Materials and Metallurgy and Plant Operations - June 5, 2002

Official Transcript of Proceedings


Title: Advisory Committee on Reactor Safeguards
Materials & Metallurgy and Plant Operations
Joint Subcommittee Meeting

Docket Number: (not applicable)

Location: Rockville, Maryland

Date: Wednesday, June 5, 2002

Work Order No.: NRC-418 Pages 1-496

Court Reporters and Transcribers
1323 Rhode Island Avenue, N.W.
Washington, D.C. 20005
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JUNE 5, 2002
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The Subcommittees met at the Nuclear Regulatory Commission, Room T2B3, Two White Flint North, 11545 Rockville Pike, at 8:30 a.m., F. Peter Ford, Co-chairman, presiding.

F. PETER FORD, Co-chairman
JOHN D. SIEBER, Co-chairman

ALSO PRESENT (Continued):

ALSO PRESENT (Continued):
STEVE HUNG, Dominion Engineering
GLENN WHITE, Dominion Engineering
NATHANIEL COFIE, Structural Integrity Assn.
PETER C. RICCARDELLA, Structural Integrity Assn.
MICHAEL LASHLEY, South Texas Project
THOMAS B. HENRY, Toledo Blade
DANIEL KOFF, Cleveland Plain Dealer
JACK ROE, Scientech
ALTHEIA WYCHE, SERCH Licensing/Bechtel

Introductory Remarks, F. Peter Ford 6
Status of NRC Bulletin 2001-01 Review, Allen
Hiser 9
Status of NRC Bulletin 2002-01 Reviews, Andrea
Lee 17
Status of MRP Work on Technical Issues, Larry
Mathews 60
Presentation of John Hickling 90
NRC Assessment of Davis-Besse Martin, Glenn
White 195
MRP Inspection Plan, Peter Riccardella 248
NRC Assessment of Davis-Besse Margin, Mark
Kirk 309
Presentation of Nathaniel Cofie 339
Status of Activities at Davis-Besse, Jim
Powers and Nathaniel Cofie356
NRC 0350 Panel Activities, Jack Grobe392
Lessons Learned Task Force, Edwin Hackett 418
Management by Leakage Detection, Allen Hiser 435

(8:30 a.m.)
CO-CHAIRMAN FORD: I'd like to get started please.
The meeting will now come to order. This is the meeting of the ACRS Joint Subcommittees on Materials and Metallurgy and on Plant Operations.
I'm Peter Ford, Chairman of the Materials and Metallurgy Subcommittee. My Co-chair is Jack Sieber, Chairman of the Plant Operations Subcommittee.
The ACRS members in attendance are everybody apart from Dana Powers. They are George Apostolakis, Mario Bonaca, Thomas Kress, Graham Leitch, Victor Ransom, Stephen Rosen, William Shack, and Graham Wallis.
The purpose of this meeting is to discuss the vessel head penetration cracking and RPV head degradation issues. We've had a number of full committee and subcommittee meetings on these issues.
Ms. Maggalan Weston is a cognizant ACRS staff engineer for this meeting.
The rules for participation in today's meeting have been announced as part of the notice of this meeting, published in the Federal Register on May 21, 2002.
A transcript of the meeting is being kept and will be made available as stated in the Federal Register notice.
It is requested that speakers use one of the microphones available, identify themselves, and speak with sufficient clarity and volume so that they can be readily heard.
We've had no written comments from the members of the public regarding today's meeting.
The last letter that we wrote on this subject was in July 2001 in which we supported the issuance of the Bulletin 2001-01. In that letter and in the subsequent meetings, we raised a number of technical questions.
In his reply to the July letter, the EDO stated the answers would be given to us in early 2002. We requested that data be presented today to support the conclusion relating to three basic questions:
One, what do we know about the degree of degradation of the vessel head assemblies and what is the future predictions?
Second, what are the safety issues?
And, thirdly, what are the mitigation plans?
We shall not be discussing safety culture and impacts on the reactor oversight process as associated with, for instance, Davis-Besse, at this particular meeting.
Jack, do you have any comments?
CO-CHAIRMAN FORD: Before we proceed, Mag, do you have a statement?
MS. WESTON: Yes, one little housekeeping issue. We're going to be using the full committee books today, Tab 2. This is the same material that's for your book tomorrow. That's why you have your books, and I think I have opened them all to Tab 2.
That is all of the information that I have that you have not received in hard copy.
CO-CHAIRMAN FORD: We will now proceed with the meeting, and we will begin with Bill Bateman of the NRR, who will make some opening comments.
MEMBER WALLIS: There is no Tab 2.
MS. WESTON: Yes, Tab 2 is turned.
MEMBER WALLIS: It's not labeled as Tab 2. Oh, excuse me.
MR. BATEMAN: Okay. While your looking for your Tab 2s, which --
MR. BATEMAN: It's a pleasure to be here today. We have an ambitious schedule, as you can see. We're scheduled to go until six o'clock, and everybody on my staff hopes that we're finished by six o'clock. So that is certainly our goal and we'll do our best to get us all through by then.
And so we are looking for an interactive session. We think we're on the right track. We hope to get some good feedback from you folks today.
I know one of the things that Dr. Ford has commented on a number of times is the lack of data. I think this time we'll have more than enough data for you folks to chew on.
So why don't we get started? And I guess that would be Allen Hiser.
MR. HISER: Good morning. I'm Allen Hiser with Materials and Chemical Engineering Branch at NRR.
What I want to do this morning, very briefly to keep us ahead of schedule, is to provide a status of the review of responses to NRC Bulletin 2001-01, which was entitled "Circumferential Cracking of Vessel Head Penetration Nozzles."
We were here two months ago and provided a more detailed status with putting the inspection results in the overall context so that hopefully you had some understanding of how the data or how the inspection results are falling in line.
At this point, I want to do just one slide to give you a brief overall status. There are no new inspection findings since the April 2002 meeting and presentation.
MEMBER WALLIS: You mean nothing has been done or nothing has been found?
MR. HISER: Nothing has been found. There have been some inspections that have not identified any cracking or leakage.
MEMBER WALLIS: Then there are findings if you found nothing.
MR. HISER: Correct.
The MRP did make a presentation to the staff in late May with a proposed inspection plan. I know that is on the agenda for later this afternoon, hopefully after noon.
The NRC staff is considering a generic communication that would address interim guidance for nozzle and vessel head inspections.
We will talk a little bit this afternoon on some of the concepts and ideas that we have on that. No details at this point, but just some of the concepts that we have at the present time.
In addition, we do have interactions ongoing with the industry that will provide the technical basis for the NRC staff to develop long-term inspection requirements. There are also activities that are ongoing within the appropriate ASME code groups.
So that is basically what I wanted to say about the status.
CO-CHAIRMAN FORD: Is there going to be any more discussion on any of those bulletinized things, Allen?
MR. HISER: I believe two, three, and four will have -- we will have some ideas on later, some presentations this afternoon.
CO-CHAIRMAN FORD: So we will have some heads-up on what the generic communication will entail? For instance inspections?
MR. HISER: A lot of concepts, more at the concept sort of a level.
CO-CHAIRMAN FORD: Will you be discussing the degree of completeness of visual inspections versus 100 percent volumetric inspections?
MR. HISER: We can talk about that this afternoon.
CO-CHAIRMAN FORD: Okay. If you're not going to cover any more on the first bullet, I do have a question on it which was brought up by Dana Powers at the last meeting.
You've got this famous curve -- I've almost forgotten -- of the time since the CONY (phonetic) versus the vertical axis showing -- and I must admit to myself some degree of conviction that the simple algorithm that we have, prioritization fusion algorithm, seems to be reasonable.
However, Dana Powers brought up at the last meeting in April the statistical relevance of that, given the same number of inspections have not been made at a given time period.
Can you -- and I don't know if you remember that question. It was towards the end of the meeting. Do you have any comments?
MR. HISER: Well, clearly the level of inspections that have been performed throughout that, the plants listed on that chart, are different. The plants that have -- that would seem to provide the greatest support, you know, the plants that have identified cracking and leakage have tended to have the more intensive inspections.
There are very few plants outside of that area that have done under the head, volumetric type of inspections that are capable of detecting cracking. So many of those plants have no results because visual exams have not identified any leakage.
That doesn't mean that there is no degradation ongoing. It just means that thus far, the degradation has not progressed to the point that there are leaks apparent on the head.
We will -- what I will do this afternoon is provide a little more information on which plants have performed which kind of inspection.
MR. HISER: Maybe that will put those results in greater context.
CO-CHAIRMAN FORD: Will you also be discussing later on the completeness of that prioritization algorithm or has it served its purpose as of now?
I am referring specifically to the facts that other countries, France specifically, have got much more elongated prediction algorithm, taking into account micro-structure, stress, and position of the nozzle, et cetera.
Are the NRC or the industry planning on developing such a more complete prediction algorithm?
MR. HISER: I think that would be the -- from a technical standpoint, that would be the desire of both the NRC and the industry. I think one of the issues that the industry has run into in trying to put together a more thorough model is the lack of information in some areas.
I know that in the early mid-'90s, some of the initial modeling tried to incorporate some material parameters. And I think the results over the last several years have demonstrated that those modeling efforts were really not as successful as the current model appears to be.
So I'm not sure. Maybe the industry folks can speak to their efforts later during their presentation.
CO-CHAIRMAN FORD: Can we jump -- are you going to, Larry?
MR. MATHEWS: I don't think we were planning on addressing it specifically. Basically the model we've got right now is very simple, like you say. It has tended to sort of mash the data that we're seeing coming in from the field.
To gather -- one of the problems is the welds. Some of the flaws have been in the welds and it is very difficult to quantify the material and all that, properties from a weld material.
I guess our plan was we are going to track data by fabrication and fabricator and things like that as we do inspections. And if we start to see a demarcation, then we can try to take that into account.
But so far, we haven't got enough data on individual heats and individual penetrations to start to try to make that demarcation. So at this point in time, we don't have concrete plans to do more than track the data as we get inspections over time.
MR. HISER: And it may be, as well, that one of the biggest parameters would be residual stresses. I think there is the variability from plant to plant and uncertainties in that may tend to --
CO-CHAIRMAN FORD: But there's a generic relationship between fit-up angle and residual stress and, therefore, position that you might expect as a secondary variable.
MEMBER BONACA: I would like to ask a question. I don't need an answer now, but I would like to understand by the end of the day why visual inspections is acceptable as a means of detecting this degradation process for RCS. Why we would not accept leakage in other location of the RCS as a means of detecting cracking?
And so I would not understand why in this case, it is acceptable. Is it because of the difficulties in these inspections? Is it logical, however?
The second point -- so this is an issue I would like to understand -- the second point is I'm concerned about the projection curve, the predicting curve that you are showing. You are throwing on the curve MISDON 2 (phonetic), for example, that perform volumetric inspections. They found cracks, but they didn't have any leakage.
Therefore, you are mixing together visual results with indications from volumetric and that creates confusion, in my judgement, about that predicting curve, and I would like to understand why you are doing that.
MR. HISER: Yeah, I will try to clarify that this afternoon.
Your first question about visual inspections is also addressed in, I believe, the second to last presentation on the use of leak detection as an appropriate management tool.
MEMBER BONACA: If it is appropriate, why wouldn't it be appropriate for cracks in nozzles or, I mean, why don't we wait until we see leakage before doing anything to these plants? Why would we want to attend field inspections?
Thank you.
MR. HISER: If we need to make a distinction, we will do that in that presentation. I'm not sure that will be necessary.
And with that, I will turn it over to Andrea Lee on Bulletin 2002-01.
MS. LEE: I'm Andrea Lee from the Materials and Chemical Engineering Branch, and I'm the lead for Bulletin 2002-01 on RPV head degradation and the rest of the reactor coolant pressure boundary.
With regard to background on Bulletin 2002-01, it was issued March 18 to all PWR plants, and within 15 days, we asked licensees what kind of inspections have you done in the past to identify RPV head degradation. With those inspections, what's the ability of those inspections to determine head degradation?
In addition, after we got information on the actual inspections, we asked: what kind of deposits, descriptors such as was it residue or staining or what types of deposits; did you see what was left on the actual reactor pressure vessel head?
After we asked what was done in the past and what kinds of inspection results were obtained, we asked what kinds of plans do you have for the future to enhance inspections or what kinds of inspections, do you have planned to address this problem.
MEMBER WALLIS: So you asked what they were doing. Was there any kind of instruction as to what they should be doing?
MS. LEE: It was an information request: what kinds of things have you done; what have you seen; what are your future plans?
I will get to, in a little bit later, calls that we have had, conference calls to address the types of things that they've seen; taking experience we've had from talking with each of the licensees; making suggestions on how some of the licensees we've talked to could improve based on what we have heard from other licensees.
MEMBER WALLIS: But it is very much up to them. If you think of Davis-Besse, until they almost accidently found they had a problem, they would have reported everything was fine.
MS. LEE: Un-huh. I think there's been --
MEMBER WALLIS: It just up to them.
MS. LEE: I think there's been a lot of lessons learned from both on the industry side and on the NRC side with this interaction with the rest of the 68 plants, as well as Davis-Besse. Those types of exchanges have occurred during conference calls.
And each of these conference calls and subsequent supplements have been put on the NRC external Web site so that the public is aware of the kinds of conversations that we've had.
MS. LEE: After we asked what you've done; what you plan to do in the future, we also ask for the basis of continued operation. How can plants ensure that they met the regulatory requirements with regard to this issue?
There was also 30-day and 60-day responses to this bulletin. The 30-day responses are what are your inspection results in a detailed fashion; what kinds of things have you seen, and we have asked for documentation so that the record is clear.
And then the last of the responses was a 60-day response asking what have you done for the rest of the reactor coolant pressure boundary.
MEMBER APOSTOLAKIS: Do the resident inspectors know all of this?
MS. LEE: No, no, the inspection results--
MEMBER APOSTOLAKIS: The inspectors, the NRC resident inspectors; can they answer these questions?
MS. LEE: In a lot of cases -- there was a TI written for Bulletin 2002-01 and these are primarily the same inspections. So what we have tried to do in our interactions with the plants is to make sure resident inspectors and regional inspectors are on the actual calls.
In some cases we have gotten information that has helped to guide our interactions with the licensees. We have gotten some good insight from the resident inspectors: where to focus our area and focus the question.
So they are involved and they have been able to provide information.
MEMBER APOSTOLAKIS: I mean, if you ask them instead of the licensee to answer these questions. would they give you good answers or they really don't know?
MS. LEE: Well, one example when we had a pre-qual. with the region to give us information, the same type of questions, there were additional issues that were raised that we were able to talk to the licensee; whereas the licensee addressed it, but we had more of an informed conversation because we were able to dig a little deeper from the inspector's results.
So they have been able to give us information that has helped guide the calls and the interactions.
MR. BATEMAN: This is Bill Bateman from the staff.
In answer to that question, I don't think we were prepared to speak for every resident inspector as to whether or not they could specifically answer these questions if asked.
MEMBER APOSTOLAKIS: Is it up to them? I don't understand that. Your answer implies that it is up to them to decide whether to know or not. Aren't there any rules as to what they're supposed to know?
MEMBER BONACA: Well, the resident inspector can go every morning to the morning meeting and listen to what the results of all the inspections. I mean he has, right, hands-on on everything that takes place in the plant.
MR. GROBE: This is Jack Grobe from Region 3.
I think the residents would have a cognizance of licensee activities in this area. They wouldn't have direct knowledge necessarily of the results of the head inspection because they wouldn't have been involved in those through the past refuel outages necessarily.
So they would assist NRR in focusing activities based on their cognizance from being aware of licensee activities.
MEMBER WALLIS: Are they so far removed? I mean, can't they actually demand to see photographs of what was seen instead of relying on what somebody said they saw?
MS. LEE: Well, they have. We have seen videotapes that were provided. They've seen pictures. There is interaction in that respect, both still pictures and videotapes. And those are primarily how we've gotten some additional information that has helped us focus our calls.
MR. HISER: Yeah, I think part of the confusion may be that plants that have done inspections since last summer,- the residents, the regional inspectors are very familiar with the results, the findings, the condition of the head, things like that, and what sort of inspection was done.
Plants that have not had a refueling since the issuance of the Bulletin 2001-01, the head was not a major focus area. And I think there is much less detailed information available or detailed knowledge by the inspectors for those plants.
That's maybe where the dichotomy is occurring right now at the present time.
MEMBER BONACA: But for the boric acid corrosion prevention program, you don't have to make an inspection of the head alone. You have other symptoms you are looking for.
And one question would have been: in that 60-days, have they performed a lock-down and containment or checked some for deposition, boron deposition upon surfaces? Have they checked filters?
There are elements that can be checked even without a direct inspection of the head.
MS. LEE: One of the things we have covered in the calls for the 15-day responses is information known as 2002-13 which talks about containment error, radiation element fowling (phonetic).
Since that information has come out, licensees have addressed directly on phone calls, in some cases prompted by questions and in some cases on their own, what they're doing to look at filters and things like that in terms of fouling.
MEMBER BONACA: But it seems to be like more -- you know, I mean, some of them are addressed verbally, some in writing. Why can't we be more specific and request specific answers to questions on this?
MS. LEE: Well, we have done that.
MEMBER BONACA: So that you have consistent answers.
MS. LEE: Every time we have calls, we ask for supplements to the actual response.
MS. LEE: Both our written telephone conference summary and their supplement goes on the NRC external Web.
With regard to the 15-day responses, we received all responses except for Davis-Besse. In getting to the punch line first, we haven't identified any plants that have the same conditions of degradation as Davis-Besse.
And the way we came to the conclusion was a priority categorization scheme for contacting plants. This scheme was basically a subjective categorization by the plant to guide us in how we were going to contact licensees, and it was based on needing more information from the actual submittals.
In some cases we didn't feel we had enough clarification or verification with what was provided. And those plants reached a higher level of priority in terms of how -- the order that we were going to contact them.
CO-CHAIRMAN FORD: Surely, the prioritization would be exactly the same as the cracking prioritization out of them because cracking is a precursor to the low alloy steel corrosions; are they not?
MS. LEE: No. It's not exactly the same as the industry prioritizations for a couple of different reasons. One is if we read a response and it wasn't clear. For example, significant deposits were left on the head, and by significant something that would preclude seeing the bare metal, or if there were leaks external to the insulation such as Conoseals or canopy seal leaks, and it wasn't clear that those were repaired within the same outage that they were found.
Those types of considerations that went into this priority scheme. So it's not exactly the same as the industry cracking scheme.
MR. HISER: The other thing that maybe is counter-intuitive is that the plants that have the highest susceptibility to cracking have already done head exams. I think generally, every plant has looked at the head. So they have been able to identify the absence of that sort of degradation.
CO-CHAIRMAN FORD: Now, when you say "look at the head," Allen, do you mean using what technique? Purely visual or --
MR. HISER: Well, uh --
CO-CHAIRMAN FORD: That tells you nothing.
MR. HISER: They have looked visually. So they have been able to generally to see the interface around every nozzle. If there is significant degradation or probably -- I don't want to put a threshold. If there's degradation of a certain level, they would have been able to identify it previously.
So the plants that are the most susceptible to cracking have been, I think, in the best position to address this issue.
What is not readily apparent is the plants that have a lower susceptibility maybe have not done as extensive a visual examination of the head or maybe have not had an outage since over the last year. Those plants, we've had to rely more on photographs and other prior inspection results.
CO-CHAIRMAN SIEBER: I guess the example there, your top priority plant is Beaver Valley 1. In the chart of results from the bulletin that NRR compiled, the result was called "other." When I looked into that, "other" meant did the visual inspection, found what they interpreted to be old Conoseal leakage; the Conoseals had been repaired; that they didn't clean the head, and so there was residual boric acid crystals on the head, which they claimed came from the Conoseals. They didn't clean it because of ALARA considerations.
So that would -- and their response really wasn't all that clear as to, number one, whether they could have seen leakage from the nozzle; whether the leakage that they saw was really Conoseal leakage; and, third, did they return the head to a condition where visual inspection could be done unimpeded by deposits. So maybe that helps.
MS. LEE: And in that specific case with Beaver Valley, there were subsequent interactions with the licensee supplements to the response and future commitment to address those issues.
So that's how that particular issue was resolved.
MR. HISER: And I think Beaver Valley was a case, as well, where we got a lot of input from the resident inspectors and the regional staff who were on site when they were doing the visual exam and could provide a little bit of context.
You know, if somebody says, "There were deposits on the head and we left them there," six months ago that would have been a benign observation. Now, the context is a lot different.
And maybe it really is a thin layer, you know, a crystal thick or something like that. That's the kind of context that we have had to follow up on extensively with a lot of these plants.
CO-CHAIRMAN SIEBER: I would point out that Beaver Valley 1 is on the susceptibility list as a medium point, whereas, on the questioning list was a number one priority.
MS. LEE: Un-huh.
MR. HISER: And partly because they acknowledged leaving deposits on the head and they were moderate susceptibility to cracking. That doesn't mean the cracking is unlikely. I think, to the contrary, it's likely that they may have cracking. It may be unlikely that it's through wall at this point, but there's a certain probability that it could be.
That combination is what we saw at Davis-Besse. And maybe not -- there may not be a scaling necessarily, but the bulletin was really focused on the conditions.Boric acid on the head and some probability of nozzle cracking were the two main parameters.
MS. LEE: And one of the follow-on items with a number of these plants is commitment for future cleaning. Whereas the sensitivity may not have been there at the time, the inspection was done before leaving even, was considered insignificant deposits. The sensitivity is there now. The next time they go in, even those deposits will be cleaned off of the head.
So that's one of the things that has come out of these interactions.
CO-CHAIRMAN FORD: I guess I'm still missing a key point to this rationale here. The main point of this bulletin is, to put it in layman's terms, is to make sure we don't have another Davis-Besse sitting out there.
And your inspection method or an allowable inspection method is just to see whether there's boric acid crystals on the top of the head. That's an allowable measurement.
MS. LEE: No, that's not the --
CO-CHAIRMAN FORD: I can't see how that tells you anything at all about the degree of degradation of the low alloy steel head.
MS. LEE: That's not the only parameter that the bulletin deals with. The first few questions asks about inspection methods and how to ensure that you don't have this particular issue. So those inspection methods go toward the 101 issue of cracking.
CO-CHAIRMAN FORD: When they answer the question to give you a rationale on why they should continue to operate, do you accept the rationale that I haven't seen any boric acid on my head and, therefore, I have no problem?
MS. LEE: No. It's a combination both of what have you done inspection-wise to see -- because axial cracks come into play with this phenomenon. It's not just the 0101 concern of circumferential cracks above the nozzles.
So the first part, it's almost a combination of the two bulletins. The first part asks have you done inspections; what types of inspections have you done of the nozzles to see what you actually have in regard to cracking and degradation.
The second part asks about what have you seen in terms of deposits on the head and things like that. So it is a combination of the two issues and the two concerns.
MR. HISER: But I think, fundamentally though, if I have a head and I'm worried about degradation and I go and look at the head and see no degradation; I can check that plant off.
CO-CHAIRMAN FORD: It didn't at Bouget 3.
MR. HISER: Now it may be that there are conditions that could lead to degradation, but at the present time I do not have degradation ongoing.
CO-CHAIRMAN FORD: But my point is at Bouget 3, for instance, there was no boric acid and yet there was cracking.
MR. HISER: Right.
CO-CHAIRMAN FORD: So that's one. What we need is one more, guys, and we're dead.
MEMBER BONACA: I think, in the context of this question, I agree with that. Even for the plants that already perform inspections, clearly when they did inspections, they did not know that Davis-Besse would occur.
There are tell-tale signs that Davis-Besse was seen. For example, you know, the bottom-up spraying that they have identified and never figured out why they had it, but I'm sure that Oconee didn't look for it whenever they did an inspection.
I think it would still be wise for them to go back to the inspections, review what they did, try to remember if there were signs that Davis-Besse had identified as delta signs.
So I think just the fact of having inspected visually those heads, in the very difficult conditions of the inspections, many of them, I don't think should be just sufficient. I think that they should look back at what they did and try to interpret some other signs that may have seen.
MR. HISER: Well, I think given the information that is in the 2002-13, many of the responses address those kind of indirect indicators directly. They said -- and I think you were at a plant -- they had a used filter from their radiation monitors and a brand-new filter. They were indistinguishable.
Plants are looking at those kinds of indirect indicators as well. If I look at the head and see no degradation, that gives me a good feeling right now that I do not have a Davis-Besse situation at that plant.
Now, that doesn't tell me in five years I may not, and then it becomes incumbent on the NRC and the industry and the licensees to implement effective inspection programs to ensure not that we don't get Davis-Besse, but that we don't get down the road any of the precursors that led to Davis-Besse. That's the thing.
MEMBER WALLIS: You are very reassuring. I mean the crack growth varies by orders of magnitude and the graphs that we look at -- you are going to say that just because someone didn't see some crystals, that there is no crack there which isn't going to grow more rapidly than you thought and is going to lead to some incident?
MR. HISER: I'm saying right now we don't believe that the conditions are there at any plant.
MEMBER WALLIS: I have the concern with this slide. I mean, the statement that was made was a little more reassuring than the first one that the staff has not identified. I think it was a little different. It was ten minutes ago. I'm not particularly remembering it, but I think you wanted to reassure us that there wasn't another Davis-Besse out there.
The fact that the NRC has priority categorization doesn't have any effect on the physics. The fact that the NRC has no concern about 49 plants really surprises me.
There has to be concern about every plant out there.
MS. LEE: Yeah. With regard to the no concern bullet, that doesn't mean we don't have clarifying questions or verification questions. So some of those plants do have questions associated with them. It was prioritized as no concern just based on the order of --
MEMBER WALLIS: Or what you thought you knew before Davis-Besse.
MS. LEE: No, actually this was after, after Davis-Besse.
MEMBER WALLIS: After Davis-Besse?
MS. LEE: Yeah.
MEMBER WALLIS: After Davis-Besse, you had no concern for 49 plants?
MS. LEE: The no-concern categorization really was based on -- and the whole priority scheme is based on -- the order of contacting. And it is caveated to say we may still have clarifying questions or something that wasn't particularly clear.
MEMBER WALLIS: So when something was found at one of these 49 plants, someone is going to remember that the NRC had no concern.
CO-CHAIRMAN SIEBER: I gather the no concern means you didn't have a concern about the response to the original bulletin.
MS. LEE: Yes. There may have --
CO-CHAIRMAN SIEBER: It doesn't mean that you didn't find something.
MS. LEE: It doesn't mean no concern with the actual what would be future occurrences at the plant. It was based on the licensee response was primarily complete, but there may still be a question here or there; to just ensure that we have all the information we need to make the informed decision.
CO-CHAIRMAN SIEBER: I guess one thing that bothers me is the fact that you can have nozzle cracks and you can't find them by visual inspection unless they are through through wall and leaking. To me, that gives me little comfort.
MEMBER BONACA: That is exactly right.
MR. HISER: We'll talk about that later this afternoon, but I think --
CO-CHAIRMAN FORD: It's important line right now.
MR. HISER: The purpose of this bulletin was really short term. Do we have similar conditions at any of the other 68 plants?
The bulletin has served its purpose in that we don't think there are any other plants out there with those conditions. Now that doesn't tell us that in two years something could not develop because clearly it could.
But, for the present time, we don't think that's the case. We are working to implement inspections that will ensure that in two years we can come back and say this problem is being managed and will be for the long term.
That's where we are after. The bulletin is just a short-term instrument to give us a status report on where plants are with this degradation.
CO-CHAIRMAN FORD: You're saying here that you don't have any situations similar to Davis-Besse, based apart from the first ones issued, 100 percent volumetric; based primarily on visual. And that makes me feel really worried.
Because we may hear later today about what the specific criteria or design criteria that will give you the local annulus environment, that could give you one inch per year low alloy steel corrosion rate. We may hear that later on today.
But until we hear something definite, some design feature that would preclude that you've got to assume --
MEMBER BONACA: Yeah, until you rely on the visual, I mean, you know, certainly you know that as soon as a crack develops, it could start the process of erosion and corrosion of the head.
MR. HISER: I think that --
MEMBER BONACA: So we need to hear more about it.
CO-CHAIRMAN FORD: Are we missing something, Andrea? Visual -- you, as professionals, are sure that by looking on the head and not seeing boric acid, therefore, you do not have low alloy steel corrosion.
MR. BATEMAN: This is Bill Bateman from the staff.
I would just like to refresh everybody's memory of the process here. We issued a bulletin requesting information from the licensees with the respect of the condition of their head. We got 68 responses 15 days after we sent the bulletin out.
Those responses were under oath and affirmation. The licensee knows the condition of their heads much better than we do. And so we basically believe what they tell us in their responses.
What we have been doing since then, which is a little over two months ago, is having phone calls with licensees in a priority order here based on the quality of their response and trying to get a comfortable feeling; fill out the details that are missing; et cetera, to come to some kind of conclusion with respect to whether or not we feel they have the potential for the problem.
We have not looked, personally, at any of these heads. Well, maybe I'll take that back. Maybe we've looked at one or two heads. But again, the licensees have sent us their response under oath or affirmation and they basically have made the claim, each and every one of them, that they don't have any evidence of something similar to Davis-Besse.
So that's the process we're in.
I think to take the staff to task for not having seen each and every head and making a visual observation is not fair.
CO-CHAIRMAN FORD: Obviously, you can not go in -- you personally can not go and look at every head. I just -- I'm trying to delve into the rationale.
Right now what you're saying is essentially engineering judgement. You feel comfortable by engineering judgment based on --
MR. BATEMAN: We feel comfortable based on the licensee responses that came in under oath or affirmation, the descriptions that they put into those responses, asking them questions in a priority order of those licensees who didn't give us enough information so that we could come to a clear conclusion. Yes, we feel comfortable based on that.
Their responses and our subsequent questioning of their responses and this kind of a priority order.
MR. HISER: The two things that I guess I would add to that is if you do have corrosion ongoing, you do have water leaking, you do have boric acid, that goes somewhere. The corrosion products have a much lower density than the low alloy steel.
It's going to be obvious somewhere that something is going on. If you look back at the Davis-Besse visual examination results from their head, there were many, many, many signs on the head, containment air coolers, radiation monitors, that something was going on.
These other plants have not identified any of those kinds of indicators that we think are persuasive in indicating that there is no degradation going on in this area.
MS. LEE: And in many cases --
MEMBER LEITCH: What concerns me is that on November 9, we met here and were being briefed on the results, the early inspection results from or the early responses from Bulletin 2001-01, and one of the things that we were told at that time was that Davis-Besse, in trying to justify why they didn't have CRDM cracking at that time, referred to some earlier video tapes they had done of their head.
They did videotapes in 1996, 1998, and 2000. They claimed at that time that they were not specifically looking for CRDM cracking, but they were trying to use those tapes as a justification for why they didn't have CRDM cracking.
But they further claimed that they made those videotapes specifically looking for head degradation as a result of boric acid on the head probably from historic flange leaking and claimed that after reviewing those video tapes, from those three inspections, they were satisfied that there was no head degradation.
And so my question is: aren't we hearing the same thing from these plants?
In other words, when we probed deeper then into the Davis-Besse situation, there were questions about how, well, we couldn't see certain CRDMs very well.
I mean, is there anything here about how-- what percentage of the head they can really look at? And how does one interpret what is seen on the videotapes? Is it what is referred to as "popcorn"? Is it what is referred to as "lava"? Is there common understanding when someone says "popcorn" and somebody else says "lava"? Do we really know what we're talking about there? If somebody talks about "white deposits," "red deposits" -- I mean, there is a lot of subjectivity in those kind of words.
MEMBER BONACA: Furthermore, a number of these plants have never inspected their head, I would suspect. I mean some of the 49 plants are not concerned. They may not look at them.
MEMBER LEITCH: So what I'm saying is in the time frame of November 2001, Davis-Besse would have satisfied these criteria, not only could have, but did effectively answer this bulletin before it was written in response to questions at this meeting and answered them in a way that satisfied us all, and we were wrong.
MR. HISER: I would expect if you look at their root cause analysis report, that I think some of the information provided in there is not necessarily consistent with what the ACRS was told and what the staff was told last fall. That would be the main comment that I would make in that area.
The other thing is that, again, from the input we've gotten from the residents and the regional inspectors, from documentation, for plants that are not inspected since prior to Bulletin 2001-01, there tends to be some photographic evidence of the condition either of the head or the insulation that is directly attached to the head, and if that is undisturbed, that, again, is a positive indicator that there is nothing going on.
If you get corrosion, the products are going to go somewhere. For the short term, that provides us with the basis for the first statement on here. For longer term management, I don't know that that is an acceptable approach.
We'll talk about that later this afternoon. Because at the present time we are looking for an outlier condition, you know, gross degradation. For long term management, that's not the correct standard to use.
We want to ensure that we don't have precursors. We don't want to get -- we don't want to say how far down the path. We don't want to be on the path, overall. We don't want to preclude the industry from being on the path.
MEMBER LEITCH: So I guess what you're saying is the reason that I should have some confidence in these results versus what Davis-Besse told us in November 2001 is that these results are done -- are made with an informed judgment because we now have the history of Davis-Besse.
MS. LEE: Yeah, I think that is one of the most important distinctions to make. When we were in the November time frame, no one could have imagined that we would have discovered this type of degradation on a reactor vessel head.
We're in a different climate now. Because of Davis-Besse, there's heightened sensitivity to these types of issues, and again, the plant that I visited with regard to filter papers, and if you recall, I think it was the April 2000 picture at Davis-Besse with the corrosion pouring out of the mouse holes onto the reactor vessel studs. There were many, many indications of degradation on that head.
I think with the climate that we're in now, people have gone back, looked at their pictures; have gone back, looked at inspection results; and are doing inspections now with a more in-tuned eye and more informed decisions on what they're actually looking for.
That's why I personally think that there's much more scrutiny in terms of per-Davis-Besse and post Davis-Besse.
MEMBER LEITCH: But some of these plants have no new inspection results really since Davis-Besse. In other words, they are just manipulating old data and analyzing old data in light of the Davis-Besse incident.
In other words, a lot of this response represents not new videotapes or new photographs, but going back and looking at videotapes and photographs previously and interpreting them in light of Davis-Besse; is that --
MS. LEE: But they actually do have indicators. The indicators would always be there whether they had done an inspection or not. For example, unidentified leakage. One of the things that a lot of the plants have indicated is they have extremely low unidentified leakage. The tech specs say one gallon per minute. They're at somewhere like .06 gallons per minute.
So the indicators are an important factor with the rest of the plants, even if they haven't done inspections.
MEMBER LEITCH: Well, yeah, but the difference between .1 and .2 gallons per minute could be very significant as far as this is concerned. Your point operators may not react to that kind of change.
What I'm saying is this is small, I think, compared with the normal variability that one sees in unidentified leakage.
MR. HISER: Some of the things just to -- you know, how did some of the plants come on this high priority list is an example of programmatically they did not tell us if they had Conoseal leaks or something like that. Did they immediately clean-up the boric acid spillage?
If they did not say that, we were asking for additional information regarding their practices. There's a variety of practices in areas like that.
So we tried to look at the holistic approach, looking at all of the available information from the programmatic aspects to maybe interpreting old inspection results and any documentation of those inspections, plus the more recent inspections that clearly have been focused on this area as a prime area of concern.
So we tried to gather all that information together to make the determination in this case.
MEMBER LEITCH: Was one of the variables that you considered the ease with which the head could be completely inspected?
MS. LEE: A lot of the questions we've asked licensees very directly is did you get 100 percent inspection of 360 degrees around the circumference of each nozzle, and in some cases the answers were we got 96 with a robotic-type crawler, but we got the rest with a camera on a stick.
So we've gotten very specific in terms of what they could see, what they couldn't see, and what inspection methods they actually used.
CO-CHAIRMAN FORD: Even with conformal insulation?
MS. LEE: Pardon me?
CO-CHAIRMAN FORD: Even with insulation which is conformal to the pressure head?
MS. LEE: In the cases where there is insulation, for example, glued to the head or contoured to the head, we've had discussions about what are your plans.
In some cases, there have been nondestructive examinations performed. So --
CO-CHAIRMAN FORD: So in those cases there was nondestructive --
MS. LEE: Not in every case, but in some cases there were. In the cases where there haven't been inspections done yet, they have plans to do that in the next inspection.
CO-CHAIRMAN FORD: So it's not 100 percent then. In those cases where they were not able to do a visual --
MR. HISER: But the kind of -- I think a typical situation would be, as a part of our normal outage inspections, we look at the insulation. We have seen no disturbances on the insulation. We've seen no staining, no deposits --
MR. HISER: -- nothing like that on the insulation. We looked at the flange every outage.
MEMBER WALLIS: But are there indications of what those deposits would look like on the insulation, that they would be visible?
MR. HISER: These insulation packages are pretty much watertight.
MEMBER WALLIS: This stuff is creeping under the insulation and eating away the head and you wouldn't see anything.
PARTICIPANT: Right at the top of the insulation so you can see it.
MR. HISER: Well, they also examine the flange area. If there is anything ongoing under the insulation, we would expect that it would flow out and be visible there.
CO-CHAIRMAN FORD: Could I try to come to a kind of an agreed upon conclusion as to where we are?
MEMBER ROSEN: Peter, before that, could I --
MS. WESTON: And I have a question too.
MEMBER ROSEN: -- could I make a comment?
CO-CHAIRMAN FORD: Sure, you bet.
MEMBER ROSEN: Allen, you said something I thought was very important, which was that the root cause analysis report, presumably gave the Davis-Besse's report was what you were referring to -- gives you different information than what was provided to the staff and to the ACRS at various times; is that correct?
MR. HISER: That's my understanding. Just reading through some of the observations of their inspections.
MEMBER ROSEN: I'm saying is that what your saying?
MEMBER ROSEN: I assume someone is following that up.
MR. HISER: I believe that's my understanding.
MEMBER BONACA: Was it different or was it additional?
MR. HISER: Probably additional as much as anything. Character deposits, colors, things like that that were not -- information that we were not aware of.
MS. LEE: And also degree of cleaning the head, the level of cleaning.
MEMBER ROSEN: But I'd like to have some assurance that someone is carefully sorting that out.
MR. HISER: Regarding Davis-Besse, I think Davis-Besse has issued press releases to that effect, that there are regulatory activities going on.
MEMBER ROSEN: No, I don't really -- I am interested in what Davis-Besse says, but I would prefer to hear it from the staff, that someone in the staff is carefully sorting out what Davis-Besse told NRC and the ACRS and what they now know and wrote down in their root cause analysis report.
MR. GROBE: This is Jack Grobe from Region III.
There are two activities that are ongoing in that regard. One is follow-up inspection to the AIT inspection evaluating the results of that inspection which included not what the licensee told the ACRS, but certainly what the licensee told the staff. There's also an investigation ongoing by the Office of Investigations into various aspects of what resulted in the head degradation at Davis-Besse.
I'm not sure it is appropriate to discuss the details of exactly what issues the Office of Investigations is focusing on in a public forum.
MEMBER ROSEN: Thank you.
MS. WESTON: I have a question. How much information do you get documentation to independently verify the statements that are made by the licensees? For instance, photographs, videotapes, things like that. Does the staff actually get that information and look at it independently to see?
And I'm thinking basically of the Davis-Besse photo that apparently had been taken some time before it was provided. What do you do to independently verify any of this information?
MS. LEE: In a lot of cases, the licensees have included pictures right with their initial response and also indicate that they have videos. We have followed up with some of the plants and asked for actual videos.
Also the residents are an important factor in that as well. Because a lot of times, they are the first in line that have seen these pictures, seen the videos, were with the licensees when the actual inspections were occurring. So there is the opportunity for independent verification.
And I think in terms of Davis-Besse as Allen said, there were some differences in what was provided back in the November and December time frame and then what was provided after the degradation was discovered.
So again, as Jack said, there is follow-up, investigative follow-up as to sorting out all of that and what was provided and how it differs now.
MS. WESTON: So my question, then, is how do you assure that is not happening again?
MS. LEE: I think in terms of the information that we have gotten and the information that we have followed up on, we try to do integrated types of reviews both -- as Bill said, it's under oath and affirmation. We go with that as the first line.
But we've constructed the questions to dig deeper into what they've provided. In some cases, we have asked for additional pictures, asked for additional video and additional evaluation of that with regard to what the resident saw right directly on conference calls. We try to sort through as much information as we can get at the time.
MR. HISER: In at least one case there were some photos that we were provided of the condition of the insulation, as an example. It appeared, to us, to indicate some sort of degradation of the insulation. It wasn't obvious if it was external, if it was from the head.
In that case, the licensee went in, removed the pieces of insulation, did a bare metal visual exam of the head itself, and confirmed that there wasn't a degradation at that point.
It has been a myriad of approaches to try and to reach conclusion on each plant. But at this point, there are still some outstanding plants that we need to nail down the final details on, but in an overall sense, we have a very good feeling that there is not significant degradation going on.
MEMBER WALLIS: How big are these responses? Are they two pages, a thousand pages, ten thousand?
MS. LEE: No.
MS. LEE: Did you say a thousand?
MS. LEE: No, it's not a thousand. It varies. Typically they may be like, for example, the 15-day responses, they could be 40 pages; they could be 20 pages.
MEMBER WALLIS: So you've read 68 20-page responses?
MS. LEE: Some --
MEMBER WALLIS: So it come down to what a professor grades in one day?
MS. LEE: -- on average.
MEMBER WALLIS: The kind of thing a professor grades in one day?
MS. LEE: No.
MEMBER WALLIS: You're only 20 percent complete in a month?
MS. LEE: You're talking about the 60-day responses now? You're going down to --
MEMBER WALLIS: Oh, am I going down to the -- am I out of -- okay. I'm sorry.
MS. LEE: Yeah. We were discussing, really -- the original discussion was on the 15-day response.
MEMBER WALLIS: So they have a fat one so that they are much bigger?
MS. LEE: Well, the 60 -- I'll just go on to the end of the slide -- the 60-day responses were due May 18. And we've gotten the last of them in at the end of last month, the end of May.
The staff has begun the review. It's been about 20 percent done.
MEMBER WALLIS: Those are the fat ones?
MS. LEE: The 60-day responses are the rest of the reactor coolant pressure boundary.
MEMBER WALLIS: Oh, the rest of them, okay.
MS. LEE: And again, that varies. There are some that are 40 pages. There are some that are less.
MEMBER WALLIS: So the 15-day responses -- I'm sorry -- have all been reviewed thoroughly?
MS. LEE: Yes.
MS. LEE: Yes. And just another note about the 60-day responses. Some of them may refer back to past programs on boric acid corrosion programs. So in terms of the length of them, they may be smaller because they are referring back to information that was provided on the docket.
MEMBER WALLIS: Isn't part of the problem in reviewing is that you allow them too much latitude in the way in which they present the evidence?
If you were very firm about that you must have evidence of 360 degree inspection of every nozzle -- we want to see it. We want it at a certain place in the report -- then you could run through them all and see if there was any concern.
MS. LEE: Un-huh.
MEMBER WALLIS: If every report looks different, it is much more difficult to review it, isn't it?
CO-CHAIRMAN FORD: I'd like to bring this one towards a conclusion.
MEMBER BONACA: Could I just make one? We talked about Davis-Besse, and I think Davis-Besse gives us the wrong comfort in my judgment. Because however responsible Davis-Besse will be found to be, we have to recognize we were all surprised by the finding we had at Davis-Besse. We did not -- I did not expect -- that kind of degradation.
Therefore, I don't think we can be comfortable about all the remaining plants out there that are sitting with insulation on their heads expecting that what will happen will be either what we discovered last year, that axial cracks might become circumferential, or we will discover this year that cracks may become degradation of the head. There may be something else that is developing there.
So I think it is important that we don't get too much comfort with the fact that maybe Davis-Besse made some wrong judgments.
MR. HISER: I think short-term comfort is all. For today, I think we have comfort. For the future, we need --
MEMBER WALLIS: Could I have just one quick question for the fact -- you may have said this, but of the seven, four, and eight plants that your contacting, what is the status of that? Have those contacts been made or are they yet future?
MS. LEE: For all of the plants and even the majority of the no-concerns plants, the contacts have been made. The calls have been documented and the supplements are coming in. The majority have come in, have been documented and put on the Web site.
MEMBER WALLIS: I'm not sure I understood your answer. For the high, medium and low priority plants, they have all been contacted?
MS. LEE: Yes. And then some of the no-concerns plants that we may have clarifying questions on, the majority of those have been contacted as well.
CO-CHAIRMAN FORD: Let me finish off, unless there's any burning questions, with a -- could you keep that up please, Andrea?
I'd like to suggest that a better wording which would be a compromise wording of the first statement there is that you have not identified any plants with the gross lava flows that you have observed at Davis-Besse.
CO-CHAIRMAN SIEBER: However, until we do the 100 percent examination on all plants or until we understand the chemical and geometrical aspects that would give rise to one inch per year corrosion rates, you can't assume that there isn't an incipient Davis-Besse out there.
Is that a fair compromise statement?
MR. HISER: At this point, we are not far down the path. What we need to do now is make sure that nobody is on the path that would lead to Davis-Besse.
MR. HISER: I think that's correct.
CO-CHAIRMAN SIEBER: Maybe as another sort of summary of what I thought I heard when we complained about visual might not be being adequate enough to identify cracking, visual was originally chosen because of fracture mechanics arguments that say even if it leaks a little bit, it is not going to separate and go sail on up to the roof of the containment, which I thought was okay at the time.
But that is just the first step. Sooner or later -- and you indicated it yourself -- that you've got to move to a better inspection technique than a visual or the camera on a stick.
MR. HISER: That's correct.
CO-CHAIRMAN SIEBER: Is that the right impression?
MR. HISER: I think that is correct. I think we will talk about that a little bit later this afternoon, but I think Davis-Besse has raised the bar a little bit in terms of the information that we need. How far down the path of leakage and cracking are we comfortable with?
It may be that we need to move back quite a bit, push the bar back.
CO-CHAIRMAN SIEBER: Okay. Mr. Chairman, I now feel comfortable that we can move on.
CO-CHAIRMAN FORD: Okay. Andrea, Allen, thank you very much indeed.
Larry, are you up?
MEMBER WALLIS: That's a new reactor design you've got there?
MR. MATHEWS: Yes, it has plenty of containment.
MEMBER ROSEN: This is some report.
CO-CHAIRMAN FORD: Larry, I understand that Glenn White wants to give a presentation before lunch. Can you arrange, whatever you are both going to do, so we can get Glenn in before lunch?
MS. KING: Yeah, we currently had that planned for the --
CO-CHAIRMAN FORD: Very good. Excellent.
MS. KING: -- for the two and a half hours.
MR. MATHEWS: I'm Larry Mathews, by the way, from Southern Nuclear Operating Company and the Chairman of Alloy 600 Issues Task Group of the EPRI Materials and Liability Program.
