFIELD: Right.
MR. HACKETT: I guess we managed to talk about this long
enough that we're right in time for Jim.
MR. MEDOFF: Just about.
MR. SEALE: I'm impressed with the way you guys keep trying
to work yourself out of a job.
MR. MAYFIELD: In 1987, I think it was, Milt Vegans came
down the hall just about this time of year, because it was budget time,
and said, well, with the budget I just put in, in five years, I'll be
out of a job. Milt retired about a year ago and we're still flogging
away on the same issue. The materials do keep surprising us with some
of the things they do.
MR. SEALE: That may be true, but the thing that impresses
me, Mike, is that there is -- the guidance that is out there is
reasonably contemporaneous with the database, which means that it's not
sitting in somebody's shelf -- on somebody's shelf someplace or
something like that. You guys are integrating it into the process. And
I think that's your job.
MR. HACKETT: We hope we're doing it right. We think we
are.
MR. MEDOFF: My name is Jim Medoff. I'm a chemical engineer
with the New Materials in the Chemical Engineering of NRR. And,
basically, I'm here to talk about the industries and the NRC's action to
address the issue of primary water stress version cracking in control
mechanism models.
Basically, this discussion is a condensed version, a rehash
of what we discussed with NEI, the MRP, and the industry in our February
meeting, that basically brought everybody up to date with the steps that
we're taking and how we're resolving the issue. In April of '97, the
staff issued generic letter 97-01, and, basically, the generic letter
informed the PWR licensees that primary water stress version cracking
was a safety issue in the long term.
The issue has -- the industry and the NRC were basically
discussing the issue for a number of years prior to issuance of the
generic letter. And although everyone concurred that it wasn't an
immediate safety issue, we did conclude that it was a prevalent age
related degradation mechanism in the nozzles, as was demonstrated in
some of the French reactors and that we concluded that it was a
long-term safety issue. The generic --
MR. SHACK: When did this thing first start popping up in
France?
MR. MEDOFF: I think it was '89.
MR. SHACK: Okay, 10 years.
MR. MEDOFF: Basically, they requested that the addressees
provide the staff with their intent to inspect their penetration nozzles
and also we requested that the addressees provide some primary chemistry
data that might relate to contributing a PWSCC.
Now, when we issued the GL, we basically requested a 30-day
response to performance of the intent to provide the technical data and
then if they were going to provide the technical data, the request be
submitted within 120 days. But as always, we encouraged the industry to
come back with an even greater response. So when the industry responded
to the generic letter, we both got generic responses from NEI and the
vendors and the owner's groups, and we, also, got plant specific
responses from the PWR licensees.
We went -- what the staff did, at that point, was do a
review of all responses and because of the legalities with the way we do
business, we had to issue our REIs to the licensee. So, we sent out a
series of plant-specific responses. And in those responses, we had
basically four generic requests: we asked for the susceptibility
rankings of the vessel at penetrations, as compiled from the
susceptibility models that were provided in the generic responses that
were initially submitted to us; we asked for a bench marking of the
ballistic models that were in use by the vendors; we asked how the
models were going to be refined, if a plant had gone out and done some
inspections and how they were going to incorporate the inspection data;
and we asked some -- how the models incorporated plant specific
aggregation of materials data.
In December, 1990 -- as always, we encourage the plants --
the licensees to come back with an integrated response. So, in December
of 1998, NEI submitted their generic response, on behalf of the
industries. And what we -- to ease the burden on the licensee, we
basically told him to refer to the generic response, as it was
applicable to the facility and, in addition, if they were going to have
any deviations from the generic response, to identify those deviations.
Now , I thought this is an important slide to get up there,
just to show that the industry has taken a lot of steps to address the
issue. There have been a number of comprehensive inspections of the
vessel penetrations and most of these are the more susceptible plants.
Now, when the industry came back with their integrated response to us,
what they did is they identified three categories of susceptibility:
one was -- would be those plants, whose penetrations were going to have
-- had postulated cracks that would grow to 75 percent through all,
within five years of 1997; and the second category was within -- between
five and fifteen years of 1997; and the third category, which is the
least susceptible, would be those plants where the cracks were greater
than 75 percent through all 15 years, using January, 1997 as their time
line.
So, basically, we had some inspections at Point Beach, at
O'Coney, D.C. Cook, North Vandeville, Stoney. They all did
comprehensive inspections of the majority of their penetration nozzles.