This is Christine King, the project manager from EPRI. We'll have other speakers and I will go over that on the agenda here.
I have a few minutes on the status. Then we're going to turn it over to somebody who knows a lot more about this stuff than I do. We have John Hickling from EPRI, who will make a presentation on our Alloy 600 crack growth rate work and the expert panel and where we stand on that.
Then we have Pete Riccardella from Structural Integrity, who will discuss the probablistic fracture mechanics model, and also how he used that or how we used that as the basis for our initial cut at an inspection plan.
I have just a few minutes on collateral damage.
Then Glenn White from Dominion Engineering will come up and make a presentation on the technical assessment that we have ongoing.
Then later this afternoon, we are going to talk about the inspection plan and where we stand on that.
CO-CHAIRMAN FORD: Will you be discussing at all during the day any work on the physics of how you can get one inch per year, low alloy steel corrosion rate?
MR. MATHEWS: That's Glenn's presentation.
MEMBER WALLIS: I guess it is chemistry, too.
CO-CHAIRMAN FORD: By "physics," I meant atom by atom.
MR. MATHEWS: Well, it's physics. Chemistry is a subset of physics.
MEMBER BONACA: What's MRP? What's MRP stands for?
MR. MATHEWS: Material Reliability Program.
This is a flow chart -- and I can't see it -- this is a flow chart of basically the strategic plan that we have laid out for addressing the head penetration cracking issue. We have a similar one for the VC summer type issues.
We did not include in here work on Davis-Besse. This was put together before Davis-Besse. In fact, our initial cut at the inspection plan wasn't addressing the Davis-Besse issue. We were saying that it should be relied upon by -- well, we should rely on the 8805 program and improvements that need to be made perhaps to that program. However, based on comments we got, we are going back to take a look at what we really want to say in the inspection plan.
MS. WESTON: Larry, excuse me. Members, there is a larger version of this, page number 17, handwritten 17 in your book.
CO-CHAIRMAN FORD: Thank you, Mag.
MR. MATHEWS: How would you get that?
MS. WESTON: Magic.
MEMBER APOSTOLAKIS: Are all of these in the book?
MS. WESTON: I'm not sure. This is from a previous presentation. I will tell you if the page is there in the book. But you have this handout which has them, but I have some of these duplicate slides that are in the book.
MS. WESTON: So handwritten page 17 --
MS. WESTON: -- under Tab 2, has this in a larger version.
MEMBER WALLIS: Is there some rationale to this figure?
MR. MATHEWS: We ultimately want to arrive at a final reactor pressure vessel head nozzle safety assessment that would be submitted to the staff. And all of these other things are what we're working on to flow into that, including and what we will talk about today are the ones that are highlighted in pink or red.
The susceptibility rankings briefly. We are going to have an extensive presentation on the crack growth rate and the probablistic fracture mechanics in the inspection plan later this afternoon.
MEMBER WALLIS: So it is all cracking?
MR. MATHEWS: It's all cracking on this chart. The MRP is doing work relative to the wastage issue, and Glenn will be discussing what he has been working on at the end.
MEMBER WALLIS: Now, two questions. First of all, this is all Alloy 600 and 182 and 82?
MEMBER WALLIS: Anything on 690?
MR. MATHEWS: No, not in here.
MEMBER WALLIS: Is there somewhere?
MR. MATHEWS: It's going to be looked at, yes, but we don't have it now.
MEMBER WALLIS: I ask the question because in all likelihood some of the stations will be going to 690 Alloy 52 replacements where necessary.
MR. MATHEWS: Soon. Yes.
MEMBER WALLIS: And therefore, presumably the staff are going to ask for some quantification of the fact of improvement.
MR. MATHEWS: Yes, and there is some information out there, and it will all be pulled together. Ultimately, the inspection plan should be addressing what's the right thing to do for those materials also.
MEMBER WALLIS: Which comes to my second question: what is the time line?
MR. MATHEWS: We are shooting for this in the third quarter of this year.
MEMBER WALLIS: So a lot -- most of these have been finished?
MR. MATHEWS: Most of them are very far down the road.
MEMBER APOSTOLAKIS: Was this -- this was not started because of Davis-Besse, right?
MR. MATHEWS: No, no. This was started because of Oconee.
MEMBER APOSTOLAKIS: So coming back to Dr. Wallis' question, where do we enter this?
MR. MATHEWS: Well, it's all parallel really. The susceptibility ranking was the first thing that we put together. It was just the time and temperature ranking to try and figure out what plants were most susceptible and need to be concerned.
So that was put together and I guess it was actually submitted to the staff in response to 2001-01.
MEMBER APOSTOLAKIS: So do the colors mean anything?
MR. MATHEWS: The red means it's just what we're going to be talking about today. This is the final product color, and they're pretty.
MR. MATHEWS: The green, I think, was stuff that we were actively working on at that point in time when put these colors. You did the colors?
MS. KING: I did the coloring. Christine King with EPRI.
The green are things that we have interacted with the staff on.
Some issues are red here today. It doesn't mean we haven't talked to the staff about it. It just means that we're here to talk to you guys about it today.
The yellow are things that we would like to have interactions with NRC staff on. When we get to a risk final, put together a risk assessment, and we would also like to talk to them about the inspection technology demonstrations that we have been ongoing at the EPRI and DE center.
CO-CHAIRMAN FORD: When you say "would like to," Christine, this is one of the other questions I had, is not only the timing, third quarter this year for the blue, but at what points do you have interactions with the staff on a down-and-dirty basis, data-to-data basis?
MR. MATHEWS: We've already had interactions on several of these crack growth rates and the probablistic fracture mechanics. We've had -- I thought it was a pretty down-and-dirty meeting.
MR. MATHEWS: A couple of meetings on those issues with the staff and --
MS. KING: Yeah. We've spoken to the staff a few times on crack growth rate as well as PFM. We've been interacting on the PFM model since last September with the staff and incorporating comments and changes.
MEMBER APOSTOLAKIS: Again, is this going to be the traditional scientist's approach and the expert's approach to this? Or is it going to be a realistic risk assessment?
MEMBER APOSTOLAKIS: For example, if I look at this and I know what Davis-Besse did, where would I go and say, "Well, gee, this is really where they did things that were surprising"?
Like visual inspection guidelines, are you going to assume that these will be performed in a way that the intended result will be, in fact, achieved? Are you going to assume that the crack growth rates are the scientific rates, when I read here that the B&W owner's group had underestimated those rates in their regional calculations?
I mean, are you going to have issues like that in here? Otherwise the result would be ten to the minus X and we pick X?
MEMBER APOSTOLAKIS: Well, I mean, at some point you have to draw the line and say they are not doing it. The program is there, but they are not implementing it correctly.
I know one of our issues addresses safety culture issues, but why else are we doing this?
MR. MATHEWS: The inspection plan is going to be finalized and out to the industry. It is my understanding that already INPO in their visits to the sites are looking into how plants have done boric acid walk-downs, et cetera.
The inspection plan would probably ultimately be audited by the industry itself by INPO. That would probably be the way that it would go.
MEMBER APOSTOLAKIS: Shouldn't there be other boxes with question marks inside feeding into the risk assessment for somebody else to worry about? Or is this the only thing that goes into the risk assessment?
It says probablistic fracture mechanics and there is the arrow to the risk assessment which is of concern to me.
MR. MATHEWS: Everything is feeding into the risk assessment. All of it, ultimately if you look at it, gets into that box.
MEMBER APOSTOLAKIS: But this is the material expert's review, isn't it?
MR. COZENS: This is Kurt Cozens from NEI.
And I might be able to help just a shade on this because I think I understand what you are asking, and if I might just interject for a second.
The MRP process has an executive steering committee, and when we say executives we are talking about the chief nuclear level. These individuals that sit on this executive board have and do review the technical work that has been put out by the ITG, reviewed by its own infrastructure that critiques this.
They look at this, not only from a technical issue, but from what I'll call the policy level issue of what is the right thing to do. And I think that is the essence of what you're looking at.
Not only what do the engineering numbers say, but is that really the right thing to do in managing their plants?
So that is a very big consideration. I believe the staff is looking at that from the same point of view. You know, the numbers may tell us one thing, but when you really look at the real world, what are the things that should be accomplished?
And there is a lot of oversight at a high level within the industry to ask some of those tough questions.
Larry, I defer that back to you. But I think, I believe that's what you were driving to, wasn't it?
MEMBER APOSTOLAKIS: Well, these are policy.
MR. MATHEWS: The risk assessment question or risk assessment that is being done is not just a bare bones. We are putting conservatism in there at various stages, and you'll see some of that in Pete's discussion of the PFM work.
MS. KING: And I guess I would like to point out that this whole thing is fed with the inspection data that we are getting from the field. We continue to evaluate that data, what we're finding in the field, and reviewing our work.
MEMBER APOSTOLAKIS: But if I want to, I mean there is such a thing as Defense in Depth, and the structuralist interpretation is that if I'm wrong or if I don't have good information, I want to make sure that nothing will go wrong.
So in light of Davis-Besse now, if the inspections are inadequate or if the crack growth rates are underestimated, what is it that is protecting me? What Defense in Depth do I have in here that says, yeah, your estimate is ten to the minus six, but it is really .3?
So something needs to be there to protect me and I don't see that.
MEMBER WALLIS: There's a containment.
MEMBER APOSTOLAKIS: Oh, the containment. I think we have to ask those questions because if we don't ask them now, we'll never ask them.
MEMBER BONACA: That's why we're asking questions about the inspections. Because if you went in now --
MEMBER APOSTOLAKIS: If things are implemented the way they are supposed to be implemented, then I will believe this analysis. But unfortunately, sometimes they are not.
So I have to have some measure somewhere that satisfies my Defense in Depth needs. I don't know how we're going to do that.
MEMBER ROSEN: Well, Mario, you have more than the containment. You have your emergency core cooling systems as well.
MEMBER APOSTOLAKIS: Anyway, let's go on.
MR. MATHEWS: I was just going to show what we're going to talk about.
I'm going to turn your ranking around. Okay? What we have done and what we have decided is the right way to look at this thing in the future is not to try and take a reference plant like Oconee 3, which had a large circ. flaw at the time it was discovered, and figure out and back calculate how long each plant had until they got to that point, but rather just look at the degradation that each plant has at a point in time or for degradation time at temperature.
So what we have done is recalculated. This information was in MRP-48; it was just a different column that we had ranked --
MEMBER WALLIS: You mean there are no points where there are no leaks and no cracks? It doesn't seem to be anything, any data for no leaks and no cracks.
MR. MATHEWS: No leaks or cracks detected in all of these.
MEMBER WALLIS: Oh, there are no leaks and no cracks.
MEMBER WALLIS: Oh, that wasn't clear to me at all.
MR. MATHEWS: Or cracks.
MEMBER WALLIS: I thought it was that there were no leaks, but there were cracks.
MR. MATHEWS: No, no, no. No leaks or cracks.
The X-axis is now what we're calling equivalent effective degradation years, which is the same thing that was presented as effective full power years normalized for 600 degrees Fahrenheit. And I think we even used the term effective degradation years in the original submittal in MRP-48.
But our ranking system was based on taking each plant's number, at that time, and then figuring out how many years they had left to be equivalent to Oconee III.
We said, you know, that's probably not the right way to look at it in the future. So we are just ranking it. Where does each plant are they? Starting at zero at zero and going to the highest plant at the time we had the data was Oconee I, I believe it was.
MEMBER APOSTOLAKIS: So these are the years that are left in the future? No?
MR. MATHEWS: No, no, no. This is accumulated years from time zero to the -- to February 28th. We are going to update all those numbers.
MEMBER BONACA: For understanding, the blue ones, the diamond, no leaks, cracks detected. Some of them have not been inspected, right?
MR. MATHEWS: No, well, all of the ones that are solid blue have done either a top-of-the-head visual or a volumetric of their plant.
MEMBER APOSTOLAKIS: So pick a point and explain what it means.
MEMBER APOSTOLAKIS: Let's pick the very first one.
MR. MATHEWS: This point right here?
MEMBER APOSTOLAKIS: Yeah. What does it mean?
MR. MATHEWS: That plant is the lowest ranked unit on time at temperature.
MR. MATHEWS: It is a cold head plant. It's a very cold head plant. And even though they have been running for a significant number of years, when you normalize their time at temperature, they are only about one year, effective full-power year at 600 degrees Fahrenheit.
MEMBER ROSEN: Effective degradation year.
MR. MATHEWS: Yeah. One effective degradation year because they have run at such cold head temperatures.
You take another plant here --
MEMBER APOSTOLAKIS: Wait, wait, wait. Why is it 69? What does 69 mean?
MR. MATHEWS: There's 69 units and this is just a rank. This is just a sort that shows the rank.
MEMBER WALLIS: It's not a property. It's just a number assigned to the plant.
MEMBER APOSTOLAKIS: So this is plant number 69?
MR. MATHEWS: It's plant number 69. What it means is that this one has the lowest time at temperature of all 69 PWRs in the country. This one has the next lowest. You come on down and they get higher and higher in their effective degradation years until you get to Oconee I, which had the longest time at temperature run of all the plants at that time.
MEMBER KRESS: How do you normalize the temperature? Is that linear?
MR. MATHEWS: No, it's an arrhenius equation.
PARTICIPANT: It's a arrhenius equation, okay.
MEMBER KRESS: Is that what accounts for the big split right there or --
MR. MATHEWS: Right. These plants are cold head plants. So when you normalize it to 600 degrees, they accumulate effective degradation units at a very low rate in real time. Ones that are over 600, these and Davis-Besse and some of the others that are slightly over 600 accumulate effective degradation units at greater than real time.
So, you know, even though they got 21.7 or whatever the number was, their effective full-power unit was less than that, but they had been running it over 600 degrees. So to normalize it to 600 would --
CO-CHAIRMAN FORD: But the fact that you have a discontinuity and your algorithm only takes in temperature, does that give you --
MR. MATHEWS: In the time that you operate.
CO-CHAIRMAN FORD: But the fact that you have a major discontinuity in that relationship is telling you there is something missing from that algorithm.
MR. MATHEWS: There will be some plants running cold head temperatures and some plants run hot head.
CO-CHAIRMAN FORD: But using an arrhenius plot, they should all meld into the same plot.
MR. MATHEWS: No, no, no. then the other variable is how long that they've been running.
MEMBER APOSTOLAKIS: But the vertical axis is still not clear to me.
MS. KING: What we did was when we made this calculation for EDY, we just sorted it from top to bottom and assigned a number one through 69.
MEMBER APOSTOLAKIS: Oh, afterwards you assigned a number? Okay.
MR. MATHEWS: Yeah, we assigned a number after we sorted, ranked on EDY. This is just the rank of the unit based on EDY.
MEMBER ROSEN: This is too simple for you to understand.
MEMBER ROSEN: It's to simple for you to understand. You can't get your guns down that low.
Now let me go back to my question. The break in the data that I was referring to was not the one down all the way out in the EDY curve. It's the one up at five EDY. Do you want to point to that and tell me what that one's about?
MR. MATHEWS: These plants right here are all Westinghouse units that are later designed and were designed to run with significantly colder heads, somewhere around T-cold, around 550 to 560 degrees Fahrenheit in the head region. They have got a lot of bypass flow that goes to the head.
Most of the plants in here were designed with some bypass flow, and you can call them warm-heads, if you will. They are 580 to 600 degree range.
MEMBER BONACA: The others are hot-heads.
MR. MATHEWS: And these are the hot-head plants --
MR. MATHEWS: -- that run at 600 or higher on their temperature on their head.
MEMBER ROSEN: Now some plants have modified that flow scheme during their life. They have gone from being hot-heads to warm-heads. Some of the warm-heads have gone to cold.
MEMBER ROSEN: Did you take that into account in EDY?
MR. MATHEWS: We took each period of operation at each temperature when we calculated the effective degradation years, and then we will use their new head temperature to figure out how fast they move to the right, if you will.
MEMBER KRESS: How did you get the activation years?
MR. MATHEWS: We used -- for this we used 51 kilocalories per mole for crack initiation.
MEMBER KRESS: Oh, so that's for experiments on crack initiation.
MR. MATHEWS: Yeah. Okay?
MEMBER WALLIS: It has a lot of uncertainty associated with it, I would assume.
MR. MATHEWS: It's not a lot, but there is -- well, there may be. I don't know. We did some sensitivity studies on our initial ranking going all the way down to 40 kilocalories per mole to see what impact it had on the stack-up of the industry and plants moved around a little bit because of different times and et cetera, but it wasn't a radical shift, and some plants were in a little different position.
MEMBER ROSEN: Now you acknowledge that this is changing every day, this chart, right?
MS. KING: Right.
MR. MATHEWS: It should be, but we don't change it every day. In fact, the data is all effective over a year ago. We are going to update all that data.
MEMBER ROSEN: I understand you wouldn't change it every day, but --
MS. KING: It's expected that the plant would calculate their EDY continuously.
MEMBER ROSEN: Have you done a calculation, a prospective calculation, so that you know where the plants will end up six months from now, a year from now, two years from now? Because obviously this picture is changing.
MEMBER KRESS: Other than the temperature problem it just shifts one point.
MR. MATHEWS: Each plant will move to the right at a different speed depending on what its temperature is. But typically, they are kind of ranked like they are here. The hot-head plants are here. The cold-head plants are here. And the warm-head plants are in the middle somewhere.
MEMBER ROSEN: Because each plant moves to the right at a different rate, the order will change.
MR. MATHEWS: I guess my intent -- and this is my chart. I kind of came up with it.
MR. MATHEWS: --- would be to maintain that initial ranking --
MEMBER ROSEN: Does that mean we can't comment on it?
MR. MATHEWS: Oh, sure, you can.
MR. MATHEWS: But, yeah. If I resorted every time I replotted the thing, then, yeah, the plants would move up and down in the ranking. But probably it would be more instructive to watch them move to the right at the different paces.
MEMBER ROSEN: I suggest that you press the sort button every once in a while.
MR. MATHEWS: That's probably not a bad idea. Press the sort button every once in a while.
MEMBER WALLIS: Well, let's tell us the substance now.
MR. MATHEWS: Okay. Now, all of the plants that are red triangles have been inspected and found leakage.
MEMBER WALLIS: That they've seen deposits?
MR. MATHEWS: Well, yeah. Every one of them has had through wall --
MEMBER WALLIS: They have seen deposits. They have not measured a flow. They have seen deposits.
MEMBER WALLIS: There might have been a leak with no deposit, but the evidence is the deposit. So those have seen deposits; is that right?
MR. MATHEWS: These two -- well, three plants. We have three plants on here that are kind of yellow squares. They were plants that did volumetric inspections, found cracks in some penetrations that were not through walls, but did not have leakage at that point.
MEMBER WALLIS: And they did not see boron?
MR. MATHEWS: Right, there's no leakage yet.
MEMBER WALLIS: Did not see boron. How do you know there's no leakage?
MR. MATHEWS: Well, they quantify as best they can with NDE at that point in time the flaws, and the flaws were not through walls, did not reach a pressure boundary.
There are three of those. This one is the Millstone, and this one was --
MEMBER WALLIS: And there is one that's behind another one.
MR. MATHEWS: No, Robinson did a visual and found no leakage.
MEMBER BONACA: A question that I have. For those that were inspected volumetrically and found cracks, did they fix those cracks? Did they replace the nozzles?
MR. MATHEWS: There's one in here that you can barely see. Cook 2 found a flaw in '94 and they repaired the flaw in '96.
MR. MATHEWS: Then they came back in 2002, this spring. They did both a visual and a volumetric on their plant and found no additional flaws anywhere.
Several of these plants, clearly the ones that have yellow have done volumetric and it's hard. You can't tell from this symbol whether they have done volumetric or --
MEMBER WALLIS: Yeah, I think that is why I have asked you about it. You said there are no leaks detected is the main thing. The cracks are somehow inferred from the leaks in the blues, isn't it?
MR. MATHEWS: Right. The reason it says that is because that triangle encompasses both visual and volumetric.
MEMBER WALLIS: It would be nice to break that out into two.
MR. MATHEWS: We have a slide and we'll put it up here if she can get to it.
What I have done is flagged the plants that did volumetric in that blue triangle.
MS. KING: It's a little busy, but --
MEMBER WALLIS: Those guys did volumetric?
MR. MATHEWS: All of these plants that have blue have done volumetric in addition to --
MEMBER WALLIS: So those other blues, say, between 15 and 20, they are just relying on not seeing "popcorn"?
MR. MATHEWS: Right. These plants have done their 2001-01 response of an effective visual examination.
MEMBER WALLIS: But we know nothing about the crack situation in those plants?
MR. MATHEWS: Correct. We know they don't have leaks coming to the top of the head. That's what we know at this time.
CO-CHAIRMAN FORD: But I assume that we are going to discuss that later on when we come to the whole question of inspection. Maybe it will be in the NRR one, but this whole question about the relationship between where you see cracks and where you see "popcorn" or not. That's going to come into--
MR. MATHEWS: I suspect we will get into heavy discussions of that when we talk about the inspection plan.
CO-CHAIRMAN FORD: Good. While she still has got that slide up --
MEMBER ROSEN: Excuse me. In the blue diamonds, again, it says no leaks, slash, but cracks were detected. You don't mean that. You mean no leaks or cracks were detected?
MR. MATHEWS: No leaks or cracks were detected.
MEMBER ROSEN: But if you just pick this piece of paper up, you will get the opposite piece of information.
MS. KING: We will make sure that gets fixed.
CO-CHAIRMAN FORD: And also you didn't actually know anything about cracks if you didn't find leaks. So I think you need two different colors, one which is no leaks detected and another one which has no leaks nor cracks.
MR. MATHEWS: Excel has a limited number of symbols. We are tracking it that way. We just -- it is kind of hard to get it all on one graph, but I'll try and do better.
CO-CHAIRMAN FORD: As I mentioned in the very beginning, there was a question raised about the statistical veracity of this. You could increase that or waylay that problem by including all the French data, using your algorithm, but on the French inspection data.
Is that a possibility or do you not even want to approach that?
MR. MATHEWS: Well, I'm not sure we got even as good a handle on French head temperatures as we have on our own. The other thing is it is not clear to me that what happened in the French plants is the same thing that is happening here.
CO-CHAIRMAN FORD: Well, could you expand on that? Because this was the answer to my question at the very first meeting in July. The French operations got no bearing at all in the United States operations, and I don't understand that. Why?
MR. MATHEWS: I think there was significant differences in the processing of the material that was used.
CO-CHAIRMAN FORD: But processing doesn't come into your algorithm. The only thing in your algorithm is temperature.
MR. MATHEWS: Time and temperature, you're right. That's right.
MS. KING: But it would affect the inspection results.
CO-CHAIRMAN FORD: Exactly. That's why I am asking why don't you improve the algorithm. But regardless, if temperature is the only thing in your algorithm, you should be able to increase your database by including the French data.
MR. MATHEWS: Hopefully, they may all be here and that --
CO-CHAIRMAN FORD: Then that screws up entirely your algorithm.
CO-CHAIRMAN SIEBER: No, it just says there is a difference between the points.
MR. MATHEWS: It says to me that there's something different then --
CO-CHAIRMAN FORD: Their algorithm is not complete, which we know.
MR. MATHEWS: Right. It's just time and temperature. Okay.
CO-CHAIRMAN SIEBER: Well, we know that the heat is apparently very important.
CO-CHAIRMAN FORD: Not in this algorithm.
CO-CHAIRMAN SIEBER: No, but we know it is important to the physical --
MR. MATHEWS: And what we -- I guess what I hope and what I believe is that the plants that are out here are the leading edge not only in time at temperature, but in the bad material, too. And so what we may find -- and personally I expect to find -- there will be plants that will reach these same time at temperatures that have no problem.
CO-CHAIRMAN FORD: The reason why I keep hammering on this is that the algorithm that you've got served a very useful purpose back in July of last year when you were coming up with your inspection prioritization.
But I hope that it is not the intention of the industry to keep willy-nilly on this algorithm as if it's the only prediction algorithm in existence because it is obviously incomplete.
MR. MATHEWS: We know there are other parameters, and when we are able, based on what we see in the field --
CO-CHAIRMAN FORD: Well, I would hope that from a research point of view it is not when we are able. I mean, I hope that we have got ongoing work to come up with this prediction algorithm which we are going to need until all the heads are replaced. And even then you're going to need it.
MR. MATHEWS: I guess the main problem I see with trying to do it is that all of the tools that I've seen are based on Alloy 600 base metal, and we've got several of these plants where the through wall leakage came through the weld metal.
CO-CHAIRMAN FORD: Well, put yourself in two years' time when I assume that the staff are going to ask you the question, tell me why my safety posture has changed significantly; tell me quantitatively why my safety posture has changed by going to 690 and Alloy 52. Will you be able to answer that question?
MR. MATHEWS: I certainly hope so, and we will be looking into --
CO-CHAIRMAN FORD: Being a researcher, I'm very susceptible to this question because it takes more than two years to come up with that answer unless you've already got it in your back pocket.
MR. MATHEWS: Well, I don't have it in my back pocket finally, no.
MR. MATHEWS: That was what I had as the introduction, and I'd like to move on in and get EPRI to come up here and discuss the crack growth rate for Alloy 600 and where we stand on that in the material in the report.
MS. KING: We had this planned as a 45 minute presentation. Do you want to go into that now or do you want to take a break?
CO-CHAIRMAN FORD: I see. John, does your talk actually go into two parts, fall into two?
MR. HICKLING: Yes, it does.
CO-CHAIRMAN FORD: Let's take your first part and then we'll break.
MR. HICKLING: Good morning ladies and gentlemen. My name is John Hickling from EPRI, and I'm going to talk in some detail about a small piece of this jigsaw, but it is only a small piece, and there are the questions which this presentation certainly won't answer.
What I'm trying to get to is an agreed crack growth rate for thick section Alloy 600 material exposed to PWR primary water. Everybody knows that Alloy 600 is susceptible to primary water stress corrosion cracking. We've known that for a very long time, every since Coriou back in the '60s first discovered the phenomenon.
It's been studied mainly on steam generated tubing where its impact until recently has definitely been greatest, and the challenge now in terms of head penetrations is to find out what a thick section material -- how that behaves and to agree on what sort of crack growth rate we should be using in deterministic and probablistic analyses.
So the goal here is to establish a generic crack growth rate applicable to this material, and our approach was to gather together some of the experts in this field to advise us, and this was done starting in August last year.
Can we flip forward to the slide of the people names? One more.
And we looked around the world for those people who we thought could offer the best advice on this problem. These are the core team members of the MRP expert panel.
We've had a lot of people at various meetings. We've had about four or five meetings of the expert panel since August last year. I myself came into this field only in December when I joined EPRI, but I have worked on stress corrosion cracking for very many years.
As your Chairman well knows, it's not necessarily a particularly exact science, and these are the people who have been in the core team advising us right through.
Can we go back to the overhead?
CO-CHAIRMAN FORD: If I could, just for the other members, apart from Bill, who don't know these names, these are good people. It's not just a random selection of experts.
MEMBER KRESS: Are you including this one?
MEMBER KRESS: Yeah, called Bill Shack.
MEMBER SHACK: No doubt about one of them.
MR. HICKLING: Bill is by definition okay.
MEMBER APOSTOLAKIS: But when you say "expert," you're not conducting any expert opinion solicitation here, are you?
MEMBER APOSTOLAKIS: It's just that they're advisors to your program.
MR. HICKLING: Not quite. We, as you'll see when I get into the presentation, we have to look where the data we're using has been generated. So those people who have generated the data qualify straight away to some extent.
We've also included other people whose expertise is more in analyzing the mechanistic side of primary water stress corrosion cracking. We've included people whose expertise is more in analyzing application of data.
MEMBER APOSTOLAKIS: But their role is what? To advise you on the problem.
MR. HICKLING: Their role is to try and reach a maximum degree of consensus on what the crack growth rates should be that we're using for Alloy 600.
MR. HICKLING: So the work of this expert panel, which started, as I say, in August last year, falls really into two sections, and that's why I would take the presentation perhaps in the two sections here.
The first one was to consider following the Oconee experience. What might be happening in the environment which would exist in the annulus of a crack where a leak had already occurred, i.e., we're talking about external OD cracking in that case.
And I'm going to take that issue first in this presentation and then come back to the rather large body of work which is on the actual crack growth rate under normal PWSCC conditions.
I put in a little bullet here and will come back to that right at the end of the presentation about Davis-Besse. The expert panel or a subgroup of it met quite recently to consider the implications of the Davis-Besse incident to this argument and has reached the conclusion that the arguments I'm presenting today are basically valid in a non-Davis-Besse situation, i.e., at low leakage rates.
And I have a couple of comments to make about how we think the Davis-Besse environment might affect that growth rate.
Next one, please.
So if we move through the presentation on to how we are trying to use it, I think we'll go straight on to the external OD environment.
Slide. Thank you.
A lot of thinking was put into this, first of all, as to what the most and likely environment would be once you had a through wall crack in a CIDM nozzle, and the conclusion was there were three likely environments, and they depend to some extent on the situation as the leak develops because intragranular stress corrosion cracking, primary water stress corrosion cracking in Alloy 600 leads to extremely tight, highly branched cracks.
So that the first time that a crack penetrates the material, the OD surface, the leakage rate is likely to be extremely low, and the pressure drop is likely to be taking place purely within the crack.
So the environment at that stage is almost certainly going to be hydrogenated, super heated steam.
MEMBER WALLIS: So where does the boron go? If you've got boron coming in with the water, it can't just turn to steam. The boron has got to go somewhere.
MR. HICKLING: No, the boron will exit also with the steam.
MEMBER WALLIS: Well, it so. So it's steam carrying boron in some form.
MR. HICKLING: Yes, yes.
MEMBER WALLIS: So it's borated, super heated.
MR. HICKLING: Borated, super heated state.
MEMBER KRESS: That depends on the pressure at which you convert it into steam.
MEMBER WALLIS: Just by continuity.
MEMBER KRESS: If the pressure is very high, it will concentrate in the water. If the pressure is very low, it's going to go out with the steam. So I don't know how you --
MEMBER WALLIS: Continuity has got to go out some --
MR. HICKLING: It depends on leakage path and the hydraulics of the situation.
MEMBER KRESS: That's what I'm trying to say, yeah.
MR. HICKLING: Absolutely.
MEMBER ROSEN: Now, the boron in the water will range from, depending on the cycle, from something like 2,000 parts per million down to very low, maybe 100 parts per million.
It will also characterize the boron in the super heated steam, or is there a partition factor?
MR. HICKLING: I think that's not an issue in this case for the super heated steam environment. If you see, looking down the slide, we have the three environments. We have the two extreme cases, at the beginning, when we're dealing almost certainly with only steam in the annulus, and we have the second case where we've already flooded the annulus, much later where we have a very high leak rate.
I'm not saying we've got wastage or corrosion or cavity formation. I'm saying we have flooded the annulus with liquid so that the boiling point is high up in the annulus, well above the J-grove weld.
And remember that the J-grove weld determines where the cracking is going to occur because of the residual stress consideration.
And then the third point, which is what we've attached most attention to, is what would happen if you're getting considerably boiling and partition at the point of exit from the crack, i.e., you're getting a different environment forming exactly at the point where you have your residual stress, and that is what most effort has bene put into.
MEMBER ROSEN: Well, are you implying that the concentration of boric acid to be higher than the concentration in the primary water?
MR. HICKLING: Yes. Oh, yes.
MEMBER ROSEN: The concentrates?
MR. HICKLING: Oh, yeah, and the lithium hydroxide does, too.
MEMBER ROSEN: Ultimately it concentrates, but at the very first instance, I guess it's not that relevant. At the very first instance, there's a little boron. Perhaps what the partition factor between steam and water doesn't really matter as long as a little carryover.
The water that carried over stays there.
MEMBER ROSEN: And then it continues to build and build.
MR. HICKLING: Yeah. The steam environment, because it's a pure super heated steam environment with the exception of the boron and lithium carryover, is basically not a difficult environment to handle because there's been a lot of work done on that. The --
MEMBER WALLIS: I'm wondering about that. I mean it depends on where boron and lithium goes. If it builds up, if it deposits on the walls, then your environment is essentially walls plated with boron in various --
MR. HICKLING: Are you talking about the walls of the crack or the annulus?
MEMBER WALLIS: Of wherever the steam is coming out and impinges upon. The OD annulus environment here.
MEMBER WALLIS: And presumably some boron is carried out by the steam, but it's a very low flow rate. It's a big area in that.
MEMBER WALLIS: I would think it would fill up with boron crystals or whatever, the popcorn or whatever.
MR. HICKLING: Yes, very good point.
MEMBER WALLIS: So the environment, what the wall sees is whatever the bottom of those crystals' condition is, which presumably is dry or wet or whatever, depending on the various phases of boron, boric acid with temperature and concentration.
MR. HICKLING: Correct.
MEMBER WALLIS: So it could be doing something to the wall because it's concentrated boric acid. It's not steam that the wall sees.
MR. HICKLING: Yes. You'll see it right at the end when I come back to talk about the Davis-Besse situation. There's a little -- we have very, very little data on stress corrosion cracking of Inconel in concentrated boric acid solutions. There is one paper essentially resulting from one French program which has addressed that particular condition.
The main concern behind the consideration of the environment in this case on the OD environment has always been traditionally caustic and caustic formation.
MEMBER WALLIS: That puzzled me. That's what Bill was telling us earlier. I guess he can't tell us anything now.
How does it get to be caustic when there's so much boric acid there?
MR. HICKLING: Because the concentration mechanism that is taking place here, depending upon the interactions and particularly the precipitation, as you correctly pointed out, you are going to get precipitation and plugging, and depending upon the exact way in which that forms, you can postulate different chemical environments which might form.
And you cannot per se rule out the tendency to go caustic, and as was also mentioned, you have to consider the differences in boron concentration between beginning and end of cycle, which will affect potentially the final pH of that concentrated solution, and all of that was taken into account.
MEMBER ROSEN: And the fact that there's a coordinated lithium being used in many plants.
MR. HICKLING: Absolutely.
MEMBER ROSEN: The pH of the rapid coolant during normal operation is typically not above neutral. It is basic, kept in the 7.0 to 7.4 range, I would guess.
MR. HICKLING: Right, yes.
MEMBER ROSEN: Now, that does not characterize the pH in the crack.
MR. HICKLING: The pH in the annulus, if you're having boiling in a concentrated environment.
MEMBER ROSEN: Will drive it acidic?
MR. HICKLING: I'll get to that in two minutes, if I may. Let me take the two simpler environments first because the simpler environment -- well, no, I'm sorry. One more slide, Christine, please.
There's one consideration I'd like to take first of all before considering the three environments because it's a very important one, but it is actually the same arguments apply to all three potential environments, and that is the extent to which you might get an oxygenated condition developing within the annulus low down, just above the J-groove weld where you're expecting a stress corrosion cracking to occur.
And traditionally, of course, oxygen virates' (phonetic) effect on electrochemical potential has a huge potential impact on cracking susceptibility. So the panel spent quite some time looking at the arguments as to whether or not the crevice, right down in the crevice, could be oxygenated.
And there are various ways that that was done. The first was to use some back diffusion models for oxygen. In fact, two independent assessments were made.
Considerations of oxygen consumption along the metal walls --
MEMBER WALLIS: But does it just diffuse? I mean, there's a flow pattern in this annulus.
MEMBER WALLIS: There's a crack at one place producing a jet of some sort. I would think it's not just diffusion that's going on. You have to analyze the fluid flow pattern in that space.
MR. HICKLING: Correct.
MEMBER WALLIS: There's a mechanism for back flow in the place where the jet is not perhaps.
MEMBER ROSEN: In fact, the jet could be pumping the crack, right?
MEMBER WALLIS: But I don't know if it can. We'd have to see an analysis.
MEMBER ROSEN: Like a jet pump in a BWR, just like a jet pump.
MR. HICKLING: You've got to remember that we're talking here about a very, very narrow, deep annulus --
MEMBER ROSEN: Around the grain.
MR. HICKLING: -- at this point.
MEMBER WALLIS: But again, I haven't seen any equations or figures or anything.
MR. HICKLING: Right, yes.
MEMBER WALLIS: So I'd have to look at the model to see whether -- when you say "diffusion," it makes me a little suspicious. If someone assumed it was diffusion, I doubt if that's what was going on.
MR. HICKLING: No, the model, both of the model concerned, in fact, do take that into account. I think probably more important in concluding that oxygen is not present right down at the bottom of this very deep and narrow crack, also some of the other points, the oxygen consumption, the presence of hydrogen itself because, of course, hydrogen is present in the water and by diffusion through the metal of the head and is available to react with any oxygen that might be there.
And finally, the fact that even if you were to postulate very low oxygen levels still being credible at the bottom of the crevice, you do have a coupling effect between the alloy steel and the Alloy 600, a galvanic coupling effect, all of which will keep the potential low.
MEMBER WALLIS: Why does the hydrogen react with the oxygen here when it doesn't in the containment?
MR. HICKLING: This isn't --
MEMBER WALLIS: After putting miters (phonetic) in there?
MR. HICKLING: We're talking about reaction here within an aqueous phase.
MEMBER WALLIS: Oh, okay. So that's much more graphic.
MR. HICKLING: Yes. So the bottom line conclusion of all of these considerations was that it is not necessary to consider an oxygenated crevice condition right down at the bottom. As I said, this analysis does not treat a wastage in cavity formation situation.
MEMBER WALLIS: Is there any real evidence of non-oxidation in this annulus space, observation of no rust?
MR. HICKLING: I think the answer to that has to be that there is no observation of what that crevice looks like right down at the bottom.
MEMBER WALLIS: That would have been destructive examinations of real cracked --
MR. HICKLING: The only one I'm aware of is in Bouget nozzle that first cracked, which was destructively examined, in fact, and there was no real evidence of --
So the fact is it was useful.
MR. HICKLING: Oh, yes, yes.
CO-CHAIRMAN SIEBER: If wastage does occur, then these arguments, except for corrosion potential, then fall apart; is that correct?
MR. HICKLING: I'm sorry. I didn't hear the first part of the question.
CO-CHAIRMAN SIEBER: If wastage does occur--
CO-CHAIRMAN SIEBER: -- okay, then these arguments about oxygenation fall apart because the geometry is now changed.
MR. HICKLING: If significant --
CO-CHAIRMAN SIEBER: With the exception of corrosion potential; is that correct?
MR. HICKLING: Correct. If significant wastage and cavity formation were to occur, then this is a different situation, which would require separate consideration.
CO-CHAIRMAN SIEBER: Now, aside from the factor of the wastage weakening the basic structure of the head, the added oxygen would increase the crack growth rate significantly, don't you think?
MR. HICKLING: Not necessarily. Primary water stress corrosion cracking of Alloy 600, Alloy 600 has a number of separate modes of stress corrosion cracking, and your conclusion would be correct for some of them, but not to primary water stress corrosion cracking.
Remember the original finding that Alloy 600 cracks in pure water or in PWR primary water is extremely surprising, and the mechanistic reasons for it doing that are very closely linked with the fact that the electrochemical potential --
MR. HICKLING: -- is established in the region of the nickel/nickel oxide transition.
MR. HICKLING: And that is a low potential phenomenon. So in that case it's not fair to assume automatically that oxygen would be negative. It was just a consideration that needed to be very carefully looked at in terms of the narrow annulus.
Now, I'll come back to make a comment right at the --
MEMBER SHACK: Because it could be cracked by another mechanism, and you would have to address that one.
MR. HICKLING: Absolutely, yes. If you had an oxygenated environment, a highly alkaline environment, then that is not primary water stress corrosion cracking. It's a different mode, I think.
MEMBER WALLIS: Tell me more about the hydrogen. I mean, we were hearing about hydrogen explosions in BWRs where they had essentially a stoichiometric mixture of hydrogen and oxygen resulting from radiolysis (phonetic).
MEMBER WALLIS: So there is an oxygen in there, not just all leaking out necessarily by the hydrogen.
MR. HICKLING: In the PWR, primary water environment, that is your main reason for adding large over pressures of hydrogen, to make sure it is all --
MEMBER WALLIS: So these are all hydrogenated plants?
MR. HICKLING: All PWRs run with high hydrogen levels for that reason.
So that consideration was the elimination of oxygen from the picture for the narrow crevice at the beginning of the situation, the non-wasted situation.
Looking back then at the three environments that were considered, and the first one is hydrogenated steam, and as I mentioned, there is quite a lot of evidence, quite a lot of information available on the way in which Alloy 600 cracks in hydrogenated steam primarily because hydrogenated steam has been used as an accelerated test method for determining crack susceptibility in this and other nickel based alloys.
And the main conclusion of the data that's available is that in terms of pure hydrogenated steam, and not including boron or lithium in this, the impure steam environment which is used to accelerate cracking involves chloride and sulfate as contaminates.
In terms of the hydrogenated steel environment which you would expect at the beginning with a very tight crack, the rates of cracking are going to be virtually the same as they would be in normal primary water at the same temperature.
MEMBER WALLIS: Is cumulative percent with IGS? So that means that after 1,000 hours, 60 percent of them have cracks?
MR. HICKLING: Yeah. This is one diagram picked out of a -- it's very hard to summarize in some cases all of the work that's been done on Alloy 600. This particular issue has been studied for very many years, particularly at the Westinghouse laboratories from about 1987 through '95.
MEMBER WALLIS: My question really was this crack development is so rapid because the temperature is so high. Isn't that why?
MR. HICKLING: Correct.
MEMBER WALLIS: If we looked at this as typical, we'd be really scared.
MEMBER ROSEN: You see, now that's the danger of coming to ACRS. We start putting things together.
If you just said that these crack rate growth rates are accelerated tremendously in chloride and sulfate environments, chloride and sulfate contamination --
MR. HICKLING: Contamination, yes.
MEMBER ROSEN: -- did that happen at Davis-Besse?
MR. HICKLING: I'm going to deal with what we know about that, and I know nothing whatsoever about the Davis-Besse situation. I have no reason to believe it did, but I'm going to --
MEMBER ROSEN: That's a question we could perhaps ask the staff with the applicant. It's easy to get chloride contamination in the primary from a leak from the secondary side. If your secondary side has a, you know, brackish or that kind of water, you're going to be -- in your cooling water, you're going to have chloride.
So if you get some sort of ingress into the secondary side, you will have chloride contamination in the secondary side. It's possible, although not likely to have an intrusion into the primary system.
CO-CHAIRMAN SIEBER: I'm not sure how that happens since the primary runs at a higher pressure.
MEMBER ROSEN: Yeah. That's why it's difficult, but it can happen during shutdown or --
CO-CHAIRMAN SIEBER: It's like pushing water uphill.
MEMBER ROSEN: Well, yes, but it's not always true that the primary is higher than the secondary. You can have chloride contamination in the primary or sulfate contamination.
CO-CHAIRMAN SIEBER: I'd have to think about that. It doesn't pop to mind readily.
MEMBER ROSEN: No, I'm talking about in shutdown modes.
CO-CHAIRMAN SIEBER: Oh, all right.
MR. HICKLING: Let me just point out that when I said impure steam as a test environment, I'm talking about very considerable levels of chloride contamination, much larger than you could ever postulate, I think, in terms of an accidental contamination of the primary circuit.
MEMBER WALLIS: Unless it concentrates in some way.
MR. HICKLING: Correct, but this was referring to the hydrogenated steam environment.
MEMBER WALLIS: But it came in as water and is going to go back again. And so did it get carried out with the steam or not?
MR. HICKLING: The second OD annulus environment which we're going to talk about in detail in terms of likely crack growth rates that have to be assumed is then normal primary water, which could definitely be the case once the annulus is flooded and when boiling is not taking place down at the bottom of the annulus where you might be expecting OD cracking.
MEMBER WALLIS: So someone has worked all of that out in terms of heat transfer rate? Because with the hot head you would expect that it would boil or flash pretty quickly, wouldn't it?
MR. HICKLING: Yeah, well, in terms of boiling or flashing, they're all going to flash quickly. The head temperature differences are minor in terms of the phase changes which go on.
MR. HICKLING: Although they do have cracks.
MEMBER WALLIS: Doesn't it take a pretty big leak to get any boiling at all in the annulus?
MR. HICKLING: Well, it will take a significant amount of leakage before that scenario takes place, yeah.
So the environment which attracted most attention in terms of the expert panel is the environment number three of the concentrated PWR primary waters as a result of boiling, and the caveat on this is that these considerations apply to low leak rates, and the panel has adopted a definition of less than one liter per hour to quantify what we're talking about here, which is pretty low leakage, in some cases very much less.
There are various ways in which we can analyze the problem of what environment is formed and particularly whether or not caustic forms and pH. One of them is to use the thermodynamic calculations, which are available, which have been produced largely because of secondary side stress corrosion cracking in steam generators, a phenomenon which has been studied very, very intensely over many years.
And EPRI has a program called MULTEQ, which will calculate the expected pH as you concentrate up an environment of that sort, and the answer that comes out by using that program is that you would expect a high temperature pH of somewhere initially between 4.0 and 9.4. So it's quite a narrow range that, in fact, due to the composition of the liquid which is being concentrates.
In fact, that pH range is probably far too broad as calculated because as was correctly pointed out, you're going to get precipitation of various insoluble compounds. We know that, and that narrows it down because it has a buffering effect.
So the likely pH range is going to be much smaller than that. What experimental evidence do we have for what pHs might be involved? After the Bouget experience, the French -- next slide, please -- did a very interesting experiment. This is CEA, the French atomic laboratory, which simulated leakage in this case by injecting the liquid, which was to be concentrated through a heated block, blocking off the flow of liquid so that when it exited the nozzle, there was a very, very tight leak path exiting, simulating what might be expected from a strained granular stress corrosion crack, and allowing that vapor to impact on a heated plate of low alloy steel material simulating the vessel head.
And the next picture gives some feel for what actually happens. In fact, you do get a huge amount of precipitation occurring in the annulus.
Now, there was one caveat unfortunately on this experiment, which was the -- there was a considerably amount of cooling generated of the low alloy steel, relevant certainly to the Davis-Besse incident, but not relevant perhaps to the conditions initially in an annulus where the leak rates are very low and where you would not expect local cooling of the head.
MEMBER ROSEN: Is that some red rust I see there?
MR. HICKLING: Yes. That is the low alloy plate which is being corroded both by boric acid corrosion and impingement and simply, you know, moist atmosphere. So it is rusting.
Okay. We go back to the previous slide.
There's been a second experiment, again, performed in France to look at this particular issue, and the results of that were published only very recently, in fact, a month ago. And this involved a slow concentration of a fixed volume of primary water in an autoclave system, which they considered realistic to simulate what would be happening.
And the interesting factor here, in fact, after a concentration factor of 1,000 was that the pH was acid, slightly acid, 4.5 rather than alkaline.
So the general conclusion from both the theoretical analysis and the experiments we know about is that the caustic formation can almost certainly be ruled out. The pH is going to be very limited. It's certainly not going to move strongly alkaline. If anything, it's probably likely to move slightly acid in that environment.
MEMBER SHACK: In that French test, I mean, that was done in what? Did the autoclave have nickel and a low alloy steel?
MR. HICKLING: Yeah. They, in fact, set up a whole system called EVA, and I've forgotten what EVA stands for, but it was for a simulation of what would be expected to happen as you concentrated a limited volume in contact with low alloy steel and nickel, and it was not a simple autoclave, cook-it-up test at all. It was a leak and bleed and reconcentrate test involving quite a complicated experimental system. It was published in Avignon, the Avignon conference last month, yes.
Then the issue came up earlier in connection with the steam: can we exclude the possibility of contaminants which are known to promote more rapid cracking of Alloy 600, and in particular, chloride and sulfate, which might be involved.
And it's very difficult to make any absolute sweeping, generic conclusions here. Obviously the practice during assembly of the heads was to clean. So the amount of contamination that would have been left after assembly is expected to be relatively low.
And, secondly, we know that there's going to be considerable steam flushing within the annulus, which would help to drive out any initial deposited contamination from assembly of the head.
The expert panel did some calculations of possible concentrations, maximum concentrations that could ever be expected, even making very negative assumptions as to contamination which might have been encountered during fabrication, and they were orders of magnitude below the levels at which you would expect any effects on primary water stress corrosion cracking.
MEMBER ROSEN: But is that the only way they thought about getting chloride and sulfite into that crack? Did they think about it as a contamination event of the primary coolant system and then the chloride and sulfates exiting with the steam?
MR. HICKLING: Not specifically because I think there's some -- as the discussion earlier showed, there's some doubt as to whether that is a significant possibility that you could have a contamination of the primary system by chloride and sulfate in the way that you could get --
MEMBER ROSEN: Well, if someone were to inject chloride, for example, into the primary system?
MR. HICKLING: Well, I think that's something that we would very much hope the water chemistry monitoring and guidelines would prevent.
MEMBER ROSEN: It wouldn't be intentional. Let me say that.
MEMBER ROSEN: But it has happened.
MR. HICKLING: The more likely scenario is resin intrusion, and that has been considered.
CO-CHAIRMAN SIEBER: That's the only place I --
MEMBER ROSEN: Resin from the?
CO-CHAIRMAN SIEBER: Let-down system, yes.
MEMBER ROSEN: That's happened, too. So there are several mechanisms I can point to.
MR. HICKLING: Yeah, but you've got a huge volume of water in the primary system to dilute that.
CO-CHAIRMAN SIEBER: And those instances are rare and easily detected.
MEMBER ROSEN: But I'm only asking the question, Jack if that happened at Davis-Besse because it has happened elsewhere. Two bulk mechanisms: injection when the chemists were trying to -- through they were injecting something and they were actually injecting something else, and resin releases from the clean-up system.
And I don't know the answer to that question, whether there is any evidence that happened at Davis-Besse, but I know it has happened elsewhere.
MR. HICKLING: The bottom line of the panel's consideration on the OD annulus environment was that even in concentrated PWR primary water, we're considering a very narrow pH range -- there's a typo which is entirely my fault on this first slide. It should read between 5.0 and 7.5.
And even if we take a pessimistic view and rule out what we k now about precipitation of buffering so that we're looking at a whole range between about five and nine, there is only a very, very slight effect on crack growth rate of changes in pH in this area.
If we just flip forward, please to the next slide, the data in this area was generated mainly at Ohio State University on Alloy 600 specimens from steam generator tubing, but there's no reason to believe that in terms of pH effect that it should be invalid or have any less relevance to what we're considering here.
There three diagrams are showing between a pH of five and nine the effect on intragranular stress corrosion crack growth rate at three different stress intensities, 20, 40 and I believe that's 60 at the bottom.
MEMBER WALLIS: That's a freak point, that first graph?
MR. HICKLING: No. If you look at the Y axis on the first diagram, you'll find it's expanded relative to the other two. You've only got one order of magnitude difference here, whereas these two are showing two orders of magnitude.
There's no doubt there is a turn-up after about 7.5 pH, and this is to be expected because if you go sufficiently caustic, then you will get a very rapid increase in crack growth rate.
MEMBER WALLIS: It only really occurs in that top figure. It's very different.
MEMBER BONACA: No, no, because --
MEMBER WALLIS: Yeah, but then it comes back down again.
MEMBER BONACA: It's like the midpoint in your other figures.
MEMBER WALLIS: It's like the midpoint in the other figures, but then there's a point later on above -- I count above nine there, which comes back down again. So I don't know if it's a real turn-up or not.
MR. HICKLING: Yes. You've got to remember that it's very difficult in testing at low stress intensity to get a uniform, reproducible crack growth rate anyway. My inclination is much greater reliance on the low occurrence where there are, in fact, far more points.
But the bottom line, if we go back, is still the expert panel considered taking even this extreme pH range you would not expect more than about a factor of 1.5 or 1.6 on crack growth rate over that pH range.
And the recommendation was that within the high temperature range of four to nine, we should apply a factor of two on whatever crack growth we were proposing in normal primary water to cover possible uncertainties in the environment.
MEMBER WALLIS: And that crack growth rate is uncertain by more than factor of two anyway.
MR. HICKLING: That's the second part of the talk, yeah, and we'll get into that. I guess you may want to take --
CO-CHAIRMAN FORD: John, I can follow your argument, and it's fairly clear. However, on this particular rationale, you're honing in on crack growth rate. How about crack initiation, and especially crack initiation density? Because that would have an effect on the safety analysis.
CO-CHAIRMAN FORD: You're propagating for a circumferential crack all the way around the tube. Are there any comparable data for the effect of the environment change on crack initiation density?
MR. HICKLING: I'm not immediately aware of data in that pH range on crack initiation. I don't think it's necessarily relevant to what we're trying to achieve here though, Peter, because we're trying to disposition here flaws, and as we'll see in the second part of the discussion, we're trying to disposition flaws which are already of considerable size.
There's a whole lot of issues about initiation in Alloy 600 which we're jumping over in this analysis quite deliberately because we're postulating that we already have relatively deep flaws in order to make the analysis.
CO-CHAIRMAN FORD: From one point, not all the way around, not a 360 degree crack.
MR. HICKLING: Again, when we come onto the way we intend to use what we're proposing, you'll see that we're not proposing to disposition OD flaws. We'll come on to see that we're talking about hypothetical arguments about how quickly they could grow.
MR. HICKLING: But we considered the only way to handle the OD crack growth rate is a probablistic one.
MR. HICKLING: Interest in developing a consensus crack growth rate in normal primary water is in terms of ID flaws how we get to the first leakage rather than in terms of OD flaws.
CO-CHAIRMAN FORD: Okay. I've got one other question. Sorry.
Apart from the one french data where they measured pH rather than inferred it, that's the only experimental data of what that annulus environment would be in terms of pH. Are there any experiments planned or ongoing to increase the database with specific reference to the effect of leak rate?
MR. HICKLING: Yeah. Firstly, it's not the only experiment. It's the only experiment -- you're quite correct -- where they specifically measured the pH of the environment.
But the experiments, and Glenn White will be talking about this in addressing the wastage issue later, there have been experiments performed in this country as well with two prototypical mock-ups in terms of generating wastage in an annulus, and although the pH was not measured directly as far as I'm aware in either of those experiments, the results in terms of wastage of low alloy steel quite clearly show that, if anything, there's a strong move in the acid direction once leak rates become very high, much higher than what we're considering here.
MEMBER WALLIS: You have this multi-calculation.
MEMBER WALLIS: OS pH is four. Now, if you had suitable deposits in that annulus which you could postulate, you could achieve a much lower pH, couldn't you?
In other words, is there some limit to the pH achievable with --
MR. HICKLING: I think, again, it's a key question of the amount of leakage and the assumptions you make. I think it's conceivable that you can certainly go lower. The buffering is preventing you getting to a caustic condition, which remember was the original consideration.
MEMBER WALLIS: Yeah, but we don't have much of a database. We have some theoretical calculations. We don't know much about what's really going on in there, and if you looked at some extreme scenario in which you built up deposits, you could tell us what the pH could be in the worst case.
MR. HICKLING: Well, as you'll see when we go on to discuss in detail the thermal hydraulic analysis of the wastage situation, I think you can postulate certain cases where you might go very acid, yes.
MEMBER WALLIS: I thought so, too, but I haven't seen any figure yet. So I have to imagine what might be going on in there.
MEMBER WALLIS: And I can conceive of a scenario where you could have a very low pH.
MR. HICKLING: I think that's quite correct, but just jumping ahead, it's a point I was going to make right at the end. Alloy 600, the original design basis for choosing that material was its resistance to cracking in acid solution. And so there's no reason, even if you went very acid, to assume that that would automatically be negative as regards the --
MEMBER WALLIS: So it's a bounding pH rather than a calculated pH.
MR. HICKLING: That's the natural break because we now go on to the crack growth rate database.
CO-CHAIRMAN FORD: Thanks a lot, John.
I had a question for you, Larry, which is more of an administrative question. I notice John has got a few more slides, and I suspect there will be some questions. I'm proposing that we stop until five minutes to 11, but I notice that Glenn needs an hour for his presentation. So I leave it up to you and John to work out how you want to do --
MR. MATHEWS: And then we have Pete's presentation also.
MR. MATHEWS: We have Pete Riccardella's presentation also. So we're running quite a bit behind here.
CO-CHAIRMAN FORD: Yeah. The trouble is we want to hear them all.
MR. MATHEWS: We can be here all day.
MS. KING: Why don't we come back with a proposal?
CO-CHAIRMAN FORD: Okay, fine. Let's stop until five minutes to 11. Let's go into recess until then.
(Whereupon, the foregoing matter went off the record at 10:42 a.m. and went back on the record at 10:55 a.m.)
CO-CHAIRMAN FORD: Okay. We're back in session.
MS. KING: Okay. What we would propose --
MS. KING: -- since we have a lot of interest in Davis-Besse type issues, we would like to propose to bring Glenn White's presentation forward --
MS. KING: -- to this morning following John.
MS. KING: And depending upon where we land around lunch, I guess we'll either take lunch or continue into the PFM, and it shouldn't put us too far off schedule because there was 45 minutes set aside in the afternoon for Glenn.
CO-CHAIRMAN FORD: Okay. So I think what we'll do is we'll have John -- finish off John.
CO-CHAIRMAN FORD: I didn't mean that literally.
And then we'll have Glenn, and then we'll take just three quarters of an hour lunch, and then we'll catch up time that way.
MS. KING: Okay.
MR. HICKLING: The second part of this presentation deals with the meat of the work of the expert panel over the last six to eight months, which is what would be a representative crack growth rate for Alloy 600 base material, thick spectrum material.
And the initial approach taken was to look at what we've learned in stress corrosion cracking testing over the last five to ten years particularly where the international community has focused very much on issues of data quality because it doesn't matter how sophisticated your statistics or your analysis is later. If your data is bad quality, it doesn't really allow you to get a handle on stress corrosion cracking.
And the first thing the expert panel did was to make a list and discuss in depth some of the key technical issues on crack growth rate testing which need to be addressed and which conform the basis of screening out suitable higher quality data from data which is of lower quality for the purpose we are using it.
Many investigations in this area have been for different purposes, trying to understand the mechanisms, trying to understand effects of off-chemistry, things like that, and we were trying to get to where we could screen out things like that.
And as you see, there's a whole list of factors here which involve chemical environment, loading, the way the material was used, the sort of specimens which were generated, the loading characteristics during the test, the crack growth rate monitoring, and all of this sort of thing.
How did we actually do the screening? Really it involved three iterative steps. The first step was to go back to the laboratories which had generated all the data we were able to collect worldwide on thick section Alloy 600 material and ask the initiating laboratory to reexamine their own data in the light of these criteria we had put up and in the light of discussions which they had been involved in on the expert panel.
And this probably was the most important step because it led to elimination of a lot of data points by the initiating laboratory who declared these points to be unsuitable for this particular purpose for developing a crack growth rate disposition curve.
MEMBER WALLIS: It didn't eliminate anything because they didn't want to believe it.
MR. HICKLING: I would hope not. I think the people concerned, their integrity was such that would not be the case.
The second step was a screening step which EPRI put in place, and it basically covered two main areas. As I say, we involved international laboratories. You'll see the list of laboratories in a second, and in one or two cases we had some difficulty in direct contact with laboratories concerned.
One of them particularly, one European laboratory, had performed tests where they had only ever reported maximum crack growth rates during the test. Since the whole thrust of the analysis is to use average crack growth rates determined in a particular specimen, we could not use that particular data.
So in the end, after trying to obtain , and we put a lot of effort into it, we had to screen out that particular laboratory's data.
The second point was one which I was very concerned about. We've mixed in this database specimens which are actively and passively loaded, i.e., they're all fracture mechanic specimens of one type or another, but some are actually tested in a tensile testing machine under active load, and some were under displacement loading, usually by means of wedges.
And the stress corrosion cracking community has known for a number of years that these are actually or even though you are nominally at the same K value, you can get a difference in response. It's much more difficult to initiate crack growth from a passively loaded displacement controlled specimen uniformly.
And so we went back and reexamined the data from that type of specimen, the wedge open loaded specimens and eliminated all of those specimens where crack growth had been very non-uniform, and the criterion we used was less than 50 percent initiation across the width of the specimen. And what that does is it eliminates lots of artificially low points.
Finally, the third iterative step in the screening was for the whole expert panel to reexamine the borderline cases and what we had done to the database, and that was done at the beginning of March.
We didn't even bother to start to try and consider numerous tests where no stress corrosion crack growth was actually obtained, a zero result, and the reason for that is there are a whole number of reasons why you may get a zero result.
You may have a very non-susceptible heater material, but you may also have done the test in an inappropriate way. So there's no zero crack growth rate data in this database at all.
MEMBER WALLIS: That's a bit strange. I mean, in terms of the probability of a crack occurring, zero cracking would be a good data point, wouldn't it?
MR. HICKLING: In some ways, yes. It does hurt to have to eliminate those points. That's correct. But in terms of trying to get at crack growth rates, unless you can convince yourself that everything else was perfect, and it's very difficult to do, you just have to take that step.
MEMBER WALLIS: You're not interested in initiation.
MR. HICKLING: Correct.
MEMBER WALLIS: You're just interested in growth rate.
MR. HICKLING: Yes, absolutely.
The result of this screening was that we eliminated no less than 203 crack growth rate data points for one or more reasons, and these reasons are documented. The main reason is individually documented in the report the MRP is in the process of issuing on this exercise.
The consolidated database now contains 158 points for average crack growth rate during each test, and this is consistent basically with the ASTM recommended procedures for measuring fatigue crack growth rates, to use the average, and they're plotted at a single representative K value for the data point concerned.
And there, again, there was a certain amount of judgment sometimes involved. The expert panel was involved in that in detail because the K value in some tests will change during the test, and we satisfied ourselves that we had a representative value.
MEMBER LEITCH: Why would you not consider-- several bullets back --
MEMBER LEITCH: You mentioned that there was some data that you discarded, eliminated from consideration because the experiment only considered maximum --
MEMBER LEITCH: -- crack growth data. Why would you eliminate that data? Would that not be the conservative thing to include that data?
MR. HICKLING: Only at first glance. The problem there is that we had no detailed -- I'm sorry. Let me back up one stage.
The way these tests are run is to use an air fatigue pre-crack in usually a compact tension specimen, sometimes a DCB specimen, which produces a transgranular fatigue pre-crack. You then have to go through a second stage in the text where you initiate an intragranular stress corrosion crack from that transgranular fatigue pre-crack.
And one of the key things we insisted on was we had to have fractographic information available on each specimen or at least in the form of numbers to assess that this transition stage had gone through smoothly.
If that's not the case, you can get some very odd results. Now, you can report a maximum crack growth rate even if you've initiated cracking only over a tiny portion of that transgranular fatigue pre-crack.
And this particular laboratory concerned, they actually were also using perhaps the least suitable type of specimen, a very narrow DCB specimen of only ten millimeter width.
So the bottom line is that if you only have a number saying, "I detected two millimeters of stress corrosion cracking as maximum," you have no feel whatsoever for how representative that is of the amount of crack growth rate that actually took place during the test.
MEMBER LEITCH: Okay. Thank you.
MR. HICKLING: I mentioned I think earlier that all of these tests are obtained in controlled primary water, and we paid a lot of attention to the fact that we didn't have any off chemistry results in here and under two types of loading.
Just touching on one brief point which I'm going to eliminate, I hope, from consideration straight way as well. We have an issue in that some laboratories prefer to test using periodic slight unloading of the specimen, and what that actually means here is nothing to do with simulating possible transience in plant or anything at all. This is a typical way this is done.
It's a drop-in load to about 70 percent of the nominal value, usually about once an hour during testing, and there are very specific reasons for doing that which are connected with the way the test is conducted, and in particular, with the way the crack growth rate monitoring equipment works.
It's an advantageous method of insuring accuracy of measuring your crack depth on line during the test. However, there is a basic tendency if you start what is ultimately some cyclic loading to accelerate crack growth because you'll get out of a pure stress corrosion situation.
So we did some assessment of whether or not this would affect the results, and the answer is that certainly for susceptible heats of material, it doesn't make very much difference. It's possible that in less susceptible heats of material, the application of this procedure may lead to slightly higher growth rates than would otherwise have been measured. but we prefer to leave those in and accept those because, again, it's a degree of conservatism.
Next one, please.
What have we got in this database with 158 points in terms of materials suppliers? And this impacts directly on Peter Ford's discussion earlier about why we're not considering material characteristics in the way that he would perhaps like, and I think most of us would like to do.
First of all, we've got a number of domestic and overseas material suppliers, and we've got 26 heats of material in the database with at least one screened data point for heat.
The maximum number of heats we've got is 32 for any particular heat, and we'll see a table a little bit later on which gives a little bit more information on that.
What product forms? We've got a whole variety of product forms, thick wall tube, forged bar, rolled bar, forged plate, and rolled plate. This is where the crunch comes. Even for the materials which was used for the laboratory testing, the information on the thermal processing history is extremely limited so that we could not obtain the data we would have liked to characterize the material condition in terms of its thermal processing history.
And of course, extrapolating to the field in terms of the nozzles that are out there, that's an even worse situation. It's virtually impossible to get reliable data on the thermal processing history of what is out there.
And the next slide, please? You're already there. Thank you
Which laboratories are involved? We ended up taking data from five laboratories, one in the U.S. and four abroad who have done extensive testing on thick section Alloy 600 material. They've done it at a whole variety of temperatures ranging from 290 right up to 363 Centigrade, the desire, of course, often being to accelerate the crack growth rate to reduce the testing time.
And since we know and have known for very many years that cracking PWSCC in Alloy 600 is very highly temperature dependent, the first step was to try and put all of this on a common temperature basis.
So we did that by choosing the most common test temperature, which is 325 centigrade, or 617 Fahrenheit, and extrapolating everything back to that temperature using an activation energy of 130 kilojoules per mole or 31 kilocalories per mole.
That is, more or less, the accepted activation energy for cracked growth rate in this material, and even if you consider some of the more varied values that have been obtained, the range for cracked growth data is actually pretty small. It's from about 30 to 35.
So this does not have a huge effect on what we're doing.
MEMBER BONACA: I had a question regarding the previous slide actually. You said that the thermal processing history of material is incomplete. I'm trying to understand how significant. I mean this is Alloy 600. I mean, isn't Alloy 600 a pretty -- is it a common material we have or just specific to reactors?
MR. HICKLING: It's a common material in plants for milk processing and things like that, yes.
MEMBER BONACA: Oh, okay. That's all I --
MEMBER ROSEN: Where it works rather well.
MR. HICKLING: It works extremely well. Alloy 600 was originally developed and chosen because of its resistance to chloride induced transgranular stress corrosion cracking. Its application in the nuclear field in the '60s and '70s originated from that.
MEMBER BONACA: So what you're saying is that the thermal processing history could be very different, I mean, depending on the application.
MR. HICKLING: Yes. Unfortunately we do know about the impact of the microstructure on Alloy 600 cracking. We've known about that for many years. It's contrary to what you would expect intuitively, particularly if you know about BWR stress corrosion cracking because Alloy 600 works best when it has the most carbides on the grain boundary, which is an initially surprising result in terms of -- so it's not chromium depletion phenomena.
So short of taking samples from every heat tested and actually doing a microstructural analysis, it's very, very difficult to tie this one down.
Now, of course, in the lab you can do that. The problem arises if you have material out in the field and you don't have archive material which is usually the case. How do you ever get at what microstructure you're dealing with?
MR. HICKLING: How did we then go on to derive the curve? We knew, as I've just discussed that the heat variation was likely to be very large in this data. Our initial intention was to take a single heat of material where we had the most data points and try and derive the dependence of crack growth rate on stress intensity, on K from that heat alone.
Unfortunately by the time we'd rescreened all of this data, we simply did not have enough data left to do that even for the heat where we had the most points tested.
So we were forced to go back to an alternative approach, which is to adopt the so-called Scott equation for this material, and the Scott equation was basically developed quite some time ago using a very, very large amount of data on Alloy 600 obtained from steam generator tubing, which was undergoing primary water stress corrosion cracking in the field.
So there's a huge number of heats, a lot of very susceptible heats, and a huge number of data points in that original database, and that equation which was developed originally in '91 basically says that the stress corrosion crack growth rate is proportional to a constant alpha times the stress intensity nominal threshold -- I'll come back to what we mean by that -- I'm sorry -- times the actual stress intensity minus a value of nine, which is the nominal stress intensity threshold to an exponent beta, which describes the basic dependence on stress intensity.
And the Scott exponent from this analysis was 1.16.
The next --
MEMBER KRESS: Where does the erroneous relationship enter into the alpha?
MR. HICKLING: The erroneous relationship has been basically calculated in terms of the alpha, yeah.
How does the data actually look in terms of what we're talking about here? These are two examples from two different laboratories for two very different heats, and in this particular case, at 325 degrees Centigrade, this is the Scott model as defined by that equation developed from the steam generator tubing material.
And as you see, it comes down to very low crack growth rates, insignificant crack growth rates at a nominal K of about nine, and this particular test is producing data which clearly lies above that curve.
On the other hand, for some other material, a different heat tested in a different laboratory at two different temperatures, this gives you some feel, incidentally, for the temperature effect, there is the Scott curve for 290, and here is the Scott curve for 325.
The data is falling below the curve at either temperature.
MEMBER WALLIS: That has nothing to do with the curve really, does it?
MR. HICKLING: Correct. You would be hard put to --
MEMBER WALLIS: It's a little low, but --
MR. HICKLING: One of the problems is that experimentally it's very difficult to test over a wide range of Ks because you cannot get a big enough specimen from the material available to test at high K values as you would like. So all of the data tends to crowd between about 20 and about 40 megapascals.
MEMBER WALLIS: You can't really prove the nine because the crack worth rates are so low down at that end.
MR. HICKLING: Absolutely, yeah. It's only a nominal threshold.
MEMBER WALLIS: -- a matching number then. If it's independent of temperature, it's even lower. It's not magic.
MR. HICKLING: We actually considered -- at one point the expert panel debated rather intensively whether or not we should try and make it zero or whether we should make it four or six, and we did a sensitivity analysis. It doesn't make a whole lot of difference because we're not using the result in that region. We're not trying to describe initiation at all with this approach.
MEMBER ROSEN: That nine is not like Avogadro's number. It's not an important thing.
MR. HICKLING: It certainly isn't.
MR. HICKLING: The true definition of a stress intensity threshold for stress corrosion cracking is actually what you would get if you would decrease stress intensity during a test and can prove unequivocally that the crack has stopped.
And in fact, that's a test which is almost impossible to do. So --
MEMBER BONACA: Why do you infer a curve like that, if I can go to the previous curve?
MEMBER BONACA: I don't understand. You had a very specific curve that curves and goes to 320 degrees, 330 to the right.
MEMBER BONACA: Or 325. How do you infer that curve from the distributional data? You don't.
MR. HICKLING: Not at all. We can't. That is the point I'm making. We were forced to go back to a curve which had been derived from a completely different database and force fit it, if you liked to our data.
MEMBER BONACA: Right. I understand.
MR. HICKLING: Exactly right. So I've just covered that, but it's only an apparent threshold, and we don't have data, but this is not going to be critical in use because we're actually going to be at K values above, well above, say, 15.
There is another point that you have to mention. The threat exponent from the steam generator tubing of 1.16 does imply a considerable dependence of crack growth rate on stress intensity going right up, of course, to very high K values. There's quite a lot of both field and test data which indicates this may not be valid, that we may, in fact, be going too high at high stress intensities, that there may be a plateau appearing.
But we couldn't convince ourselves that for our material that we had enough data to draw a plateau.
MEMBER WALLIS: When it's high enough the material just breaks?
MR. HICKLING: Oh, yes. Eventually it would. You would eventually turn up where you get the mechanical failure.
MEMBER WALLIS: How high is that?
MR. HICKLING: Much, much higher than anything we're dealing with, yes.
MEMBER APOSTOLAKIS: What are the typical K values you're going to have?
MR. HICKLING: You'll see when we come to the way this curve is being applied we're talking typically about Ks in the range of 25, 30, something like that.
MEMBER APOSTOLAKIS: But if you subtract nine, that should have an effect, right?
MR. HICKLING: In what sense?
MEMBER APOSTOLAKIS: Well, the equation is DADT equals alpha K minus nine.
MR. HICKLING: Yes. The equation is just a fitting. The K minus nine is just fitting.
MR. HICKLING: It was part of the original fitting to the steam generator data.
MEMBER APOSTOLAKIS: Are you going to use that equation again?
MR. HICKLING: Yes. That is the basis of--
MEMBER APOSTOLAKIS: So I don't understand why you say not critical for intended use since the equation has a K minus nine factor there.
MR. HICKLING: I did mention that we, in fact, discussed extensively whether it should be nine or six or four or even zero, and we tried out the effect of plotting, replotting using all of those different curves, and in the region of interest it makes virtually no difference at all.
It would make a lot of difference if you were trying to analyze the situation at very low K values, but that's not where we are.
So we actually tried out the effect, and we stayed with the --
MS. KING: I would point out the third bullet here.
MEMBER APOSTOLAKIS: I guess it's because the exponent is just 1.16.
MEMBER SHACK: No, if you fit with zero, you'll get a different exponent. So you'll change alpha and beta. So you'll get a different curve, but then if you look at that curve between 25 and 35, they'll look sort of similar to --
MR. HICKLING: They'll more or less lie on top of it.
MEMBER SHACK: Yeah, the curves will move around a lot. You know, your alphas and your betas will change.
MEMBER APOSTOLAKIS: Well, the alpha and beta change.
MEMBER SHACK: Yes, but the result in the range of 25 to 35 is not particularly sensitive.
MR. HICKLING: Let me just repeat. Our original intention, our hope was actually to fit our own data with the new curve, and that was the first approach adopted.
But unfortunately by the time we had screened out the reliable data points, we just could not do it. We didn't have enough data over a wide enough range of K. So the fall back position to this Scott curve is to some extent an artificial one.
On the other hand, the Scott curve has stood the test of time, and it has been used very widely, also for the analysis of --
MEMBER APOSTOLAKIS: Now, why didn't Scott have the same problem? Why didn't he screen out inappropriate data?
MR. HICKLING: The main data base that Scott was working with were field inspections on steam generator tubing of which there are literally thousands and thousands of data points.
So he didn't have the same problems that we had. He had a huge number of heats, far more than we have, and he had a huge number of tubes, which had been eddy current tested. So he could determine differences in crack length and crack growth rates. It's a quite different database he was dealing with.
MEMBER KRESS: The database you have, looking at, is crack growth rate versus K.
MR. HICKLING: Yes, sir.
MEMBER KRESS: How did the various laboratories determine the K?
MR. HICKLING: That's a very good point, and I mentioned that the test methods were different, constant displacement load. The simple answer, of course, would be to use the standard equations, whatever form of pre-crack specimen they were using in fracture mechanics, but the real issues that were involved are crack front straightness, degree into which crack Ks change during the test, particularly, for example on wedge open loaded specimens where the K value decreases.
And in one particular case, actually two French laboratories which produced a lot of the data we're using, they went back without our prompting at the beginning of this year and reevaluated their K values for every single specimen in terms of remeasuring every specimen and recalculating.
MEMBER KRESS: Were these artificially made cracks at the start?
MR. HICKLING: Yes, the starter is always a fatigue pre-crack, which is a transgranular pre-crack in the material. Now, that point in time you've got a pretty good handle on what K is. It's later on as an irregular crack front develops you have to consider that.
But that point was given a lot of attention.
MEMBER BONACA: Once you got the results at the end, did you ever go back and took the 203 points that you threw away and see whether they would fit on that curve?
MEMBER BONACA: Would it be meaningful or just simply a meaningless exercise?
MR. HICKLING: I'm not sure whether it's particularly meaningful. I think you'll see when we come to actually put up the curve in a second with the data, even 158 don't necessarily fit.
MEMBER WALLIS: We're all waiting for that with great anticipation.
MR. HICKLING: Yes, we'll get there very quickly.
The other point I mentioned is we have to take into account material heat variability because we know how important it is, and we had a very limited number of options as to how we're going to do that, and what we've, in fact, done is we've tried to look at that in terms of calculating a different value of alpha for each heat of material.
Now, what that means is we've taken every single heat of material, all 26 in the database, and we've calculated the appropriate value of alpha to fit the data for that heat to the Scott equation, and that would be the mathematical formula.
No, go ahead. The formula is less interesting than this.
These are, in fact, the 26 heats of material from the different supplies. They're rates in terms of the most susceptible in testing to the least from top to bottom. You can notice, please, the differences in product form, which is implied here, and notice also the difference in number of data points.
There is a certain tendency for laboratories to want to test a particularly susceptible heat because it's an easier testing job, and in fact, that's why some big numbers are coming up here, although there's quite a bit one down here as well.
And there is also equally a tendency -- those heats where we have very little data, and particularly ones where we only have a single data point are tending more towards the bottom, the less susceptible heats where we have less cracking observed.
And so you end up by doing this, by force fitting the Scott curve per heat, you end up with a set of alpha values, the log mean power law constant, which it varies, as you can see, between the most susceptible material actually we had in the database, from six times ten to the minus 12, right down to two times ten to the minus 13. It's quite a difference.
MEMBER WALLIS: Is it fair to ask what heat is? I don't understand what a heat is in this context. Maybe I should have done my homework or something.
MR. HICKLING: What a heat of material is in this contexts?
MR. HICKLING: It would be a single production lot as processed by the material supplier.
MEMBER WALLIS: To do with heat?
MR. HICKLING: Yeah. It starts with the heat, yes. There are other factors involved.
MEMBER WALLIS: It's a production lot.
MR. HICKLING: Correct.
MEMBER WALLIS: It's not a property.
MR. HICKLING: No, not at all. It's just a material identifier. It's a number.
So we finally then get to where we want to go by taking the log normal fit, the ordered median ranking of the alpha values for these 26 heats using standard statistical methods.
I'm not myself a very good statistician. In fact, I'm a pretty awful one. Glenn White, who did the data correlation exercise on this, and with a lot of input from the gentleman on my right who has a very strong grasp of statistics, we tried all sorts of methods, and I think this came out as probably the most valid for looking at this database.
MEMBER WALLIS: So what you're saying here is that the properties of this stuff are very dependent on how it was made.
MR. HICKLING: Correct.
MEMBER WALLIS: And that isn't a variable that's under control or is measured in some quantitative way.
MR. HICKLING: Correct.
MEMBER WALLIS: So there's a tremendous amount of uncertainty about what's going to happen.
MR. HICKLING: Yes. And that's why ultimately there's a limit to how far we can go with a deterministic approach and why we have to get into a probablistic approach.
But this is the result of doing this exercise. What we are actually plotting here is the cumulative distribution of these alpha values for the 26 heats. So every single point here represents one heat.
Now, it may have one specimen. It may have up to the maximum of 32 specimens concealed in that calculated alpha value, and because it's a log normal distribution, of course, it never completely goes to zero or to one. So as you can see, that is this most susceptible heat which was identified, but our curve here is predicting that you could have higher susceptibility heats and you could, in fact, have very, very graphic cracking, which is ultimately going to be physically unreasonable.
There is a limit. It's very hard to define. There's no fully accepted mechanism of Alloy 600 cracking. Therefore, it's very hard for first principles to calculate a physically accepted maximum crack growth rate.
But we all know there has got to be one because otherwise you're getting electro-chemical --
MEMBER WALLIS: What is your access there?
MR. HICKLING: This is the cumulative distribution of the alpha values as a function of the actual values.
MEMBER WALLIS: What does that mean? You're just adding up the number of --
CO-CHAIRMAN SIEBER: It's the probability of this.
MR. HICKLING: Basically it's the probability function.
MEMBER WALLIS: But they all have different origins, and there are 27 tubes for one alpha value, only one for another alpha value. I don't know how you get a --
MEMBER APOSTOLAKIS: Are these points treated as being equivalent?
MEMBER WALLIS: But they're not.
MEMBER APOSTOLAKIS: Some of them come from a large number of test, some do not.
MR. HICKLING: Correct.
MEMBER APOSTOLAKIS: So shouldn't that be taken into account?
MR. HICKLING: Well, there's a limit to how you can do that. If you only have one point to test, if the heat --
MEMBER WALLIS: You're looking for a pretty curve, and this looks quite pretty.
MR. HICKLING: No, no, it's not quite that. You're looking to try and represent what you have. What you have is not what you'd like to have, but you're looking to try and represent it in the fairest way possible.
And given the importance of material heat, we would have been much worse off just taking all of the data and ignoring that effect.
Having said that, the full 158 data points for all of the heats feeds straight into the probablistic analysis that Dr. Riccardella will be talking about. He does not use this approach at all for that. He just takes the data as it comes out.
MEMBER SHACK: Which has its own set of problems.
MR. HICKLING: Which has its own set of problems, too.
MEMBER APOSTOLAKIS: But still, you know, some of these points --
MR. HICKLING: Some have much bigger uncertainty than others.
MR. HICKLING: Correct.
MEMBER SHACK: You can do the analysis estimating the uncertainties in each of the alphas, and you find when you do that that the curve does not shift was much as you would expect.
MR. HICKLING: We have gone through that exercise.
MEMBER APOSTOLAKIS: Now, why do we need one curve?
MR. HICKLING: Because we are trying to propose a single crack growth rate versus K curve appropriate for dispositioning axial internal cracks in the field.
MEMBER APOSTOLAKIS: But why not a family of curves? I mean, I have uncertainty here, don't I?
MR. HICKLING: Well, you don't have enough data to generate a family of curves. Remember what we've done. We've --
MEMBER KRESS: Well, if you factor this probability in, you in essence have a family of curves.
MR. HICKLING: Yes, you do in that sense, but you don't achieve very much because your uncertainty -- I'm going to come on, if I may. Perhaps we could postpone that question until I get to the applications slide as to how we intend to --
MEMBER APOSTOLAKIS: Why assume the data is constant and focus on the uncertainty in alpha? I mean, do we really know, Peter?
MR. HICKLING: No, we don't know beta at all. Beta is assumed from this other analysis. Beta has been adopted from an analysis from Scott.
MEMBER APOSTOLAKIS: But what alpha did scott use? He varied it?
MR. HICKLING: Yeah, the alpha value -- well, the definition of alpha depends how you mean. On a heat to heat basis, yes. Alpha varies.
MEMBER APOSTOLAKIS: Beta doesn't change from heat to heat?
MEMBER APOSTOLAKIS: There is evidence that that doesn't happen?
MR. HICKLING: I'm not quite sure what question you're asking me here.
MEMBER APOSTOLAKIS: Why do you assume that Beta is constant?
MR. HICKLING: Because you can approach what you're trying -- you've got to remember what you're trying to do. You're trying to define a crack growth rate which is going to vary with stress intensity, first of all.
MR. HICKLING: There is no reason necessarily that we have to expect that the material properties will affect the dependence on stress intensity per se. They'll affect the propensity to cracking very much, but the actual stress intensity dependence is no reason to assume that that should vary hugely between different materials.
And, in fact, if you do the exercise that Bill is talking about, the fitting to the individual heats and seeing how this curve moves, it doesn't move a whole lot with the probabilities.
In an ideal world, you might only have one heat of material, and then you wouldn't have this problem, but we're trying to tackle a very real problem here with a larger number of heats out in the field.
MEMBER WALLIS: Well, it's a very strange way of doing things. If I understand, you're looking at data from all of the different sources, and then you realize there's a tremendous number of different alphas to correlate those data, and then you are saying that we're not going to use some statistical thing to relate to this to CRDM.
I want to know which one of these data points is most like our CRDM rather than just taking a mean of a lot of things which might be something like it.
MR. HICKLING: Well, it's a good desire, but they all are. They're all from thick section Alloy 600 material. They may just --
MEMBER WALLIS: There must be some reason that they're different by such large factors.
MR. HICKLING: Yes, and the main reason is almost certainly the thermal processing history of the material.
MEMBER SHACK: But if you had a CRDM nozzle picked at random, you don't know whether it comes from the top of that curve --
MR. HICKLING: The middle or the bottom.
MEMBER SHACK: -- or from the middle or from the bottom, except on a probability basis, that it's more likely to come --
MEMBER WALLIS: It's like testing a lot of nails from nail suppliers and measuring something and then saying we're going to apply that to a bridge.
MR. HICKLING: But it's the standard situation you get into in stress corrosion cracking where you're forced to use what's available, what you can generate in terms of data, not what you would like to have, which is for every single heat out in the field archive material with good quality data on it.
MEMBER SHACK: If you knew exactly what caused the spread, like the grain size and the way they cooled it down, starting raw materials, you might be able to go in and characterize a nozzle, but you know, that's asking a lot.
MR. HICKLING: There's a parallel here which is perhaps worth following very, very briefly to a different problem in the BWR industry where stress corrosion cracking has also been studied for very many years, also intragranular, but where the mechanism of cracking has been tied down fairly well and has been linked to exactly the sort of factors you're talking about so that you can tell what difference potential makes, what difference material, what difference the chemistry makes, and so on.
Unfortunately, despite 30 years or more of study, there is still at least three, probably many more, credible mechanisms for primary water stress corrosion cracking of Alloy 600, and so we do not have that in depth understanding at a fundamental level to do that.
MEMBER KRESS: Yeah, nd I think the only recourse is to fall back on a probability.
MR. HICKLING: So where does this get us to? Let's come back to that Christine and just throw up what this actually does.
These are the 158 data points. As I remind you, each one is plotting growth rate in the test against the representative K value for the test, and again, you will notice the bunching between the 20 and 40 values of K, just the odd ones which are higher or lower.
This is the modified -- this Scott curve, called the modified curve, but that's --
MEMBER APOSTOLAKIS: This curve has nothing to do with the previous curve?
MR. HICKLING: This curve is calculated.
MEMBER WALLIS: But the naive observer would say that the curve has nothing to do with the data whatsoever.
MR. HICKLING: Possibly true, possibly true.
CO-CHAIRMAN FORD: But the MRP curve, John, is the mean curve from the previous graph. It's using the alpha mean.
MR. HICKLING: What I'm going back to, it does, of course, have -- if we could just go back to the previous slide.
To get to that curve, we -- let's go back to the curve with the alphas, please. Thank you.
You're basically given the choice here. Once you've determined this dependency, how do you handle the uncertainty, and what value of alpha are you going to use to plot your single curve? Because you need to end up with a single curve in order to do anything sensible in the field.
The value that we've chosen is to use the 75th percentile from this curve for our value of alpha, and this is, in fact, the mean, if you like, of the upper half of the distribution. So it's not the median value here. It's considerably higher than that. There's a reason for this. It's basically that we are trying to make a best estimate of lightly cracked growth rate in the field, and there's obviously no point in going unrealistically low, but there's no point either in going absolutely unrealistically higher for every single heat of material that's out in the field.
The conservatism that you might want to apply, we feel should be added later in the process when you're evaluating and dispositioning an actual crack, and you have plenty of opportunity there to add engineering conservatism rather than adding it in a hidden form at this stage in the data.
And the ASME code gives some basis for this approach of taking the 75th percentile. So this is how we define the value of alpha here that we use when we create that next curve. Okay?
MEMBER APOSTOLAKIS: So this curve then is the Scott curve with alpha equal to this value, the 75th --
MEMBER APOSTOLAKIS: -- beta equal to 116?
MR. HICKLING: The shape is modeled entirely on the Scott curve. So the exponent is derived from the Scott curve, and the nominal threshold is derived from the Scott curve.
MR. HICKLING: No, the alpha is derived from our actual data.
MEMBER APOSTOLAKIS: Yeah, but in this plot it's the 75th percentile of the previous curve.
MR. HICKLING: But that previous curve is for our own data on the thick section, not for the steam generator.
MEMBER SHACK: But isn't the MRP curve the 75th percentile? The modified Scott was an earlier curve that had been proposed.
MR. HICKLING: Yes, yeah. The MRP curve is what we calculate on that basis.
MEMBER KRESS: Now, the data points --
MR. HICKLING: And it lies -- it's parallel to obviously the Scott curve because it takes the shape from it. It's force fit to it, but it's about 20 percent higher.
MEMBER KRESS: Yeah, but the data points on this curve are the same data points you use to get your probablistic alpha. So it's no surprise that it kind of goes through the mean of them because the 75th on that cumulative is like a mean.
MR. HICKLING: Yeah, it's the mean of the upper half.
MEMBER KRESS: So it's just reflecting the previous curve when you see it do that.
MEMBER BONACA: And I hope the Scott curve had a better fit to data than this.
MR. HICKLING: Well, that's why we used it.
MEMBER KRESS: Well, all this is saying if you go back to that previous curve, it went from ten to the minus 13 up to ten to the minus 11, and you look at the data on this curve. It does the same thing. It's a reflection of this curve right here.
MR. HICKLING: That's right.
MEMBER WALLIS: And any theory that you had that you forced alphas to be like this would go through the data.
MEMBER KRESS: Oh, yeah, absolutely, because you forced it to go through the data. And you forced it to kind of go through that part of the data.
MEMBER WALLIS: Yeah. That conclusion is Scott is wrong. I mean, Scott has nothing to do. Scott --
CO-CHAIRMAN FORD: Scott can't be wrong because it's based on --
CO-CHAIRMAN FORD: I'm not saying a Scott can't be wrong. But the Scott curve is an empirical relationship based on field data.
CO-CHAIRMAN FORD: But what I'd like to know John is you choose the 75 percentile of alpha according to the MRP curve.
CO-CHAIRMAN FORD: But I know there was some data where you should be at the 95th percentile. What was the reasoning behind the choice of 75 over the more conservative 95 percent?
MR. HICKLING: The reasoning is, Peter, quite simple, that we feel that in screening the database we've already applied quite a considerable amount of conservatism. There are a lot of material, as you know. For example, we couldn't consider any heats which didn't show cracking at all. So they're eliminated.
The reasoning is quite simply that we feel that this curve is a good representation, if you like, a conservative representation already of what is actually out in the field.
There will be a lot of heats out in the field which will crack at very much lower rates than this, and I'm going to come onto a comparison with field data in the next slide.
MEMBER KRESS: You're saying that all the data you threw out would fall below that curve on this plot basically.
MR. HICKLING: In general, in general. There are two types. That would be a little bit too general, that statement. We threw some data out, for example, because it was tested in off chemistry, and that might have been higher, but a lot of the data we threw out would have quite clearly fallen well below this curve.
For example, in some of the wedge overloaded data which we threw out, those points were coming out at least an order of magnitude lower than they probably should have been simply because of problems of artifacts of testing.
MEMBER APOSTOLAKIS: But if you use the 75th percentile of alpha, wouldn't you expect most of the points to be below the curve? That doesn't seem to be--
MR. HICKLING: It depends entirely on the distribution.
MEMBER KRESS: That distribution, the 75, is actually close to the mean really.
MEMBER SHACK: Well, it's the 75th percentile on the heat. Now, if a susceptible heat has 32 data points, it's going to skew. When you look at data point by data point, it skews the distribution, which is one argument for doing it by heat. Otherwise you overly weight --
MEMBER KRESS: And so this is a log scale down here
MEMBER APOSTOLAKIS: Wait, wait, wait. I'm speaking of the 75th percentile of this curve, right? If I plotted these points, you know, in the next curve, then I should have most of them below the curve.
MEMBER WALLIS: Yes, but you didn't.
MEMBER SHACK: But you didn't.
MEMBER SHACK: You plotted the raw data.
MEMBER APOSTOLAKIS: You plotted the raw data, which now brings you back to the earlier assumption of using these points as being equivalent. Doesn't that tell you something about the uncertainty of each point and how important it is?
The fact that the new curve doesn't seem to be on the high side probably tells you something about the --
MEMBER WALLIS: No, it tells you there were 21 points for heat one and only one for heat 26.
MR. HICKLING: But there's a strong tendency for the laboratory to have tested a susceptible heat if possible. That's true in the whole history. They don't want to get a zero result which is of no use to anybody.
So there is an innate bias in any stress corrosion cracking test data to have chosen usually the most susceptible material they could get their hands on at least initially.
MEMBER SHACK: But the question is: do you want to characterize the variation in the set of test data that you have or in the population of heats of material that you're likely to encounter in the field?
If you want to characterize the variation in your test data, you do your statistics on all of the data points. If you want to do that, except you sort of hope that you have enough data that's really characteristic of the population.
MEMBER APOSTOLAKIS: Let's go to the next curve.
MEMBER SHACK: But what you're looking for is the population.
MEMBER KRESS: Well, why did you feel like you had to not use the whole curve? If you do a probablistic fracture mechanics, you could have used that whole distribution.
MR. HICKLING: We are doing it. The probablistic fracture mechanics uses the whole database and --
MEMBER KRESS: Okay. I feel better about it then.
MEMBER APOSTOLAKIS: So we could have a family of curves here, you know, with some confidence instead of a single curve, and that's what you're going to do in the probablistic --
MR. HICKLING: Exactly, except the probablistic, as I say, is not based on the MRP curve at al. The MRP curve we're trying to achieve is a reasonable representation of what we would expect for crack growth rate already involving some conservatism for heats out in the field.
MEMBER APOSTOLAKIS: So this is a reasonable representation?
MR. HICKLING: As Bill says, of the heats that are likely to be out in the field.
MEMBER SHACK: It's his choice.
MR. HICKLING: This was the expert panel's recommendation.
MEMBER SHACK: Yet in a deterministic world you pick one curve. Which curve do you want to pick?
They have chosen the 75th percentile for the reasons that John has stated. You could make arguments that it should be the 95th percentile. You want to bound all of the data. You could make it the 50th percentile. You want a representative.
You know, you have to decide in a deterministic world with a lot of scatter. You have to make an argument for which curve you want to pick.