In the early '90s, Palisades also did a partial inspection of their
penetration nozzles. And the only -- to date, the only plant that has
reported relevant PWSCC type indications has been D.C. Cook, and what
they did is they repaired the nozzle with the relevant flaws by
performing what they call an embedded welded repair technique.
Basically, it uses a welded prepared type, but incorporates an embedded
full upper weld that meets the embedded flaw criteria in the ASME code
section XI. And the staff of NRR has reviewed that and accepted that
approach.
MR. FONTANA: What did they find at O'Coney II?
MR. MEDOFF: At O'Coney II, they had a few penetrations with
flaws and they used both eddy current and ultrasound to characterize the
flaws. Basically, they concluded that the flaws were only a few mils
thick, because the UT wasn't picking up the relevant indications, but
the eddy current signals were.
MR. FONTANA: And how about the reinspection?
MR. MEDOFF: The reinspection, the two nozzles -- what they
did is they picked what they considered was the bounding worst case
nozzle at the plant and they reinspected a second nozzle that showed
considerable noise in the eddy current technique and they wanted to
further characterize what the signal was from. And what -- during that
reinspection, they did additional penetrant testing examinations and
what they determined was that there was significant cracking along the
profile of the weld and they characterized it as craze cracking, a
fabrication defect. What they were having was showing parallel axial
flaws around the profile of the weld and the flaws, basically, picked up
the profile of the weld. They weren't -- they didn't extend too far
above it or below it.
MR. FONTANA: And that's not much of a concern?
MR. MEDOFF: Well, what they did, they did a flaw analysis,
to determine whether the flaws were going to grow. And what we
concluded was, if you took the eddy current profiles from the 1996 exams
and you took the eddy current profiles for the 1994 exams, that the
profiles basically matched up. So, we concluded that there wasn't a
crack -- flaws. Now, what they're going to do is in -- I think it's
1999 or the year 2000, they're going to go and reinspect them a second
time, just so they can characterize whether there was any flaw growth
over the last cycle.
And, basically, we have other plants, who are volunteering
for inspection, basically, Farley, and Diablo Canon, and Santa Nogreen,
Crystal River. And, Bob, you'll correct me if I say this, but I've
heard through the grapevine that Calvert might be doing some inspections
in the license renewal term.
MR. HARTAGE: I'm not sure if that's true.
MR. MEDOFF: Your the third susceptibility.
MR. SEALE: I'm sorry, I wasn't --
MR. MEDOFF: We were going back and forth. I was just
wondering if they do inspect all.
MR. SEALE: I sort of stepped out for a moment, but could I
ask, this was just a random sample?
MR. MEDOFF: No. For the most part, these plants reflected
the plants that are in the first susceptibility category.
MR. SEALE: But, I mean, it's a sample of that?
MR. MEDOFF: Yes.
MR. SEALE: So, there's no reason to believe that O'Coney I
and III are any different from II?
MR. MEDOFF: Right. They're using O'Coney II -- the
inspections as in O'Coney --
MR. SEALE: Okay. So, if you did find a problem, there
likely would be other units, then, that would be susceptible, then, to
-- you want to verify whether or not it was showing up?
MR. MICHMAN: No, I believe they know the susceptibility of
the units and, obviously, the penetration, itself.
MR. MEDOFF: Basically, the approach of the --
MR. MICHMAN: O'Coney II was the most susceptible of the BMW
units that were currently operating. I'm not sure where the other two
--
MR. SHACK: Based on what?
MR. MEDOFF: Based on the susceptibility of the models.
MR. SEALE: They got a different one than one and three?
MR. MEDOFF: Let me go back; let me go back. When the --
when -- let me start again -- when the plants submitted their initial
responses to us on the generic letter, the generic responses provided
what they called susceptibility models. They're basically probablistic
Monte Carlos analyses that evaluate the response of a postulated flaw in
a penetration over time. And response -- the models were basically
provided by Framatome, Westinghouse, and CE. And Framatome, basically,
subcontracted it out to Union Engineering. So, basically, you initially
had three models, one from Dominion Engineering on behalf of the PWOG;
one from CEAVB, on behalf of the CEOG; and a Westinghouse model on
behalf of about half the people, members of the WOG, the other half were
endorsing the model that was endorsed by the BWOG, the Dominion
Engineering model.
Now all these models, basically, had the commonality of
being Monte Carlos probablistic models, and what they did is they
postulated flaw and see how long it took to grow to 75 percent through
all, which is basically our criteria that was agreed upon between the
industry and the NRC, as the axial form of penetration.
MR. KRESS: The growth model had the plant history of
chemistry and stress?