MEMBER APOSTOLAKIS: And the argument is that the points above the curve don't matter that much?
MR. HICKLING: Well, let's develop the argument a little bit more because the test of any curve is does it describe the field observations, and that's the point. It's already indicated a little bit.
There are actually two points written in here, which I'm going to come onto in the next slide what those are. There is very little data available in the U.S. from the field on nozzle cracking where there have been sequential measurements of crack length and depth.
The only data that's available is from one nozzle in D.C. Cook 2 where a crack nozzle was allowed to operate for a certain period of time, and there was increase in the measured length and depth of the crack.
And these two points are plotted here. This is the length increase of that crack, and this is the depth increase.
Now, agreed this is only one isolated indicate, but it is worth noting that both of those points fall very well below that curve.
We go on to the next slide --
CO-CHAIRMAN FORD: Could I just interrupt for one minute, John? I wanted -- this is the reason why we are discussing this data. This is one of the first times that this group has seen these data, and I wanted to be aware of the amount of work that's gone into this area.
However, we could go on forever discussing this, and what I would like to suggest is that we will finish this at 12 o'clock, this particular presentation at 12 o'clock. We will recess for lunch for three quarters of an hour, and we'll come back at quarter to one, and that will give Glenn hopefully time to do his presentation and leave when he wants to do. Yes?
CO-CHAIRMAN FORD: Will that be okay?
So, John, could you pick and choose and try to finish by --
MR. HICKLING: Yes, we can get through the rest very quickly, I think.
MR. HICKLING: With your help. Basically whenever you do a comparison from what you derive from the laboratory data with the field data, we've talked a lot about the uncertainties in the laboratory data, but it's worth remembering that there are very considerable uncertainties in the field data because we're basically talking about differences between two ultrasonic measurements of crack size, and we are really analyzing the difference between the delta between those two measurements.
So there's considerable NDC uncertainty, feeds in straight away here.
Secondly, there are uncertainties in the estimates of K, depending on how you analyze the residual stresses for the particular component concerned, and that's a very significant problem in this area.
And, thirdly, of course, there may be some uncertainty in the actual operating temperature of the nozzle, and we know how corrected these values are for temperature in different plants and in different countries.
I've showed on the previous slide the D.C. Cook data. The main body of field data we have available to compare with our curve is, in fact, French data because the French, once they detected cracking Bouget, did a lot of ultrasonic inspection, and they never had a second leakage.
So there is a lot of field data out there, and we made very considerable efforts to obtain everything we could.
The French reported their data at certain operating temperatures for their plants, and there has been some movement in what they've reported over the years as the operating temperature of different plants.
We have taken the latest report we were able to obtain on individual plants and extrapolated the reported data to a common temperature of 325 degrees Centigrade in order to compare it with our curve.
What we've done, rather than just comparing it simply with the curve, is we decided to go to a statistical approach here to show you how, in fact, the data, the screened data in our database, is going to work. And what we've actually done for the comparison is the following.
For every point where we had a field data point at a particular K value where we could derive a crack growth rate. We've done some random sampling from the upper half of the MRP distribution of crack growth rates, are using the same approach that we got, basically the letters to the 75th percentile, and using the K dependence of the Scott equation.
Let's just put up the results, and then we can come back to that. In this diagram, the black points represent the EDF field data extrapolated to the nominal temperature, 325, from the reported temperature of the head.
The red data points are the data points obtained from our MRP distribution applying this Monte Carlo approach to the top half of the distribution. So every time you did that, you'd get a different set of red points.
But remembering the uncertainties in that field data, we feel that's a more valid comparison than just putting a curve through it, and at first glance you can see that the Monte Carlo does produce some very high crack growth rates, of course, as you'd expect from the MRP distribution, and the agreement doesn't look that bad.
In fact, the next curve shows what that would look like on a cumulative probability plot of the French field data here, the black points, and this statistical treatment of the upper half of the database, which are the red points.
And there's no denying the French field data is higher, showing that the cracks measured in France in the field did grow more rapidly than what we're predicting, and when we consider there are very real reasons for that, as Larry mentioned earlier, we don't think it's just a matter of chance that the French plants have this problem so much earlier.
MEMBER WALLIS: Would you do the exercise of taking random numbers between 20 and 50 for K and between 1E minus 11 and 1E minus nine for crack growth rate?
Just take random numbers, do exactly the same thing you've done here. You'll get the same sort of picture.
MEMBER KRESS: Well, that's what he did, except the random numbers are --
MEMBER WALLIS: But what does it tell me? If the random numbers give the same result as your data, I'm not quite sure I've learned anything from the data.
MR. HICKLING: No, they're not entirely random numbers. It's a Monte Carlo treatment of part of the data.
MEMBER WALLIS: Well, no, I mean if I look at this curve here with this distribution of points.
MEMBER APOSTOLAKIS: Which distribution are we referring to? I haven't seen a single distribution here.
MEMBER WALLIS: If I had random numbers here, I get the same --
MEMBER APOSTOLAKIS: Which distribution? Of the alpha?
MEMBER KRESS: Yeah, but they only selected from the top half though.
MR. HICKLING: Correct. It's an attempt to recommend the sort of variation that is inherent in the data, whether it be from the lab or the field.
MEMBER WALLIS: But there are people who have tried to publish reports like this, which show that taking random data on the same graph gives the same result, and that doesn't give me a good feeling at all that it's a useful exercise.
MEMBER KRESS: Well, it's a way to compare the French data to this database that went into making the curve. That's all he's saying. It's a way to compare those two.
MEMBER WALLIS: But if you compare the random numbers thrown at the --
MEMBER KRESS: But he's showing what would happen if you took the French data and put it on this same curve with -- you'd have ended up with a different distribution.
MEMBER APOSTOLAKIS: The French data were not part of the derivation of the curve for alpha?
MEMBER KRESS: No, and they say it's clearly a different set of data, and they have reason to believe it should not be part of the database, and I think that reason is maybe weird, and that is, well, they started cracking a lot earlier than ours. So it must have been something.
MR. HICKLING: No, no. Excuse me. There are two separate issues here. That is the reasoning why the French data will always come out higher no matter how you treat it, because we do believe that the material susceptibility was higher.
The one thing we do know is that the material processing temperatures in general were much lower in France for that nozzle material, and there's good reason to expect that that would lead to a higher degree of susceptibility.
The second point, the reason why we didn't use the French data, for example, in deriving our curve is that there are uncertainties in the French field data which we cannot fully tie down and which we are ultimately somewhat unhappy about. We've extrapolated up very much in temperature. Whether or not that's fully justified is another issue, and it's an issue we couldn't solve.
MEMBER KRESS: It depends on whether your final product you want to be highly conservative or you want to be a representative value, I guess.
MR. HICKLING: Exactly, and the feeling is that we are trying for a representative curve, and the conservatism which needs to be added is added in the engineering analysis later on and is visible, not hidden in some way.
MEMBER KRESS: Yeah, which the ACRS has said is the way you ought to do things with respect to different issues in the past.
We have always advocated that as the right approach.
MEMBER APOSTOLAKIS: Well, yeah. There was a bullet that said if you did something because it was conservative. I mean, they're not as pure as it would seem.
MEMBER KRESS: There's always a mixture.
CO-CHAIRMAN FORD: It was the screening criteria which they said was conservative, and that's why they're using the 75th rather than the 95th percentile for alpha. It's reasonable.
MEMBER APOSTOLAKIS: So what Tom said is not quite accurate.
MEMBER LEITCH: John, one thing that concerns me regarding that French data, I guess, I've always wondered whether -- you know, we spend a lot of time talking about crack growth rate. I'm wondering about the depth of the crack at initiation. In other words, does the crack grow more or less linear? It's how many inches per year from zero, or might it be a fact that instantaneously the crack proceeds to some depth?
MR. HICKLING: No, definitely not instantaneously. You're quite correct. We're not trying to describe that whole phase of initiation and early growth, but all that we know about both primary water stress corrosion cracking in general suggests that the initial phase of crack growth is very, very slow, indeed, and getting the crack -- remember in the field we're not dealing with transgranular fatigue pre-crack which then goes into granular at all. We're dealing with a crack which develops as an intragranular stress corrosion crack at a point in time where you can't calculate it.
And all of the evidence is that a huge part of the lifetime, perhaps as much as 85 percent of the lifetime of the crack, as it were, is developing the initial crack, whatever you'd like to call initiation, and growing it to a level at which you can detect it with NDE methods.
So we're not addressing that whole area at all here. We're just saying what would we do to disposition once we find a flaw which is large enough to be found by NDE.
And I think the one thing that you can be sure about is that there's nothing instantaneous about stress corrosion cracking in that sense.
MEMBER LEITCH: So you're saying that the evidence seems to suggest that that initial phase is relatively slow compared with the ongoing. I was wondering if -- you know, in my mind I had pictured a model that was just the opposite of that. Initially it took a quick depth and then the growth was slow from there.
MR. HICKLING: No. I think you'd find pretty uniform agreement among anyone who's worked on stress corrosion cracking.
MEMBER APOSTOLAKIS: So the growth rate is independent of the size of the crack?
MR. HICKLING: No, it's actually not. It's very dependent upon it.
MEMBER KRESS: It's part of the K
MR. HICKLING: It's later part of the K, and in the very initial stages, it's more complicated that --
MEMBER APOSTOLAKIS: Now, where do the curves cross up there? Is there any reason why they should do that?
MR. HICKLING: Yes, because the black points, in fact -- well, it's a function, of course, of the sampling that has been applied to the MRP distribution to get these particular set of points, but if we just go back very quickly to that alpha curve, it's a point I'd like to make.
Remember this is a log normal fit which is approaching one exponentially. So you are predicting infinitely high crack growth rates, albeit with a very, very low probability that it will ever occur. So that is physically unreasonable.
And, in fact, as Dr. Riccardella will talk about in the probablistic talk this afternoon, for that purpose you're going to have to truncate this log normal distribution, go to a log triangular because it's physically unreasonable to go to infinity. A stress corrosion crack would never do that. It can't do.
But the effect of using it in the way we've just done it is, of course, it can generate some very high crack growth rates even at low K.
MEMBER APOSTOLAKIS: So how big was your Monte Carlo sample? Was it big enough to pick up those values, the sample?
MEMBER APOSTOLAKIS: You said you did a Monte Carlo.
MR. HICKLING: You mean the number of iterations?
MEMBER APOSTOLAKIS: Yeah, yeah, because it will be a very large number to start picking up the very unrealistic --
MR. HICKLING: No, I'm not saying we'd be picking up any which are way out in the table here, but I'm saying it's inherent in the approach that we're using.
MEMBER APOSTOLAKIS: Does that explain why the curves cross?
MR. HICKLING: I think so, yes, because the French field data is real data, albeit with uncertainties.
MEMBER APOSTOLAKIS: Oh, okay. So it's an artifact.
MR. HICKLING: Can we go on quickly?
I want to make one very -- one before, please. Thanks -- I want to make one very important point. In actual fact, in France in the regulatory context, the French finally did not use any of these approaches. The actual French approach that was finally agreed upon was that in no case did the actual measured crack growth rate in the through wall direction of any crack which was found in plant exceed four millimeters per year, and this was actually the figure they adopted irrespective of head temperature as a limit which would allow them to justify continued operation for at least one cycle even with cracks which were already 11 millimeters deep.
MEMBER WALLIS: And your French data plot shows 20 or 30 millimeters a year. That's in the other direction.
MR. HICKLING: No, but that's because it's been temperature corrected, and it's been pushed up a lot in temperature. The reported temperatures for the French plant, as I said, have moved somewhat, but they tended to move down quite low. So we've had to extrapolate up an awful lot, and we're not very happy about having done that, quite frankly.
MEMBER WALLIS: That's one reason they're so high.
MR. HICKLING: Absolutely.
MEMBER WALLIS: Or it is the reason they're so high.
MR. HICKLING: So moving on to what do we actually intend to do with this curve and why do we think it makes sense, it's intended that it would be used to detect the disposition, PWSCC floors, either if they're axial ID floors or if they're below the J-groove weld, i.e., we're not -- floors which are not part of the pressure boundary.
The main application we see is a deterministic evaluation of axial ID floors which are part of the pressure boundary. We're not intended to use it, as we discussed earlier, at very low K values. Such floors, once detected, will already be well above any K value that you might be looking at here.
And this is to give you a feel for a generic calculation of what that ID axial crack growth would look like. The Y axis here is showing the depth of the axial ID crack initially, and this is showing the calculated operating time to reach a 12 millimeter deep crack, which would be 75 percent through wall acceptance limit in the nozzle, to give you a feel for the sort of way in which this would pan out.
MEMBER WALLIS: There's a lot of uncertainty in this, isn't there?
MR. HICKLING: There's a lot of assumptions I would say is perhaps a better word as well rather than --
MEMBER WALLIS: I don't know how you can get one curve from that tremendously uncertain data without showing many curves or something.
MR. HICKLING: Well, the way we get to a single curve is defined because of the way we've defined the curve. I think the question is what uncertainty remains in the analysis.
For example, we've assumed in this particular case a particular K value based on a residual stress here. Now, this is a generic calculation. It's purely an example calculation, nothing else.
In any application of this, we'd expect that a found floor would be dispositioned correctly in terms of the best possible stress analysis to reduce the uncertainty, for example, in --
MEMBER KRESS: Yeah, but I would have also expected for a specific case for the decision maker to make an appropriate decision, you would have a set of curves for the distribution of the uncertainty about that curve.
MR. HICKLING: Not in terms of the deterministic approach, no.
MEMBER KRESS: Well, yeah, but that's one of our problems with the deterministic approach. We never know what the uncertainties are, and the uncertainties are what drive our decision making process.
You know, if that curve had uncertainty bounds on it, five and 95 percentile or something, then as a decision maker I'd have enough information to at least think about what decision I want to make, and you could do that with the database you have. It's inherent in it.
MEMBER APOSTOLAKIS: We're going to discuss this this afternoon.
MEMBER LEITCH: I'm afraid I don't understand how that curve would be used. Maybe I don't understand the axes.
MR. HICKLING: In an actual plant situation, you would detect with NDE a crack which you would size as best as you possibly could.
MR. HICKLING: And here we're saying that we might size it as let's take an example and size it at four millimeter depth (phonetic).
MR. HICKLING: You do the best possible analysis you could of the residual stress driving that crack based on all sorts of things, including nozzle downhill angle and all of the other things you might be able to put into that to get your K value, which would feed into the equation here.
You'd adjust your head temperature to the correct value for the actual plant, and you'd then read across and determine that without adding any subsequent conservatism, which you would almost certainly want to do; the prediction from the MRP crack growth rate curve would be perhaps in that case that you would need something like 16 months or 15 months for that crack to have grown from four millimeters deep to 12 millimeters deep.
MEMBER KRESS: And that's part of the analysis you make to determine whether you can continue operating in a certain amount of time.
MEMBER BONACA: So that curve will shift.
MEMBER ROSEN: Well, if you have an 18-month cycle, you look on that curve and see if your operating time is greater than 18 months and it says it is; then you can run the cycle.
MR. HICKLING: That's a good point. This is the temperature of what we regard as the hottest head, which might be actually applicable.
MEMBER APOSTOLAKIS: But is there any reason to believe that this curve is conservative? I mean, in a deterministic world at least you want to have something conservative.
Is it conservative?
MR. HICKLING: There are some conservatisms inherent in the derivation of the curve. That's the point I was trying to make earlier. Whether or not it's a conservative curve is a global question which is very difficult to answer.
We consider that it's a representative curve for some of the heats which are more likely to crack because remember it's the 75th percentile, not the 50th, of our database.
Could I just go quickly over the very final slide?
There is no intention, I think, in the industry to try and disposition OD cracks which are actually found. Going back to what we talked about right at the very beginning, if we were talking about hypothetical calculations, we would recommend that this factor of two, which represents the uncertainty in the chemical environment be put onto that curve.
And a subgroup of the experts did look at the experience. We still think the arguments as I mentioned that we put forward on the environment are valid in the non-Davis-Besse situation, which we consider to be the usual case which has been found to date.
However, last slide Christine.
It wouldn't be valid, and we're not claiming that it would be if the leak rates were sufficiently high to get a large, local decrease in temperature, cavity formation, and steel.
That brings up the question: what would happen with stress corrosion cracking of Alloy 600 in that case?
And that takes me back to this point I mentioned earlier, that in general, we think of Alloy 600 as being very resistant to cracking in acid media. There's very little data available. What there is shows that in order to get cracking in concentrated boric acid, you need quite high levels of both oxygen and chloride contamination, not just one or the other.
And interestingly, the effects at N was at intermediate temperatures, suggesting that we're now in a different type of Alloy 600 cracking, not the primary water stress corrosion cracking we've been talking about.
And that's all I had.
CO-CHAIRMAN FORD: Thank you very much, John.
MEMBER KRESS: The factor of two that's put on there, because of chemistry uncertainties, strikes me as being a little strange in view of the uncertainties in the data about getting the curve in the first place. It's just overwhelmed by the --
MR. HICKLING: It's handling a different situation.
MEMBER SHACK: It moved the whole population is the theory.
MEMBER SHACK: On any crack growth rate of heat, it's insignificant compared to the variation between heats, but if you're moving the whole population.
MEMBER KRESS: I'll have to think about that one. I still think it's gilding the lily.
CO-CHAIRMAN FORD: John, thank you very much indeed.
I'd like us to go into recess until quarter to one when we'll start again. Quarter to one, guys.
(Whereupon, at 12:04 p.m., the meeting was recessed for lunch, to reconvene at 12:45 p.m., the same day.)

(12:49 p.m.)
CO-CHAIRMAN FORD: Okay. We're back in session.
We're going to start with the technical assessment of Davis-Besse's degradation. Am I correct?
MS. KING: Yes, you are correct. I do have both presentations for you, and in your packets, this would be Slide 81, about three quarters of the way back. And we will come back to the fracture mechanics.
MS. WESTON: If I may, some of the slides and tables are in your book starting at page 131.
MEMBER APOSTOLAKIS: So when you said the 81?
MEMBER KRESS: The package of slides.
MEMBER APOSTOLAKIS: This package, yes. Okay.
MR. WHITE: Good afternoon, everyone. My name is Glenn White, and I'm with Dominion Engineering.
Since March 22nd, Dominion Engineering has been supporting the Electric Power Research Institute and the Materials Reliability Program on assessing the Davis-Besse experience. Specifically we've been trying to understand, based on calculations, analysis work, and also looking at experimental data that's available, what the degradation progression was at Davis-Besse.
MS. KING: We're in animate mode. Let me fix it real quick. Go ahead.
MEMBER APOSTOLAKIS: Show without a dimension. See that on the left at the bottom?
MS. KING: Thank you very much.
There we go.
MR. WHITE: Okay. The presentation that I have prepared that's in the packet here is approximately 15 slides of material that summarizes the various mechanisms that could possibly be active and summarizes our conclusions as to what we believe happened at Davis-Besse, what the likely progression of degradation was.
Two weeks ago at an NRC meeting with some of the NRR staff and research staff, I presented a longer presentation, 63 slides. That presentation is available on the NRC Web site, and we have that as back-up material for this discussion.
So if there are questions that get into particular areas, I'm prepared to answer them using that longer presentation, but the original time allotment for my talk was only a half hour. So that's why they're sticking to the 15 slides in the packet.
MS. WESTON: Glenn, they have copies of that package in the notebook.
MR. WHITE: Okay.
MS. WESTON: They have the whole package.
MR. WHITE: Great, perfect.
I'm going to start off talking about the purpose of this work, the approach that is called for, and then get into the individual mechanisms briefly, as I said, and then outline what the likely degradation progression was based on our analysis work, supplemented with experience and experimental results, and then also touch on the most relevant experimental test that had been performed in the past because I think it's important to touch on that.
We've done work to try to quantify the chemical environment and the thermal hydraulic environment along the leak path in the annulus on the OD of the nozzle, and so there are a lot of other analyses that we can get into, as I say.
So if we go to the next slide, the purpose here is to answer two main questions that have been put forth. The first one is if there is significant degradation it will be detectable visually, by doing a visual inspection of the region above the head.
And the unit could be detectable a couple of different ways. One, you might see a void directly so that you could see the wastage directly.
But the other way, you could infer that there might be wastage that would require a closer look if you found a significant amount of deposits, either boron deposits or some corrosion product deposits. So that's the first main question.
The second main question has been put forth is what is the time scale of this process following initiation of a through wall leak. Is there a period of time that we all have assurance that we can't reach unacceptable wastage? That's the second question.
A related question to that is: what is an unacceptable level of wastage, and I'm not directly addressing that in this presentation here because it's a closely related, but a slightly different subject that really goes to the structural stress calculations.
What I'm going to be concentrating on is the degradation progression, the environment in the annulus, and the various corrosion and potentially erosion mechanisms. But on the question of what is acceptable, I will mention that in the early '90s, in the '93 time span, the three owners' groups did finite element analyses taking out a certain volume of the -- actually six cubic inches of volume of the low alloy steel head, and they did that using different geometries of the assumed loss, different aspect ratios of the voids.
And at that time it was determined that six cubic inches allows the code margins to be maintained.
MEMBER WALLIS: It depends how it's removed.
MR. WHITE: It depends how it's removed, but each owners' group took two or three different bounding assumptions. So based on those --
MEMBER WALLIS: But if it's a straight hull, it's very different from taking off six cubic inches all the way around.
MR. WHITE: Yes. For example, it would take all six cubic inches along the other surface, the top surface of the head, or you could take the six cubic inches along the bore, and no matter how they were taken out, the stressors are still within code margins.
MEMBER WALLIS: That's assuming you had a lined head?
MR. WHITE: Assuming different geometries, different bounding geometries is what they did.
Since that time, we have just recently begun to look at this question of what is acceptable wastage, and Dominion Engineering has performed some preliminary finite element analyses, taking out some of the elements that make up the head, and the conclusion from that work is that it's most likely significantly more than six cubic inches can be lost and still the primary membrane stresses will still be below the code allowable stress intensity values.
And just mentioning because this is a related question --
MEMBER WALLIS: This is with the stainless steel liner, cladding?
MR. WHITE: The cladding is a second question. The first thing we did --
MEMBER WALLIS: Well, without your cladding you could make a hole six cubic inches, couldn't you? You could drill a hole through it and remove six cubic inches. You have a small LOCA that's all
MR. WHITE: We've also looked at the issue of the cladding, and I believe later this afternoon there will be some discussion about the margins in terms of the cladding for Davis-Besse, and there, again, there could be a significantly large area where the cladding is retaining the pressure.
MEMBER WALLIS: Okay. So like 200 inches at Davis-Besse?
MR. WHITE: Yes, approaching 200 cubic inches of material loss at Davis-Besse, and I'm going to put that in the context of the progression in some other slides here.
Okay. The basic approach is to examine how the various conceivable mechanisms and material loss change as the leak rate increases. Through our analysis work, what we found is it's really the rate is the controlling parameter for two main reasons which are shown down here.
Number one, the level of cooling. When you start with primary water, it has a certain enthalpy, about 613 BTUs per pound. If you have saturated steam at atmospheric pressure, its enthalpy is higher. So you need to have some heat input in order to completely boil off that primary water.
But the primary water because of the temperature and the pressure, it does have enough enthalpy to boil itself through flashing al the way to 45 percent quality, assuming atmospheric pressure.
To get from the 45 percent quality all the way up to 100 percent quality, you need a heat input, and obviously that heat input is proportional to the size of the leak rate. So the higher the leak rate, the higher the heat sync, the more local cooling. The more local cooling you have, the more ability there is for liquid to exist in that annulus, and it's the liquid environment which is potentially corrosive to the low alloy steel.
The second point are the velocities, the magnitude of the velocities. For very low leak rates, velocity, just a simple average mass balance velocity calculations show very small velocities which are not consistent with erosion or potentially flow accelerated corrosion mechanisms.
So,a gain, the leak rate is the controlling parameter in terms of the potential for erosion or flow accelerated corrosion. So that's why we concentrate on varying the leak rate.
Okay. Go to the next slide.
The leak rate also has another important determining characteristic, and that is the leak rate determines the magnitude of deposits that will exit the pressure boundary. As we've heard, of course, the concentration of boron in the primary waters decreases over the fuel cycle from in the neighborhood of 2,000 ppm down towards 100 ppm, in some cases lower than that, ten, five ppm at some plants right at the end of the fuel cycle.
But if you integrate over the same time period for two different leak rates, you'll get the amount of deposits being proportional to the leak rate.
The bottom line here from the analysis is that we integrate all of the results together to determine the time frame for significant degradation and then correlate the volume of wastage, material loss of the head versus the volume of deposits produced, and, for example, at Davis-Besse it has been reported that there were 900 pounds of boron deposits on top of the head.
So we're trying to do analysis work in order to try to show how much wastage you would expect as the amount of deposits on the head. Obviously hundreds of pounds in deposits should be readily visible on top of the head. Much smaller amounts of deposits may require the insulation to be removed.
All right. The material loss mechanisms. If we go to the next slide, we start off on the corrosion or the chemical type of mechanisms. The first one here --I'll just briefly touch on each one of these -- boric acid corrosion.
In the leak process, you can have a concentration occurring due to the boiling, flashing and boiling, process which tends to concentrate the boron. So you can end up with a concentrated boric acid solution.
However, if there's no oxygen, typically these sort of de-aerated boric acid tests of low alloy steel show very low corrosion rates. So that's the first thing to keep in mind.
The second potential mechanism here is deposits themselves. Could they be corrosive without liquid?
And there have been some tests that have been attempted with some deposits on top of low alloy steel and found to be very mildly corrosive in a human environment. So that's the second potential mechanism.
Then we do have a crevice geometry here. We have the annulus. So potentially there could be a crevice corrosion mechanism. Crevice corrosion is a mechanism that's of concern in marine applications often. It's also a concern with the waste packaging at Yucca Mountain.
So we've looked at crevice corrosion as a potentially significant mechanism.
We also have, as mentioned before, the low alloy steel is in contact with the Alloy 600 nozzle. So there's a galvanic couple, and perhaps that could drive a corrosion mechanism. Where that coupling, the low alloy steel will raise the corrosion potential or the Alloy 600 will raise the corrosion potential of the low alloy steel and provide the driving force for the corrosion. So we've also looked at that.
Then the next mechanism coming down the list here is classic boric acid corrosion. Now we have an aerated environment. There have been many tests performed in this sort of environment. They're documented in the boric acid corrosion guide book that's been published by EPRI , and you can have up to one to five inches per year of corrosion shown in these tests where you have oxygen that's in the solution.
Lastly here, molten boric acid corrosion. Boric acid deposits have a melting temperature of about 340 Fahrenheit. So even without water, you can have a liquid at the higher temperatures, and the question becomes: how corrosive is that liquid? And so I'll have some comments on that molten salt type corrosion.
And this slide here are the flow type, velocity type mechanisms here, and the first one being flow accelerated corrosion. That's a possibility depending on whether or not there's a magnetite layer that may form on the low alloy steel. This is, of course, a mechanism that is seen on the secondary plant in the piping. So we've examined looking at the possibility of that having an influence on the development of the process.
And then there are more just the straight erosion type mechanisms, flashing induced erosion. If we think about gaskets that can develop leaks, you may have a local region that may be a somewhat analogous situation here with erosion.
You hear the term "steam cutting erosion." That's just really another term for flashing induced erosion. We have water droplets. So, therefore, the term "droplet impingement erosion."
Single phase erosion of steam velocities as you boil water off all of the water content in single phase steam and potentially you might have velocities of the steam and potentially that could lead to a single phase erosion.
So that's an introduction to all of the mechanisms that we could come up with for removing material.
This matrix here is a preliminary take based on the last two months of work on how these mechanisms may stack up in terms of which ones are active. As I mentioned, the first two have low rates. So we don't think they play a major role in the progression.
Then we get to single phase erosion. We start with an initially tight annulus, a gap on the order of 1/1000 of an inch radially there or perhaps tighter. So initially if you have a leak, it may lead to velocities high enough to get erosion.
Now, once that annulus would open up, then the velocities would be reduced because of the greater flow area. So perhaps for the initial tight annulus the single phase erosion could be a factor or impingement erosion also.
I've got full accelerated corrosion listed here if the velocities are high enough. Crevice corrosion. I can say that this is not a classic crevice corrosion type system here because crevice corrosion is typically associated with materials that passivate (phonetic), like stainless steels.
If we had -- crevice corrosion is driven by a chemical process where the anodic corrosion reaction occurs deep down in the crevice, but the cathodic reaction occurs away at the exposed surface on top of the head. If there was a liquid film up on the top surface of the head, potentially you could have the driver for a corrosion circuit from the outside to the inside deep down in the annulus.
However, in our case, if there's going to be a significant water film on the outside of the head, in the top head surface, then we would expect there also to be deposits in an acidic environment, which would lead to significant corrosion rates themselves. So it would act as an anodic site up on the outside. So we don't see this separation of the cathode and anode excites in the low alloy steel due to the crevice corrosion, provided that you have the acidic environment on the outside of the head.
But the next mechanism here, galvanic corrosion in the secluded type geometry may be more of a possibility. We do have the coupling from the low alloy steel to the Alloy 600, and that potentially does give you a driver for the corrosion.
However, there isn't enough data available in the literature to try to quantify the magnitude of that mechanism. There just hasn't been a lot done with low alloy steels and boric acid type environments with things to measure polarization curves and so on. We haven't addressed that from a basic corrosion science standpoint yet.
Molten boric acid corrosion here. I'm saying that it's possible, but we expect lower rates. There isn't a lot of available data experimentally in terms of trying to measure its corrosivity for low alloy steel. However, if we look at the basic corrosion chemistry there, we know that the molten boric acid has a lower -- the solubility of corrosion products are lower in molten boric acid than in aqueous solutions. So that's one factor.
Electrical conductivities are likely to be lower in molten boric acid, and also the oxygen and hydrogen ion concentrations are also likely to be lower in a molten salt type solution.
So for some fundamental reasons we believe that the molten boric acid corrosion is unlikely to produce the one to five inches per year that has been observed with the aerated concentrated boric acid solutions, but it's still something that has to be looked at.
Okay. So that takes care of this slide here. This next slide here really sums up the analyses that have been done in terms of understanding the chemical environment, looking at the pH through multi-Q calculations.
MS. WESTON: It's page 139 in the book.
MR. WHITE: And we've also performed thermal hydraulic calculations and heat transfer calculations to try to quantify the temperature as a function of the leak rate. We've calculated velocities as a function of leak rate, wall sheer stresses, as I mentioned, the pH under various conditions.
So putting all of those things together, we've developed this degradation progression here which really goes from the left side of the slide to the right side of the slide as the leak rate may increase over time.
The top row of boxes here has a nozzle or weld condition. Early in time you would just start out with a leak path to the annulus, but in a very small leak.
As that crack growth continues, that leak -- an axial through wall crack may reach above the top of the weld for a significant distance. At Davis-Besse, which would be associated with the far right area here, there was an axial through wall crack that reached .9 inches above the top of the weld on the nozzle ID and 1.2 inches above the top of the weld on the nozzle OD.
So there was a leak path that extended all the way through the nozzle a significant distance above the top of the weld and leak rate calculations that we performed as part of this work have shown that should result in a high leak rate, meaning on the order of .1 gpm, which is consistent with all of the evidence for the Davis-Besse nozzle number three.
So we have growing cracks, increasing leak rate as we go from left to right across the page here.
MEMBER SHACK: Now, what does the pressure drop look like, say, with that .9 inch crack and I have a pressure drop across the crack into the annulus and then I have the annulus -- the interference fit to the atmosphere? What's the pressure drop across the crack and then across the interference fit?
MR. WHITE: Well, I do have some slides on that, but I don't want to go right to them. What I would say is initially when you have that very tight initial annulus of a mil, a half a mil or so, you may have also a significant pressure drop in the annulus itself.
But as the annulus tends -- as you begin to have some material loss, very quickly you'll reach a couple mils radial gap and the calculations show that you basically have atmospheric pressure at a very large range of leak rates in that annulus.
So fairly early in the process we believe that we essentially have atmospheric pressure in the annulus, and really the choke point in the flow is at the exit of the crack.
And that's what I'm showing here on this line, is the annulus condition. Here possibly hypothetically starting off clogged, but then opening up and allowing more and more flow through, but it's really the crack that's more the governing resistance to the flow.
Leak rates here. Well, we'll start over there. We have a hypothetical zero leak rate. Contrary to experience, we had a nozzle with a leak path type crack, in other words, a leak path reaching to the annulus, but there was no actual flow making it to the outside to the top of the head. Then we would have a hypothetical zero leak rate, and this column addresses that situation.
As we go to the right, we're increasing in leak rate, .001 gpm, .01 gpm as we move to the right, and then up to the point greater than .1 gpm on the far right.
MEMBER ROSEN: Why do you say in your first column that you will at least have some small amount extruded in that circumstance? This is the classic stealth crack that we worried about.
MR. WHITE: Well, just thinking that if you're going to precipitate and go up the annulus, you should be pushing out a small amount. I'm not claiming how visible that's going to be.
MEMBER ROSEN: Pardon me?
MR. WHITE: I'm not claiming how visible that amount will be. I'm just saying that you have a clogged up annulus with --
MEMBER ROSEN: It could stay subsurface you're saying. It says here at least a small amount is extruded . Presumably you mean outside the crack in the annulus. The extrusion results in deposits that are visible.
MR. WHITE: Right. Well, as I say --
MEMBER ROSEN: It's your chart. I'm just asking what you mean by that.
MR. WHITE: What the real experience has been over here in this chart, in this column over here, we do have small amounts of deposits that come up that correspond to small leak rates.
MEMBER ROSEN: I don't think I agree with you that it's been in the second column. That column has a bottom line of seven pounds, and we've seen pictures where there were very small amounts.
MR. WHITE: Less than seven pounds.
MR. WHITE: Yeah, much less, yeah.
MEMBER ROSEN: So the column on the left was what was operating in those conditions. We had a lot less than seven pounds, and I'm trying to examine what happens down at the end --
MR. WHITE: Right.
MEMBER ROSEN: -- the boundary of that.
MR. WHITE: So let me talk about if there is a zero leak rate what happens and you don't have significant deposits that come out.
In that situation, in a hypothetical situation, we have no velocity. so you have no erosion type mechanisms that could be active, and you would have no cooling going on. So you would have a crevice environment there that's at 600 degrees approximately, the primary temperature.
But since this is a clogged annulus up to the point where the clogging is, you're going to have pressurized water at the primary pressure. You're not having any boiling going on because there's no flow. If there was boiling, there would have to be a leak that would be actively going to the outside.
So there is no vaporization driven concentration mechanism with no flow at all, and then as we heard earlier in John Hickling's talk, there's not going to be oxygen down in that crevice environment. So there aren't the conditions that would produce -- the corrosion rates would be limited to the low corrosion rate s that had ben measured for de-aerated environments, and without a large concentrating mechanism it should be even less than most of those tests which were done in concentrated boric acid conditions.
MEMBER WALLIS: If I remember correctly, the analyses that were done to preclude oxygen at the bottom of the annulus were done for fairly tight crevices and straight fits that you have --
MR. WHITE: Right.
MEMBER WALLIS: -- in these designs. In order to get to the right of that diagram, to get your temperature down, which you will need for the high corrosion rates, does that preclusion of oxygen analysis still hold for the fairly wide annuli that you're going to need to have the flurry?
MR. WHITE: No. Well, as we move all the way to the right here, aerated boric acid corrosion once you have something that opens up to the problem, you definitely would have the aerated boric acid corrosion as --
MR. WHITE: The question becomes: at what point does the oxygen get down into the crevice? It's obviously between those two points, and at this point we just can't say exactly where that point is based on the work that's been done so far.
MR. WHITE: It's just when you're very hot, the hot iron is going to be very efficient at taking out the oxygen. It's when you have the cooling and the opening up together and the higher velocities and the eddies that could form. Then you could start to have oxygen coming down deep into the crevice.
MEMBER ROSEN: So to finish this discussion, the stealth cracking mechanism that has been postulated that what we saw at Davis-Besse could be going on under the surface, in your own words now, how likely is that here?
MR. WHITE: Well, the work shows that it's unlikely, taking in turn first the case of no leak rate at all, having a pressurized annulus with single phase liquid without a big driver for concentration and no oxygen. That would have no active mechanisms.
As we move towards small leak rates, ten to the minus six gpm, ten to the minus five gpm, for much of the cracking we see on the order of a cubic inch of deposits that corresponds to a gallon of leakage in a year. That's two times ten to the minus six gpm.
So as we approach ten to the minus five gpm, when you do the heat transfer calculations, you don't get the cooling. So what's going to happen is that that annulus is going to boil dry immediately right near the bottom of the crack, right near the bottom of the annulus at the crack. So there isn't going to be liquid over a significant volume or height inside that annulus. So that's really what's preventing corrosion mechanisms that may potentially occur in the absence of oxygen from really being significant.
I mean, this is just consistent with all of the experience out there for very small leaks that show minimal material loss. You don't have the velocity mechanisms, and you don't have very much liquid around at all. Perhaps it's all boiling dry low in the annulus, and you need that liquid even to get something like a galvanic type mechanism going.
CO-CHAIRMAN FORD: If I go from the left-hand side and approach the right-hand side, you're having more and more conjoint requirements that are necessary to get a Davis-Besse situation on the right-hand side.
MR. WHITE: Yeah, you're --
CO-CHAIRMAN FORD: And because there are so many conjoint requirements, annulus size, exposed crack length, leak rate into the annulus. So you're precluding the possibility of this being a generic phenomenon.
However, you don't have to be on the right-hand side to have a real bad situation. Those EPRI and CE tests were one inch per year. So you've only got to get over to the middle column before you've got potentially a fleet wide problem.
I use that obviously to make a point. It's not an isolated set of criteria that you need. Am I overstating it?
MR. WHITE: If I were to draw this down here, these tasks that are on the upcoming slides, I would probably draw this more towards this range. We can go over the actual leak rates in these tests, but they were closer to the .01 to .1 gpm.
There was one test down at .002 gpm by Combustion Engineering that had a significantly lower rate of corrosion than the other test at .01 and .1. So it's really the .01 number that I'm taking from those tests as being sort of a critical value based on that.
At Davis-Besse we believe that the leak was between .04 and .15 gpm based on the unidentified leakage, based on the mass of deposits that were observed, and other indicators. So that would put it all the way off to the right there.
MEMBER WALLIS: There seem to be various things I'd like to know more about. I don't know the details of your analysis, but the way in which the annulus clogs or doesn't clog or periodically extrudes whatever is in there, is that just hypothetical?
One could postulate all kinds of things that could happen in an annulus in terms of deposits and the way they can be pushed out or slowly slide out or do various things.
MR. WHITE: Yeah, one possibility is that when the head cools you have the difference in cold fission or thermal expansion. So the annulus tightens up, and as it depressurizes, at that point the annulus comes back to that interference.
MEMBER WALLIS: It could slowly flow out although it's apparently solid. It could slowly be extruded from the --
MR. WHITE: Right, being in molten form. What we're saying though here is we're trying to show that regardless of those details, without having a liquid high up in the annulus and without having any velocities to speak of, there are no credible active mechanisms.
MEMBER WALLIS: Why is the velocity coming out of this hole zero feet a second and not 1,000 feet a second?
MR. WHITE: Well, if you're postulating that the annulus is completely blocked up.
MEMBER WALLIS: No, it's a crack. It's coming out of the crack. The crack tip goes through, and the velocity -- it says liquid velocity exiting the crack. It's coming out of the crack. So if we had a fairly broad crack and as it breaks through, what is it going to say, a sonic flow at the exit poll? Why is it such a low velocity coming out of the crack?
MR. WHITE: As we increase the leak rate, you're asking about the --
MEMBER WALLIS: Well, even at the beginning. I mean at any time why is it so low? Why isn't it -- why couldn't it be much higher at the beginning?
MR. WHITE: Well, if we took the -- should we put up the slide?
MEMBER WALLIS: Maybe even do just a calculation of flow through very long, very fine tube of a flashing liquid. It takes a pretty long tube before you stop getting choking at the exit from the tube.
MR. WHITE: Let's show you what the --
MEMBER WALLIS: Maybe it's too complicated to get into now, but I'm surprised that you couldn't get a much higher velocity under these circumstances.
MR. WHITE: Go to 544 in the other presentation.
MEMBER WALLIS: It depends a bit upon the shape of the crack. You do it as a two-phase calculation of the flow in the crack?
MR. WHITE: Right. What we're really looking at here is we took as a flow area the area opposite the crack.
MEMBER WALLIS: Well, if you're using Moody and Fauske and HEM, aren't those models for choking?
MEMBER WALLIS: Critical flow? Yeah, that's what Moody and Fauske deal with, critical flow.
MR. WHITE: These are just slip models we're just using. We're just assuming two-phased flow in a pipe, for example.
MEMBER WALLIS: Well, you're using a square root of density ratio.
MR. WHITE: Yes, right, right. Just to get a handle on the velocities, we were interested in the velocities not right at the crack exit, but --
MEMBER WALLIS: You're basing it on the shape of the crack, not just on the --
MEMBER WALLIS: -- flow rate.
MR. WHITE: I agree, I agree. As a first cut, we wanted to get some --
MEMBER WALLIS: So you assume something about the shape of the crack?
MR. WHITE: No. All we did was we took the flow area as the area opposite the crack. As the flow turns, it's going to expand.
MEMBER WALLIS: Opposite the crack? No, it isn't. What matters is the flow and the area in the crack itself.
MEMBER SHACK: This chart is showing a leak rate through the crack of a given amount. this is the annulus velocity that you would get.
MR. WHITE: Right, as you're --
MEMBER WALLIS: It says here exiting crack. Maybe it's the words that are wrong.
MR. WHITE: I agree.
MEMBER WALLIS: If you were saying the velocity in the annulus -- I agree the velocity in the annulus could be low, but the jet coming out of that crack could conceivably be sonic, and that's going to do something in that annulus presumably.
MEMBER ROSEN: I have a slightly different model that at the crack itself, you know, is a very labyrinth kind of thing, and it functions as a breakdown orifice.
MEMBER WALLIS: It's like a porous median, and then it maybe breaks through the outside, a little hold.
MEMBER ROSEN: Just barely, and there's almost no -- the pressure drop through this labyrinth and pathway is enough to --
MEMBER WALLIS: Well, maybe it is.
MEMBER ROSEN: -- initially create -- there's no velocity at all. I mean as it first breaks through, it just drips.
MEMBER WALLIS: It certainly doesn't drip. It may come out with steam.
MEMBER ROSEN: Yeah, well, it flashes. I mean a little bit of liquid which is completely broken down; pressure that's completely broken down in this labyrinth --
MEMBER WALLIS: Well, that's your picture of it.
MEMBER ROSEN: -- drips out, drips and flashes.
MEMBER WALLIS: That's your picture of it.
MEMBER WALLIS: I'd like to know what the reality is.
MEMBER ROSEN: Well, I'm just saying that there's a way to think about it that creates very low velocity.
MEMBER WALLIS: Yeah, but there's also a way to think about it that gives you 1,000 feet a second or so.
MR. WHITE: We've done calculations to try to calculate the crack opening area. So we can use those to give you some velocities also.
CO-CHAIRMAN FORD: If I could suggest we don't do that right now.
MR. WHITE: Okay.
CO-CHAIRMAN FORD: Time and what I want the committee to understand is where they are in this overall approach. There are hundreds of questions, and you get the idea.
MEMBER WALLIS: But then they're off by a factor of 10,000 in velocity, and it's interesting to know.
CO-CHAIRMAN FORD: That's true.
On this diagram here, and it's the last question we'll take on this one.
MR. WHITE: Okay.
CO-CHAIRMAN FORD: It's my understanding the tech spec is one gallon per minute.
MR. WHITE: Right.
CO-CHAIRMAN FORD: And, therefore, all of the operating plants, if they could detect, you could be right over the right-hand side there and have all of your mechanisms which would be -- have one gallon per minute, absolutely okay. That's the only criterion we're taking. That's correct, isn't it?
MR. WHITE: Well --
CO-CHAIRMAN FORD: I'm saying it could be done at -- according to the EPRI --
MR. WHITE: Right.
CO-CHAIRMAN FORD: -- tests of one inch per year, you could be down at .01 gallons.
MR. WHITE: The way that I look at the far right of the chart here is that the calculations show if you have more than .1 gpm of low, you're likely to locally cool all the way down to 212, the metal. So that you can have liquid that's making it all the way out onto the top of the head. So there's going to be a significant amount of boron deposits that are going to be wetted by that liquid that's coming out, and it's going to be colder.
There are liquids that are going to exist over a certain area, and that is going to be similar to situations that we're seeing at plants in the past that had large leaks from up above sources that led to lots of deposits and wetting the top of the head where up to about a half inch of material loss has been seen in the past.
And some plants in Europe have also observed this with large leaks. So it may not matter so much where the leak source is coming from one you have a large leak here, that you can wet the top surface of the head, and you could have corrosion possibly occurring from the top, from the top top.
CO-CHAIRMAN FORD: But my point is right this instant in time. Obviously there's more work that has to be done, but right at this instant of time, if there's any ability to your logic in that diagram --
MR. WHITE: Right.
CO-CHAIRMAN FORD: -- you'd better change your tech specs.
MR. WHITE: Well, what we're --
MS. KING: If you're depending upon leak detection only.
MS. KING: If you're looking at leak rate only, and what we're saying here is we expect there to be significant visible evidence during a visual examination of your head.
MR. WHITE: Yeah, it's important to put this in the context of a time frame.
MR. WHITE: And based on the Davis-Besse root cause analysis report work, it's believed that the high corrosion rates were occurring for four years, the last four years, roughly an inch and a half of corrosion rate per year occurring.
But before that, it's believed that another four to six years, and of course, it's not possible based on all of our information to nail down the exact time progression, but it's believed there were another four to six years of leakage that was occurring.
So it makes sense that as those cracks grew and you had more crack opening area along that crack, that you would get the higher leak rate. So there still would have been the four to six years to be able to detect something similar to or larger than the amount of the deposits that were seen at other plants.
MEMBER SHACK: Just coming back to that then, in the four years you've got now a one inch crack above the nozzle, and if you go back four years, how big is the crack when you're getting significant of the low alloy steel?
MR. WHITE: Well, it's something that could be looked at.
MEMBER SHACK: Well, you know, presumably with this getting -- you know, as I look at your mechanism, I keep coming up to some critical leak rate, which means I need a critical axial crack size, which is far less than any structural limit, and your argument would seem to tell me, you know, one inch minus four years worth of crack growth.
MR. WHITE: Well, for this particular crack at nozzle number three, the evidence indicates led to a leak rate on the order of .1 gpm. It was about an inch above the top of the weld.
Typical growth rates argue for about a millimeter per year to perhaps up to five millimeters per year, perhaps slightly higher based upon the French experiment.