MR. MEDOFF: The chemistries and the fabrication and the
materials factors came into the crack initiation models and, basically,
the crack growth models were typically power loss stress models.
MR. SHACK: So the Monte Carlos is to initiate the crack and
then to grow --
MR. KRESS: It's to initiate it, and then grow it by the bad
luck model.
MR. MEDOFF: I was wondering what was Monte Carlos.
MR. KRESS: Yeah, that's what I was trying to figure out.
MR. MEDOFF: It's really a crack initiation.
MR. SEALE: And there's that much difference between the
assay, if you will, on vessels for O'Coney I, II, and III, that you
would expect that the position of O'Coney II to be due to more than the
particular choice of the random number that was used to start this off
with?
MR. MEDOFF: Well, what the BWOG did supply us with the
fabrication materials factors for all used in the BMW design plants.
So, yes, they did take that into account into their model, if I'm
getting your point.
MR. SEALE: Well, my concern is, why are they that
different? I mean -- or maybe they're not that different; I don't know.
MR. MEDOFF: Basically, the models had certain variations,
but they did take into account operating stress, dual stresses,
chemistry factors, fabrication factors, materials factors. That was all
into the crack initiation models. But, obviously, the models devised by
Westinghouse isn't exactly the same as the model devised by Dominion
Engineering. And what NEI did was take on the task of -- how do you say
-- normalizing the models.
MR. HARTAGE: Do you want me to address it just a little
bit? I don't know the specifics, but --
MR. SEALE: I'm sorry?
MR. HARTAGE: Bob Hartage.
MR. KRESS: Can you come up here by the mike?
MR. HARTAGE: Between O'Coney I, II, and III, if they were
fabricated exactly the same, then they character the same driving force,
as they figure out the number of weld passes and they figure out the
stress for the weld passes. The other thing that interacts with the
stress is the yield strength of the material, itself. And I would --
I'm making a guess here, but the yield strength for the -- there are
different heats in each of those three different vessels, because they
were fabricated --
MR. SEALE: Yeah; sure.
MR. HARTAGE: They don't have a significant effect on
initiation. And the other factor is time. They've operated different
amounts of time.
MR. SEALE: Yeah.
MR. HARTAGE: And I don't know the specific history --
MR. SEALE: I can appreciate that.
MR. HARTAGE: But those might explain it.
MR. SEALE: BMW had heat specific data, okay. They
identified all the penetrations by heat. And they were better than
others.
MR. MEDOFF: They, basically, accounted for residual stress,
as a multiple, basically, of the stress. So, Westinghouse went into --
with their models, went into things like carbide coverage and the
correct boundaries, in addition to the chemistry of the materials data,
like the fabrication data for the heat.
MR. SEALE: Were there any other -- well, in the NEI
program, did they look, then, at the fact that D.C. Cook unit II
apparently had some flaws --
MR. MEDOFF: Right.
MR. SEALE: -- that required some --
MR. MEDOFF: Exactly. What they did --
MR. SEALE: What about mere siblings of that plant, were
they looked at in any more detail?
MR. MEDOFF: Well, basically, when NEI went to normalize the
response for the industry, the plant that they did compare it to was the
-- they compared it to the response of D.C. Cook, when they postulated
the flaw to grow beyond 75 percent. And then they normalized the
susceptibilities for the other plants, based on a time line factor, when
they were postulating the crack, and their penetrations to grow to 75
percent, and that's how they came up with their histograms.
Any further questions on the models?
MR. SHACK: Do we understand why we seem to see less
cracking than the French? Do we know that their stresses, for example,
are higher? I always thought my --
MR. MEDOFF: I'm not a Ph.D., but I do understand that a lot
of the French reactors operate slightly at a higher temperature. I
don't know if that has something to do with it.
Right now, we have concluded that the integrated program
that is proposed by NEI, the MRP, and EPRI, on behalf of the industry,
is acceptable, and our basis for this is that most of the plants that
have been inspected, most of them fall into the most susceptible
category, D.C. Cook, Point Beach, O'Coney. And if they haven't
inspected, they are all volunteering to inspect or they're bounded by
inspections at the sister plants, such as O'Coney I and O'Coney III are
bounded by O'Coney II. There have been several other plants that have
been inspected that fall into the second and third categories. And at
this point, only D.C. Cook has reported relevant PWSEC-type indications.