MEMBER SHACK: Yeah, I would say a five millimeter crack.
MR. WHITE: Well, that would say that we went up to about 25 millimeters at five millimeters per year, it would have taken five years to get to that point.
MEMBER SHACK: But significant attack then starts with the five millimeter through wall crack is what you're arguing.
MR. RICCARDELLA: This is Pete Riccardella.
Bill, you know, that crack could have been there for a while though because remember as the crack is growing, it's growing out of the residual stress field and probably slowing down in that axial direction. I don't think a linear assumption on crack growth is fair.
MR. HUNT: Let me just add one other point here. We do have a number of other nozzles in other plants that have cracks just under one inch that seem to be consistent with the lower leak rates over on the left-hand side of the chart, and one of the things that we're looking at from a finite element standpoint is, you know, where the transition occurs in this flow rate.
Steve Hunt, Dominion Engineering.
CO-CHAIRMAN FORD: Could I just in terms of managing time here? I know it's not fair to you. Could you try and finish by quarter to two?
MR. WHITE: Sure.
CO-CHAIRMAN FORD: The other presentation also, the main purpose being to just let everybody around this table know what the concerns are, what you're doing to resolve those concerns.
CO-CHAIRMAN SIEBER: Let me just add one word about the applicability of leak rate tech specs to this situation. If you look at the reactor coolant system, there's a lot of places where it can leak a little bit, and that's through interconnecting valves, through other systems, through safety valves, PRVs, pump seals and so forth, and generally speaking leak rates like you're talking about on the head are very small compared to some of these others.
This chart, which we haven't discussed yet is the one that shows weak rate versus time. If you go back three cycles and you look at the leak rates in those early -- the first two cycles, the leak rate is very low, which is pretty much typical of PWRs, but it's probably enough to support the fact that you might have had crevice leakage and annulus leakage of this nozzle.
So just to clarify that. That's not the only reason for the leak rate tech spec.
MS. KING: I think we discussed these.
MR. WHITE: Yeah, the next slides go over the basic -- this one might be worth touching on here. Again, this is outlining the idea that was put forth by the Davis-Besse root cause team as one possibility, that the material loss for nozzle three occurred more from a top down type mechanism.
Perhaps these mechanisms like galvanic erosion led to some growth down deep in the annulus, deeper than -- greater material loss deep in the annulus than at the outside, but that once the leak rate reached that .1 gpm, then water would reach all the way to the top, and it would have been a top-down type mechanism where you have the aerated concentrated boric acid corrosion.
As the corrosion would have moved downward, then the surface area covered by liquid would be less because now you would be going more into a pool geometry. So this might explain the change in slope at the outside of the cavity.
In other words, the area at the outside of the head is greater than the area as you move down.
And then also what might produce the shape of the cavity, the oblong shape, it being longer in the downhill direction than the transverse direction?
Well, gravity would have displaced that pool, the initial pool on top of the head in the downhill direction, and as you move down, that could explain the shape.
CO-CHAIRMAN FORD: So you're still having no significant velocities in that pool?
MR. WHITE: Well, once things are opened up, velocities are not going to be that high.
CO-CHAIRMAN FORD: So this isn't a solution mining type of thing where you go down there and dissolve the rock with a jet of liquid? It looks like it. I mean if you had a jet coming out of that crack, it would make a cavity something like what was observed, I would think.
MR. WHITE: I'm not completely discounting the erosion type mechanisms. It is a possibility, but we know, therefore, the aerated boric acid, concentrated boric acid conditions, you can have the high corrosion rates.
So it seems consistent that that would have been the primary mechanism when you got there.
CO-CHAIRMAN FORD: Okay. You're about to discuss those two tests. Just let me make sure we know factually where we are right now. Right now you come up with a series of hypotheses, qualitative hypotheses enunciating the conjoint requirements to get the temperature in the annulus down to a lower value necessary to sustain high crack growth rates, and you're relating that to leak rates from a practical point of view.
Are there any tests planned for the near term to qualify that hypothesis?
MR. WHITE: Well, there have been discussions initiated between the MRP and NRC Research as to what tests could be performed, and so we're in discussions with the industry and with the NRC about--
CO-CHAIRMAN FORD: And how urgent are those?
MS. KING: We would expect this work to identify the appropriate tests to go perform, and then we would take immediate action.
CO-CHAIRMAN FORD: Immediate being tomorrow.
MS. KING: Well, he needs to finish first.
CO-CHAIRMAN FORD: Well, I recognize that, but I still say it with some -- quickly.
MS. KING: Quickly, yes. I don't plan to wait until 2005. As soon as we can identify what the appropriate tests would be, we would immediately start to pursue --
CO-CHAIRMAN FORD: And to fill hydraulic analyses. There are obviously a lot of questions on thermal hydraulics in that crevice and how they change with operating conditions, fit up and shrinkage, ovality (phonetic), and the dimensions of annulus as they change in time. All of them will be addressed.
MR. WHITE: If we go to these slides here, we can go over briefly what's been done in the past. This slide just touches on different types of boric acid corrosion tests, but here we see some of what the mock-ups look like for testing that was done sponsored by EPRI back in the '96-'97 time frame with different leak rates simulating an annulus geometry with leakage, and if we could go to the next slide, here's a specimen, one of the specimens from one of the six tests. This was a leak rate of .01 gpm. The actual injection point is here along this hole here. This is a thermal couple probe area here.
But the flow came through here, and then impacted on a stainless steel tube that was inside this hole, and so you can see some of the corrosion that occurred in this test and how it's deeper down in the annulus.
CO-CHAIRMAN FORD: The erosion was not on the impact point at this -- the back side of the impact point.
MR. WHITE: Well, right. Here the flow is coming through --
MEMBER ROSEN: Remember the impact is on the stainless steel tube in this case.
CO-CHAIRMAN FORD: Oh, okay, okay.
MR. WHITE: Here's an example of one test that was performed in the past. Future tests may want to look at the development of the corrosion rate versus time, and there are techniques to try to capture that as a function of time.
They could try to quantify the environment carefully in terms of the temperature along the leak path, in terms of the chemical composition along the leak path and so on., the electrochemical potential.
So that's one area of potential testing. Other areas would go to the properties of molten boric acid, its potential for being corrosive, for looking at the galvanic mechanism.
In this test, one could decouple the stainless steel tube from the low alloy steal, electrically isolate them and see if that was a major factor in terms of the amount of corrosion that would indicate galvanic mechanism here.
This slide here just summarizes that those tests that were performed in the '96-'97 time frame, along with tests that were performed in the late '80s by Combustion Engineering of the pressurizer nozzle geometry, an inverted geometry so that the nozzle was facing down rather than up out of the low alloy steel.
Those tests both produce similar corrosion rates, two to two and a half inches per year, and one key thing form this testing was that for leak rates greater than .01 gpm, as the leak rate was increased, actually the corrosion rate decreased, and the belief is that that tends to indicate a corrosion type mechanism rather than a flow erosion type mechanism and the reason is believed to be that the higher flow rates would flush out the impurities, and you'd get actually a lower boric acid concentration because you'd be with greater flow flushing out the crevice.
These tests had interference or I should say gaps of about 5/1000 of an inch radially, which is larger than the initial fit-ups for the CRDM nozzles, but would be representative after that CRDM nozzle annulus opened up over some time.
MEMBER SHACK: I'm sorry. In the CE test, is that another one where the jet impacts the tube or, no, the flow is coming --
MR. WHITE: That one they actually had a crack in a steam generator tube and let the flow come from inside the steam generator tube and then go into the annulus and then down, and that test, although it had a similar material loss rate, the location of maximum corrosion was at the outside, at the exposed surface down at the bottom.
MEMBER SHACK: But at least that one you did have a potential for erosion of the low allow steel.
MR. WHITE: But the material loss didn't happen up there.
MEMBER WALLIS: Well, this two inches per year is for these particular tests.
MR. WHITE: Right.
MEMBER WALLIS: And I don't know that it's being predicted theoretically.
MEMBER WALLIS: So there's no reason to suppose that two inches per year in this test is the same as what you'd get in the reactor situation where flow rates and commissions are not quite the same and the geometry isn't quite the same.
MR. WHITE: Also, I think an important factor is the amount of cooling that you get because obviously it's difficult to mock up the way the reactor heats the head with that large heat source. In these tests, there are cartridge heaters that may be used to do the heating so that the amount -- the temperature drop, the local temperature along the leak path could be much different.
MEMBER WALLIS: So you mean in the absence of a predictive method based on physics and chemistry. I don't quite know what to do with two inches a year from these tests. It could be ten inches a year or .2 inches a year in the reactor for similar conditions because they're not going to scale it to the reactor condition, unless I have some sort of a physical model.
MR. WHITE: Well, the objective of the test was to try to simulate typical conditions as much as possible.
CO-CHAIRMAN FORD: I think the main point here, Graham, is that they've done some preliminary hypothetical work and come up with a potential progression of events, and there's an urgent need to do some confirmatory analyses and tests. I think that's a fair --
MEMBER WALLIS: You're not going to be confirming anything. You're going to be investigating and --
CO-CHAIRMAN FORD: Well, confirming the hypotheses and coming out with a prediction of what happened in the actual plant.
MEMBER WALLIS: That's a long way to go.
MR. WHITE: But so far everything is consistent with the experience, I'd say. The majority of the leaks we've had on the order of 35 leaking nozzles in the U.S. The large majority of them have had small amounts of boric acid and no measurable wastage or very small amounts of wastage.
That's consistent with not having a lot of liquid in the annulus with having the temperature close to the primary temperature with the low velocities, and we've had the one case, much larger in comparison, where the calculations showed that liquid could make it all the way out into the top of the head, and that's the case where we had the large corrosion.
MEMBER WALLIS: As soon as the inspection shows rivers running down the head instead of just crystals coming out of the ground.
MR. WHITE: Right.
MEMBER WALLIS: That indicates there's liquid up there, doesn't it?
I've seen all sorts of photographs. I've seen these little popcorn around.
MR. WHITE: Right.
MEMBER WALLIS: And I've seen the popcorn with some sort of a river down below it. That indicates that there's liquid. As soon as you see something flowing down from the --
MS. KING: Well, but that doesn't necessarily mean -- in those photographs it does not necessarily mean that the liquid -- the source was the PWSCC crack. It potentially could have come from --
MEMBER WALLIS: What it means is that it was wet boric acid.
MR. WHITE: Also boric acid, you know, melts at 340 degrees, becomes molten. It's very hydroscopic. So it like to pick up whatever moisture is in the air.
MEMBER WALLIS: It dries up as it --
MR. WHITE: So the appearance of deposits and the morphology of them is going to change as the plant cools down.
CO-CHAIRMAN SIEBER: My impression was that the so-called lava flows were mostly iron oxide and molten boric acid because it was hot enough that the liquid containment pressure, that would vaporize right away, and you would end up with crystals which would then melt and form these rivers.
That's at least my first impression of what I saw. Could you comment on whether that was correct or not?
MS. KING: Well, I guess I could comment. The boric acid crystals initially early on in the videos were brittle, and you could see that as they were being cleaned off the head surface, and it was verbally reported later that they got --
MS. KING: -- very hard and very difficult to remove, which would go towards the molten boric acid.
CO-CHAIRMAN FORD: Could I suggest that we call a halt at this point?
MS. KING: Sure.
CO-CHAIRMAN FORD: Before we do that, could I ask just the staff? I know there's a cracking action plan to deal with the cracking issues. Is there going to be an associated degradation action plan?
They talked about in talking to you and talked about the appropriate tests that they want to do to validate these hypotheses. Is there an NRR action plan associated with that?
MR. WHITE: Not specifically at this time. We've asked Research to give some idea of what we'd be looking at with respect to if we wanted to build a mock-up and run a test or something like that, what it would conceptually cost us with respect to dollars, et cetera.
I don't know if there's anybody here from Research. Bill, have you had a chance to look into that at all?
MR. CULLEN: Bill Cullen, Office of Research.
The panel has asked a few times this morning about research that might be considered going forward. Peter himself has specifically asked twice what's going to happen, and just a few minutes ago Christine indicated that on the industry size there's research that's being proposed.
I have received, as you can imagine in the last three months all kinds of proposals from all kinds of people who have considered themselves to be experts in boric acid corrosion. I'm currently going through those things trying to figure out what's good, what's bad, and what would be helpful.
Additionally, as Bill Bateman has just indicated, NRR themselves has asked Research to come up with a plan.
So combining all of those requests and all of that input, I am I would say nearing the end of the line on deciding what it is that we're going to do. Even as we speak there's some proposed funding documents that are circulating in the next building. So we will, I think, know within a very short time how much funding could be made available for Office of Research sponsored funding to look into some of these issues dealing not only with the corrosion aspects of this, but also some nondestructive inspection programs that might, you know, when they get implemented within the industry, serve to help find this sort of situation or this sort of degradation long before it gets as far as it did get in the Davis-Besse.
Also have some other plans about I would like to maybe do some sensor development because I think we've talked about the right element monitors and the containment air coolers being credit up (phonetic), going along that line or down that road.
I think there's some sensor developments, some instrumentation development that could be undertaken that would also help.
CO-CHAIRMAN FORD: Will that be covered in part by Ed? Are you going to be talking later on on the inspection?
MR. CULLEN: It's not my position to say, but Ed Hackett will not be presenting today. Mark Kirk will be presenting a little later on, PFM.
MEMBER BONACA: Since we are on the subject of inspection, just one thing that is a no brainer, doesn't need the research. Two things actually.
One, are we going to make some criteria on what the licensee has to do when he finds he has flanges leaking?
I mean one of the problems at Davis-Besse is that they manage the leaks. They only fix some, and then they decided to put off until the next outage some.
On deposits the same thing happened. They simply had a certain time allotted for removing deposits. They removed what they could at the time, and then they just started again without removing all deposits.
Are we going to establish some criteria for this? It's not only inspections. It's what we're going to do with what we find after we inspect.
It seems to me that as a minimum one would expect that if you find leakage you fix the flanges before you restate. That's become a priority.
MEMBER BONACA: Also it would be the removal of boric acid deposits.
MR. BATEMAN: Yes, you're right. If licensees do find leakage at their flanges, they do repair the leakage before they restate.
We're going to talk a little bit later this afternoon on the inspection plan methods and frequency. So I think that will probably address the other --
MEMBER BONACA: Because, you know, those things, I mean, are no brainers. You don't need research for that. If you do that, you're going to find where the problem is. You know, you're not going to be stumbling and propagate the problem, cascade from cycle to cycle as it happened at Davis-Besse.
I would expect that that would be a requirement that it would be very reasonable, in fact.
MEMBER BONACA: If you had accumulation of pounds of boric acid crystals on top of the head, I think the requirement should be remove them all. You don't restart until you've done that.
MEMBER BONACA: I think any licensee who can think with his own head in this situation would do that.
MR. BATEMAN: From the results of Bulletin 2002-01 inspections, I think we feel at this point that Davis-Besse was an anomaly, and I think maybe we have a tendency to try and apply that to everybody else, but we haven't discovered anybody else in the industry who has come anywhere near close to having the boric acid accumulations on their head that Davis-Besse had.
MEMBER BONACA: But you understand the requirements I'm discussing here are reasonable actions.
MR. BATEMAN: Absolutely, absolutely.
MEMBER BONACA: And those could have prevented so much of this pain and attempt on our part now to try to foresee the future. It's going to be very hard to do anyway, but I think fundamentally some basic ground rules, and I would call them almost housekeeping for a plant.
MR. BATEMAN: I think it's basically more of an implementation issue. Licenses have a boric acid inspection corrosion program based on their response to generic letter 8805, and we found with the exception of one licensee that they're implementing it.
I think it was more of an implementation problem as opposed to a program problem. I think the programs are out there. It's how well are they implemented.
CO-CHAIRMAN FORD: Could I ask that we move on at this stage?
And, Larry, could I ask the two of you to do both of your presentations by quarter to, finish them by quarter to three, at which point we'll take a break?
MR. MATHEWS: I really don't have much to say. We could skip the collateral -- it's just two slides.
MR. MATHEWS: We really haven't done anything since last time.
MR. MATHEWS: We can come back later and talk about it.
CO-CHAIRMAN FORD: If the rest of the committee -- if it's okay with them, we will skip Larry Mathews on collateral damage. There's not a lot that has been done since then, since the last time we met.
MR. RICCARDELLA: Okay. I'm Pete Riccardella from Structural Integrity Associates.
We were contracted back about September of last year to develop a probablistic fraction mechanic's model for this top head degradation and cracking issue, and the focus of that model is primarily looking at probabilities of the growth of large circumferential cracks and nozzle ejection.
What I plan to present today is somewhat of an overview --
MEMBER APOSTOLAKIS: Excuse me. Where are these slides?
MS. KING: These slides follow the crack growth rate.
MS. WESTON: Page 46 on this handout.
MS. KING: There you.
MS. WESTON: And they start on page 59 in the book.
MR. RICCARDELLA: Are we set?
My purpose today is to present an overview of this model, and I should say that in the period of time since September, we a have had several meetings with the NRC staff. There's been several interactions, both teleconferences and meetings where we've discussed, traded ideas on the methodology.
And in fact, we've gone back and made some modifications, adaptations to the model based on NRC staff input.
So first I'll give an overview of the methodology and then talk about some PFM analyses that we've performed in support of the propose MRP inspection plan.
The key elements of our probablistic fracture mechanics model are listed on this slide. We have an experiential based probability of leakage model. We don't try to model the initial nucleation and growth of the crack. We're basically just going back and looking at based on experience probability of leakage versus time, and then we take it from that point.
We have a fracture mechanics model for stress intensity factor in which we've considered both part through wall and through wall cracks in different nozzles, different locations on the head, different places on the hillside.
But the assumption in our fracture mechanics modeling is, I believe, a conservative one, is that once we detect a leak, we assume that we instantaneously have an axial crack which has branched and turned to a circumferential crack and is already 30 degrees of the circumference.
So that's the starting point for our analysis. We've compared that to looking at a leak and then getting multiple initiations, reinitiating new cracks around the periphery, and we believe that our model instantaneously assuming a 30 degree circumferential crack is both conservative and less arbitrary than you get by trying to model these multiple reinitiations of circ. cracks.
It also agrees at least with the anecdotal evidence of how the circ. cracks developed at the Oconee plant, that they tended to be more like axial cracks that branch into circ. cracks rather than reinitiated circ. cracks.
MEMBER APOSTOLAKIS: Where does the work that was presented earlier on the rate of growth of cracks fit into this?
MR. RICCARDELLA: We have the next slide a key. A key element of our model is the statistics of crack growth, and I'm going to show you how I've used the work that John --
MEMBER APOSTOLAKIS: I'm a little confused by the first bullet there.
MR. RICCARDELLA: Okay. Well --
MEMBER APOSTOLAKIS: What does it mean, that you're already having a leakage?
MR. RICCARDELLA: Well, what we're assuming is that at a certain period of time we have a leak.
MR. RICCARDELLA: And then when we have a leak, we assume that at that point in time, we have an axial crack that branches into a 30 degree of circumference circ. crack, and then we use the crack growth to analyze the progression of that 30 degree of circumference crack out to failure, out to 300 or 330 degrees, whatever it is that produces ejection of the nozzle. Okay?
So we are arbitrarily giving up that initial nucleation and growth portion of it.
MEMBER APOSTOLAKIS: Which could have included the crack growth rate again, right?
MR. RICCARDELLA: Some amount of crack growth to get to 30 degrees, but we're kind of giving that away.
MR. RICCARDELLA: And we're saying we start there basically.
MEMBER SHACK: Well, you start there, but you take the Weibull model into account.
MEMBER SHACK: So I mean, you accounted for it in a different way.
And then finally in our model we have the ability to look at the effect of inspections on this cracking and on the probability of an ejection. We can look at different inspection intervals, as well as different levels of reliability for different types of inspections, and we have some assumptions we've made regarding the probability of detection.
If you have a leak and you do an inspection, what's the probability of detecting that? Also the probability of detection for ultrasonic or other --
MEMBER APOSTOLAKIS: So where does that go?
MEMBER APOSTOLAKIS: The probability of detection?
MR. RICCARDELLA: Down here, effective inspections.
MEMBER APOSTOLAKIS: And you also have a model for the probability of detecting and doing nothing about it?
MR. RICCARDELLA: No, no. The assumption is that --
MS. KING: Do you mean no inspection?
MEMBER APOSTOLAKIS: I know it is there --
MR. RICCARDELLA: -- if it's detected you fix it.
MEMBER APOSTOLAKIS: -- but I don't have time to do anything. I'll work as best as I can.
MS. KING: Essentially I think what you're saying is the effect of not completing, not completing it.
MEMBER APOSTOLAKIS: Not doing anything about it.
MS. KING: Yes. We can take this model and do no inspections, and you can see what the --
MR. RICCARDELLA: Well, no, not fix it. He's saying you detect it and you find it and you don't do anything.
MR. RICCARDELLA: We can conservative -- let's just say we'll conservatively bound that in our probability of detection because we're using some pretty low numbers for probability of detection.
CO-CHAIRMAN SIEBER: Let me ask a question about that a little bit. I've been thinking about it since I'm the ultimate determinist. If you find a crack in the through wall or greater than 40 percent and it's not at a mechanical joint, okay, you know, a bolted joint, the code applies to that, does it not? And the code says you've got to repair it.
CO-CHAIRMAN SIEBER: Otherwise you're in violation of the boiler and pressure vessel code; is that correct?
CO-CHAIRMAN SIEBER: And so everything you find that is greater than 40 percent has to be repaired, right? Is that true?
MR. RICCARDELLA: I think it's 75 percent.
MS. KING: Yes.
MR. RICCARDELLA: It's more like 75 percent than 40.
MEMBER SHACK: I'm not sure there's an exact code section that applies.
CO-CHAIRMAN SIEBER: Well, you can calculate how much margin you have.
MEMBER SHACK: Yeah, and in fact, there was a memo from Jack Strosnider to the MRP that says, "Here's an acceptable set of acceptance criteria until we figure out what's the right thing to do."
CO-CHAIRMAN SIEBER: But a through wall crack you have to repair.
MEMBER SHACK: Yeah, if it's leaking, yeah.
MS. KING: Actually the flaw acceptance criteria is related to cracks that intersect the pressure boundary at specific depths and the location of that crack.
MEMBER LEITCH: Ninety-five percent limit after the next operating period.
MS. KING: Right.
MR. RICCARDELLA: But the assumption in a probablistic model is that if you inspect and find a crack, you fix it. We take it out of the population as far as possibly proceeding to a nozzle ejection.
MEMBER APOSTOLAKIS: But, I mean, how real is that? I mean, why are we doing it? Is somebody else dealing with the issue of if you find it, you decide to do nothing about it, you know?
MR. RICCARDELLA: No. I think the inspection plan and the code tell you what you have to do if you find it.
MEMBER APOSTOLAKIS: But if the code is implemented correctly, I expect the probabilities to be very low. That doesn't tell me anything. I mean, the finding is the boric acid corrosion control program at the site included both cleaning and inspection requirements, but it was not effectively implemented.
Now, to tell me that, you know, I believe that they will find it and do something about it doesn't address this issue.
CO-CHAIRMAN SIEBER: Well, one of the problems --
MEMBER APOSTOLAKIS: Now, that's not fracture mechanics, but that's the issue.
CO-CHAIRMAN SIEBER: One of the problems with visual inspection is you're beyond 70 percent. You're through wall, and then if you have, for example, the CRD in flange, which I think is a bolted joint, right? We had welded joints, but you know, those by code can leak. Okay?
So the issue is can you do a visual inspection with all of this boric acid that leaked down laying on top of the head, okay, and if it's there, what do you do about it?
I think that's part of the issue, which again tells me that sooner or later you have to go to a volumetric kind of inspection to be able to satisfy the requirements of the code.
MR. RICCARDELLA: Yeah, I think we might be able to address the question a little better if I get a little further into the presentation and talk about exactly how we're using the probablistic fraction.
MEMBER APOSTOLAKIS: Now, on this slide it says theta. What is the expression for the Weibull?
MR. RICCARDELLA: What is the expression?
MEMBER APOSTOLAKIS: Yeah. Do you have the mathematics of it so that I know what theta is?
MR. RICCARDELLA: Give me the one with the curve. I have an actual curve of the Weibull. Okay? This Weibull paper, it's a standard, two parameter. I'm sorry I can't quote it off the top of my head. Perhaps Glenn can bail me out and give me the expression.
It's a standard two parameter Weibull.
MEMBER APOSTOLAKIS: Yeah, but it has several different expressions.
MEMBER SHACK: Theta is like the mean value.
MEMBER APOSTOLAKIS: Well, but it's not.
MEMBER SHACK: It's not, but it's like.
MR. RICCARDELLA: Theta is like the 63 percent cracking, and there's a function of service. Now let's go back to the previous slide.
We have a Weibull analysis that was actually developed by Dominion Engineering based on all of the B&W plants and the cracking that's been experienced in those, and we made the assumption of a Weibull slope of three.
Actually, Christine, if I could go to the next slide, if you look at the actual data, you would actually predict if you just did a pure analysis of the data, you would predict a much steeper Weibull slope, like about a Weibull slope of nine. That's the curve that --
MEMBER WALLIS: Once they get to 20 they're-- oh.
MEMBER WALLIS: Once they get to 20 it's --
MR. RICCARDELLA: Pretty much, yeah, but we believe that there is something else going on here, that there is somewhat of an inspection transient going on and that some of these were leaking earlier in time, but we didn't start doing inspections until pretty late.
And so --
MEMBER SHACK: Except the Oconee 3.
MEMBER WALLIS: Still it's cumulative.
MR. RICCARDELLA: That's true, that's true. Well, except if I use a steeper slope, I'd get a less conservative result. So we're using the slope of three.
MEMBER SHACK: Steep slope is sort of good news. So it's good news and bad news, but your header, you really meant the slope is three, not theta.
MR. RICCARDELLA: Yes, you're right.
MEMBER SHACK: You've totally confused us here.
MEMBER WALLIS: Weibull analysis is a prediction of these lines. Is that what it is?
MEMBER APOSTOLAKIS: They assume the functional form. That's what it means, Weibull analysis.
MR. RICCARDELLA: Yeah, well, this is actually a Weibull paper. So, you know, the shape of the equation is built into it.
MEMBER APOSTOLAKIS: How many parameters?
MR. RICCARDELLA: Two parameter Weibull.
MEMBER APOSTOLAKIS: Two parameter. And then by fixing the slope, essentially you end up with one parameter.
MR. RICCARDELLA: One parameter. That's right.
MEMBER APOSTOLAKIS: Now, can you tell me what the cumulative fraction of number of leaking CRDM nozzles is? What does that mean?
MEMBER WALLIS: Just what's the fraction of the number of the leak. If there are three out of 100 or --
MEMBER APOSTOLAKIS: So if I have 150 of them, this will tell me the fraction of them that are leaking?
MR. RICCARDELLA: Yeah, Oconee 3 had this fraction leaking, and then the next inspection they had that fraction leaking in that plant.
MEMBER APOSTOLAKIS: So this is between inspections?
MR. RICCARDELLA: Between inspections? There's only one plant on here that's inspected twice, and this is the time period between inspections, from here to here. The others are just until the first inspection. That's the fraction of nozzles that were found. So there --
MEMBER SHACK: With two inspections he can calculate both of the parameters. With one inspection, he has to assume one.
MEMBER APOSTOLAKIS: So let me understand what you just said. The other plants are not inspecting at all?
MR. RICCARDELLA: No. This is just -- this Weibull analysis is just based on the B&W type plants.
MR. RICCARDELLA: Because they've had seven out of seven leakers. The others that have been inspected, most of them have had non-leakers. There have only been two other plants that had leakers, and they're not shown on here, but they fit very well into this group of data. That Weibull fit fits all nine of the plants that have leaked, that have had leaks fairly well.
And, in fact, at the time this chart was produced, the Davis-Besse hadn't been inspected yet, and the mean prediction was here, and when we actually did the inspection, they came out -- the point falls very, very close to that.
MEMBER APOSTOLAKIS: But, I mean, this is the result of some inspection scheme, isn't it? So what was that inspection scheme? How often do they inspect these things?
I'm trying to understand that.
MS. KING: This data came from the Bulletin 0101 inspections.
MEMBER APOSTOLAKIS: Yeah, and? And? Don't assume that I know.
MR. RICCARDELLA: It was just the first inspection of a large number of plants, and what we did was, you know, based on a lot of data from stress corrosion cracking behavior, this type of material, we concluded that the largest slope that we'd expect to see is three, and so we fit the data with a slope of three.
As I said, if you did a pure fit of the data to solve for both slope and theta, you'd end up with a much steeper slope.
MEMBER WALLIS: You don't put in any data at all really.
MEMBER WALLIS: You're just drawing some lines. You're not fitting any data.
MR. RICCARDELLA: No, not really. No, we're just saying where does the slope of three best fit between that group, that group of data.
And then what we did is we had an upper bound and a lower bound, and in our Monte Carlo modeling we assumed a mean and then a variation about that mean, and you know, we assume a Weibull slope if you go back to the previous --
MR. RICCARDELLA: -- 15 with a -- nine is the worst case and a 21 is the best case.
MEMBER APOSTOLAKIS: And these are the fifth and 95th percentiles? In the Monte Carlo simulation, how will these --
MR. RICCARDELLA: They're triangular actually. We're using a triangular distribution for this particular --
MEMBER APOSTOLAKIS: So these are 100 percent?
MR. RICCARDELLA: Yeah, 100 percent and zero percent.
MEMBER SHACK: Now, Peter Scott with a much larger database to work with comes out with a 1.5 slope, which is in your case more conservative. So your three isn't conservative.
MEMBER APOSTOLAKIS: Where was this information?
MEMBER SHACK: When you do this kind of analysis for the French plants where you actually have a larger set of data so that you don't have to assume the slope, you get a number of 1.5 instead of three.
MEMBER APOSTOLAKIS: So the curve then -- the straight line would be very almost horizontal.
MEMBER SHACK: Well, much closer to --
MR. RICCARDELLA: It would be shallower like that, yeah.
MEMBER SHACK: Which is bad because you get earlier initiation.
MR. WHITE: Bill, can I address that?
Dominion Engineering did the work of determining that three was the appropriate slope to use. One major source is MRP Report 66, which just came out earlier this year. In that work, the investigators looked at a large set of available data mostly for crack initiation, and the best fit Weibull slope to that large set of data, and I can't remember exactly the number of data points, but this was a much larger set, I believe, than Peter Scott was working with.
And the best fit was 2.7 for the slope.
MEMBER SHACK: Was that steam generator tubes or nozzles?
MR. WHITE: It was on all available crack initiation tests for Alloy 600.
MEMBER SHACK: Okay. Because the earlier results from Dominion just looking at steam generator tubes gave numbers much closer to the 1.5.
MR. WHITE: Well, we've also --
MEMBER SHACK: Original Gorman, you know, reports.
MR. WHITE: One of the presentations that I made at the meeting on May 22nd with the NRC went over this in a little more detail, but we looked at the available data, and there is a range that's observed, but if you look at that, there are for some steam generator field experience in some locations in the tubes higher PWSCC slopes than others, and three seems to be appropriate based on that also.
MEMBER SHACK: Well, in the steam generator, it's always conservative to take the higher slope because that's predicting lots of tubes to fail.
MR. WHITE: I'm just talking about actual observed ranges of slopes for role transition PWSCC for various locations, U bands, for example, and I can show you that data if you'd like.
MEMBER SHACK: And compare with my data.
MR. RICCARDELLA: I think we could do the analysis with a slope of 1.5. I don't think it would have a huge effect on the probablistic fraction mechanics results. I've done it for nine and three, and I've found that that was worth maybe about a factor of two. You saw that.
And I think the difference between three and one and a half would be even less of an effect than that.
And considering that I benchmarked it against Oconee, it really wouldn't make that much of a different. Okay?
MEMBER APOSTOLAKIS: Now, you're going to use this for future?
re using this in our Monte Carlo analysis to create --
MEMBER APOSTOLAKIS: Right, but the inspections will have some sort of a period in the future?
MR. RICCARDELLA: Yeah, we can assume various inspection intervals and --
MEMBER APOSTOLAKIS: So why does this apply?
MR. RICCARDELLA: Well, under the assumption of no inspection. We have a time based Monte Carlo analysis that we start at zero, and we say at so many years we would predict this many leak, and a couple of years later we would predict this many leaks. So we can do a complete analysis with no inspections, and then we can come back and superimpose inspections on top of that and see what the impact is on those results of different inspection intervals.
Okay. So that's just the starting point. So here is, for example, for a 600 degree plant, beta equal to three, theta 15 plus or minus six. These are the assumed times. So if we're at ten years and we're just the mean case in this particular case, that would be about a 25 percent probability of leakage. If we're out at 16 years, that's a 60 percent probability of leakage, but we vary it between these extremes in the Monte Carlo modeling
So that's the very starting point of the analysis.
MEMBER APOSTOLAKIS: The triangular distribution you mentioned.
MR. RICCARDELLA: Yes, it's between these extremes.
MEMBER APOSTOLAKIS: In the vertical sense or the horizontal sense?
MR. RICCARDELLA: Yes, in the vertical sense.
MEMBER APOSTOLAKIS: In other words, ten effective years has a probability anywhere between .1 and .7.
MR. RICCARDELLA: Yes, and incidentally, this is the probability of first leak in a head of a certain number of nozzles. In other words, it's not the probability of a leaking nozzle for any individual nozzle. It's the binomial probability given 69 nozzles that you'll have at least one leak.
MEMBER APOSTOLAKIS: Oh, so this probability on the left is not the previous probability?
MEMBER APOSTOLAKIS: The previous was accumulative.
MEMBER APOSTOLAKIS: Now it's something else.
MR. RICCARDELLA: The direct relationship, if you go back --
MEMBER APOSTOLAKIS: Why is that still viable? It's not viable anymore, is it?
MR. RICCARDELLA: Yes, it is. In fact, it is, and the relationship is theta for a leak in a nozzle is equal to -- I'm sorry. Theta for the first leak is equal to theta for a leaking nozzle divided by the beta root of N, where N is the number of nozzles. There's a direct relationship between theta. The slope stays the same, and there's a direct relationship between theta for that given leak.
MEMBER APOSTOLAKIS: Do you have that derivation someplace?
MR. RICCARDELLA: Yeah. Yes, we do.
MEMBER APOSTOLAKIS: And we can look at it?
MR. RICCARDELLA: You certainly can. I have it on my laptop.
MEMBER APOSTOLAKIS: Mag, can you please get that document so we can look at ti?
MS. WESTON: I'm sorry. What is it you want, George?
MR. RICCARDELLA: Derivation of the relationship between theta for first leak and theta for nozzle leakage in general.
MS. WESTON: And where do I find it?
MS. KING: On his laptop.
MR. RICCARDELLA: We'll give it to you.
MS. WESTON: Is it in your original presentation that you did to the staff?
MS. KING: No, we haven't had this question yet.
MEMBER APOSTOLAKIS: This is the first question that you get that you haven't had before?
MS. KING: For the derivation. No one has asked to see the derivation yet.
MR. RICCARDELLA: You know, that just gets us to the point where we assume a leaking nozzle. Then we have to say, "Okay. How do we evaluate a nozzle growing from this assumed condition at leakage, which is the 30 degree crack, to a large circ. crack that could potentially lead to ejection?"
And so we've developed a series of finite element models with cracks of different sizes and different depths. This is the model we use for a through wall crack, 180 degrees, and this is a crack that is assumed to initiate on the up hill side of a hillside penetration.
MEMBER APOSTOLAKIS: Again, I'm a little slow here. You said that basically you use a binomial distribution there to get with the expression for the first leak.
MEMBER APOSTOLAKIS: Now, what happened at Davis-Besse, as I recall, was that there were three nozzles that were adjacent. Now, in the binomial, of course, you assume independence. So is that a valid assumption?
MR. RICCARDELLA: Yeah, if we look at the distribution over all the plants that have had leaks, it is pretty random distributed around the head.
MR. RICCARDELLA: Davis-Besse happened to have three, but those happen to be three that were out of the same heat of material that happened to be a particularly susceptible heat of material.
MR. RICCARDELLA: Okay? But we believe that as far as time to leakage, there's no geometric dependance at any of the nozzles at any particular location in the head. The Oconee nozzles, the ones that leaked, tended to be toward the periphery. The Davis-Besse nozzles tended to be near the top dead center.
Now, in terms of the tendency to develop large circ. cracks, we believe there is a dependence on where you are on the head, but the time to leakage, we believe, is pretty independent.
MR. RICCARDELLA: So let's go back to that one. This is the model we use for the through wall crack initiating here, running parallel to the weld. The red Xes that you see in the bottom of the condition we applied for the J-groove weld, and here's the crack tip. You see the added refinement that we put in the mesh of the crack tip.
And this model enables us to calculate the stress intensity factor at that crack tip, and we've run this for 30 degrees up through 330 degrees, and we have K versus crack size.
We've run it for nozzles of different angles, you know, top dead center going all the way out to the hillside like this, and we also use gap elements on the back side of the crack to represent the constraint provided by the vessel wall. This is where it shrunk fit into the vessel.
We also have part through wall crack model where we consider an axial crack that is branching and turning into a circ. crack, and this is what we use for the shallower crack configurations to calculate the K.
So this is what we use to calculate the stress intensity factor K that we use in conjunction with the crack growth expressions that John Hickling presented. You have to get a stress intensity framework, and John said, well, it's typically 25 to 30 or 35. These are the models that we use to develop that stress --
MEMBER WALLIS: How independent is this model that you choose? I mean you could have chosen really different geometry, couldn't you?
MR. RICCARDELLA: Yes. Could I have the next slide?
What we've done, we've assumed a -- for most of the analysis I'm going to present now and really all that we have done right now is the B&W type plant. Okay? So we specified that type of geometry, and then we've looked at nozzles of zero, 18, 28, and 38 degree angles, and so that takes us from top dead center to the most hillside.
And in the Monte Carlo analysis, we bend the nozzles into one of these four categories. You have a nozzle for that and like every single category, and what we find -- and then we've also looked at cracks emanating from the uphill side, growing down, and then also emanating from the downhill side and growing up.
And for this particular geometry, what we found is that the uphill side is much worse and also that the stress intensity factors get higher particularly for the longer cracks as you get further away from the center.
MEMBER WALLIS: They depend upon what you are assuming about the shape of that?
MR. RICCARDELLA: No -- well, yes, they do to some extent. They depend upon that. We've made what I believe is a conservative assumption on the shape of the crack. They also depend on the residual stress, which is the size of the weld and the welding parameters, and we currently have underway analyses of a CE type head and of a Westinghouse type head so far.
MEMBER WALLIS: So with these assumptions you have to make about the crack shape and all of that stuff, what's the uncertainty in these Ks?
MR. RICCARDELLA: I would say it could be as much as a factor of two.
MEMBER WALLIS: A factor of two. So that covers pretty well the range of the data that we were looking at this morning.
MR. RICCARDELLA: No, but you'll see that when we get into the Monte Carlo modeling that the effect of the uncertainty in crack growth rate is like factors of ten to 20, and they tend to overwhelm. You know, the scatter in that lot normal or distribution overwhelms, and remember we're using --
PARTICIPANT: The variation in --
MR. RICCARDELLA: Yes, the variability. And remember there's an exponent of one. So it's pretty much a one-to-one relationship between K and crack growth rate. So I think that, you know, further sharpening the pencil on stress intensity factors isn't going to make that big an effect.
MEMBER WALLIS: -- aware of how uncertain it is.
MR. RICCARDELLA: Yeah, I would say it could be as much as a factor --
MEMBER WALLIS: Well, when you give us 26.9, it's probably anything between 20 and 35 or something like that.
MR. RICCARDELLA: We have analysis -- the highest number that we have anywhere here is this 38. We have an analysis for another plant where that's as high as 60, okay, for a different plant type, different residual stress.
And then we went ahead and did the probablistic fracture mechanics on that, and it had maybe a factor of two influence on the probability of nozzle ejection.
MEMBER SHACK: Zero angle nozzles. So I mean this is a cylinder under pressure. Pi squared over pi R squared P. Why am I not getting at least a pressure K that's going up by the time I'm getting the 300 degrees?
MR. RICCARDELLA: I'm not sure. That's something I've got to go back and check into. I think it has to do with the distribution of the street. You know, it's a through wall where you've got residual -- it's residual plus.
MEMBER SHACK: I've even got a large gap here. So I've really got bending at this point, right? You're letting this sucker bend.
MR. RICCARDELLA: No, that's not --
MEMBER SHACK: Isn't that what the large gap means, that the nozzle is free to bend? It's not constrained in the axial?
MR. RICCARDELLA: Yeah, but we don't have the -- this case here -- well, yeah, a large gap. It's still got some interference.
MEMBER WALLIS: Why does it leap from 20 to .6 in 160 and 180 degrees? Is that a typo?
MR. RICCARDELLA: No, that's the change in the model from --
MEMBER WALLIS: On the top there, the fourth line.
MR. RICCARDELLA: I understand, yeah. It's the change in the mode from the part through wall crack to the through wall crack.
MEMBER WALLIS: So by changing the model you make all of the difference in the world.
CO-CHAIRMAN FORD: Could I make a comment? Again, it's on terms of time management here. Could I request that the members kind of --
MEMBER WALLIS: We're trying to establish credibility. That's all.
CO-CHAIRMAN FORD: You can take credibility as 100 percent.
CO-CHAIRMAN FORD: Okay. Ninety-nine percent. My point is that we requested this so that the members would understand the approach that was taken, the completeness of the approach and where we're heading. Obviously this is not finished. There's no way this is finished, I am assuming, in its entirety.
I just wanted the members to understand the depth of what's being done here. So, Pete --
MR. RICCARDELLA: We have some very interesting conclusions and observations on the basis of what we've done, and I'd really like to get to that because I think there will be a lot of interest --
MEMBER KRESS: Before you go though, one more question.
MEMBER KRESS: Your K is a strong function of the residual stresses.
MEMBER KRESS: How do you get those?
MR. RICCARDELLA: We have residual stress analyses that were performed, elastic, plastic residual stress analyses of a nozzle that --
MEMBER KRESS: Based on how it was welded?
MR. RICCARDELLA: Yeah, un-huh, based on weld size. We didn't take into account that much heat rates and things of that sort. I think standard heat rates were used, but as I said, I believed there could be an uncertainty as high as a factor of two on these results.
And they tend not to dominate the probablistic fracture mechanics results because of the slope of the curve.
Okay. The next is how we use the crack growth data that John Hickling presented, and here you'll recognize this upper plot with the black as being the fit. This is the cumulative distribution function for that constant alpha, and the black points are the heat by heat data.
So each of these points represents the average of those groups of heat. You remember some heats had 27 specimens; some had one; some had two.
The lower curve with the red data is the integral of all of the data points, the individual data points, and as you can see that's more conservative. The mean is a higher alpha for those, and John discussed why that is. It's because there's more testing that has been performed on the higher rate heats of material than the other.
What we've chosen to do in our analysis is to use both variabilities, and this is basically as a result of some comments at the meeting that we had at the NRC where we look at heat to heat variability, and then we superimpose upon that within heat variability, and we can specify. For example, you specify 69 nozzles in a head. You could say, well, that head consists of three heats. Twenty of the nozzles are from one heat, 30 are from another, and ten are from a third heat.
So we picked from this distribution for the heat, and then we sample again for the individual nozzles in that heat, and we look at the heat to heat scatter in that analysis.
And another parameter that we've taken into account, and again as a result of our interactions with the NRC, is a correlation effect between crack initiation and crack growth. The comment was that you shouldn't just go in and randomly for a time to a leakage from the Weibull distribution and then pick a second completely random parameter because if you have a nozzle that leaks, chances are that's a bad actor.
So you have higher crack growths in the ones that leaked than the ones that don't leak. And so what we've done is we've built into our sampling scheme in the Monte Carlo analysis an ability to correlate the random number for leakage with the random number for crack growth. Okay?
And this particular slide shows a .8. It's a minus point eight because it turns out that a high random number for leakage means a long time until leakage, a high time until leakage. A high number for cracked growth means a high cracked growth rate.
So if we have a heat of material that's out here in the .8 for crack initiation, then we're going to sample from this narrower set of data for crack propagation, and the .8 is an input parameter. We can input zero. They'd be totally independent. We can input one and be totally correlated. Okay?
So basically it's a knob that we have in our analysis to calibrate or benchmark our analyses against real behavior. Okay?
MEMBER WALLIS: What are the crosses?
MR. RICCARDELLA: Oh, that's just the randomly generated -- go ahead and put in the .99. this is the actual spreadsheet that does it.
MEMBER WALLIS: Randomly generated numbers?
MR. RICCARDELLA: Yeah, these are -- let me show you. These are the random numbers that actually go into the distributions to pick our crack growth rate, to pick our time to leakage, see.
So if I assume .99 or a very high correlation, basically I'm using the same random -- it's like using one random number to pick both parameters. They're very, very highly correlated. Okay?
If I put zero, they're totally independent. So by going from zero to one, I can span the entire range from no correlation between crack growth, time to crack growth, and time to initiate in crack growth to very highly correlated time to initiate a crack growth. Okay?
And then we've got to go back. Thank you.
MS. KING: Sure.
MR. RICCARDELLA: Okay. This shows just some typical results of this analysis. So this is a typical probablistic fracture mechanics analysis. What I'm creating is the probability of net section collapse with no inspections for a 602 degree Fahrenheit head as a function of EFPYs. Okay? Starting in about 20 years, and I've got several cases here.
First, the difference between these two parameters here represent the difference between assuming that the head is made up of three heats and the --
CO-CHAIRMAN SIEBER: Could you move closer to the microphone, please?
That the head is made up of three heats or 69 heats. In other words, every nozzle is an individual heat, and that addresses a specific question that came up at an NRC meeting about is it appropriate to sample each tube individually or should you be sampling them in groups. It turns out that it really doesn't have a significant effect.
The other thing we looked at was a log triangular versus a log normal fit of the data. Did we not go through the -- actually this got a little bit out of sequence. Let's go to the next two slides.
This is the distribution, again, showing the distribution of that parameter alpha by heat. The black data points are by heat, and I show a blue curve, which is the log normal basically that John Hickling presented earlier. The red curve is the log triangular, is a log triangular fit for that same group of data where it's truncated at two extremes.
So we don't get into these very, very high crack growth rates in the very tails of the distribution.
Okay. This is what we're doing for the heat to heat variation, and then the next slide shows we took the entire population of data and looked at each data point relative to the mean of its heat, and we developed basically a deviation from the mean in terms of the multiplication of one for every data point.
And so you see that we get about a plus or minus six multiplier for within heat variation. So as you go through the Monte Carlo simulation, we say, "Okay. I have at least 20 tubes in the header out of one heat."