And the last point, which is probably the most important
point, is the integrated program proposed by NEI. It's an ongoing
program and the scope is designed to allow the program to be applicable
license for all applications. Basically, when they get their time line
for evaluating -- trying to evaluate when a plant might go beyond 75
percent through all for postulated flaw, it didn't bound it just to the
40 years time frame. It took it out until it reached that point. So,
that might be within a 40-year time frame or even into the license
renewal term. And they're going to keep looking into it, in accordance
to the program that they've designed.
So what we did on March 21st, is issue a closure letter to
NEI, informing them that we accept the integrated program for addressing
the issue of PWSC and the HP nozzles. And we're going to send out some
plans -- specific closure letters and to let the licensees, that they
can refer to the integrated program when it comes to assessing their
penetration nozzle.
MR. SEALE: And this letter acknowledges the validity of
this conclusion beyond the 40 year life time?
MR. MEDOFF: I'd have to go back and double check that. I
don't think we worded it specifically that we -- to address the license
renewal --
MR. SEALE: But, you don't -- the question is: is that now
an issue that Mario is going to have to worry about --
MR. FONTANA: I'm not going to worry about it.
MR. SEALE: -- when we do the --
MR. MICHMAN: This is an issue that has to be addressed for
license renewal.
MR. MEDOFF: But that comes from a plant specific
evaluation.
MR. SEALE: Yeah, okay.
MR. MEDOFF: The plant comes in for a license renewal under
the CRDM. They have to refer to the integrated program, as it relates
to the evaluation of their penetration nozzles, and they have to satisfy
us that it's not going to be an issue.
MR. SEALE: But, they are undoubtedly going to refer to this
letter that you're just getting ready to send them to, too?
MR. MEDOFF: That's true. But, they're also going to refer
to all the inspections that have been done, and the fact that only one
plant has --
MR. SEALE: Yeah; okay.
MR. SHACK: How do they do the inspections, on the eddy
current information?
MR. MEDOFF: It's an eddy current with a rotating pancake
coil that has three different orientations with welds. And then, if the
plant has a penetration where they can't get the internal housing --
what do they call it, the sleeve -- what they do is they have the eddy
current growth that sticks in between the sleeve and the penetration
nozzle. And we were down there for the O'Coney inspections and they
were using rotating pancake coil.
When it came to the penetrant testing -- in 1994, they,
also, did some penetrant testing, but they weren't getting any results.
And they -- I forget which way they went -- but they ultimately changed
from an organic to a water soluble base. The second time they did the
penetrant testing, it worked. So, they basically changed their dye and
the soluble.
So, having been down in O'Coney and knowing the effort that
went into their inspections, and Ginai just completed some and basically
they've been in contact with Duke, in terms of qualifying the eddy
currents and having to go about doing the eddy currents analysis. We
really feel that the industry is doing a good job of going out and
inspecting their penetrations and assessing the nozzles.
Any further questions?
[No response.]
MR. MEDOFF: Thank you.
MR. SHACK: I think the rest of it seems in good shape,
except dealing with that estimate.
MR. SEALE: Yeah.
MR. SHACK: And, in fact, until that's resolved, they can't
really go anywhere. The probablistic thing is sort of hang in there
until you decided what you can do with the --
MR. SEALE: I guess the other thing that the committee might
have some interest in is the point that there is an outstanding -- there
was an outstanding set of technical issues that were identified.
Approximately half of those issues have been identified as upper tier,
if you will. It was a big fundamental that required an answer, as a
part of the policy. The other were details that were appropriate to the
negotiation of the particular position or the particular approach,
particular concerns at a given utility. And, in essence, that defines
the level at which discretion or innovation or whatever can take place
in doing the case by case assessments. And I think that's something
that might be interested, because it tells you how these guys have
decided when to quit in being specific.
MR. SHACK: Although, I think if we have Steve in there, I
think there will be enough discussion that we will probably chew up all
available time. That's what I think.
MR. DUDLEY: We have two hours to discuss items coming
forward.
MR. SHACK: I can easily see doubling his time, because I
think once we get into it --
MR. KRESS: My overall impression is I still -- this bunch
is clinging a bit too strongly to traditional way to do things. I don't
know, maybe if we -- I don't know how to get that and then -- maybe that
will come out in --
MR. SHACK: I thought Steve was the one who was putting the
kicker on it, because you can make the argument you can relax that
factor of three, which is the killer, except he wants it, because it's
what keeps him out of trouble in the severe accident high temperature
case, just because he wants that extra margin, which you don't need
under the dying basis and you can give up. So, it's the risk guide
that's eliminating you.
MR. KRESS: That's limiting.