We pick a heat from the previous chart, and for each of those 20 tubes, we sample from this distribution to say where that -- you know, to get the actual crack growth rate for that tube, and we correlate that to the time to crack initiation from the Weibull.
MEMBER KRESS: So for a log triangular, shouldn't you get a discontinuity at .5 in the slope?
MR. RICCARDELLA: No, I don't think so. At .5?
MEMBER KRESS: That's where the triangle turns around and goes down the other way.
MR. RICCARDELLA: Yeah, but still, 50 -- there might actually be a -- if you look real closely there might actually be a discontinuity.
MEMBER KRESS: Okay. Maybe it's just my eyes.
MEMBER SHACK: But that's sort of good because those are the sort of two bounding distributions that you would pick.
MR. RICCARDELLA: Yes, right.
MEMBER SHACK: And you're not seeing all that much.
MR. RICCARDELLA: What we find is about a factor of two, which I think is kind of within the levels of uncertainty of this type of an analysis really.
MEMBER SHACK: Considering, you know, you'll never determine those tails. So in one case you've chopped them off and in the other you've let them run to infinity.
MR. RICCARDELLA: Yeah. Okay. Next slide.
Okay. Now, the real key, I think, to this whole analysis is we've made an attempt to benchmark the results with respect to the B&M plants, and so what I'm showing here is -- the previous slides were probably density functions. This is cumulative probability. Okay?
So this is cumulative probability assuming no inspection for a plant operating at 602 degrees, like the B&W plants.
This is the cumulative probability of leakage versus time, the cumulative probability of large circ. crack versus time, and the bottom is the probability of net section collapse versus time.
And what this slide says is that for that group of the seven B&W plants operated at approximately this temperature, they had about, at 20 years, those have about greater than a 90 percent probability of at least one leak, and that's fairly consistent with the operation. Seven out of seven of them had leaks.
MEMBER SHACK: Of course, since that's how you determine the Weibull, I would hope it would --
MR. RICCARDELLA: Yeah, right. That's a good observation. But then more significantly, one out of those seven plants had a large circ. crack. And now when we integrate the fracture mechanics into it, we're predicting about an 11 or 12 percent probability of a large circ. crack, and then that drops down to what the actual probability of net section collapse would have been at that time, assuming no inspections.
Now, as soon as we do inspections, of course, we change that probability of a large circ. crack.
MEMBER WALLIS: What does net section collapse mean?
MR. RICCARDELLA: Net section collapse basically means nozzle ejection. The same terminology.
MEMBER WALLIS: The same, okay.
MR. RICCARDELLA: Okay. Now, with that as the methodology, now we've used this model as a method to basically assess and provide a technical basis for our proposed inspection plan. Okay?
And the method we've used for this is to, first of all, start with the benchmarked analysis parameters that I've just described. Okay. So we've somewhat benchmarked the analysis.
Analyze different plants at various head temperatures, and what we've done is we've set risk categories based on both the probability of net section collapse per year and based on the cumulative probability of leakage. Okay?
And then we've also set inspection intervals looking at the effects of inspection based on probabilities of net section collapse, based on the impact of inspections on probability of net section collapse.
So I'm going to run through some of the results that we have and then later this afternoon or this evening, Michael Lashley will talk about the resulting inspection plan that's resulted from this.
MEMBER WALLIS: Inspections result in a change in the profile though because you do something as a result of what you find?
MR. RICCARDELLA: Yeah, the assumption is that if you find it you fix it, and so that particular nozzle no longer has a chance to propagate to ejection. You fix it or do something to take it out of the mix.
MS. KING: Well, the assumption and the experience to date is that you find it and you do something about it.
MR. RICCARDELLA: Okay. Just to review the analysis parameters, we've used the head temperature. We've analyzed ranging from 560 to 605 degrees Fahrenheit. I mentioned already the Weibull parameters of slope of three with a beta and a theta of 15 plus or minus six, and it's assumed to be a triangular distribution.
The crack growth rate statistics we've discussed. We're using the log triangular for both heat to heat and within heat variation.
We've used this cracked growth versus leakage correlation factors. We've used minus .8 for both the heat to heat and within heat, and --
MEMBER WALLIS: Is this something you thought was real?
MR. RICCARDELLA: Yeah, well, you know, it's kind of the knob that I used to make it match the results on the B&W plant.
MEMBER WALLIS: I thought it was. There was a dial
MR. RICCARDELLA: It is, in fact, yeah.
Okay, but you know, the real use of this type of analysis is to make apples to apples comparisons of different things. So I think it's appropriate to pick a set of numbers.
MEMBER SHACK: It also doesn't seem physically unreasonable.
MS. KING: Right.
MR. RICCARDELLA: You know, if you told me that you wanted me to use log normal and it doubled the probability, that probably lowered that correlation factor a little bit because, you know, in the end you want to agree to reality, to what we've observed in reality, and if reality changes, if we make some inspections and find some additional unexpected results, we'll have to go back and recalibrate, I guess.
And then we need some sort of acceptability criteria, and just for purposes of this inspection plan, what we're using is sort of an acceptable level would be a probability density function for a nozzle ejection of one times ten to the minus third, and that's consistent with the most predictions of the consequential core damage frequency, given a nozzle ejection is also about ten to the minus third.
So we've got a couple of plots here. This is a plot for a lot of different temperatures, 570 up to 605. The probability of net section collapse versus EFPYs at different temperatures, and you see two lines on here. You see the 1E to the minus three that I've talked about as being the acceptability limit. There's also one down here at 1E to the minus four.
You can see that these tend to jump around a little bit. Let me show you. Go two ahead to the conversion study.
Here's a convergence study that we did on one particular case with a 600 degree F. where I've run these with 10,000 -- this is the same thing, probability net section collapse versus EFPYs, assuming no inspection. I ran them with 10,000 Monte Carlo simulations, 100,000, and then a million Monte Carlo simulations. Essentially that would take about a ten-hour run to do the million Monte Carlo simulation.
But you can see that even though you get this jumpy curve, if you pass kind of a best fit through the jumpy curve, you'd predict about the same time to one times ten to the minus third. Okay?
All of the cases I showed earlier were run with 100,000, the middle of those three. Also you see that in terms of the probability of leakage, it has very little effect, the probability of leakage. Because it's a higher probability number, basically it converges much faster.
This is the cumulative probability of a leak, assuming no inspections, again, versus EFPYs for a bunch of different head temperatures. And, again, I've drawn two horizontal lines on here, one at 75 percent probability of leakage, and one at 20 percent probability of leakage.
Now, what I've done in the next plot is I've taken the intersections of those horizontal lines with the results of the analysis and created a locus of basically a time versus temperature locus of that data. So these upper two curves correspond to the net section collapse of one times ten to the minus three. That's the red chain link curve, and the 75 percent probability of leakage in terms of a time-temperature domain.
The lower two curves represent one times ten to the minus four, probability of net section collapse, and that just approximately corresponds to a probability of leakage of about 20 percent.
So what we have here basically is the temperature, the heat temperature, versus EFPYs of operation. However, as somebody mentioned earlier, some plants have operated at different head temperatures. They operates for a while at 600, and then they dropped it to 570.
And so this has been integrated into the number of -- the EFPYs are the effective EFPYs for those plants that have had multiple head temperatures, assuming that it has always been operating at the current head temperature.
CO-CHAIRMAN SIEBER: Now, these susceptibilities do not incorporate any knowledge you might have about the susceptibility of different heats.
MR. RICCARDELLA: No, we haven't taken that -- this is still generic. Basically it's a time-temperature, the same type of time-temperature correlation that Larry was talking about earlier. I've broken it into two, and, in fact, these are exactly the data points that Larry showed on his plot earlier of the actual plant.
So we show where the actual plants lie, the 69 plants lie on this time-temperature domain.
CO-CHAIRMAN SIEBER: I have another question. You have a susceptibility that's a function of temperature which you've described in everything you've done so far, but we also know that there is a susceptibility due to the heat. Which is the more predominant effect as far as determining how long it will be until section collapse?
For example, all of the leakage we've seen so far came out of one heat, right?
MR. RICCARDELLA: A couple of them came out of welds, I guess.
CO-CHAIRMAN SIEBER: All right, okay.
MEMBER SHACK: And there were more than one heat.
MR. RICCARDELLA: There was more than one heat.
MS. KING: There's more than one heat that has leaked.
MR. RICCARDELLA: There is a strong heat-to-heat sensitivity, as there is a strong temperature effect. Right now I can't say which is more important, but, you know, the heat-to-heat variability though, that variability is built into the distributions that we've used in our analysis.
And what we're trying to present here for purposes of the inspection plan is sort of a summary of the fleet or, you know, a simulation of the entire fleet.
CO-CHAIRMAN SIEBER: I can appreciate that, but when we started out, we used the temperature data as a basis for ranking the plants and saying these are the high susceptibility plants; these are moderate; these are low.
And then you put them in order, and that tells the agency who to go after first. If it doesn't consider the heat data, it's not totally clear to me that we're capturing everything that needs to be captured to do that ranking.
And this going back to --
MR. RICCARDELLA: But what the problem is is that we really don't have much information about the susceptibility of the individual heats in the individual plants. So, I mean, even if -- is that what you were going to say, Larry?
MR. MATHEWS: Well, what I was going to say is by ranking them the way we did, just based on time and temperature, there's an inherent assumption in that process that every plant has that same bad material that Oconee 3 had, and it's very likely that many plants aren't nearly that bad.
CO-CHAIRMAN SIEBER: I guess that's one of my problems, that when you put that assumption in there, then the ranking is less accurate than it would be if you took that effect into account.
For example, if you buy a deep draft pump and there was an instance with an information notice about ten years ago where the heat of some pump couplings in the shaft was not good, and that became a shut down your plant deal, and they were able to identify where the bad couplings were depending on when they were made and who you bought them from.
And so they ought to be able to tell where all of these nozzles came from, right?
MR. RICCARDELLA: Oh, we have information, but we don't have information on the susceptibility. You know, as we continue to do more inspections and collect more data, if some form of correlation becomes apparent, we'll take that into account in the model.
We could adjust this model so that we favor, you know -- so that we could analyze individual groups of material that are on the bad side or on the moderate side or on the good side, and if we start to see those --
CO-CHAIRMAN SIEBER: It seems to me that if we continue on this methodology of inspections and so forth and rankings that you ought to maybe do that.
MS. KING: Yeah, currently we are tracking the inspection data to the heat, but right now our stance is we don't have enough data to differentiate.
CO-CHAIRMAN SIEBER: To do something real--
MS. KING: And I'm not turning away from that. It's just that at this point we don't have enough data to differentiate between the heats.
CO-CHAIRMAN SIEBER: Well, if I were in your place rather than mine, I would be looking to trying to do that, to give me a better picture as to what's going on as time goes on and you collect the data.
MS. KING: Right.
MEMBER KRESS: Let me see if I can understand the basis behind your one times ten to the minus three acceptance criteria. If you have that happen, it means you have a small break LOCA.
MEMBER KRESS: And you can't put in one rod.
MS. KING: Essentially.
MEMBER KRESS: Essentially.
MR. RICCARDELLA: Essentially, yeah.
MEMBER KRESS: And that has a conditional core damage probability of probably ten to the minus three itself.
MEMBER KRESS: So you're talking about one times ten to the minus six core damage frequency.
MR. RICCARDELLA: Core damage frequency.
MEMBER KRESS: As your acceptance criteria.
CO-CHAIRMAN SIEBER: That's right, or whatever it comes out when you add on all the other mitigation you get out of the plant.
MEMBER KRESS: Yeah, but that should be at a conditional already.
MR. RICCARDELLA: I guess the other thing, too, is we're really not using that as acceptance. We're really saying that that's the limit that defines when we proceed from the moderate risk region into a high risk region, which is using this to set --
MEMBER KRESS: That's kind of a definition.
MR. RICCARDELLA: -- to set inspection requirements.
MR. RICCARDELLA: But that's where it comes from, exactly.
MS. KING: And you'll see it hopefully before this evening. We'll get to show you what these inspection requirements are.
MR. RICCARDELLA: And, you know, we're doing inspections to try to make sure that we never get to that point. We're starting to do inspections, you know, even in the low risk regime. We have different inspection levels, but they're graduated as plants move up from one regime to the other.
So you can see that a high risk model, basically it captured -- there's a total of nine red points that were leaders. Okay? And all but basically one of those red points is either on or above our high risk line.
And also I should say that all of these data points are about a year old. So they're all really going to move up about a year, and actually this data point here is three plants. There's one right on top of another. So you can't see them.
The three points where there were inspections that found cracks but no leaks are the three yellow points, one, two, and three, and then there's a whole group of plants that have done inspections and found nothing that are shown.
So it has really taken the plot that Larry presented earlier and breaking it into a two dimensional plot so that you can really see where these plants lie, time and temperature.
And now the plants progress upward on this line in real time, not in dog years, but in real years.
MEMBER SHACK: What I'm looking at now, when you have those dots, isn't that a median value for a plant with that temperature?
And if I ranged it up to the 95th percent, as I go through and I vary different heat assumptions, that low temperature plant is going to get better, and it's going to get worse, you know.
I've done a bunch of Monte Carlo runs. What's being plotted here? Is that the median value from that?
MR. RICCARDELLA: This actual data point?
PARTICIPANT: No, the third, the chain link line.
MS. KING: Oh, the chain link line.
MEMBER SHACK: The lines.
MR. RICCARDELLA: The lines are the median results from my Monte Carlo analysis. The data points are just time and temperature.
MEMBER SHACK: But where would the 95 percentile of the curve be?
MR. RICCARDELLA: I haven't really put confidence bounds yet on the Monte Carlo analysis. That requires some assumptions about, you know, the confidence in the various assumptions that occurred.
MEMBER SHACK: I mean, for a given temperature you get a distribution of failures, right?
MEMBER SHACK: Well, you can take the fifth to 95th to that.
MR. RICCARDELLA: This is all of -- this 100 percent of that.
MEMBER SHACK: It's 100 percent?
MR. RICCARDELLA: There's no -- you know, in terms of putting confidence bounds, I think you'd have to look at uncertainties in your various assumptions that went into, you know, the analysis.
MEMBER SHACK: This is all of the failures.
MR. RICCARDELLA: This is all of the failures, yeah.
CO-CHAIRMAN FORD: Could I make a suggestion?
MEMBER ROSEN: One question. What would a failure look like? Where would you plot a low risk plant that had inspected and found the crack? What color would that be and where would it be? Say it was a 600 degree --
MR. RICCARDELLA: Well, anyone who has inspected and found leakage is a red dot. Anyone that has inspected and found cracks is the yellow circle.
MEMBER ROSEN: So it doesn't matter whether you're a low risk or a high risk plant.
MR. RICCARDELLA: No, not in how you plot the individual points. I mean, if --
MEMBER ROSEN: So if I'm to take any comfort from this plot at all in terms of stuff, you know, if they're falling within the boundaries, because you're by definition saying if you get a crack or a leak and you're a 600 degree plant, you're right there.MR. RICCARDELLA: Yeah.
MEMBER ROSEN: And you may need a brand new plant, maybe one of the youngest plants that --
MR. RICCARDELLA: Well, no, no, no. The probability of leakage for a 600 degree plant, let's say a 602 degree plant, your probability of leakage hits 20 percent at about eight years in accordance with this, and then you continue to operate that plant. It gets higher and higher.
By the time you hit 18 years, it's 75 percent. This is Davis-Besse. It had, you know, at the time of that inspection about a 75 percent probability of leakage in accordance with this model.
MEMBER ROSEN: I'm trying to figure out where a point would be on this chart that would not be consistent with your model.
MR. RICCARDELLA: Oh, if one of these guys comes out as a red triangle, we're back to the drawing board, okay, or a circ. crack or anything like that. I mean, then it's reevaluating the whole model.
CO-CHAIRMAN SIEBER: That would tell you your temperature correlation is no good.
MR. RICCARDELLA: Yeah. It might be that the temperature or estimates of that head is wrong. We don't have absolutely certainty in our estimate of the head operating temperatures.
CO-CHAIRMAN FORD: Again, Pete, I hate to do this to you, but could you just move straight to your conclusions?
MS. KING: I guess could we show a couple of slides on the effect of inspections?
MR. RICCARDELLA: Let's just real quickly show the next one. All we've done here is to take those same -- that same chart and put on lines of constant EDYs, which is degradation, and it just shows that's how we get the 18 and the ten basically, because those are the ones that fall on top of our risk curves.
Okay? All right?
MS. KING: Now we'll go a couple ahead.
MR. RICCARDELLA: Now what we do is I've taken that same analysis, same model and said here's the probability of net section collapse versus time. This is run at 600 degrees. So this is actually EDY. It says EFPYs, but in this case EFPYs equal EDYs.
And at the time that I get to 18 years, which is approximately that one times ten to the minus three, I assume inspections of various levels. I assume a bare metal visual, and there's three curves. One is a bare metal visual every refueling outage. One is every two EDYs. One is every four EDYs. Okay? And what's the effect of those?
And we made some assumptions about probability of detection, which I think we should cover.
MR. RICCARDELLA: Yeah, we assumed .6, which means --
MS. KING: I think that's hanging up.
MR. RICCARDELLA: I think you've got to go up. No, one more up.
CO-CHAIRMAN SIEBER: We'll trust you it's .6.
MR. RICCARDELLA: Point, six, no, but there's something else I wanted to point out, was that what we assumed also that was for subsequent exams, if you missed a leak in a nozzle, we applied a factor of .2 on that. So it's really only .12, is what we're assuming for subsequent exams of a nozzle.
The comment came from one of our interactions with the NRC that if you do an inspection and you miss it, it might be because that's a particularly difficult nozzle to inspect, and you have a higher probability of missing it the next time.
So we put the ability to input a knockdown factor on the POD or --
CO-CHAIRMAN SIEBER: You can't find it because it's covered up by boron crystals, right?
MR. RICCARDELLA: Yeah, something like that, or difficult access or tight shrink fit or all kinds of things. So we think it's a fairly conservative assumption as to what the POD is, and then we had a second POD set of assumptions for nondestructive volumetric examination, and that's a curve of probability of detection versus crack size.
MR. RICCARDELLA: So if we go to the volumetric, this is the same kind of curve again. We assume we do the inspection at one times ten to the minus three or at 18 EDYs, and then what the effects of NDEs at four and eight years are on that.
CO-CHAIRMAN SIEBER: Do you have one that shows the comparison between a visual and a volumetric?
MR. RICCARDELLA: The next one sort of shows that.
MS. KING: Kind of, yeah.
MR. RICCARDELLA: Here's the case of starting the inspections earlier. You know, we are proposing some inspections for the moderate category. We're not proposing that people just operate without any inspections until they get to high risk. We're actually specifying inspections in the low risk and also in the moderate risk.
These are the moderate risk recommendations, and it's either a visual at two EDY or an NDE at four. So you can see the effect of the two. Obviously the NDE is more effective as the large curve.
The NDE at four is more effective than the visual at two.
CO-CHAIRMAN SIEBER: Yeah, that gets back to my earlier point. If you really want to find them, it ought to be volumetric.
MEMBER ROSEN: It's a question of whether you want to find that or whether you want them to find us.
CO-CHAIRMAN SIEBER: Well, I think that's well put.
MR. RICCARDELLA: Okay. Let's just go to conclusions.
CO-CHAIRMAN SIEBER: You don't have anything with NDE and visuals at the same intervals, right? That would be a yes or a no.
MS. KING: No, we do not.
MR. RICCARDELLA: No. We could back it out from the previous two curves if you want. The NDE is --
CO-CHAIRMAN SIEBER: I think I know enough.
MR. RICCARDELLA: The NDE is much more effective because it's finding -- first of all, we're using a higher POD for the NDE, and secondly, it's finding things even before they leak.
CO-CHAIRMAN SIEBER: And it also helps you to some extent to see if you've got a cavity somehow in the ferritic material that you can't see from the surface, if you're good enough at looking at it.
CO-CHAIRMAN FORD: I'm going to let the members read the conclusions during their break time.
CO-CHAIRMAN SIEBER: Our understanding is more important.
MR. RICCARDELLA: This is the key though. I think when Michael gets up later to present the inspection plan, you're going to see that this is the basic result of this analysis, is we've got low risk, medium risk, and high risk categories that correlate to those EFIs, and I've kind of explained where those different categories come from.
CO-CHAIRMAN FORD: Thank you very much, indeed. I appreciate it.
CO-CHAIRMAN FORD: We'll recess until quarter past three.
(Whereupon, the foregoing matter went off the record at 3:00 p.m. and went back on the record at 3:15 p.m.)
CO-CHAIRMAN FORD: Mark, you're up.
MR. KIRK: Okay. Thank you.
Is that working?
MR. KIRK: Okay. The title of this presentation is NRC assessment of the margin available at Davis-Besse. My name is Mark Kirk. I'll be making the presentation for the NRC Office of Research.
What I'll be presenting in the next 40 minutes or so represents the collaboration of a whole host of people, and I don't think I have all the names on the top slide.
Wally Norris is another, like myself, is another program manager in the Office of Research. He manages the work at the Engineering Mechanics Corporation of Columbus, who has done some of the finite element analysis. I manage the work at the Oak Ridge National Laboratory under the HSST program.
Of course, Bill Cullen is leading the Davis-Besse effort within the Office of Research.
Nilerh Chokshi is the head of the Materials and Engineering Branch.
At Oak Ridge, Paul Williams and Richard Bass have been doing the finite element analysis. At the Engineering Mechanics Corporation of Columbus, the work there has been led by Gary Wilkowski and Dave Rudland.
CO-CHAIRMAN FORD: Could you just -- we've also got a quorum of people here. I just want to interrupt for one second just to let everyone know that at the rate we're going, in case you have to make family arrangements, et cetera, it might be a quarter to seven or seven o'clock before we're finished, if we keep up the density of questions.
MR. KIRK: Okay. And I'll apologize in advance. In order to give you the most up-to-date information, we've revised these slides since I provided them to Mike at the end of last week. I do not have handouts right now, but I will. We'll make them and we'll get them to you. They are probably about twenty percent changed.
What we'll be talking about today is mainly a discussion of our deterministic assessment of margins in the condition that existed at Davis-Besse at the time of the March shutdown.
We'll also be giving you some views on the next steps in this analysis which include some further refinements of this deterministic assessment and also moving on to do a probablistic analysis.
The scope of our deterministic assessment was first to asses the margin to rupture of the exposed cladding left in the condition that existed at the March '02 shutdown.
The next step was to determine how much of either -- how much over-pressure it would have taken to rupture the cladding in that condition or how much more wastage would it have taken to rupture the cladding at operating pressure.
Finally, we had planned to assess various weld repair options.
The red text, it's just up here to provide you a perspective of where we are, well, where we thought we were last Friday. We've had an increased level of understanding which I think I should say is a reduced level of eposemic (phonetic) uncertainty regarding our failure criteria. So we are going back and redoing some calculations, but I think that's all for the better.
We're still working on the middle bullet. The last bullet we are not going to do because repair isn't being considered at this time.
This slide provides you with an overall perspective of the analytical tools we've been using. We've been using to different sorts of finite element models.
At Oak Ridge National Laboratory, we've constructed a full 3-D finite element model where we've got a global model. It includes the specific head geometry as installed at Davis-Besse. It includes all the control drive penetrations.
That global model, when subject to internal pressure, establishes the boundary condition on a sub-model which then means that we get a much more refined representation of the head wastage at least at best we can tell at the time. So this is the model that we would regard as giving us the answers that are the closest to reality.
We also have been using an axi-symmetric finite element model. That was constructed at MC2. Because of the limitations of axi-symmetric modeling, the wastage had to be modeled as a spherical pit at the top of the head.
Obviously, that's geometrically not a completely accurate representation, but the reason why we wanted to do that was to enable us to do some quicker parametric studies about increase growth and so on. Moreover, Gary Wilkowski, who's been doing the analysis at MC2, has considerable background in modeling of corrosion damage in gas pipelines and so is familiar with some of the approximations that is used in that industry.
But in any event, in the end we'll be reporting and relying on the results of the 3-D model. We've used the axi-symmetric model largely to help guide the 3-D modeling effort and provide quicker results at the time.
This table provides just some details of the analysis and the various inputs that we've used. The loading in these analyses has been either the design pressure or in cases where we've tried to calculate the over-pressure margin, obviously, we've ramped that up.
The temperature has been the operating temperature and we've not considered any temperature gradients because none exist at operating, at least in any practical sense.
I'll show you more about the material properties and the local geometry that we've modeled on the following slide. That's a new slide that is not in your pack.
On failure criteria, I'm going to give you a little of a now-and-then flavor because this is the area where we've done some refinements in the last few days.
Up until last Friday, we considered -- or we defined, I should say -- failure to occur when the average through thickness plastic strain in the exposed cladding area exceeded 5.5 percent, with the 5.5 percent corresponding to the strain at the beginning of plastic instability.
That was derived from uni-axial tension data that showed an 11 percent strain at max. load, and furthered the assumption that failure occurs at the same stress level under uni-axial and bi-axial loading.
I want to stress that is an assumption that maybe isn't as coupled as well as it should be to the actual ductile failure mode.
We'd honestly never been completely satisfied with that as a failure criteria because up until last Friday, we hadn't known of the existence of any better data to calibrate to. But I'll be discussing how we've changed that shortly.
MEMBER WALLIS: Don't you have stress concentration around the edge where there is sort of a sharp edge?
MR. KIRK: Yeah. Yes, you do. And that is considered in the geometric finite element model, yeah.
MEMBER SHACK: Why would you even start with that assumption, Mark?
MR. KIRK: Start with what assumption?
MEMBER SHACK: That failure occurs at the same stress into the uni-axial and bi-axial loading.
MR. KIRK: If you want the straight and unvarnished answer, because it made the math work easily. But don't go there too far because everything has changed.
MR. KIRK: Okay. This just shows the material properties that we've been using, just simply appropriate properties for the RPV steel and for the 308 cladding.
I'm now going to give you a short time history of the geometries we've assumed. Our first cut at this, when this all hit the fan back in March and the Office of Research was asked to assist, we had to get some cut on the geometry.
So we took one of the photographs that was taken in the vary initial inspections. It was a head-down shot of the cavity. At that point, the brown that you see at the bottom of the cavity, that was water sitting in the cladding.
We used the diameter of the hole as a dimensional reference and simply digitized the shape of that cavity.
Our current model reflects the results of Figure 13 which is shown in the licensee's root cause document. It's our understanding that that's the best current representation of the cavity.
What we've incorporated into our model is a -- I think everybody here has also seen the companion profile view which shows the nose in the RPV steel. However, we don't believe or we don't have any reason to believe that that contributes significantly to the load carrying capacity of the membrane. So we haven't included that in our model.
Basically, the 3-D model that we're using now has a hole in it down to the cladding along the green contour.
MEMBER WALLIS: What's the boundary condition on the control rod drive cylinder there?
I understand the boundary condition around your green line, but what about the boundary where there's a gray? What's your boundary condition for the cladding there?
MR. KIRK: I'm not -- I mean it's a -- it's hooked to the rest of the head and you don't apply a boundary condition there. You apply a boundary condition remote to the head.
MEMBER KRESS: It's free to move there.
MR. KIRK: It's free to move, yes. It's not constrained. But I'm not sure I'm answering the question.
MEMBER KRESS: It's hooked at the corners where the green --
MR. KIRK: Yes.
MEMBER WALLIS: So where there isn't green, where that round grey thing is; it's free there?
MEMBER KRESS: Yeah. It says free-floating membrane, a free-floating area. No constraint to it.
MEMBER WALLIS: Oh, it can't be. From there?
MR. KIRK: From there, yes. That just expands with pressure.
MEMBER SHACK: No, but the displacement of the cladding is constrained to be the displacement at the nozzle?
MR. KIRK: Yes.
MEMBER SHACK: It's not free-floating?
MEMBER WALLIS: It's not. It rests on the nozzle.
MEMBER SHACK: And it's attached?
MR. KIRK: This is where the nozzle attaches at. That's correct. Yes.
MEMBER BONACA: I thought the portion of the cladding was exposed within and beyond the image that you have from a picture taken above.
MR. KIRK: I believe that's what's reflected -- well, these are two different --
MEMBER BONACA: I understand.
MR. KIRK: Better -- presumably better knowledge going from here to here. I believe there is -- I should say I believe because nobody is going to band-saw through this thing and cut it open for all to see.
My understanding from what I have seen -- and I think, you know, yours too -- is that there is exposed cladding back here.
MR. KIRK: I believe this contour here which I have not outlined is what you would -- what I'm trying to say --
MEMBER BONACA: Oh, that's what you're seeing?
MR. KIRK: -- is that if you're looking down from the top there's metal here. This is the position of the nose. That's where the cladding will dispose.
Now what's really there, we still don't know. I think that's fair to point that out, that in our current calculations -- in anybody's current calculations -- what the actual geometry is is, indeed, unknown. I mean we're getting better and better representations of it. But I think it is important to point out that the first order effects that are important is the overall exposed area.
The shape of that, obviously it's different if it is a perfect circle than if it is along the ellipsoid. Also the details of the thickness, overall thickness of the cladding and thickness variations.
We don't know all those. You know, those are, to borrow a phrase that I've learned from our PRA friends, "those are in principle knowable," but we don't know them right now.
MR. KIRK: So we like everyone are proceeding with our best current information which to my understanding is this right here. But if anybody in the audience can tell me later about better information, I'd greatly appreciate it because we're about, as you'll learn later, we're about to embark on finite element analysis to drive some probablistic calculations. If we can go into that with a better knowledge of the geometry, that would be certainly desirable.
MEMBER KRESS: I have a little bit of a strange question. Why do you want to do this?
MR. KIRK: Because my boss asked me to.
MR. KIRK: No, you had a serious question.
MEMBER KRESS: Right, seriously. I mean, you're asking -- this is kind of a what-if question. How close were we to disaster?
MR. KIRK: Exactly.
MEMBER KRESS: Is there some use for that information?
MR. KIRK: In terms of -- do you mean in terms of the probablistic analysis or the -- we've been doing the deterministic analysis, I think, just to -- my understanding would be to satisfy that question of how close were we. Were we really close or were we not so close at all?
MEMBER KRESS: You just want to know that?
MR. KIRK: Yeah.
MEMBER KRESS: Is there some use for that information?
MR. KIRK: Now, going to the probablistic calculation -- and I'll give the short answer and some of my colleagues in the back can perhaps give a more detailed answer -- the probablistic calculation is being used as one of the inputs to NRR's safety determination process.
MEMBER KRESS: The old ASP type thing or?
MR. KIRK: Steve, do you want to take a cut at that so I don't use the wrong acronyms?
MR. LONG: This is Steve Long.
MR. KIRK: Yes. Yes, significant. See, I knew I'd do it wrong.
MEMBER KRESS: Okay. I understand that.
CO-CHAIRMAN SIEBER: The way you can do that is to assume it fails and look at what mitigating systems were in service and what the failing duct you had, which comes out to what, three times ten to the minus three or something like that for CDF?
If you assume the failure frequency is one, that's the first cut.
MR. KIRK: What I'm going to show you is a series of slides that summarize our current results, and some of these are as current as just this morning. So you are getting the latest and best.
What the contour plot shows you here is the equivalent plastic straining contours in the cladding.
We've removed all of the reactor pressure vessel head so you can see what's going on. We've taken this up to the operating pressure of 2165 psi. At that pressure we get the highest strain somewhere around about the center of the wastage cavity, and the peak strain is somewhere between 2.5 and three percent.
We've been going through extensive debates, as I think most of the committee members are aware, with the industry over what an appropriate failure criteria is, but I don't think anybody has ever presumed that it would be as low as this.
The finite element model with the best representation of the geometry as showing us that at operating pressure we wouldn't really expect it to fail. Indeed, it did not fail.
CO-CHAIRMAN SIEBER: Let me ask you a question. How did you model the cladding itself? Cladding is not a plate. It is a series of weld stripes, which to me would seem to be weaker than a solid piece of material that was just a plate there.
Did you treat the cladding differently--
CO-CHAIRMAN SIEBER: -- than you would have as a solid metal?
MR. KIRK: No. Right now -- well, it's weld strip cladding. So we've assumed -- I mean, it's been modeled as a plate. So you've implicitly assumed that there are no flaws in it and that you've got no significant lack of inner rod penetration.
CO-CHAIRMAN SIEBER: Do you feel comfortable with that?
MR. KIRK: Yeah. I feel reasonably comfortable with that. The only further modification that I would think would be appropriate at some point -- and again, this gets to the question of why are you doing this -- is how refined a model do you want to get to get a warm, fuzzy feeling that you weren't that close after all.
You might want to include the natural undulations that result from the welding process. I would personally take the position that I wouldn't want to do that until I had a lot better picture of what those undulations were. I don't have that right now.
MEMBER ROSEN: You'd just be making it up.
MR. KIRK: Yeah. Right now I would be forced to make it up. That's right.
MEMBER ROSEN: I'm not sure. You need to be careful about assuming that because it's weld metal that it's weaker than a plate. There's lots of evidence that they think it might actually be stronger.
MR. KIRK: Well, just in terms of the --
CO-CHAIRMAN SIEBER: Wait a minute. It seems to me that I've seen weld overlays on various vessels where it wasn't continuous. I've seen places where the weld didn't --
PARTICIPANT: Didn't overlap.
CO-CHAIRMAN SIEBER: -- and the undulations actually exist because they are crud-trapped. That's what makes all these clad vessels, unless they're micro-polished, so radioactively hot.
MEMBER ROSEN: But would you agree with me that we don't know -- a priori we don't know whether it's stronger or weaker?
CO-CHAIRMAN SIEBER: I think that you would say it was weaker if you knew exactly what the weld metal was and the temperature conditions as --
MEMBER ROSEN: But we don't.
CO-CHAIRMAN SIEBER: -- how it was laid down. You would know something about it, but it would be a guess. It really would.
MEMBER ROSEN: I'm just trying to make the point that we don't know whether it's stronger or weaker than a model plate because we don't know what the configuration is (a), and (b) we don't know whether a weld metal deposited that way is, in fact, weaker or stronger.
MR. POWERS: This is Jim Powers from FENOC.
MEMBER KRESS: The question is: to what detail do you think you all have to go to with this.
MR. KIRK: One of the things that we will be doing -- and I'll get to this in a bit in the probablistic analysis -- is we will certainly be including -- because we know from measurements that were reported in Figure 14 of the licensee's root cause report; we know there are measurable variations in the cladding thickness.
And so in our probablistic analysis, I can say with a fair degree of certainty that variations in a uniformed plate model of thickness will be included. Whether we need to, want to, whether it's warranted to go to the next step and include the details of the undulations is, indeed, up for questioning.
Like I said, I wouldn't -- I, personally, wouldn't want to do that until I had a much better picture. By that, I do mean something like a photograph and profilometry of what's actually there because otherwise I'm just guessing.
MR. POWERS: This is Jim Powers from FENOC.
We do have some undulations on the surface, but it's relatively smooth. There is no separation of contact bead to bead. It was a six wire sub-arc application of the clad. We PT-tested that clad area and found no indications in situ.
So we had some degree of confidence in its continuity.
MEMBER WALLIS: There is a measure of the residual bulging, isn't there, in this?
MEMBER WALLIS: Does that check your analysis? I mean the actual movement of the center from --
MR. KIRK: I don't have those figures reported here, but my memory is from an early analysis that they were -- given the approximations in the analysis and the difficulty attendant to measuring a set deformation off of initially curved surface, that if you will forgive the phrase, "they were close enough for government work."
MEMBER WALLIS: That's your predictions, or the measurements?
MR. KIRK: Both.
MR. KIRK: In this case, the measurements weren't reality either.
I mean, remember those measurements were made in an environment where they were trying to minimize man REM so it wasn't exactly like somebody got down there with a micrometer and made a measurement that was good to the mil.
I think we're in the position the piece is now cut out. I apologize because I don't know where it is. Clearly somebody in this room does. But, you know, we're in the position of making much less equivocal measurements.
MEMBER WALLIS: Is this going to the Smithsonian or somewhere, is it?
MR. KIRK: I don't know.
CO-CHAIRMAN SIEBER: We probably are dwelling on this more than is necessary. So I think at least I know in my own mind what was done and how it was modeled and that's good enough for me.
MEMBER KRESS: A strain is a measure in the change in length divided by the original length.
MR. KIRK: Right.
MEMBER KRESS: Your original length, is that your finite element node that you use? You get a change in that finite element node?
MR. KIRK: Yes. Yeah.
MR. KIRK: This is the slide there where--
PARTICIPANT: I could put cartoons on there.
MR. KIRK: This is the slide where we've had some significant changes and, I think, changes for much the better in our predictions of margin on over-pressure. All the predictions that we've made, that anybody's made obviously depend upon how you modeled it and what you've assumed for failure.
In particular, the assumed failure criteria, the failure strain makes significant differences in how much pressure you think you can withstand.
There was considerable discussion given in earlier presentations of this work that the industry analyses performed by Dr. Riccardella were predicting considerably higher over-pressure margins than our analyses. It's not hard to see that was related to differences in the failure strains we were using.
One thing I would point out is that even with our at the time more pessimistic view of the strain that the material could withstand before failure ensued is all of our over-pressure margins exceeded the SRV set-point of 110 percent. So something even with the very pessimistic view that we took initially on what the material could take, a controlled SRV trip would have happened before we would have expected the SRV set-point to have been reached, before the membrane would have blown.
However, as I said, we've been having continuing discussions between ourselves and the industry regarding the issue of the failure criteria. We've recognized from the beginning that the failure criteria that we took on was somewhat arbitrary.
Pete pointed out to us -- pointed us back to a paper that he had presented way back in 1972 at PVP, where experiments had been run on, among other things, burst discs of 304-stainless steel. I have diagramed the experiment here.
The disc had a thickness of both an eighth inch and a quarter of an inch. It was a six-inch diameter exposed area, and it was subjected to pressure on the backside until it ruptured.
Now, to quote Richard Bass, who has looked at this over the weekend, in fact, if I were to design an experiment to calibrate the failure criteria in my finite element model, I would have designed this experiment.
So over the weekend, once we finally got the peculiarities of electronic data transfer perfected and actually got a copy of the paper, Paul Williams and Richard Bass at Oak Ridge modeled this geometry, which is very conveniently axi-symmetric, and used it to calibrate a failure model that we would use in the Davis-Besse analysis.
We believe that these experiments are extremely relevant and appropriate to this end because the experiments have a similar material, have a similar thickness, and have a very similar exposed area to the conditions of interest at Davis-Besse.
By calibrating the failure criteria to these experiments, we are able to significantly reduce our uncertainty in the failure criteria, of course, by referencing the relevant experiment data.
In doing these analyses, we've reached the same conclusion that was reached back in 1972, that disc rupture occurs shortly after the finite element solution fails to converge under pressure loading, of course. What that means, physically, is that the elements -- we're doing large deformation, large plasticity, finite element analyses -- the elements have been stretched so far that you can't maintain -- you can't reach an equilibrium condition.
This, of course, produces what we'll call an NRC failure criteria, which is much, much closer to that that's been advocated by the industry for quite some time now.
In exercising this new failure criteria, we're using a new sub-model of the wastage area just based on our most recent geometric understanding and also including more refinement through the cladding thickness.
MEMBER KRESS: I have a little problem with that criterion. Doesn't the failure to converge of your finite element model depend on the size of your finite elements that you choose?
MR. KIRK: Yeah, yes it does. We've done the studies on that. But the more -- the less refined your model, the stiffer the model becomes. In other words, our initial model included only one element through the thickness of the cladding.
MEMBER KRESS: Okay. You mean --
MR. KIRK: That --
MEMBER KRESS: -- you only had sort of a surface?
MR. KIRK: Yeah. Yeah.
MEMBER KRESS: That went all the way through?
MR. KIRK: That's right. That model will fail to converge at a lower pressure than a more refined model. So the -- if you fail to refine adequately, you will --
MEMBER KRESS: But, how about in the other two dimensions? You can make that smaller and smaller. On the top.
MR. KIRK: Yeah. Yes, you're right. You're absolutely right that that will depend upon the level of mesh refinement.
What I'd like to point out is that if you under-refine the mesh, which is the only error that you can make because it is an inherently discrete model, that will lead to an under-prediction of the true failure pressure, not an over-prediction.
MEMBER KRESS: You may be right. I am still bothered by having a failure criteria that's tied to how well my finite element model behaves. It seems a little strange to me, but I'll buy what you say.
MEMBER SHACK: The system is too stiff. Therefore, I'm going to get less deflection than I would for a given load.
MR. KIRK: That's right.
MEMBER SHACK: Wouldn't that tell me I'm -- I'm getting less deflection so if I go -- the strain I'm predicting is really too small, right?
MR. KIRK: I'd have to check, Bill. I think it goes -- oh, what I do remember is --
MEMBER SHACK: But your going to run the mesh refinement?
MR. KIRK: We're running the mesh refinement. We know that if we have four elements through the thickness, we get to a higher plastic strain before we can converge them with one element through the thickness. As of 0800 this morning, we had a pressure of 3.5 ksi or 60 percent above design without failure, and the model continues to run.
MEMBER ROSEN: Why wouldn't you let the licensee do any more? They want to get more and more margins. You know, let them do it. You're done with the problem as far as I'm concerned.
MR. KIRK: I'll give you a list of people I'd like you to say that too, if you would.
MEMBER ROSEN: I just said it.
MEMBER WALLIS: No, I don't think your done with the problem because the public is going to ask this question, the newspaper reporters, all kinds of people.
Have you done the ASME diaphragm tests? Have you predicted that too?
MR. KIRK: I'm not familiar.
MEMBER WALLIS: The one you just drew. The one you showed us -- the pictures.
MR. KIRK: Yes. Yes, that's the -- that was the -- I don't have that here, but those results, we were able to predict the results in the paper.
MEMBER WALLIS: You did a good job on that?
MR. KIRK: Yeah, within ten percent of the -- we systematically under-predicted the true burst pressure of those experiments by a factor of ten percent.
MR. POWERS: Jim Powers from FENOC again.
From a licensee's perspective, we have a very short presentation that we'd like to do that shows what we did in terms of optimization of the node, numbers of nodes for the modeling, as well as a correlation to the disc burst criteria and shows how we selected our failure criteria. We have about a dozen slides, if we could respond afterwards.
MR. KIRK: So as I said, these are very new results. This gives you a sense of the line that we're trying to pursue.
Also, right now the only information that we have on the additional -- how much bigger the cavity would have had to have been in order to fail comes out of our axi-symmetric model that was done at MC2.
We haven't yet gotten this into the 3-D model. What we did is we just expanded the diameter of the pit at the top of the axi-symmetric head until the failure pressure, and I should emphasize this is a failure pressure at assuming the old 5.5 percent strain failure criteria. So the newer, better, updated version should be bigger.
In any event, based on that criteria, we calculated that we needed, in round terms, two more inches of wastage along the main axis in order to fail at the operating pressure. Given the changes that I just reflected and our understanding of an appropriate failure criteria, I would expect that when we do this with the 3-D model, with the new failure criteria, the amount of the additional wastage could indeed be considerably more.
MEMBER KRESS: Are you going to convert that into how much time was left before the --
MR. KIRK: Yes. We do consultation with Bill Cullen. Yes. Yes.
MEMBER ROSEN: Did you get any information about what would happen to the rod after failure? Would it eject?
MR. KIRK: That's not part of our current analysis. I'll throw that open to anybody else in the room if anybody -- do you know is anybody considering what would happen to the rod if this membrane ruptured? Anybody?
I haven't heard about that, but --
MR. POWERS: Jim Powers, from FENOC.
We submitted in our safety analysis of this rod ejection effects. We described those the last time we came to this subcommittee in terms of the shield above the rod housing area and lateral loads from jet, cavity loads on adjacent rods, and the fact that they'd remain in the elastic range and should function properly.
So we had submitted that previously.
MR. KIRK: This is my -- the last slide that I was planning on presenting. It just gives you a perspective on where we're going. I put on the slide last week that we were looking at a better definition of the failure criteria. That, based on the work over the weekend, is now well under way.
On that basis, we intend to recalculate the margin on over-pressure and the additional cavity growth needed to fail using the new failure criteria and the 3-D model.
As I indicated before, we've begun the FE analysis to support -- to generate the inputs needed for a probablistic analysis that's needed to support NRs, and now I've got a wrong again, significance determination process.
MEMBER WALLIS: If your cavity grows enough, then the liner is actually holding the nozzle.
MR. KIRK: That's correct.
MEMBER BONACA: In fact, a similar question I have is this analysis clearly is looking at the strain in the material and the ability of what it would take to rupture.
MR. KIRK: Yeah.
MEMBER BONACA: In reality, during the clean-up of the head, there was work being done on the nozzle from below and that's when the tube moved.
So I guess the question I have is: how well attached is this nozzle to the cladding, okay, that would result in that being the weak link?
So, therefore, the cladding probably could have still survived, but the nozzle would be ejected. I don't understand what caused them to do that.
MR. POWERS: Jim Powers from FENOC.
What caused the rotation is we were going into the repair methodology for the J-groove weld cracking phenomenon. So we machine-up through that weld and actually separate from it. Then it wasn't supported up above due to the cavity and it tipped a bit.
MEMBER BONACA: So the weld was still affected before --
MR. POWERS: That's correct.
MEMBER BONACA: -- they did their work.
MR. POWERS: That's correct.
MEMBER ROSEN: They had already cut it when it moved.
MEMBER BONACA: Okay. I just wanted to know. Okay.
CO-CHAIRMAN FORD: Mark, thank you very much for your -- who's next? Is it the -- well, how about let's invite Jim Powers?
MR. POWERS: This is Jim Powers.
I'd like Nat Cofie from Structural Integrity Associates to give a short presentation on what he's done in evaluating this cladding and also comparing it to the disc burst pressures and give us a quick look at that.
MR. COFIE: My name is Nathaniel Cofie. I work at Structural Integrity Associates.
We've been assisting Davis-Besse in trying to determine the margins, set the margins in the as-found wastage condition. What I'm here to present this afternoon is just a very brief summary of the analysis, the failure criteria that we use, and how we've been able to justify this failure criteria that we're using for analysis.
We use a three dimensional finite element analysis to build a model.
MEMBER WALLIS: Do we have a --
CO-CHAIRMAN FORD: Yes, it's coming around.
MR. COFIE: We use a 3-D model because this geometry is very, very complicated. We've tried to explore the possibility of using a 2-D model which would really make the analysis very, very quick and very ready-available. But the geometry of the wastage inside that really didn't lend itself to a 2-D axi-symmetric analysis.
We ran some preliminary 2-D analysis compared with the 3-D results, and they didn't agree very well. Because of that, we decided to use a three dimensional finite analysis, which includes the head, the affected nozzle and the adjacent nozzle, and all the features that would capture the stress and strain distribution as we subject the head to the pressure loading.