MR. SHACK: As I understand, you know, the argument --
MR. KRESS: Well, I thought they also thought that factor
three was a good defense in there.
MR. SHACK: Yes. But, we -- well, and, again, you never
know whether we're hearing -- I mean, you know, one opinion was that,
you know, do you need the factor of three all the time to cover every
possible normal operating transient.
MR. DUDLEY: Well, the other issue that the -- if you start
considering your maximum delta P and your shutdown, startup conditions,
that's very limiting.
MR. SHACK: Yes.
MR. DUDLEY: And if you just consider --
MR. SHACK: Normal operating conditions, it's a very
different answer.
MR. DUDLEY: Definitely. The industry can live with that,
if it's being killed by your startup conditions.
MR. SEALE: Startup delta P, yeah.
MR. DUDLEY: Yeah, when you are drawing in steam. So,
maybe, some things in that area that the committee would like to comment
on.
MR. SHACK: Well, I'm not sure I understand it well enough
to comment on it, but I sure know that I don't like the answer, which is
to stop things dead in their tracks. I mean, if you're going to do
three times -- you're going to make 7,000 psi, I mean, you're not going
to give up much.
MR. DUDLEY: What do you think about the regulatory issues
they brought up? They seem to be in agreement with what needed to be
done, but they couldn't figure out how to get there in a regulatory
arena, based on OGC comments.
MR. KRESS: I thought the fear that you get around all of
those things.
MR. FONTANA: Yeah, that -- you know, it seemed like they
were working on the details of that, at this point; that, you know, OGC
wasn't really -- they might have to jump through the language a little
bit, but they did seem to have a way around that.
MR. SHACK: Yes.
MR. DUDLEY: What if I say something about --
MR. SHACK: About who?
MR. DUDLEY: -- allowing a different operational windows,
with regards to startup. I'm trying to find it. Was that in --
MR. SHACK: Yes. Startup happens to hammer them, too.
We're getting to that one later.
MR. KRESS: But, in that -- but I think the PTS guys are
going to build the way. They've got a good approach to this.
MR. DUDLEY: Yeah. When I was talking to Mike Mayfield,
what he had asked for from the subcommittee was at least verbal feedback
on what he's going to present tomorrow. He did not necessarily need to
have that information in a letter.
MR. KRESS: Okay. So, we learn tomorrow.
MR. DUDLEY: But, that still -- I think it's still on the
table, whether it needs to come before the full committee or not.
MR. SHACK: My only reservation with PTS for a long time has
been does anybody care.
MR. KRESS: Well, and it looks like -- if it looks like --
MR. SHACK: If I can live with the conservative answer, do I
need a better one, and I guess the answer is maybe in license renewal
space, I do.
MR. SEALE: Those eight clients there, the list they had, is
interesting one.
MR. SHACK: But, doing all this for Palisades --
MR. SEALE: Oh, yeah, yeah.
MR. SHACK: -- I'd say --
MR. SEALE: Ta, ta.
MR. SHACK: -- it aint worth it. So, I did feel, you know,
better that it is something like eight to ten, when we look over the
longer term.
MR. KRESS: Sometimes, if you got the database, then it's
partly -- you've got the people under my care, it may be better just to
-- I didn't agree with --
MR. SEALE: Yeah.
MR. KRESS: It may not need to take --
MR. SEALE: Well, yeah. The thing is this is as cheap as
it's ever going to be to do it.
MR. KRESS: Yeah.
MR. SHACK: No, but I thought I could get to 60 years within
--
MR. SEALE: Oh, no.
MR. KRESS: Then, I would say forget it.
MR. SHACK: Forget it. Clearly, no, you're not going to put
this thing on the shelf now. I mean, if you had to redo this rule in 10
years, you might not be able to do it.
MR. SEALE: That's what I think, this is as cheap as it's
going to be.
MR. KRESS: Well, I think people on the full committee are
going to be interested in how PTS and PT parts of it are going to be
developed. But, we will hear that tomorrow, I guess. But, I'm pretty
sure that's something --
MR. SEALE: Well, that's a judgment we'll have to make after
we hear what they have to say tomorrow.
MR. SHACK: Well, Mike, he threw out that risk informed PT
limit.
MR. KRESS: Yeah.
MR. SHACK: You know, risk informed is flying these days,
why not?
MR. SEALE: Well, I think -- well, Mike is more than that.
He's one of these guys who can park his hat on a hat rack at 50 feet.
MR. KRESS: Yeah, he's going to hit the bulls eye.