We modeled the entire head and the dummy nozzle and the adjacent nozzles. Of course, because of the large strains involved in this, we used incremental elastic plastic analysis.
We used a very conservative stress strength curve in the analysis. And the previous speaker mentioned 11 percent and 5.5 percent. I'd like to rephrase that a little bit. It's really not 11.15 percent per C, but the criteria that we used was basically based on the uniform elongation of the stress-ranked curve. So that is really the basis for the 11.15.
The criterion that we use in the analysis was that any column of elements in the finite element analysis, which exceed the uniform elongation, that formed the basis for our failure criteria. Then we said that we've achieved failure.
We believe this is very conservative because when a column of elements exceed 11.15 percent, or the uniform elongation, there's redistribution of stresses and strains to the adjacent elements. So using this as a failure criterion to begin we thought was very, very conservative.
MEMBER SHACK: Suppose you did the more simple minded thing. I mean the uniform elongation in a tensile test, really it's a maximum load in the tensile test. So if you do a maximum load in the sphere under pressure and you consider the thinning of the sphere, you come up with two-thirds of the uniform tensile stress and the equivalent stress.
Why not that kind of a simple minded argument, where you are basically doing the same argument, but the thing fails because it is necking faster than it's work hardening?
MR. COFIE: Yeah, you know you build it -- once you get your large deformation, you find out using stress as a criterion becomes very difficult. Because a very small increment in --
MEMBER SHACK: No, it's still a strain criteria.
MR. COFIE: You know, as I will show later, you find that, in fact, when these evaluations started, the general feeling was that if you run the analysis all the way to plastic instability, that probably would be very close to the actual failure. It depends on the --
MEMBER SHACK: That's the equivalent of what you're doing with that kind of an argument.
MR. COFIE: Exactly.
MEMBER SHACK: Except you're going to do it without making an approximation.
MR. COFIE: Exactly. In fact, later on, I think with the experiment that I --
MEMBER SHACK: But that isn't what you said you did here?
MR. COFIE: Well, I would -- next slide, please.
You find that for the average thickness clad of .297, I've predicted --
CO-CHAIRMAN SIEBER: Could you move closer to the mic, sir? I'm sorry. Could you move closer to the microphone so the reporter can hear you?
MR. COFIE: Yes. I've predicted that the pressure was 5600, which was greater than twice the normal operating pressure.
We also ran a case with minimum measured clad thickness of .24. We got 4600 which was also greater.
MEMBER SHACK: But that's for your uniform strain in an element or that's for your plastic instability?
MR. COFIE: No, that is for the uniform strain, elongation.
MR. COFIE: So even with this conservative failure criteria, we got failure pressures which were twice, greater than twice the normal operating pressure. Of course, if we had used the instability load as a criterion, that would have been even greater. I'll show you those.
But this criterion came under a little bit of question because it was slightly based on engineering judgement, engineering judgment, but I believe that based on the fact that once you reached the uniform elongation, there's free distribution of stresses and strain. I believe strongly that that was very conservative.
But now that -- to prove, that fortunately we got this burst test that were run by PVRC somewhere in the early '70s. And Pete took that results. Peter Riccardella took those results and did an analysis of those.
So we had the test results available to us. So we used that basically to test the failure criteria that we've used to see how reasonable it is and whether it is conservative enough application to this wastage problem that we dealt with.
Next slide, please.
This didn't come out very well, but this is basically the three dimensional finite element model that we use. It takes a very sophisticated finite element model.
We have the -- this is the wastage area right here. That doesn't show very well on this slide. This is the nozzle associated with the wastage.
We modeled the four adjacent nozzles so that we catch the ligament effect. Initially we thought that we could get by without making this thing too complicated, but we wanted to get you all the details. You know, once you have some adjacent holes in the neighborhood of this area, we thought that could affect them. So we modeled adjacent models to catch the ligament effect.
This model has a total of about 6,000 elements. Through the cladding, we had six through wall elements. Because of that, the became a very humongous model which took days to run. We wanted to do it right, to make sure that we get results that we can rely upon, are very, very reliable.
Next slide, please.
This is a summary of the analysis results. The original footprint, which is 20.5 square inch with an average thickness clad, using the criterion based upon the uniform elongation, the predicted failure pressure was 5600.
For this case, we also went as far as to instability, and the instability pressure was greater than 8000. If I remember, it was 8,125. It was greater than 8000.
We also looked at a case with the minimum measured thickness of .24 and the original footprint. The predicted pressure based on the uniform elongation criteria was 4600.
For this case, we really didn't go to instability because this was failure criteria. Therefore, we just run a little bit greater than this pressure. We know that the instability pressure is 48 -- greater than 4800.
If I were a betting man and you asked me what would be the instability pressure, I would say probably it goes up to about 7,000.
We also did another analysis to look at what is the failure pressure if, indeed, we have a larger footprint, twice the area that was associated with the wastage. And in this case we've got a predicted failure pressure greater than 2750.
Once again, we stopped this just around about 3,000 because we had used a 2-D model to basically benchmark against a 3-D model, to predict when we'd get to about 2750. So we didn't run this under any pressure greater than 3,000 or so.
I believe that the instability pressure for this one is also greater than 4,00 psi.
Next slide, please.
MEMBER BONACA: That's the question I had. Can you comment on the stuff used 5.5 percent strained?
MR. COFIE: Right.
MEMBER BONACA: Okay. It seems to be a key to the difference as one may see. Could you comment why you use 11 percent?
MR. COFIE: Like I said, 11.15 percent was basically the uniform elongation. The idea of using that as a failure criteria, that once you reach 11.5 percent, once you reach the uniform elongation, you start to get necking (phonetic). That is the first onset of instability, but that's not necessarily the failure pressure.
I understand the 5.5 percent was used by the staff's contractor because they were trying to account for the so-called tri-axiality factor associated with the fact that this is sort of uni-axial loading, but it's a bi-axial, tri-axial state loading.
Unfortunately, you don't apply the tri-axiality factor to the uniform elongation. I believe, probably, if that has been explored a little bit, they would have probably done something a little different. I think that is the difference between the two failure criteria that we used.
I brought this slide only to show that the uniform elongation associated with the stress-strain curve that we used is very conservative. There's a whole lot of reference in the literature, a lot of NUREGs and EPRI reports that have reported various elastic -- various stress-strain parameters for weld metal as well as base metal, stainless steel.
Here is the uniform elongation for the base metal. It is pretty large. Our range is about 45 percent. So make-up weldments, SAWs, the average for all the data that would have to got in this reference is about 25.7, 25.7 percent. Most of the data is greater than 20 percent with only two of them less than 20 percent.
This is the data for SMAW weldments, all of them greater than 20 percent, with the average of about 30.7 percent.
If you combine both populations, both weld populations, both SAW and SMAW, the average elongation is about 27.3 percent.
MEMBER SHACK: But, I thought Davis-Besse when they were last here told us those came from measurements by Framatome, the 11 percent.
MR. COFIE: No, that's not exactly correct. The 11 -- the stress-strain curve that was used was basically obtained in the lurch and one of these handbooks. At that time, that was conservative enough that we chose to use that one as the basis for these evaluations.
But, no, there was no measurement made on the Davis-Besse --
MEMBER SHACK: No, not on the Davis-Besse. A test on weld metal, on cladding?
MR. COFIE: Yes, it was based on the test on that, but just obtained from the literature. Okay?
MR. POWERS: This is Jim Powers from FENOC.
Steve Fyfitch was there at that meeting and indicated that it came from Oak Ridge data in the handbook for the specific 308 material stress-strain curve. So it was the best data we had specific to the weld material.
MR. COFIE: So, in any case, you look at all this data and compare it to the data that was used for the evaluation, and you find that we are really on the very conservative side of what is reported in the literature.
Next slide, please.
Okay. From this slide going -- I'm going to just describe, basically, the disc burst test that PVRC -- disk burst test which was performed in the early '70s which was basically used to determine the reasonableness and conservative -- the conservatisms involved in the failure criteria that we used.
CO-CHAIRMAN FORD: This is just essentially the test that Mark just --
MR. COFIE: Yeah. This is just the test that Mark had presented.
CO-CHAIRMAN FORD: Could you just highlight any differences in your approach versus that which he did? Just for sake of time just highlight any differences you may have in your approach and --
MR. COFIE: Just to save time, this is basically, you know, the three geometries that I we did.
Next slide, please.
These are basically the properties associated with the materials of the disc.
Next slide.
Well, this slide also did not show up very well. What we did was that we looked at various through wall elements, four, eight, 12, just to look at the effect of through wall elements on the analysis results.
Next slide, please.
Okay. We also -- the slide you just saw was the axi-symmetric model. This one is a three dimensional model very, very similar to the model that we used for Davis-Besse. We used the same element types so that we get one-to-one comparison.
Next slide, please.
Now, these results show the effect of through wall elements versus the predicted pressure or the predicted failure pressure. As you can see from six elements to -- six elements onwards, there is essentially no difference in the predicted failure pressure.
So any time you use through wall elements of six and above, basically, you get essentially the same results.
In doing Davis-Besse's model, we used six through wall elements to decline.
Next slide.
MEMBER WALLIS: Why do you have two curves here? Why are those two different?
MR. COFIE: Well, there are two different because if you remember there's -- I presented two models. One is a 3-D model and one is an axi-symmetric.
MEMBER WALLIS: It seems to me that all the points are for the axi-geometry or am I misreading the figure?
MR. COFIE: Well, there are -- in the PVRC test there were three different geometries.
MEMBER WALLIS: But why are some at 7,000 and some at 14,000?
MR. COFIE: There are three different geometries.
PARTICIPANT: Some of them were one inch thick and some of them were a quarter of an inch thick.
MEMBER WALLIS: Okay. Okay. Then that's why it's twice the pressure.
MR. COFIE: Exactly.
MEMBER WALLIS: Okay. I understand.
MR. COFIE: Next slide, please.
Well, here is the typical stress-strain associated with the disc analysis that we did. Remind you everything is essentially membrane. You know, at very high pressure this is almost like a balloon, very, very high membrane stress. Right at the edge here, we have some venting stresses here.
Next slide.
Okay. This is a summary of one of the analysis results. This is the total equivalence strain of -- when makes it strain, this is pressure for one of the analysis that we did for the disc burst test. We flooded both the top level and the bottom strains as a function of pressure. This is how the outage behaves.
Okay. This really is the point where right at the end of the evaluation or the end of the pressure increment is where we reached instability.
So the instability pressure associated with this particular test was about 14,000 psi compared to a test pressure, a test burst pressure, of 15,000. So even at instability, we've predicted that we are slightly below the burst pressure obtained in the test.
Now, based on the elongation, based on the uniform elongation criterion that we use for Davis-Besse, this is where we would have predicted failure. We would have predicted failure right around about 11,000 psi, which is, of course, significantly below the test burst pressure.
MEMBER SHACK: Maybe I'm reading something wrong here. As I read from the paper, it says all the center line failures occurred at approximately the same strain level, 35 percent.
MR. COFIE: Well, don't forget that when Pete did this analysis, when this analysis was done, it was done with only one through wall element. Really this analysis is a refinement of what was done in 1972.
MEMBER SHACK: Oh, so the 35 percent is not a measurement?
MEMBER SHACK: It's an analysis?
MR. COFIE: It's an analysis.
MR. RICCARDELLA: Yeah, this is Pete Riccardella from Structural Integrity.
Yeah, you have to recognize that they did that analysis with the tools that existed back in 1972. So you really have to ignore some of the analytical predictions there. We've updated that analysis with today's tools. So that 35 percent represents sort of an old estimate.
MR. COFIE: Right. If you read the paper, I find that one through wall element was used. This had about twelve through wall elements. So this is a much more actual analysis that we've done.
So this tells you that the criteria now we're using is very conservative compared to the test results.
Not only that. The instability pressure also predicted pressures which are significantly -- well, not significantly, but slightly below the test pressure.
So really one can argue that you could go to instability and that would be a very, very good criterion to use to predict the best pressure.
Next slide, please.
MEMBER SHACK: Unless it falls at an edge, right?
MR. COFIE: Well, even that fail at the edge, you know, also predicted the same thing.
Here's a summary of all the analysis that we did on the burst test. Here is the burst test results.
Where is instability? We find that instability is very, very close to the burst test results. This is -- this are the results based upon a uniform elongation, and you can see that is conservative compared to the burst test.
So of all the analysis that we did to find out in all cases, the criteria that we've used for Davis-Besse is very conservative.
This simple analysis that we've done has proved beyond any reasonable doubt because now we have got some work as data that the criteria that we've used is conservative.
So, anyway, in confusion, I would say that what we've done for Davis-Besse, you know, we've done a very conservative analysis. We've used very good finite element models, 3-D finite element model. Like Mark said, we've used a lot of through wall elements to the cladding. We've also, basically, tested the criteria against known burst test results to show that it is very conservative.
CO-CHAIRMAN FORD: Thank you very much indeed. We appreciate that.
MR. COFIE: Thank you.
CO-CHAIRMAN FORD: As I understand it, now we've got three presentations, one by FENOC and then one by you, Jim. And then one by you, Larry. They are all scheduled for one hour each.
If I could ask you to please look at your presentations and try to make them three quarters of an hour each, I'd appreciate that very much.
(Pause in proceedings.)
MR. POWERS: Okay. good afternoon. I'm Jim Powers. I'm the Engineering Director for First Energy at the Davis-Besse plant.
This afternoon, we're going to do a brief update to the ACRS ON where we stand with the situation at Davis-Besse. I brought along with me a number of individuals.
You will recognize Mark McLaughlin as our Field Project Manager for work on the head.
Bob Schrauder is our Director of Life Cycle Management and is responsible for the replacement head project that's ongoing.
And Steve Loehlein is our root cause lead investigator. He'll give you an update on what's transpired in the root cause area.
MR. POWERS: Okay. So with that, let me turn it right over to Mark, and he will give us a description of field activities.
MR. McLAUGHLIN: Okay. Good afternoon. I will definitely try to be brief.
The first slide -- the next, keep going -- okay. The one thing that I wanted to point out, you guys had seen this slide before. I just wanted to point out the access that we had to do our inspection, and this kind of leads into the root cause report that will be coming up.
These are what are commonly called mouse holes and those were five by seven and they were installed in this lower portion of the service structure.
Next slide, please.
You've seen this nozzle depiction many times. The only thing that I wanted to point out is that on a Babcock & Wilcox reactor head, this is a gasketed joint with no seal weld. When these leak, the path that the borated water takes to get down to the head would be twofold.
One, it could drip down onto the insulation, and there is an eighth of an inch gap between the nozzle outside diameter and the insulation, or a nozzle, an adjacent nozzle in this area could spray onto this, and we have observed both of those types of leakage, And then it flows down and through the gap.
Next slide, please.
I wanted to update you with two things on this slide. Nozzle number two, we originally reported that there are eight axial flaws. There are actually nine axial flaws with this. That also brings the total number to six through wall.
The other thing, if you notice nozzle number 46 we say has no flaw indication. However, there was a shadow. What we've done since we were here last time is we've cut the nozzle up into the shadow region. We did a visual inspection, as well as a dye penetrant inspection. I guess the results are that we really don't see any reason why that shadow is there. There is no leak path present and there is no significant corrosion.
Let's skip this next one.
I guess the big thing that we've done since we were here last is we did perform the abrasive water jet cutting of the cavity. The cavity has been removed. What your seeing here is the water jet tool. This is a mock-up. We mocked-up -- performed two mock-up cuts prior to performing this cut on the head.
Next slide.
This is the actual cutout on the reactor pressure vessel head at Davis-Besse. You notice nozzle number 11 would have been in this location. We used nozzle number 11 as the entrance point so that we wouldn't do any damage to the weld material around nozzle number three to preserve it for experiments.
Next slide, please.
This is another view using a remote camera underneath the head of the cutout.
Next slide.
This is an actual view of the cavity that's been removed. It shows the lithium fixture and the as-removed was about a 17-inch diameter.
I just wanted to update you on the sample plans of what we have. Phase one was various boron samples that we had collected from the -- on top of our head. We do have a draft report from our contractor who's been analyzing those.
We've found what we expected. There's significant boron, iron, and lithium. There's also some traces of nickel and chromium which is probably from either the nozzle material or the weld material.
Phase two is currently in analysis. That is boron and material samples from the removal of nozzle number two. So that may give us some boron samples in the actual annulus region.
Phase three, we are currently working with the staff to determine what type of testing and experiments we want to do on the actual nozzle number three, the actual nozzle from number two, and the cavity.
Somebody was asking about dimensions earlier. All of these samples are down in Lynchburg, Virginia. We are arranging a trip down there within the next two weeks. Anyone who would like to go see the cavity, touch it, and measure it as much as they want, it is available.
PARTICIPANT: Keep the ALARA advised.
MR. POWERS: It is a much lower dose.
MR. McLAUGHLIN: Yeah, the dose is significantly lower now.
MR. McLAUGHLIN: This is a picture of looking in the cavity after it was removed. You can see in the under-hung portion, and I think you get an excellent view of the cavity itself as well as the exposed cladding.
The cladding looks brown because it still had the abrasive on it from the abrasive water jet cutting process.
Next slide.
What I wanted to show you here is -- the last time that we had talked to you there was some discussion about a detachment or corrosion between the cladding and the base metal around nozzle 11. What this is, this is the J-groove weld for nozzle 11 and you can see the opening where we entered to do the cut through nozzle 11.
I performed an inspection. The surface is too rough to do a dye penetrant test at this time. However, there is no evidence of cladding detachment or a corrosion in that region between the cladding and the base material.
That's all I have. Are there any questions as far as updates from the field activities?
(No response.)
MR. McLAUGHLIN: Hearing none, I'd like to turn it over to Bob Schrauder, who is going to discuss the replacement of the reactor pressure vessel head at Davis-Besse.
MR. SCHRAUDER: Good afternoon. While Jim and Mark were busy attempting to repair the reactor vessel head, I started out early on in the process looking for a potential replacement head for the vessel.
We looked at several options, one of which was to look at -- we do have a new head ordered for Davis-Besse that was scheduled to arrive at our plant during the first quarter of 2004. We looked at accelerating that schedule.
We also looked at potentially purchasing someone else's place in line, if you will, that had another head already ordered that would be compatible with the Davis-Besse vessel also. Those, the earliest one coming out there that we could find that was compatible was in the third or fourth quarter of 2003.
Both of those being manufactured, ours and the next one in the pipeline, if you will, were already on an accelerated schedule. So we were not going to be able to do much with the schedule of getting a new head in here much before 2004.
So I then began to look at what was already available in the industry. We found two heads that were compatible with Davis-Besse. Rancho Secho had a plant that had operated for a while and, as you know, has been shut down. And then at Midland, one of the two heads in that unit was still on site there.
We looked at those two options. We quickly zeroed in on the Midland head.
Next slide, please.
The Midland head -- both heads like I said would fit with some very minor adjustments. We thought Midland was the clear choice for two reasons. One, it was a lot closer to us. It's in the neighboring state right in Midland. We have to just bring it across the state line and bring it down to Davis-Besse.
It is readily available from the perspective of it's sitting in a commercial setting, if you will. It would be a commercial kind of construction job to go get it versus the Rancho Secho head which is, although not an operating nuclear plant, it is still a nuclear plant. That head, because it was used, was contaminated which complicated both any modifications we might need to make with it and significantly complicated the transportation needs for that.
CO-CHAIRMAN SIEBER: Well, the Rancho Secho head was still installed, right?
MR. SCHRAUDER: That's correct.
CO-CHAIRMAN SIEBER: So you would have had to cut a hole in their containment to get it out?
MR. SCHRAUDER: Well, actually the Rancho Secho head will fit through their equipment hatch.
MR. SCHRAUDER: The Midland head would not.
CO-CHAIRMAN SIEBER: Will it fit through yours?
MR. SCHRAUDER: No, it will not.
CO-CHAIRMAN SIEBER: All right. You can tell us about that later on.
MR. SCHRAUDER: Yes, that is in the presentation. We'll get to that.
PARTICIPANT: They're not going to fold the head.
CO-CHAIRMAN SIEBER: Cut the head in half and put it in the containment.
MR. SCHRAUDER: The other head at Midland is, by the way, cut in half. So that one was not usable.
MR. SCHRAUDER: This slide shows some of the similarities between the Midland head and the Davis-Besse head. They were both fabricated by Babcock & Wilcox in the same period of time to the same ASME boiler pressure code edition and addenda.
Now we have the records for the Midland head. We know that during construction that head was accepted for use by Consumers Power. It was signed off by an authorized nuclear inspector and identified as an acceptable ASME component.
It was, in fact, as all of the B&W plants were, it was hydroed before it was shipped to the site. It shows the hydro was there at 31.5 pounds. As you know, Consumers canceled the original plant back in the mid-1980s. Since that time, that head has been on the head stand inside the containment.
CO-CHAIRMAN SIEBER: You knew what heat and nozzles came from?
MR. SCHRAUDER: Yes, sir. That's right around in the presentation and we'll get to that.
Did you file a Part 21 related to the nozzles that were susceptible in your plant?
MR. POWERS: No, I don't think we've filed a Part 21 as of yet. But we've had discussions on that issue.
CO-CHAIRMAN SIEBER: I think that would be a good discussion to have amongst yourselves.
MR. SCHRAUDER: Because of their technical expertise and because of the fact that they had access to all of the records on this heat, we hired or we brought in with us a partner Framatome. Framatome actually purchased the head for us from Consumers. They purchased it as a basic component.
They'll verify its usability. They'll compile for us the code data package which they have the records for. They'll disposition any non-conformances on that head and then will sell it to us as a basic component for use at Davis-Besse.
CO-CHAIRMAN SIEBER: Is that an assembly or is it just the head? In other words are the control rod drive mechanisms already installed?
MR. SCHRAUDER: The control rod drive mechanisms have been removed and somebody else owns those.
CO-CHAIRMAN SIEBER: Okay. You're going to use your old ones?
MR. SCHRAUDER: That's correct.
MR. SCHRAUDER: In the process of this, Framatome will also reconcile the design requirements of the Midland plant to the Davis-Besse plant. Those design requirements, again, are covered over the next couple of slides.
Of course, Framatome will do these activities under their quality assurance program, including responsibility for Part 21 reporting.
The next slide is simply a pictorial that you can relate to as we talk about some of the similarities and differences on this head.
This next slide shows that this head and the design is essentially identical to Davis-Besse. They were both 177 plants. The materials of construction you see there are virtually identical. Even the closure head flange there is really the same material, the same specs. for that material.
The design pressure and temperatures for both reactors was identical, 2500 pounds of pressure and 650 degrees.
MEMBER ROSEN: What does the dash 64 mean on the closure head flange?
MR. SCHRAUDER: Actually that's an A50864, and that's an ASTM material. They're the same material essentially. One is an ASTM code.
MR. POWERS: Go ahead, Steve.
MR. FYFITCH: To answer his question -- this is Steve Fyfitch, Framatome -- the 64 is the date, the year. So it's the 1964 edition of the ASTM code or the ASTM specs.. Excuse me.
MEMBER ROSEN: But the materials are the same is the answer I got.
MR. FYFITCH: That's correct.
MR. SCHRAUDER: The next slide that answers the question of do we know the heat materials on this head. In fact, we do. Sixty-eight of them are from the specified heat there, M7929. And one is from M6623.
What happened was in the manufacturing, the putting together of this head, there was one nozzle 7929 that had had a problem, and the other nozzle came from the canceled Bellafont (phonetic) unit. So that's why there is one nozzle that's the same.
Neither of those two heats of materials has any industry experience. We do know, though, that they look to fall right in the middle of the pack by way of yield strength for those heats. But there is no industry experience on them.
The control rod configuration and the alignment is the same on that head as it would be for Davis-Besse. So, geometrically, it's very nearly the same or physically, its characteristics are the same.
There are a few minor physical things that we have to do to the head. The picture that is shown here is the key-way. The key-way fits into the reactor vessel itself and it makes sure that the head is precisely aligned to the vessel for latching your control rods and your control rod interface.
There's two surfaces. You see that one and then the other one would be on the inside there. There's two surfaces for each of the four key-ways that you have to be concerned about getting your fit. Four of the eight surfaces needed to have some slight machining to precisely fit on our reactor vessel head; to the tune of about five mils., we had to machine on those.
Also the control rod drive flange itself that is on the nozzle that the control rod drive mechanism flanges to has an indexing pin on that, too. There's two locations that you can have your -- that that's indexed too. As you might figure, they used the opposite hole that Davis-Besse does.
So we have to take the plug out of their indexing pin in that location, put it in the other location, and then we'll have that set-up to index for our control rod drive mechanisms.
The next slide shows another physical difference on this head and ours. The Davis-Besse head has the O-ring which is the sealing ring for the head to vessel; is 0.5 inches on Davis-Besse. On the Midland one, it was 0.455.
CO-CHAIRMAN SIEBER: You have two O-rings?
MR. SCHRAUDER: Yes, sir.
So, those two O-rings -- we have done the analysis to show that it will effectively seal in the groove that we have on our vessel. Of course, we will be able to demonstrate that with the leak-off capability on that head. We will be able to tell if there's any leakage between those seals.
CO-CHAIRMAN SIEBER: But the clearance between the vessel flange and the head flange will be slightly smaller, correct?
MR. SCHRAUDER: Well, the crush is fine on it.
MR. SCHRAUDER: So the sealing surface that you need, both of those surfaces we show will have full contact and it won't be an issue.
So we're manufacturing the new O-rings to 0.455 that will fit inside the groove for the Midland head.
The next slide, again, is a pictorial that you can refer to for the next series of slides that I'll go over, which describe the nondestructive exams that we'll do on this head to verify that its stay in Midland, since they canceled that plant, has not had any deleterious effects to it.
We did three types of exams on this head or will do three types of exams. One is to supplement the ASME code data package. One is our pre-service IS exams, and then we did some additional nondestructive exams to verify that, again, there was no deleterious effects to the head from the period of time that it's been sitting in Midland.
This first page shows the examinations to supplement the ASME code data package. I should mention that with supplement, although we had a signed off code data form, we did not have the film of the radiographs for this head. We had indication and sign-off that they had a successful radiograph both on the dome to flange weld. This is a two-piece forging for this head. We didn't have that radiograph film and we didn't have the radiograph film of the nozzle, the flange to nozzle.
So we're re-radiographing both of those. In fact --
CO-CHAIRMAN SIEBER: You need to have that.
MR. SCHRAUDER: We have completed the radiograph on the large dome to flange weld. That radiograph did prove to be very sound.
We'll do a series of visual exams, just to verify there is no obvious problems on the seating surfaces and the grooves in this head.
And I discussed the radiographs that we'll do. And we'll also do a PT examination on the J-groove welds.
CO-CHAIRMAN SIEBER: And a visual on the inside cladding to make sure it's all there?
MR. SCHRAUDER: We're going to do some liquid penetrants on the surface of the and the repaired areas of the clad, of underneath.
MR. McLAUGHLIN: The cladding is all there.
CO-CHAIRMAN SIEBER: Well, sometimes it isn't, you know.
MR. McLAUGHLIN: Oh, really?
MR. McLAUGHLIN: I was up Friday and inspected it. The cladding is all there in this head.
CO-CHAIRMAN SIEBER: PT is pretty hard to do on a welded surface that's not cleaned up, right? Dye penetrant?
MR. McLAUGHLIN: It won't be a problem on this head. When I was in there, I'm not sure what process they used. They must do some grinding on it because the inside diameter of the head is very smooth.
PARTICIPANT: The cladding?
MR. McLAUGHLIN: Yes, the cladding is smooth, as well as it was on the Davis-Besse head.
CO-CHAIRMAN SIEBER: Oh, okay. That's also not always the case.
MR. SCHRAUDER: The next slide shows the pre-service inspections that we'll do: magnetic particle exam with the flange to dome weld, an ultrasonic on that same weld, and an electric penetrant PT exam of the -- this has the peripheral CRDM nozzle to flange welds, the ones on the peripheral. That's what's required by code. Our intent is to do all of them that we can get to. We believe that we will be successful in getting to all of them. We will certainly, at least, meet the code requirements for that, and our expectation is to do PT on all of those.
The next page just shows the additional nondestructive exams we'll do, chemical smears to assure that it meets the proper class cleanliness. A baseline UT we will do on all of these nozzles so that if we do UTs in the future, we will have something to compare to. We'll know whether there was any indications in these nozzles early on.
CO-CHAIRMAN SIEBER: What kind of packaging was the head stored in?
MR. SCHRAUDER: It was not stored in any packaging.
CO-CHAIRMAN SIEBER: It was not covered?
MR. SCHRAUDER: No, it's not.
CO-CHAIRMAN SIEBER: It's in a building; is that correct?
MR. SCHRAUDER: The CRD nozzles did have some covering on them, but that was about all that was covered. It's in the containment building. That's correct.
CO-CHAIRMAN SIEBER: So you have to cut a whole in that one, too?
MR. SCHRAUDER: That's correct.
MR. McLAUGHLIN: That's correct.
MR. SCHRAUDER: And that's coming up next on how we're going to go about getting this.
I should mention -- I meant to mention this earlier -- our intent is to use this head, put it on now. We'll use it until such time as we replace our steam generators, which is currently expected to be 2010 or 2012, in that time frame.
So we are maintaining our place in line with our new head. We will get a new head and we will replace it again when we open the containment up again to replace steam generators.
CO-CHAIRMAN SIEBER: Now, why would you do that? For material change?
MR. SCHRAUDER: That's right. This head obviously has the same material on it, the same susceptibility.
CO-CHAIRMAN SIEBER: You moved the 690?
MR. McLAUGHLIN: Correct.
CO-CHAIRMAN SIEBER: Do you folks know a lot about 690 as far as the nozzle database?
MR. McLAUGHLIN: From what I understand, I don't believe there is a large nozzle database.
CO-CHAIRMAN SIEBER: Or any database, right?
MR. McLAUGHLIN: Well, there would be some in France.
MR. McLAUGHLIN: But they'd be young.
MEMBER ROSEN: What you want to do is take the head you take off, this one, and put it someplace and protect it.
CO-CHAIRMAN SIEBER: Well, I don't know. You have a whole --
MEMBER ROSEN: Just swap back and forth.
PARTICIPANT: Well, just don't take it out to the dump.
MR. SCHRAUDER: Well, as a matter of fact, our intention is to dispose of it shortly after we take it out of containment, if it is categorized as a Class A alpha waste.
MR. FYFITCH: Let me just add a point. John, I don't know where you are going with that question. This is Steve Fyfitch, again from Framatome.
The 690 has been in use now in steam generators for a number of years, and on France for the nozzles on the head, they've been replacing heads since the early '90s. So now they are almost nine or ten years in service.
By the time Davis-Besse replaces theirs in 2012 or 2010, it will be almost 20 years. So there will be a large database of experience by that point.
CO-CHAIRMAN SIEBER: Well, my only comment, I guess, is I started in this business in 1960, and the 1960, Alloy 600 was wonderful.
MEMBER ROSEN: If you do want to take my comment as a guide, I don't throw anything away. So come look at my garage.
CO-CHAIRMAN SIEBER: You can have the head.
MR. SCHRAUDER: Is it seventeen feet in diameter?
MEMBER ROSEN: My garage you're talking about? Just about might fit.
MR. SCHRAUDER: This shows and addresses the issue on the containments. Yes, we do have to cut both the Midland containment and the Davis-Besse containment structure.
The Midland containment is a pre-stressed containment so it has to be de-tensioned, and then we'll actually chip into that containment and open up a large, 20 foot by 20 foot hole approximately.
The Davis-Besse containment is a shield building, a concrete shield building with a free-standing pressure vessel and an annular region in between.
We are using Bechtel Power to assist us in the opening of both containments. They have done most of the containment openings and restorations in the United States.
We have a bullet on here that shows we will bring the head, the existing Davis-Besse head out, protected and the people around radiologically from that.
Temporarily, we hope right now -- I should get analysis back next week that will categorize what class waste it would be. And then it would be our intention at this time to dispose of it if it is categorized as a low level waste rather than create a temporary storage facility at Davis-Besse for it.
We will work with the NRC on that and make sure that the rest of the industry knows that's our intent in case there is any desire to do any more examination or testing on that head.
We are going to transfer our service structure from the Davis-Besse head to the Midland head. We are putting in the inspection, the inspection modification. That goes on the lower skirt, and that piece of the Midland head we will use, and before we ship it to Davis-Besse, it will have that modification performed on it to provide adequate inspection and cleaning of the head as necessary.
Of course, I have already said that we will re-use all of our control rod drive mechanisms on this head.
As we were repairing the head and we had to cut out a couple of nozzles, we had to reconfigure our core at Davis-Besse, specifically, the control rod locations to assure that it was acceptable. We will go back to the original core design with the new head. We will be submitting that core analysis to the NRC.
There are a couple of modifications that have been made over the years for serviceability and outage flexibility, the nozzle flange split. Split dot ring modification will be performed, and we will use the upgraded gasket design on the control rod drive mechanism flanges.
MEMBER LEITCH: Have you thought about foreign object damage when you're cutting a hole in the containment?
I guess you're planning to do this with the fuel still in the --
MEMBER LEITCH: You're going to de-fuel?
MR. SCHRAUDER: We will be full core off-load when we do the -- and I meant to say that. The cut at the Davis-Besse site will not be a classic cut and chipping. It will be a process that uses a very high pressure water lancing that essentially washes the concrete off of the rebar, and Bechtel has used this process in Spain several times.
There appears a much nicer cut on the containment and avoids having to chip back to get the rebar exposed. Then the rebar can be tagged, cut, and then restored right back into the original location so that it's already go the proper bend to it and you cad weld it back in and then restore your concrete.
So it's a much gentler process.
MEMBER LEITCH: But even so, are you going to deck over some areas to prevent foreign object outage or --
MR. SCHRAUDER: We do have a vessel cover for the Davis-Besse head. That will be in place when we take the fuel out of the reactor vessel. Yeah, we'll be very cognizant of foreign material.
They're spending a lot of time cleaning that containment up right now, too. So I'm sure that it will be left very clean when we're done with it.
MEMBER LEITCH: One issue that always concerns me when you have a major construction project like that going on. Its fire fighting capabilities, just I'm sure you're going to get into a lot of detailed planning, but I would just like to remind you to be sure that you haven't temporarily removed from service any of your fire fighting capability while you're doing that because when that kind of activity goes on, it just increases the potential for fire, and you want to be sure that, you know, all of your fire fighting stuff is up to speed.
MEMBER LEITCH: Operable, or if not, some other temporary provision has been made.
The next slide, Slide 31, just shows some of the post installation inspections that we'll do to verify that we do have a good fit on this. We'll fill and vent the RCS, do a visual for gross leakage, and we'll bring the plant to normal operating temperature and pressure with reactor coolant pump heat.
Of course, we won't be able to get right up into the nozzle space at that time. So what we'll do is we'll bring it up to temperature and pressure. We'll cool back down, and then we'll go in and look for visible signs of leakage when it was at pressure.
We'll perform the control rod drop time testing in accordance with our tech specs to verify the control rods do, in fact, go in at the appropriate speed.
Once we put the head on and you latch the control rods, you're pretty well satisfied that you've got the proper alignment here, but we will, as required by tech specs, do a control rod drop test.
The next page we don't really need to go into. They are approvals that we would need from NRC staff, and the top two there were actually needed for our existing head also in their IS program.
MR. POWERS: Okay. If there's no further questions, we'll turn it over to Steve Loehlein to talk about the root cause updates.
CO-CHAIRMAN FORD: I just got a proposal here from Jack. Has everyone read the root cause report?
It may be -- and I don't want to put you out of business.
CO-CHAIRMAN SIEBER: That was a god report, Steve. It really was.
CO-CHAIRMAN FORD: It was a very pointed and honest report, I thought.
Maybe the best way to tackle this in the cause of time is does anyone have any questions having read the root cause report.
MEMBER APOSTOLAKIS: Well, maybe you can go to the inspector summary on Slide 52.
CO-CHAIRMAN FORD: Do you mind? Do you feel s as though you're being done out of --
MR. LOEHLEIN: I don't mind. We thought that perhaps that time line slide would have had some questions on it, but if people are familiar with that, having read it, whatever is of interest to it, that's why we're here.
CO-CHAIRMAN FORD: It was a very complete report, I thought, and I enjoyed reading it. I didn't enjoy it.
CO-CHAIRMAN SIEBER: I didn't enjoy reading it.
MR. LOEHLEIN: I didn't enjoy writing it all that much.
CO-CHAIRMAN SIEBER: But it was well done.
CO-CHAIRMAN FORD: Okay. Why don't you put the time line graph up just to jog any people's memory as to whether this question --
MR. LOEHLEIN: It's probably -- I don't know by number. It's the fourth slide in.
CO-CHAIRMAN FORD: It's this one here.
CO-CHAIRMAN SIEBER: We all have it separately.
CO-CHAIRMAN FORD: Why don't you walk through that one, and it might jog people's memory as to the questions, and then go to the conclusion?
MR. LOEHLEIN: It's a little bit hard to do here logistically. So, Mark, I'll ask you to go ahead and point.
this is a little bit of clarification on the way this is laid out. You start at the very top of this diagram. We have a set of blocks that indicate what we call industry and regulatory knowledge, milestones.
At about the 1995 time frame with the boric acid corrosion guide book, and I'll pass on through, up through the bulletins and generic letters, and so forth.
As you proceed down, the first thing you see is is a blue bar graph. The blue bar graph indicates the reactor coolant system and unidentified leak rate over time.
There is also the red dashed line that proceeds on a diagonal from left to right with three data points on it or the number of nozzles that were not visible in an as found state, those refueling outages.
As you continue on down this chart, you run into the yellow colored blocks that indicate the containment radiation monitor filters and the change in preventive maintenance frequencies brought about by clogging either to boric acid or to a combination of boric acid and iron oxide.
Below those blocks we have similar blocks reporting the frequency of containment air cooler cleanings, and beneath those, we have the two time lines. The first one is simply the chronological passing of years. Beneath that are the outages and plant cycles as they line up.
Then in the numerous blocks down below, there's actually three sets of data. As you read from left to right, the first set of blocks is the conditions for the control rod drive mechanism flanges.
The next set below it is the reactor pressure vessel flange itself on the outside perimeter, and then the bottom set of blocks is the reactor pressure vessel head.
So that's how this is laid out. Any particular questions on it?
CO-CHAIRMAN FORD: I've just got a generic question. I must admit I read it in anticipation of reading -- because of my interpretation what a root cause report is -- that it would tell me specifically what the mechanism was and thereby when things started, and that would give me some idea as to how generic this was and whether it was a leader of the fleet.
And of course, it didn't have that, but having heard the reports earlier on from NRP, I'm assuming that that onus is now being passed to the NRP; is that correct?
MR. LOEHLEIN: I think --
CO-CHAIRMAN FORD: They will take on the burden of determining whether this really is --
MR. LOEHLEIN: We probably each have a piece in that answer. So I'll speak first and say that clearly in the evidence we had available to us in the large cavity region at nozzle three, we could from the plant data and other physical evidence say pretty much what happened since about 1998.
But that only describes what happens at high corrosion rates once the conditions are right, boric acid and so forth.
And what we all know and what we need to study further is what happens prior to that, and we didn't have measured data that we could go to and say how long the steps took, and that's the kind of work I think Christine at EPRI is taking on.
MS. KING: Right. This is Christine King with EPRI.
We took that on, as Glenn said earlier, just a couple of weeks after the discovery of the wastage at Davis-Besse because of the idea of understanding how this progresses, and we will obviously continue to work on that.
CO-CHAIRMAN FORD: The thing that keeps coming to mind, everything from stress corrosion cracking of turbines to tracking of small pipes: big pipes will never crack, and sure enough they do crack.
In Japan, we will never crack a pipe in Japan. And they do.
And so whenever anyone says that this is a one off (phonetic) situation, my ears immediately start to prickle, and my hair starts to prickle.
But anyway, I'm really suspicious until we understand what the real root cause was and how it relates to geometry and chemistry, et cetera. And this is why I was urging you to as quickly as possible we'd better put this one to bed.
MR. LOEHLEIN: What I would comment on is in all this investigation, we did as a team with a technical experts and so forth, is that we were unable to uncover any new evidence to provide us with any kind of insight different from what is already known, and that is that cracks can lead to leaks, can lead to corrosion if it's not discovered.
CO-CHAIRMAN FORD: And one of the conjoint requirements to have.
MR. LOEHLEIN: Or detected.
MEMBER BONACA: I would like to -- we're talking about root cause, and so your conclusion is that inadequate inspections of the closure head was the problem. I think beyond that it seems to me that the fact that you cannot fix the flange leaking completely at any given outage, but you manage that issue by saying we will fix the most severely leaking and we'll leave the rest must -- everything from that point on, in fact, you concluded that, you know, presumed boric acid leakage was coming from the flange, and so you kept doing that.
And then you presume that the accumulation of boric acid crystals on the head was coming from the flange. Therefore, you kept managing the issue, and that prevented you from performing complete inspection.
So I'm saying that to me the lesson learned is that when you have an issue of that kind you do not manage it. You just simply fix the flange leakage so you don't have it anymore. Because otherwise it will have a cascading effect, and your people are going to still live with a limited amount of time to perform the fixing of those flanges, and that cascades in not having enough adequate inspections.
I mean it seems to me that is throughout the root cause. There is that threat that people wanted to do the right job, but they said, "Well, we've reached the time limit. We could only fix this many flanges. So we'll leave this flange for the next outage."
MR. POWERS: Right, and I would say that there's a number of things in the root cause that are beyond the technical root cause that we've discussed thus far, and we're still ongoing with the management root cause issues. We're taking actions at the site as a consequence of that.
MEMBER BONACA: Yeah, and I don't want to get inside that. I'm only -- when I look at that and it says inadequate inspections, I think more than that is what was the cause of that. I mean, in part it was because you really believed that the leakage was coming from somewhere where you thought you knew, and that led you to convincingly believe that you didn't need to inspect further because you knew where it was coming from.
MR. POWERS: Right, and there's elements of problem solving adequacy.
MR. POWERS: How far we drill down, and so we've got a number of things on our list of things to do as part of our 0350 restart.
MEMBER BONACA: Yeah, because inadequate inspection could be interpreted as simply, you know, we didn't look enough or whatever, but really there was this issue fundamentally that we know where it's coming from. We don't have to look further, and therefore, we can manage it. We can keep, you know, from outage to outage, to push further fixing to the next outage.
And that seems like a threat that finally convinced a lot of your people at the working level that that was the solution, and they kept believing it.
CO-CHAIRMAN FORD: If there's no more questions on the root cause aspect, I thank you very much indeed, and thank you for coming.
I'd like to move on for the NRC.
Do you want a break? Okay. Ten minutes. We don't want any accidents. We'll recess until ten minutes past five.
(Whereupon, the foregoing matter went off the record at 4:59 p.m. and went back on the record at 5:11 p.m.)
CO-CHAIRMAN FORD: Okay. Thank you very much, Jim. I appreciate your giving us the time.
MS. WESTON: This is a part of the NRC package, part of it.
MR. GROBE: Okay. We've got three more topics that the staff will present. I'll update you on what we've been doing with respect to regulatory oversight at the Davis-Besse plant.
Ed Hackett is going to be talking about independent lessons learned task force that's been chartered by Bill Travers, and Allen Hiser is going to talk a little bit about management by leakage detection.
I'm sure you're going to have no questions for myself and Ed and about 300 questions for Allen. Are you ready for the next slide, Allen?
Allen is going to flip slides for me.
Just a brief time line of major activities that have occurred. Of course, the pressure vessel had degradation on the 6th of March. The AIT inspection on March 12th, began on March 12th. We issued a confirmatory action letter on the 13th an established the oversight panel on April 29th.
The basis for chartering an 0350 panel for Davis-Besse were fourfold. First, the situation at Davis-Besse represented a significant, complex technical issue and also a complex regulatory issue.
The plant is in an extended shutdown and regulatory hold, in effect, and that's the confirmatory action letter.
The 0350 panel would enhance the agency's focus on clearly defining and communicating the plant specific issues that need to be resolved prior to restart, and we provide as a panel a focused and coordinated oversight.
The next slide is -- please stop me if you have any questions. I'm just going to zip through this -- goals of the panel are several. One of the goals is that the panel provides oversight and assessment of licensee performance. It's a broad and integrated focus on assessment, much more comprehensive than would be applied to a routinely operated plant.
We assure that the restart issues are identified and resolved, and what's critical here is a shared understanding between First Energy, the NRC, and the public on what those issues are needing resolution prior to restart.
We have the capability to coordinate across organizational boundaries within the agency, and of course, Region III, NRR Research, Public Affairs, Congressional Affairs, ACRS. There's been many aspects of the agency that have been involved in the Davis-Besse issue.
Provide a single point of contact, a single focus for communicating with external stakeholders. We've had extensive interface with concerned citizens in the area, concerned groups across the country, federal, state, and local elected officials, and of course, the media.
So it's important to have a single focus and a cohesive message on what's going on at Davis-Besse.
MEMBER LEITCH: John, it's my understanding the 0350 panel goes on through, I guess full power operation.
MR. GROBE: Yeah, I'll get into that in a little bit more detail.
MEMBER LEITCH: But as far as identifying restart issues, other than the obvious replacing the head, is there some kind of a report or a point in time when those restart issues are clearly defined?
MEMBER LEITCH: And what is that point in time?
MR. GROBE: There's two documents that guide the activities of the 0350 panel. One is called process plan. That's been promulgated and issued publicly, and it covers more not plant specific per se, but process issues, including interfaces and communications and activities that need to be accomplished.
The second document is called a restart checklist, and that is the document where those specific issues that need resolution prior to restart will be clearly communicated. A checklist has not been issued yet primarily since the licensee, First Energy, has not completely defined the causal factors in some of the areas, and I'll get into that in a little bit more detail in a minute.
MEMBER ROSEN: What was the first document's name?
MR. GROBE: Process plan.
MEMBER ROSEN: And that is on the Web site?
MR. GROBE: Yes, it us.
CO-CHAIRMAN SIEBER: It's in the inspection manual chapter, 350.
MR. GROBE: Right. There's guidance in the manual chapter, and you interpret the guidance that's in the manual chapter as applied to the specific task. Each plant that might come into an 0350 might have different characteristics required.
MEMBER ROSEN: So if I go to the process plan, I'll see the actual milestone dates for Davis-Besse?
MR. GROBE: No, no. There are no dates.
CO-CHAIRMAN SIEBER: You'll see general format.
MEMBER ROSEN: That's what I was still interested in. Is that what you were asking about, Graham? What the dates were for when we would see --
MEMBER LEITCH: That's what I was asking about. I think I heard that the dates are not yet established.
MR. GROBE: We won't establish --
CO-CHAIRMAN SIEBER: The issues aren't established.