MR. SEALE: You know, I put that in the record, by the way.
MR. KRESS: Oh, we're on the record?
MR. SEALE: We don't have to be on the record anymore, do
we?
MR. SHACK: It helps me out.
MR. SEALE: Oh, it helps you; okay.
MR. KRESS: Oh, it helps you; okay.
MR. SHACK: Maybe we should have Emmet give a short
presentation.
MR. FONTANA: Yeah, and then maybe have him focus on the
text spec requirements.
MR. SHACK: Right. But, I think most of that time should be
given to Steve.
MR. SEALE: Have you noticed that Emmet is talking off the
view graphs, the -- for every sentence that he's got, about 20 percent
are words and the rest is "uh, uh, uh, uh." But, if he's answering a
question that you've asked him, he's very articulate. So, when he's up
there, it makes sense to replace him.
MR. SHACK: Emmet is another one of these walking
encyclopedias.
MR. FONTANA: Yeah, and you just sort of got to ask him the
right question to get him going.
MR. SEALE: Yeah, it's like a slot machine.
MR. SHACK: The BWRVIP, I think, is interesting, in the
sense that they've got all this. But, I don't know if there's anything
there that we need to bring to the full committee.
MR. DUDLEY: Yeah, I thought they were going to make a more
detailed presentation of BWRVIP 14.
MR. SEALE: Well, I think what we need to do there maybe,
Bill, is in the introductory remarks, which I assume you can make, that
we make the comment that we -- the subcommittee heard a review of both
the BWR and the PWR programs on materials, compatibilities, and, in
particular, the VIP program, which is moving very much -- essentially,
to a completion of the first round run through all of the existing
plants and there is a continuing status that they expect to carry over
in the license review or something like that, and then some comments
about the PWR setting up a similar program. And that ought to be
essentially all that we need.
MR. DUDLEY: This is at the April meeting?
MR. SEALE: At the April meeting, yeah. Just try to handle
that in the chairman's -- the subcommittee's chairman's remarks before
we get into the specific presentations.
MR. DUDLEY: Now, there does come up question. Once we get
a BWR license renewal application, is -- will the committee want to go
back and review the 48 BWR VIP document? Do they want to sample them or
have they -- have the committee seen enough of the sample to make a
decision that they're viable to use as a basis for them?
MR. FONTANA: We've only seen one and you're the guy that
read it, and that was BMW.
MR. SEALE: That's not a BWR.
MR. FONTANA: No, I know.
MR. SHACK: We've seen basically the one for the Showells,
you know, because --
MR. DUDLEY: Oh, that's right, we had.
MR. SHACK: And that one, we had gone through in some
detail.
MR. DUDLEY: That's right, yeah.
MR. SHACK: Noel was expecting to do VIP 14, if not in that
detail, at least some detail, which we didn't. I mean, since I've
reviewed VIP 14, I know VIP cold.
MR. DUDLEY: What I was trying to do is build up a comfort
level for the committee members to remove the need to go back and review
each individual document.
MR. FONTANA: Well, spot-check the ones you know that are
going to be important and, if you're happy with the quality --
MR. SHACK: Actually, I'm in the midst of reviewing a whole
bunch of VIP documents, at the moment, for contractor work. And maybe
what I should do is when I go through those, at least maybe identify one
or two of those we'll want to bring. And one of the problems is the
person to do the VIP 14 review was Bob Harmon, who is in St. Croix, and
wasn't going to leave St. Croix.
MR. FONTANA: Then, that's probably one reason --
MR. SHACK: That's the reason they decided on this style of
presentation, is that Bob was the man to give you the more detailed one.
MR. FONTANA: And who does he work for?
MR. SHACK: NRR. I mean, but he had planned -- you know,
one of these vacations a long time ago and wasn't about to change them.
MR. KRESS: You can't hardly blame him, can you?
MR. SHACK: No, I can't hardly blame him. So, maybe that's
what we should do, is, you know, we'll just say this for the moment and
as part of the license renewal effort, we'll try to maybe pick a session
somewhere. You know, I think we ought to look at some of these topical
reports.
MR. SEALE: I think so. I think we're obligated to do that,
just to be able to look the commissioners in the face.
MR. FONTANA: But not only that, but if we've got a VWR and
the inside is cracking, I want to know.
MR. SEALE: Yeah.
MR. FONTANA: Because, inform people -- you know the people
who read -- what's the heck that --
MR. KRESS: There's no safety issue.
MR. FONTANA: Who says?
MR. KRESS: They're not structural --
MR. FONTANA: I don't care if it's a safety issue or not.
It's cracking. Somebody is going to ask.
MR. SEALE: Well, there is a loose parts problem here, too.
MR. SHACK: There would be a safety problem if the shroud --
MR. KRESS: If the shroud --
MR. SHACK: -- ever came apart.
MR. SEALE: That's right.
MR. KRESS: The shroud would be the only place, I take it.
MR. DUDLEY: And that's interesting that that's the only
component that's part of the ASME -- covered by ASME.
MR. SHACK: But, you know, that's the wonderful thing about
stainless steel, is it can crack and it's going to hang together until
the last --
MR. SEALE: Tendril.
MR. SHACK: -- the last ligament, you know. It's not like a
pressure vessel, where all these days, one of these times it might
decided to go bang.
MR. KRESS: That's true.
MR. FONTANA: I first of a stress corrosion cracking when I
first showed up to work the first day in 1956.
MR. SHACK: I think they're still making molten salt
reactors.
MR. FONTANA: It doesn't matter what it is. Why haven't you
guys solved this problem?
MR. SHACK: That's corrosion.
MR. SEALE: That's just talking about corrosion. Stress be
darned.
MR. KRESS: Yeah, but we invented this new material out of
paper. What is it called, manubrium?
MR. SEALE: No, not molonium.
MR. KRESS: Malonium, okay.
MR. SHACK: One of my young techs was asking me the other
day whether he should stick around, you know, because you can look at
all us old geezers getting ready to go.
MR. KRESS: Material problems will always be here.
MR. SHACK: But, things -- you know, things die of fatigue
and corrosion.
MR. KRESS: Structural mechanics have a job forever.
MR. SHACK: You know, long after you retire, they'll be
dying of fatigue and corrosion.
MR. FONTANA: Well, you know one thing that was crossing my
mind about putting all these reports and information out on CDROMs and
all that, well, eventually, they're going to be about as intelligible as
Druid ruins or something like that. The question is: are there a
fairly large number of young people going through the structural
mechanics business at school, that the supply of people are going to be
there, they're going to be able to read these things.
MR. KRESS: They're learning CAD/CAM, is what they're
learning.
MR. FONTANA: I don't know, I'm asking.
MR. KRESS: That's right.
MR. SHACK: They'll learn on the job, like the rest of us.
We never studied stress corrosion cracking in school.
MR. DUDLEY: Yeah, but you -- you were in solid mechanics,
weren't you?
MR. SHACK: Yeah.
MR. DUDLEY: They offer material courses now, metallurgic
courses.
MR. KRESS: Time, temperature, and transformation.
MR. SHACK: You know, I think they probably get more now in
school than they did 20 years ago. You know, my guess is they come out
at least, you know, sort of knowing what the problems are. So, the kids
are very smarter.
MR. SEALE: No, the kids aren't smarter.
MR. SHACK: I mean smarter than James Clark Maxwell. But,
you know.
[Laughter.]
MR. SHACK: But, I know a lot more about solid mechanics
than he does.
MR. DUDLEY: Was there anything you heard from Hackett's
presentation that --
MR. SHACK: You want to follow up on, what?
MR. DUDLEY: Was there anything in Ed Hackett's presentation
that needs immediate follow up?
MR. SHACK: Stuff like that, I wouldn't think so.
MR. SEALE: It was one of those fire hole presentations.
MR. FONTANA: One of the big picture questions is: is that
value of money that's going into research now adequate. What, it's been
dropped down to $4.9 million or something like that, spread over 11
organizations.
MR. SHACK: I see Dana's comments on, you know, well, that's
4.9 million too much.
MR. KRESS: Just knows what he knows.
MR. FONTANA: I haven't read his comments yet.
MR. SHACK: I think there, the most important immediate is
the PTS, which we'll -- you know, we'll hear about tomorrow.
MR. SEALE: Here, again, you can have a comment pointing out
that all these things -- the rates are being updated to bring them in
contemporary -- consistent with a contemporary database and that sort of
thing.
MR. KRESS: And, of course, I'd like to --
MR. SHACK: Somebody has to -- you know, when I look at what
they've done on the embrittlement and, you know, Eisen's work and, you
know, I don't know why it's going to take him three years to come up
with a revision to RG 1.99.
MR. KRESS: Yeah, three years is a standard number to revise
the RGs, I guess.
MR. SHACK: You know, this is -- now, it is -- yeah, it's
such an important --
MR. KRESS: I tell you the truth, I would have liked to see
more of the details of the distribution results from the two sources
they have and compare it to the Marshall thing. We really didn't see
any --
MR. SEALE: Well, I assume Mayfield is going to say some of
that tomorrow, isn't he?
MR. SHACK: Yeah, that really comes up in PTS and that might
be the place to see. The one problem they have there is they're still
doing the destructive analysis, the benchmarks.
MR. KRESS: They're still doing that.
MR. SHACK: Yeah.
MR. KRESS: But doesn't that come up in the PT, also?
MR. SHACK: Yeah. I mean, it is the heart and sole of the
PTS. PT limits are based on this quarter of all thought. You don't use
a realistic flaw distribution.
MR. KRESS: You just say you're going to follow like this.
MR. SHACK: You've got a flaw like this.
MR. KRESS: No, I'd like to hear how it will change --
possibly change those PTs.
MR. SHACK: You know, that's one -- that's where we possibly
should have asked him, is why in the world they stick to the quarter T
flaw.
MR. KRESS: Yeah, why?
MR. SHACK: Why not use a realistic flaw distribution.
MR. KRESS: Yeah, that would be a good question.
MR. SEALE: Maybe we ought to trip Mayfield with that
tomorrow.
MR. SHACK: That's an excellent -- if he wants the risk
informed PT rules --
MR. KRESS: That's a good way to start.
MR. SHACK: You know, why not?
MR. SEALE: Yeah, that's the place to start.
MR. SHACK: Because that sure would give you a hell of a lot
different answer.
MR. SEALE: It sure would.
MR. KRESS: I thought all this stuff with Hackett -- I
thought Hackett was very good, you know.
MR. SEALE: He is.
MR. KRESS: He has good information, presented it well, and
gave a good impression of the whole program that they've got. And I
didn't defend him very well. I was more for Rudy. We may need to have
the full committee hear all about it.
MR. DUDLEY: The main reason for having that presentation
was to let you know what research is going on.
MR. SHACK: I think the main reason for having that was so
when we write the research letter, don't dump on them.
MR. KRESS: There might be a good reason to have it to the
full committee, then, so Dana can hear it and Yurak can hear it.
MR. SHACK: Yeah, you know, I --
MR. KRESS: I would want a version of Hackett's research
just for that purpose.
MR. DUDLEY: What, about a 15 minute?
MR. SEALE: Boy, that's quite a power move. But, it ought
to be something.
MR. SHACK: Well, since he doesn't have to say anything
about PTS --
MR. KRESS: Yeah, he can forget about that part.
MR. SHACK: -- he can forget about PTS.
MR. SEALE: And give us more data than he has time to talk
about.
MR. SHACK: Let's make that decision after we hear Mike
tomorrow. Mike also does a very good job.
MR. DUDLEY: He does, too. Both together, both great.
MR. SHACK: Very good. And maybe we only need one of them.
MR. DUDLEY: Yes, let's wait until tomorrow.
MR. SHACK: We certainly do need one of them, as I said,
because I think that we need it for the research letter. Because, this
program is, again, a highly visible one with big bucks. You know, the
one problem I had with Ed's presentation is, okay, those PT limits are
restrictive, why doesn't industry fix the problem. And I guarantee you
that's what Dana will come down with.
MR. KRESS: Yes, absolutely. You can almost bet on it.
MR. SHACK: Right.
MR. SEALE: Well, he's already said it in his presence.
MR. SHACK: And I didn't hear anything in Ed's presentation
that would really address that.
MR. DUDLEY: And the last one, about the penetration
cracking issue.
MR. SHACK: That was so dull.
MR. KRESS: That was sort of my -- that was my reaction of
that, too.
MR. SHACK: I did all these inspections and I couldn't find
a goddamn thing, except for two lousy cracks at D.C. Cook.
MR. DUDLEY: So, you don't need to hear about that?
MR. SHACK: No. It seems to me something the staff had to
go through. It happened in France and you really had to go see it. You
had a problem here.
MR. KRESS: They didn't have much of a choice.
MR. SHACK: They didn't have much of a choice. They've done
it. And for whatever reasons, you know, it just doesn't seem to be a
problem to us. You know, like I say, it just seemed to me they did
their job, but the results sure was dull.
MR. KRESS: Dry as dust.
MR. SHACK: I mean, it's good news, but, you know, if you're
looking for excitement --
MR. KRESS: I think you can put it away now.
[Whereupon, at 4:45 p.m., the meeting was recessed, to
reconvene at 8:30 a.m., Thursday, March 25, 1999.]

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