MEMBER LEITCH: But the process plan is not specific to Davis-Besse. It's more or less a checklist of those things that one must consider --
MR. GROBE: Right.
MEMBER LEITCH: -- before moving to restart.
MR. GROBE: We will serve no wine before its time.
MR. GROBE: You won't find dates in our documents. Like I said, we will develop a shared understanding of those issues that we expect to be resolved prior to restart.
When the licensee believes that each of those is ready for evaluation, we will provide inspections of those activities and then address any findings with the licensee.
So there won't be any dates in our restart plan, our process plan.
The panel provides continued oversight after plant restart. Our expectation is that the panel will continue to provide that oversight at Davis-Besse for at least one calendar quarter following restart.
And finally, we create copious amounts of documentation. All of our internal meetings and external meetings are documented, and those are available on the Web site.
We're now going to be transcribing the meetings that occur in Ohio to make sure that people who can't make it to Ohio have access to the specific issues that are discussed.
The panel members include two senior managers, one from Region III, myself, and one from NRR; three supervisors, two from Region III and one from NRR: the NRR project manager; the senior resident inspector; and a risk analyst from my staff in Region III.
So as I said before, it's a very broad oversight. It brings together a variety of different skills from different parts of the agency.
The routine reactor oversight process, what's come to be known as the ROP, is suspended in the situation where you have a plant that goes under 0350. There's a number of reasons for that.
One is that the plant is in a configuration that the reactor oversight process was not written to address.
In addition to that, a variety of the operationally focused performance indicators will atrophy when the plant is shut down. So those PIs will not be providing insight into plant performance.
We talked about the process plan. The process plan will include coordination, communication activities, inspection and assessment activities, licensing activities, and a variety of things. It's about a ten-page document.
The restart checklist has not been issued yet, but that will contain all of the restart items.
We have been averaging about two internal meetings per week, and we had our first public meeting in early May. Our second public meeting at the site, in the vicinity of the site is next Wednesday, a week from today.
The licensee has submitted what they call a return to service plan. That was submitted on May 21st. That's also available on the Web site. There's what they call building blocks. Is that -- yeah, okay. I'm getting nods back there.
Six substantive building blocks that need to be completed to return to service effectively. Three of them are pretty straightforward. Three are a bit more complex.
The reactor head resolution is a fairly straightforward activity, much more straightforward now that the head is being replaced instead of repaired.
Containment extended condition, that includes extensive inspection of the reactor pressure boundary, as well as inspection of other equipment inside containment for damage or the effects of the environment that the equipment was subjected to.
The other one that is pretty straightforward is the last one, restart and post restart test plan. Those are fairly clearly understandable and definable activities.
The remaining three are a bit more complex in defining exactly what is necessary prior to restart, the scope and depth of those activities. The licensee has defined a system health plan where they're going to select risk significant systems and evaluate those at some level of depth to insure that they actually have what they thought they had as far as safety system health.
A program or a process review plan, where they're going to pick at least three programs, I believe: the boric acid management program, of course; the corrective action program; and the design change program, and possibly others that they're going to review at some level of detail.
And the next one is one that has not yet been fully developed yet, and that is the management and human performance excellence plan. There's been, I think, four different activities that have been undertaken to try to get their arms around exactly what went wrong from an organizational effectiveness perspective, a human performance perspective, management effectiveness.
That included a group chartered by INPO, which was senior executives from a number of plants that came in an evaluated what happened; a group chartered by Bob Saunders, the Chief Nuclear Officer, that included review of various activities; the root cause team, of course; and there was one other. It slips my mind at the moment.
But the licensee is now accumulating all of that data and is going to define what it believes are necessary activities prior to restart.
Not only is it difficult to understand the scope of what activities in these areas are necessary, but how to measure success is not an easily defined concept. So those are the areas where we're going to be having some dialogue in our public meetings at the site.
MEMBER APOSTOLAKIS: Do you have any guidance as to what a human performance excellence plan is?
MR. GROBE: No. The way I've approached these kinds of activities in the past is really four steps. First is insuring that we have confidence that the licensee's identification of causal factors is sufficient.
Second, to insure that the scope of what their activities that they're going to undertake -- they define these activities, and we make sure that the scope is sufficient to address the root causes, the causal factors.
We'll provide inspections of their implementation of that plan and then resolve any deficiencies, and there could be a substantial number of deficiencies that we identify that don't need to be resolved prior to restart that can be ongoing activities after restart.
But there is no specific guidance in that area. Clearly there's a number of performance, organizational effectiveness and performance issues that contributed to what happened at Davis-Besse. So we'll be making sure that they identify those to our satisfaction and that they have a plan to assess how they're improving in those areas.
There's three inspections that are ongoing right now: the AIT follow-up. The primary focus of that is taking the results of the AID inspection and putting them into a regulatory framework, what are violations, what aren't violations. There are some technical issues that have come out of the AIT that we'll be forwarding on to headquarters for evaluation.
The head replacement plan we've received from the licensee the process that they're going through and milestones, activities so that we can start scheduling our inspection activities, and the extent of condition inside containment inspection has been initiated.
Those are the activities that I wanted to cover with respect to what we're doing at Davis-Besse today. There were two issues that came up earlier in the day that I wanted to comment on.
One, Dr. Apostolakis, you raised an issue regarding the resident inspector knowledge of the head inspections. The resident's primary focus is on operational safety, day-to-day operational safety, and that encompasses operator performance, equipment operability, maintenance activities, testing activities. It's at least a full-time job for the two residents that are on site.
We're rather protective of distracting their focus off of operational safety. For PWR linguists, you're at risk of losing the bubble if you distract the residents from their operational safety focus.
Members from my staff, particularly several metallurgists, would be the ones who would be going out to the site and observing the head inspections that licensees have undertaken.
The challenge with that is that obviously they're traveling out of the regional office. So they can't be everywhere all the time. We have to depend, as Bill Bateman mentioned earlier, on the veracity of the statements made by the licensee, and we challenge those through phone calls and the residents participate in that, and they have some awareness of what the licensee has been doing.
But I wouldn't expect them to get into detailed evaluation of the head inspections because it would take them away from their principal responsibilities.
MEMBER APOSTOLAKIS: Let's see. I mean, the fact that the containment filters had to be replaced much more frequently than originally anticipated, isn't that something that somebody ought to notice?
MR. GROBE: As soon as that issue came up, I know we in Region III assessed that, and the containment air cooler cleaning and the red monitor filters, and the resident inspectors did that.
And of course, the information notice was issued. So the licensees were also sensitized to that. So we did follow up on those types of indicators and found no problems at the other sites in Region III.
MEMBER APOSTOLAKIS: No, I mean at Davis-Besse.
MR. GROBE: Oh, in retrospect?
MR. GROBE: There were two inspections in the fall of 2001, and the resident inspector had become aware of operational concerns with the -- this is actually a leakage detection system, the RAD monitors, and focused both on the operational performance of that system, as well as the source of the corrosion.
The licensee had committed at that time to do a comprehensive inspection. They did do some evaluation in containment of sources of leakage, but did not identify any and committed at that time to do a comprehensive assessment during the 2000 outage.
I misspoke. It was the fall of '99, and so they committed in the 2000 outage to do a comprehensive evaluation of what might have been leaking in containment. In fact, that's one of the issues that Ed Hackett's group is going to be looking at, is how we followed up on that organizationally; the inspection program, how it addresses issues of that nature.
MEMBER APOSTOLAKIS: One last question.
MR. GROBE: Sure.
MEMBER APOSTOLAKIS: It's really a comment. When we were discussing with the staff the revised oversight process, this committee expressed concern about the safety conscious work environment cross-cutting issue, and the issue that we raised was, you know, how are you going to know that the safety conscious environment is, in fact, acceptable.
And the answer was: we're not going to do much about it because if it is not good, we're going to see it in the hardware. Things will start failing or, you know, doing things.
I wonder now as a result of this experience whether we still believe that that's the case, and do you?
MR. GROBE: Again, that's an issue. I had the distinct pleasure of spending four hours with the lessons learned task force yesterday, and that's an issue that they're going to be asking.
The results of our inspections and PIs and assessments over the last really decade or more of Davis-Besse performance has shown good performance. We do inspect the effectiveness of their corrective action program, and that gets to a certain extent to this safety conscious work environment or safety focus of the folks at the facility, and those inspection results revealed the program was operating effectively.
MEMBER APOSTOLAKIS: So in retrospect then, we have to rethinking that.
MR. GROBE: That's correct. We have to look at what lessons we can learn, and that's why --
MEMBER APOSTOLAKIS: Now, I don't know if you want to make a comment on it, but I believe the problem is that this agency does not have the tools to do that. Now, you may not agree with me, but --
MR. HACKETT: I think I'd add the comment. I think Allen is going to get into this. One of the early themes, if you can call it a theme, in the lessons learned task force is let's look at management of these issues through leakage, basically through leakage management, and obviously in this case, you know, you've eroded margins to the point there is effectively no margin.
And that does go back to what tools are available to do better than that because in several instances now we've gotten to these points by people finding leakage, either NRC or in most cases licensee inspectors, and it's going to challenging the adequacy of that and then how do you do better.
You can do nondestructive examinations, but they're costly. They may not be entirely effective at going after exactly what you're looking for. So I think it does go to development of the tools, and I think that's going to be one of the things to come out of it.
MEMBER LEITCH: I know we don't want to go too far down that road, but that inspection of the corrective action program is not an ongoing inspection. It's module 4500, right, which is done every two years or something like that?
MR. GROBE: It's got a new number today, but, yes, it used to be 4500.
MEMBER LEITCH: Yeah, right, and so someone comes in from the region and looks, I guess, retrospectively at the effectiveness of the corrective action program.
MR. GROBE: The assessment of the corrective action program is in three phases today. The first part is a certain portion of each inspection procedure, each inspector every time they go out whether it's a health physics inspector, an engineer, resident inspector, a certain portion of their time during each inspection is focused on selecting certain activities retrospectively and making sure that those activities were properly resolved. So that's one part.
The second portion is that we just recently changed the periodicity of the major inspections from annually to once every two years. The reason for that was that freed up a number of resources.
It did two things. It gave us more time when we do it once every two years. We added about 25 percent to the duration of that inspection. So it gave us more time and more resources when we actually do go out to get more intrusive.
Secondly, it freed up a number of hours to select certain activities that are ongoing during that two-year time period between inspections and really drill down deeply. The more complex issues that come up, we can go out in a more real time basis and send an inspector out or the resident can do these kinds of inspections.
So it's in those three phases. We have a major team inspection every two years where it's a risk focused selection of quite a few deficiencies that have occurred over the last two years and evaluating how they resolved those; the real time situation between two years where we drill down and every inspector every time they go out samples.
MEMBER BONACA: But it seems to me, following up on this issue, oftentimes we see this concern with inspections, adequacy of inspections, and all of the ROPs focused on performance of safety systems, which are really managed and maintained on line outside of the outage.
And it seems to me that an area of concern would be to look at the outages specifically because there you see the constraints of activity, length of time given to activities that leads to inadequate corrective actions, inadequate inspection, and so on and so forth.
And that really is what is more likely to have a conflict between the need to restart and taking care of business completely. So I know you do have, in fact, your active inspections during outages, but is it -- I think still you have the resident inspector simply there just looking at what's going on, I mean.
Are there any lessons learned there? And should it be stepped up, the focus?
MR. GROBE: I bent the lessons learned task force here on a number of these issues yesterday. In today's environment, competitive environment, outages have been getting shorter and shorter, and outages are frequently less than 20 days now.
It becomes more and more difficult for us to inspect those kinds of activities that are only available during outages. So that's a challenge for us.
We try not to schedule complex inspections during outages because the entire work force of the facility is focused on the outage. So we try not to distract them from that focus.
So it's a challenge, and that's one of the issues that is before the lessons learned task force.
MEMBER BONACA: That's the major trend in the industry performance, has been the shifting towards shorter and shorter and shorter outages, moving out, for example, you know, all of the maintenance equipment, all line, when it's done without the pressure of the outages. So, therefore, you have much higher assurance that the work will be done properly.
And so it seems to me that there would have to be almost like a revisiting of the focus on that outage because that outage becomes critical, and the pressure in on the operators. I mean, I know I've spoken with some of them, and they have told me they feel the pressure from peers, who are really competing with them, and then from their management because if somebody else is doing it shorter and shorter time, why not us?
So, you know, I think certainly that's an area where I understand it's a challenge for you, but you know, one may conceive that you would want to have less focus at large on those activities which you know have been dedicated resources and time like staff under maintenance rule and more conceptive (phonetic) teams maybe, you know, just focusing on outages.
MR. GROBE: One of the things that we've observed as outages have gotten shorter, of course, as you mentioned, some activities have been taken out of outages and put on line, but one of the other things that we've observed is much more complex and effective scheduling and work management activity, which actually improves the quality of work.
There is that additional schedule pressure, and we're sensitive to that, but in fact, we've seen the outages are better managed, and that's one of the ways that the outage schedule has gotten compressed.
MEMBER BONACA: Well, no, I agree. I mean, they can do it. If they haven't done a very strong improvement affecting the way the outages are managed, then there are a lot of things.
However, time pressure is still time pressure. There are going to be some things which are a decision is going to be made that this is not important enough that we have to do it completely or this can be postponed, whatever. It has to be done because time is more limited.
MR. GROBE: And that's, quite frankly, one of the issues that is part of our follow-up activities at the AIT, is looking at those specific questions.
MEMBER ROSEN: I'd like to come away from the discussion of the outage for a minute and come back to your earlier remarks about operational focus, which I absolutely commend. I think that is the right thing for the inspectors to do, but I'm puzzled by that comment and the fact that what was going on at Davis-Besse for perhaps four years or maybe more was an event, an ongoing event, of the degradation of the head which sent a lot of signals, operational signals, the containment atmosphere, coolers, pressure drop, and the need for recurrent cleaning of that.
Just take that for an example.
MR. GROBE: Sure.
MEMBER ROSEN: There's clearly an operational event that your inspectors with their operational focus had to know about and had to draw a conclusion about.
MR. GROBE: In fact, I'm not sure that we had focused on the containment air cooler cleanings. I just don't think it rose to the level of cognizance on the residence staff, and Ed Hackett and the rest of the lessons learned task force team will be out interviewing all of the inspectors, but for my interaction with them, I don't believe that came to our attention.
MEMBER ROSEN: Well, clearly, in hindsight, which is always 20-20, one would say that that was maybe the preeminent signal to inspectors who have an operational focus that there was something amiss.
MR. GROBE: I think that's clearly one of the signals. The other one is the RAD monitors, which was probably more directly connected to what was going on. I believe it was July of '99 that they sent the sample filter out to be analyzed, and it came back that there were corrosion products that were produced in a steam environment.
That was a clear message that there was some leakage going on, primary coolant system leakage, and that did come to the attention of the inspectors through their routine inspections, and they did follow up on it, and it's documented in two reports.
It didn't get above the resident supervisor, and it didn't come to the cognizance of myself or the division reactor projects director.
We asked the right questions, but maybe didn't follow up the way we should have.
CO-CHAIRMAN FORD: I'd like to move on if I may.
MR. GROBE: Sure.
CO-CHAIRMAN FORD: Because this is not a topic that we covered in the letter.
MR. GROBE: There was one other if I could
MR. GROBE: There was one other question that came up, and I just wanted to make sure despite Research's desire to be done with the finite element analysis.
That really is an important activity for two reasons, and I think they kind of came up, but I just wanted to make sure. One of the things that is part of the new program is a new definition of how we communicate significance to the public, and the results of that analysis and the following analysis, which will be the probablistic assessment. That will feed the probablistic assessment and are critical to us in our ability to communicate the significance of this event both internally and to the public.
The second though is we also use the results of that analysis to budget staff, and the more significant the finding, the more staff we put on a project.
And one of the things that I also bent the lessons learned task force's ear yesterday on was, you know, we've shifted to a, quote, risk informed framework. The significance determination process is actually risk driven in this arena. In other areas like health physics and emergency preparedness and security, it's risk informed.
But in the areas where we can do probablistic analysis, it's fairly well risk driven. You heard some analyses both from our Office of Research, as well as the licensee's staff, on burst pressure of the remaining cladding. It will be interesting to see how that's handled within the significance determination process and, when we're done with that, whether that truly reflects the significance of the performance deficiencies.
And that may be an opportunity to reexamine the way we do risk significance and whether there should be some other factors that are considered.
Taking notes, Ed?
MR. HACKETT: In fact, I am.
MR. GROBE: Good. Those were the other issues.
CO-CHAIRMAN SIEBER: So it's going to be green.
MR. GROBE: If you looked at it as a binary gate, you could come to that conclusion, but, in fact, there's probability distributions on all of those things. So even though the burst pressure might be some psi, that doesn't mean it wouldn't fail at a lower pressure.
CO-CHAIRMAN FORD: Ed, thank you very much.
MR. HACKETT: I think like Jack said, Jack had already reached several conclusions for the task group yesterday.
MR. GROBE: If you need any help, just let me know.
MR. HACKETT: I think we're going to get all kinds of help.
I guess given everything that's been discussed here and the situation, it's not surprising that we're talking about a lessons learned task force. The agency has done these before. We don't have criteria for deciding exactly when they might be done.
The last one was done for the Indian Point Unit 2 tube rupture; this one for Davis-Besse reactor vessel head degradation.
I'm the assistant team leader. Art Howell from Region IV, he's the division director, division reactor projects in Region IV -- division reactor safety. I'm sorry.
MEMBER LEITCH: Who is learning the lessons here? In other words, is this an internal --
MEMBER LEITCH: Is it the NRC going to look at Davis-Besse or look at the NRC's performance?
MR. HACKETT: I'll make several comments in that regard. I guess go ahead and put up the next slide here to get into some of that.
The primary focus, as you are indicating, is on the NRC and the NRC's internal processes. It's not limited to that though, however. It's also to look at recommended areas of improvement, both the NRC and the industry.
We also say reactor vessel head degradation. The scope and charter is actually broader than that. I think you can use --
MEMBER APOSTOLAKIS: I'm really confused. If it's broader, why doesn't it say that? Why do you have to say, "But really it is broader"?
It always confuses me.
MR. HACKETT: It was written before I got there.
MR. HACKETT: So I guess the charter --
MEMBER APOSTOLAKIS: Because that was my next question. Why limit yourself to reactor vessel --
MR. HACKETT: That's a good question. It was written this way. I think the charter is publicly available now on the NRC's Web site, and if you go below this basic mission statement, it does say that it is to consider other areas, you know, basically.
Especially in this case, looking at reactor coolant pressure boundary leakage in general, you know, would be more consistent with the charter.
MEMBER APOSTOLAKIS: I would not defense in depth the scope of the task force.
MR. HACKETT: That's a good point, too.
The other point I'll make, since we're literally just kicking this thing off this week, we are looking for public comment, soliciting public comments on the charter. I'll get into the charter here in a few minutes.
So far we have a charter that's been written. That was written before the team was even in place, and the charter is still open to suggestion, comment from the committee, from the public and others.
MEMBER APOSTOLAKIS: Let me understand something. If I go -- I haven't done it; I should do it -- if I go to the NRC Web site and look up reactor oversight process, Davis-Besse, am I going to see greens all over the place?
MR. GROBE: yes.
MR. HACKETT: I believe so.
MEMBER LEITCH: For the last two assessment cycles.
MEMBER APOSTOLAKIS: Okay. So there must be some lessons learned.
MR. HACKETT: I think there will be some.
MEMBER APOSTOLAKIS: There will be some. Okay.
MR. HACKETT: Maybe a couple other things I'll mention up front here in terms of coordination and interfaces. There are other investigations going on that I'm sure the committee is aware of and others are aware of.
The Congress, Energy and Commerce Subcommittee, I believe, has an investigation ongoing. I believe they've been out to the site. They will likely be talking to the NRC, probably to the lessons learned task force, to Jack and 0350, and there are others.
There's Jack's 0350 panel, obviously. The Inspector General, internal to the NRC, is also looking at the NRC decision process leading up specifically to delaying the inspection at Davis-Besse.
So those are going on. Those are going on in parallel with this.
MEMBER APOSTOLAKIS: Would it be appropriate to add safety conscious work environment there?
MR. HACKETT: That is part of what we'll be looking into.
MEMBER APOSTOLAKIS: Of the oversight process, yes.
MR. HACKETT: So yes.
MR. GROBE: They asked me many questions yesterday about the corrective action program inspections and about inspection perform --
MR. GROBE: The task force.
MR. GROBE: Yeah. They were brutal.
CO-CHAIRMAN SIEBER: Well, there's one thing about examining the corrective action program, and that's if the standards are low enough and there's not a questioning attitude. Then there's not much in the program, but everything that's in there probably gets corrected.
And so that's part of it, which the inspection maybe doesn't get to.
MEMBER APOSTOLAKIS: These guys will define questioning attitude every six months. He will come back and say that the definition is this, right?
MR. HACKETT: I wish we had six months.
MEMBER APOSTOLAKIS: We all talk about it, but we don't know what it is really.
CO-CHAIRMAN FORD: Well, the ACRS certainly has it.
CO-CHAIRMAN SIEBER: The question would be what's all of that red stuff coming out of that hole.
MEMBER APOSTOLAKIS: And the answer would be: don't worry about it.
CO-CHAIRMAN SIEBER: That's standard.
MR. HACKETT: We'll come to the schedule in a bit, and I'll wish I had six months, I'm sure. Actually it's mandated to be done in about three months, almost exactly three months from today. So it's an ambitious effort.
The charter elements are listed here as we have them right now. There's really these five pieces with an awful lot of the front end focus is going to be on the reactor oversight process, and I think Jack covered that more than adequately.
In addition to that, regulatory process issues at the NRC, including evaluation of the regulations, licensing review process, regulatory processes, such as the generic communications and the clarity thereof for regulatory process.
An element on research activities. We've heard from the Research Office today, and that's my home base. So there are obvious issues with not just the research. This isn't restricted to the NRC Research Office. This is research activities in general.
Should there have been some things that should have been being done that might have led us to be in a better place to identify this type of thing from a research perspective or to mitigate it more successfully?
So we'll be looking at that type of thing, including research performed external to the NRC.
International practices. I think it's pretty obvious that some of the foreign industry has looked at this issue very differently than the United States did. Most aggressively handled in France, and I think Allen has presented this many times to the committee.
With the initial discovery of Bouget in 1989, they embarked very quickly thereafter on a head replacement program, which, you know, we didn't do after discovery of some axial type indication in maybe like the '97 time frame, general letter 9701.
At any rate, it has been handled differently for some very different reasons, but the lessons learned task force will be looking into that, too.
The generic issue process, there have not been generic issues associated with boric acid corrosion or much involved with corrosion in general. That will be one of the topics.
Should there have been? Should there be now? Should this process somehow be better tuned to picking these kind of things up? Because that type of thing has not happened.
So at least those five elements are there. One of the things I'll mention right now is the EDO feels strongly about soliciting input on this charter. So I'd be glad to take input that anyone might have.
MEMBER APOSTOLAKIS: Yeah, are we going to see you before you publish your results?
MR. HACKETT: Well, I guess that's probably largely up to you guys. We're going to be plenty busy enough. So I guess I didn't come here, especially from Art's perspective, to be volunteering too many presentations over the three-month period.
I would think what I'll come to in some of the subsequent slides here is that we have a period where we're basically in a preparation phase right now. We've literally just assembled a team this week.
The review phase really starts at the end of June and should complete more like the end of July, and by then there will probably be -- there will be a developing story, obviously, along the way, but by then there would be something to tell, and we would be in the mode of trying to integrate it and writing the report at that point.
So that might be a point to talk some more about. It will be briefing. Obviously internally we report directly to the Deputy EDO, Bill Kane, and to the EDO, Bill Travers. They'll be receiving at least weekly briefs on the progress of the task force.
And if the committee would like to hear, you know, an update --
MEMBER APOSTOLAKIS: I think we need to discuss that in private.
MR. HACKETT: That's something we'll take as an action.
MEMBER ROSEN: We have a discussion of the schedule for this weekend.
MEMBER APOSTOLAKIS: No, but this is something new.
MEMBER ROSEN: Right, but I think we can take this up.
MEMBER ROSEN: I'm saying on Saturday.
MEMBER WALLIS: This second bullet, does that include looking at how we might view risk informed regulation as a result of what we've learned?
MR. HACKETT: I think that's fair. That one is fairly broad in terms of regulatory process. Certainly the NRC processes have been focused at performance based risk informing for a number of years now. So I think that's fair game under that element.
MEMBER WALLIS: This kind of event isn't in the PRA, I understand, or is it?
MR. HACKETT: I don't --
MEMBER WALLIS: There's no analysis of --
MR. HACKETT: This specific event I don't believe would have been anticipated to be in a PRA. I would think the -- I'll defer to Steve or others to answer that more definitively.
I think what is or what has been evaluated, I know, is the LOCA that would result from multiple rod ejection has been, and that was shown in terms of the LOCA situation to be bounded by the hot leg break.
MEMBER ROSEN: PRAs typically don't address passive components. The head of the vessel is a passive component. So it wouldn't show up as the component.
MEMBER WALLIS: Passive component about to become active.
MEMBER ROSEN: That's been fairly accurate.
MEMBER KRESS: LOCAs are all passive.
MR. LONG: This is Steve Long with NRR staff.
The PRAs typically address initiating events that would be failure as a passive component to pipe break or whatever. So there's a medium LOCA frequency. There's a small LOCA frequency, except for special initiators where you have postulated a mechanism and gone in and analyzed the failures that lead to that mechanism, such as an interface systems LOCA or something, you really just lump everything that might create a hole of this size into an initiating event frequency.
MEMBER APOSTOLAKIS: We had recommended when we reviewed Athena that the project look at the possibility of having an initiating event due to human actions during normal operations.
You know, so before you go to the PRA, you have to do all this. Athena has to take care of it, and then eventually, of course.
But you're right. Right now it doesn't have it, but these are -- I think the problem is broader. I think there has been reluctance to get into organizational issues, you know, for a number of reasons for the last several years, and these naturally involve organizational issues, I mean, however you want to --
MEMBER WALLIS: You can fall back on Defense in--
MEMBER APOSTOLAKIS: Well, that's what I'm going to do, the structuralist approach. What if you're wrong?
MR. HACKETT: I think you're --
MEMBER APOSTOLAKIS: Well, there has to be a way out of it, Steve. Either we have to understand it or we put Defense in Depth, right? That's what Defense in Depth does. It helps you when you don't understand.
CO-CHAIRMAN FORD: I'd like us to move on if we may.
MR. HACKETT: We're fortunate that the EDO has been kind to us, and I should say Mr. Collins also, in terms of putting this team together. Art Howell is a highly capable individual. He's leading the team from Region IV.
I was assigned as his assistant leader, and we have a very capable team here that's distributed among both the headquarters operation and the regions.
In addition, we're going to have --
MEMBER APOSTOLAKIS: Have come you have -- well, I don't recognize anyone there who's an expert at human performance. Shouldn't there be someone?
MR. HACKETT: You know, the team is literally so new. I have to say I believe that Ron Lloyd has some experience in that area, and possibly Tom Koshy (phonetic), although I could take that as an action and get back to you on it.
MEMBER APOSTOLAKIS: When we had the Athena presentations, there were usually four or five guys sitting where you are sitting now. Maybe one of them should be involved in this. It would help you draw some conclusions that perhaps otherwise you wouldn't draw.
MR. HACKETT: Yeah, we have the ability to draw pretty much from what we need on the NRC staff, you know, with the --
MEMBER APOSTOLAKIS: See, my concern is, again, that maybe we would focus on the technical part, the hard science part, when, in fact, the failures were not there.
MEMBER ROSEN: I think the management, George, of this lessons learned task force, Art, Hal, and Ed, have enough experience to understand the organizational and management factors to deal with the issues that I think you're referring to.
MR. HACKETT: I think, in fact, the focus is much more initially on the -- well, the charter elements, what we're calling charter elements A and B on the reactor oversight process issues and the regulatory process issues, I think, in fact, the focus is going to be largely there.
The other three elements are important, but if I had to weight these, I think the first two are the most important, and that's going to be the primary focus of the task group for sure.
Anyway, we're fortunate to have this. We're also fortunate to have been given the physically separate space on the 16th floor.
MR. GROBE: Just one other thing on the structure of the folks that are on the committee that's important is that the committee is completely independent of anybody in Region III or anybody in NRR that was involved in these activities. So it's going to be a fresh look.
MR. HACKETT: In terms of how things are going to progress, I just briefly mentioned schedule previously. We're in this preparation phase right now which really extends to the end of June effectively. That's, you know, running from some mundane things like getting people set up in offices to actually starting to conduct some interviews with NRC staff and managers and, starting next week, discussions with plant personnel at the site and also with the region.
Jack mentioned earlier there's a trip out to the site vicinity next week that several of us will be going on. I'll mention some more about that in a minute.
The expectation from the EDO is that we're going to complete this activity in September of this year. That's the marching orders right now. Obviously things could be subject to change. If any new information comes to bear that would bear on the schedule, in particular, but that's where we're heading right now.
And then I'll just end with current status. I'm sorry. This is sort of where we are as of today. We just literally this morning completed two and a half days worth of team orientation briefings. The team, the nine folks that I had up there on the slide are physically here at NRC headquarters from the regions and from the headquarters functions.
And we're all assembled in one place on the 16th floor in One White Flint.
Team orientation briefings they said are completed. We are having -- Jack is having the 0350 panel meeting next week at the site vicinity. We are having what Art has been calling a public entrance in the site vicinity right after that. I believe it's late morning
MR. GROBE: It's actually before.
MR. HACKETT: Before?
MR. GROBE: Yeah.
MR. HACKETT: It's like ten o'clock in the morning, I believe.
MEMBER APOSTOLAKIS: So what is a public entrance?
MR. HACKETT: Basically it's really part of the communications plan for the task force, is to get out to the site vicinity and let people know that we're doing this and sort of what the expectations are going in to do that particularly in the site vicinity.
One that I didn't put on the slide is that we are working right now on also having a public meeting probably the week of June 17th where we'll be sort of rolling that charter, duplicating that same kind of meeting here at headquarters and soliciting input from anyone who's interested in providing some at that point.
Art, in particular, has been on this longer than the rest of the team. There have been a lot of interviews with key NRC managers who have been involved in this, and many more are going to be in progress.
And right now the team, in fact, just this afternoon is working on detailed review plans for the separate activities that we'll be doing. So that's where we are at the minute.
I'm especially glad to take any inputs on the charter or any thoughts the committee might have are welcome at any time.
CO-CHAIRMAN FORD: Thank you very much.
MR. HACKETT: Thanks.
MR. HISER: I guess what I'd like to do is take a tack that is maybe a little bit unusual for ACRS, a little bit of a philosophical twist to things.
MR. HISER: I know you guys don't like to do that.
CO-CHAIRMAN FORD: In the course of an hour.
MR. HISER: You guys don't like to do that. Very short; three slides.
We talked quite a bit earlier this morning about use of leakage detection. I just wanted to go over some ideas that we have. We don't have any real firm ideas at this point, in all honesty. We're still gathering information.
We do have maybe some ideas starting to gel in terms of the philosophy of how leak detection can fit in.
Clearly, first of all, before you determine what the appropriate inspection methods and frequencies, what the inspection program should be, you have to understand what it is you're trying to manage from the standpoint of where we were almost a year ago.
When we were discussing Bulletin 2001-01, the focus was really the safety concern of nozzle ejection. With the recent findings at Davis-Besse, that as we discussed early this morning has really raised the bar a little bit to where leakage may be the thing that we're really most concerned about.
And I guess the one thing that I want to impress upon the ACRS is it's not just the nozzle base material that's of concern. Cracking has occurred in the nozzle base material. It has occurred in the weld material. It has occurred at the interface of the weld and the base material. It has occurred at the interface of the butter (phonetic) and the vessel head. So pretty much all components of this structure are at issue here.
CO-CHAIRMAN SIEBER: And none of it is allowed by the code.
MR. HISER: None of it is allowed. That's exactly correct.
But also, how can we effectively manage each of those parts is really another key part to this. That's dependent on the state of the art, of the inspections, and tooling and the availability of those.
CO-CHAIRMAN SIEBER: It seems to me that if you're inspecting visually for leakage, then you've already passed the threshold in which you're in violation of the code, and it seems to me that if you have a susceptible plant, you ought to do volumetric and work for the 70 percent crack and fix it.
MEMBER APOSTOLAKIS: I think the leakage part is part of managing the accident and preventing it from becoming an accident, right?
CO-CHAIRMAN SIEBER: Well, part of it is compliance with the code.
MEMBER APOSTOLAKIS: Isn't that what it is?
CO-CHAIRMAN SIEBER: That's an NRC requirement. It's a state requirement, insurance company requirement.
MR. HISER: Well, I think it's a good lead into the next bullet.
MEMBER SHACK: Well, before you --
CO-CHAIRMAN FORD: Before you go, you skipped that one. Surely there should be, as Jack says, there's a code that says, "Thou shalt not have a crack."
CO-CHAIRMAN FORD: Well, I meant a deep crack.
MEMBER ROSEN: Peter, we have a member of the public who wants to make a comment.
MR. LASHLEY: This is Michael Lashley, South Texas.
And I didn't bring the code book with me, but that's probably not a perfectly accurate statement. The code allows evaluations and has certain acceptance criteria. Cracking has acceptance criteria throughout the code. It's not precluded, and in certain instances, specifically an example is buried pipe, it will clearly say you can live with that as long as it's within your operational boundaries.
So it's known in the code that cracking is not a totally tabu thing. You do have to do other measures and have other compensatory actions.
CO-CHAIRMAN SIEBER: But the reactor coolant system pressure boundary is an exception to that.
MR. LASHLEY: Well, that's the tech spec issue. The tech spec will say.
CO-CHAIRMAN SIEBER: It's a code issue.
MEMBER BONACA: We do not wait until you have leakage in the tubes. I mean, you go in and inspect, and you're looking at certain criteria. Now, you may have leakage, but by the time you restart the plant you're not supposed to have any leakage in the tube.
MEMBER SHACK: But here they don't allow operation with through wall cracks, which is analogous to the steam generator case. I mean, you don't allow operation with known through wall cracks.
MEMBER BONACA: But you're waiting for leakage to detect. What I mean is in the tubes you go in, inspect, you do sampling, but you inspect and plug if your through wall is beyond certain criteria.
MR. GROBE: I think there are two issues on the table. One is having a leak, a through wall crack. You're clearly not permitted to operate with a through wall crack.
But it's not uncommon to have very shallow cracks identified during IS activities and have those be analyzed that it's safe to operate for another outage, another cycle, and oftentimes that's exercised, and the licensee prepares for whatever repair or replacement activities they'll do.
CO-CHAIRMAN FORD: But, Jack, surely it is up to a certain point.
MR. GROBE: That's right. That's right.
CO-CHAIRMAN FORD: You can't wait until there's a through wall crack.
MR. GROBE: Absolutely.
CO-CHAIRMAN FORD: The code doesn't allow that.
So that comes back to Jack's point. Should there not be a third sub-bullet on the second bullet? There's a limit to the amount of cracking, non-through wall, that you can have.
MR. HISER: Yeah, I think that's correct. The purpose of these bullets was really to look to the point of, you know, leakage and deposits. What is allowed within the tech specs and the ASME code, and how does this fit? How does use of visual examinations fit within this context?
MEMBER WALLIS: Right, yes.
CO-CHAIRMAN SIEBER: Well, the way you wrote that tells me that you should look at the code, and it tells me how far you can go, what you have to do in your tech spec.
MR. RICCARDELLA: Peter Riccardella from Structural Integrity Associates.
You know, we're not talking about operating with known leakage here. If we find the leakage, we fix it. We're talking about operating with some non-zero probability of a leak, and the code doesn't prohibit that, and we do that in the primary coolant system all over the place.
We operate with some non-zero probability of having a crack or of having a leak, and you know, that's the issue that I think we have to have addressed. What is the acceptable probability that we could live with, not that we operate with leaks?
MEMBER BONACA: But you do IS in the vessel, right?
CO-CHAIRMAN SIEBER: And piping and everyplace else.
MEMBER BONACA: In piping, in volumetric inspections, and so on and so forth, and here we're talking until now we just do visual. So with visual it means we're waiting until we see leakage to determine that we're going to now repair it.
CO-CHAIRMAN SIEBER: Are you going to leak? That's right.
MR. RICCARDELLA: But you know, IS of small bore piping we do visual, and you know, we accept the fact that, for example, socket welds and small bore piping, we have a finite probability of leakage that occurs from time to time.
MR. RICCARDELLA: In the primary coolant system.
MR. HISER: Yeah. I think the one context that the staff would come at this from is the expectation previously was that these components wouldn't fail. You wouldn't get leakage, and so maybe leakage was an appropriate method to manage for that unlikely event.
Now, given the incidences that have been identified, you know, we need to take another look at it. That's all we're trying to do here, is just to lay out some of the basis for this.
CO-CHAIRMAN SIEBER: Maybe I can add additional confusion. I already wrote my comments, and I --
CO-CHAIRMAN SIEBER: -- and I'm just waiting for you to say them.
MEMBER ROSEN: Well, Jack, do you want some more input first? We've got another --
CO-CHAIRMAN SIEBER: Well, let me finish. I have the floor right now. Okay?
It seems to me that the susceptibility ranking curves, if they're done right, could be a process where you decide what kind of inspection and examination you need to do.
For example, a plant where the probability of actually having cracks is pretty low. Maybe visual is good enough. On the other hand, if you're in the hard runner list, you know, the most susceptible plant list, maybe volumetric is a better deal, particularly if you can calculate, which I think that we're all trying to do, how fast these cracks will grow, and that's basically what you do with steam generator examinations.
You're trying to predict can I run another cycle without losing a tube, and I think there's some value in thinking about that kind of an approach.
I would be happier if one of two things. One of them is that the database that was used to come up with the susceptibility ranking also included information about heats or, on the other hand, I think that whoever has a leak that appears to come from a susceptible heat of material, write a Part 21 so that everybody knows that here's additional susceptibility, and they can do something about it.
So that would be my thought process as to how I would deal with these issues you've put up here, for what it's worth, and if I get ten other people to agree with me, we can do it right.
MR. LASHLEY: Let me make one other comment. We talked about code and we talked about regulation. I'm going to read Criterion 14 out of the general design criteria, which is for the reactor coolant pressure boundary.
"It is the reactor coolant pressure boundary shall be designed, fabricated, erected, and tested so as to have an extremely low probability of abnormal leakage of rapidly propagating failure and of gross rupture."
The code follows that same structural integrity process. It doesn't preclude crackage or through wall leakage outright.
MEMBER APOSTOLAKIS: So don't you think though that having a through wall crack and leakage is inconsistent with the requirement of an extremely low probability?
MR. LASHLEY: If you accepted it and just gross leakage --
CO-CHAIRMAN SIEBER: Step to the microphone and identify yourself, please.
MR. LASHLEY: Your point is well taken if you lived with it and didn't fix it or didn't do an evaluation to show it's not a structural integrity issue.
MEMBER APOSTOLAKIS: Oh, yeah, sure. We're not talking about shooting anybody. I mean fixing it. I think we --
CO-CHAIRMAN SIEBER: And when you talk in general terms --
MEMBER APOSTOLAKIS: Can we go to the last bullet? I'm dying to see what they have to say.
MEMBER BONACA: You guys keep talking.
CO-CHAIRMAN SIEBER: Let me say one other thing. EDC-14 really is looking at the reactor coolant system pressure boundary as a whole where there are some flange gasketed joints, mechanical joints like spores (phonetic) and safety valves and things like that, some of which leak, and so you just can't have an absolute prohibition against leakage because some things just leak. Seals leak; inner system leaks occur.
MEMBER BONACA: But remember those flange leaking in my judgment, they were a measured contribution to this event because there were a fixed--
CO-CHAIRMAN SIEBER: Well, it masked the problem.
MEMBER BONACA: They masked the whole issue, and they -- so, you know, one could even say the codes are not perfect.
CO-CHAIRMAN SIEBER: Well, I think there's a difference between leakage at some mechanical joint and leakage because of a defective wall.
MR. HISER: Ongoing degradation does tend to cause problems.
MR. HISER: Right. Now, within the overall context of safety of these components we have robust designs to minimize failures. We have quality fabrication practices and inspections to insure that we have quality components.
The role of leak detection may be at a minimum Defense in Depth. If one had inspection requirements that were more intensive, say, NDE, something like that, there still may be a role for leak detection just in case something happens different from what we expected, more rapidly than was expected. But it could be used as a Defense in Depth approach to management.
MEMBER APOSTOLAKIS: So Defense in Depth now means that I have a redundant or diverse barrier to something, right?
MEMBER KRESS: Not necessarily.
MEMBER APOSTOLAKIS: No? The Commission says it's the use of multiple barriers? That's what the Commission said.
CO-CHAIRMAN SIEBER: You could use alternate techniques, too.
MEMBER BONACA: Alternate techniques or back-ups or trains, for example.
MR. HISER: Say again.
MEMBER BONACA: Redundant trains, for example, would provide you further Defense in Depth. I mean it doesn't have to be necessarily a passive barrier. That's only for the barrier portion
MR. GROBE: And there are three barriers. There's the fuel, primary pressure boundary, and containment.
MEMBER APOSTOLAKIS: So anything that reduces the probability is Defense in Depth measurable?
MEMBER BONACA: Well, I mean, it measures -- it's a broad definition.
CO-CHAIRMAN SIEBER: Sure. That's philosophical, but it sounds okay.
MEMBER APOSTOLAKIS: Well, the Commission said the use of multiple barriers, and that's what it is.
MEMBER BONACA: No, in the protection of those barriers.
MEMBER KRESS: They didn't mention the barriers in the white table paper at all. They said multiple -- I forget the words, but it wasn't barriers.
MEMBER KRESS: Multiple measures to address incidents.
MEMBER APOSTOLAKIS: So this is a Defense in Depth measure against which event? What are we talking about here? Defense in Depth against what?
MR. HISER: Nozzle ejection, a redundant way of identifying the degradation that could be ongoing.
MEMBER APOSTOLAKIS: I'm sure it is, yeah. That's what it is, yeah.
MR. HISER: Now, the industry will present their proposed inspection plan following this.
MEMBER ROSEN: Some time after midnight.
MR. HISER: Sometime today. We started ten hours ago. So we'll push it along here.
We did have a meeting with them about two weeks ago where they presented this to us. Just to pull out some of the characteristics of this plan, one is it does not consider explicitly the vessel head degradation experience at Davis-Besse.
The technical basis is still in progress. There is no report that's available at the present time. For moderate susceptibility plants within the plan there can be a reliance on bare metal visual examinations.
The report explicitly is limited to Alloy 600 heads with 82-182 weld metal, and again, explicitly assumed a robust generic letter 8805 program that is effectively implemented. And clearly, with the recent experience we've had those are some pretty good assumptions.
I think some of the comments that the staff presented at that meeting and that we will be transmitting to the MRP first is that the relevant visual conditions that require follow-up examination do require better definition. Right now it just describes relevant conditions.
Clearly, inspection methods and frequencies that they propose for the various populations of plants requires a robust technical basis, and that's still something that's being worked on.
The discussion of NDE, we thought that the capability and recent experience with inspection methods and the developments that are ongoing, we thought that should be provided somewhere in the inspection plan. The technology has improved significantly over the last year, and hopefully that progress will continue.
As I mentioned before, right now our examinations of the J-groove welds and some of the interfaces with the nozzle and with the vessel head are not real detectable using the current ultrasonic methods. So that's something that requires some work.
Another thing that isn't clear within the plan is how it's benchmarked. Clearly we know when leakage was identified at plants. We know when circumferential cracks have been identified, but it's not obvious that the thing is benchmarked to when the leakage first occurred, when the first through wall cracking occurred, but it appears to be based on discovery of the conditions as opposed to benchmarking to the onset of the unacceptable conditions.
There have been some questions on the appropriateness of the application of Reg. Guide 1.174 within the plan.
And finally, there is a provision in there to delay scope expansion to the next refueling outage, and that's something we think requires significant technical basis.
MEMBER APOSTOLAKIS: We're going to talk about this application of 1174 at some point? I don't understand. Why is it relevant here?
MEMBER SHACK: One times ten to the minus three probable failure, conditional probability --
MEMBER APOSTOLAKIS: Are we changing anything on the licensing basis? And we're seeing whether it is risk significant? Is that what we're doing?
MEMBER SHACK: It says, yeah.
MEMBER APOSTOLAKIS: We're changing the licensing basis?
MEMBER SHACK: Well, no. We use that to evaluate changes in risk in a more global sense.
MEMBER APOSTOLAKIS: Well, presumably as a result of the inspection of plant, the change is negative.
MR. HACKETT: Well, no, the inspection plant admits some possibility of an increase in risk. Otherwise you'd inspect more frequently.
MEMBER APOSTOLAKIS: Increase from what? From the previous state? See, I don't understand the definition. Is there a change here that is permanent that is increasing risk?
MR. MATHEWS: I would say that they're evaluating the increase in risk from this phenomenon that we didn't know about when we originally assessed the risk from the plant, and this is a change because now, oh, well, we could have the rod ejection here that we didn't evaluate when we looked at the whole thing to start with. What is the impact of that, and what is the change in risk to the public?
And what we're trying to evaluate is what is that change, and ten to the minus six is a ballpark number that we were trying to say, you know, it would be okay if I came in and did something to my plant and said, well, that's less than a ten to the minus six change in the risk if I do this.
MEMBER APOSTOLAKIS: Are you doing a regulatory analysis now?
MEMBER APOSTOLAKIS: Whether it's worth backfitting. Is that what you're doing?
MEMBER APOSTOLAKIS: So Regulatory Guide 1174 can be used to evaluate the impact of previously unknown phenomena?
MEMBER BONACA: As a change, assume it is a change with respect to what was known.
MEMBER ROSEN: No, I think the question that the staff is asking is is this an appropriate application of Reg. Guide 1.174. We haven't even heard what the application is. The representative from the industry hasn't been given a chance to tell us yet.
MR. HISER: And hopefully he will describe that; is that right, Mike?
MR. LASHLEY: I'll give it my best shot.
CO-CHAIRMAN FORD: Could I understand the timing of this? Obviously the industry have come to you with a proposal. You're looking at it. What is the timing on the resolution of these various issues?
MR. HISER: If I can get to the last slide and --
MR. HISER: -- you still have that question when I'm done, then I have failed.
We do have ongoing activities, and we have some areas of concern in general. First of all, relative to Davis-Besse, the degradation mechanisms and rates as described in the root cause analysis report don't have a lot of physical evidence from Davis-Besse.
What we're looking to do is for them to back that up with work on the cavity at Lynchburg and also hopefully some laboratory demonstrations that will give us some confidence and reduce the uncertainty of the mechanisms and the rates of those mechanisms.
CO-CHAIRMAN FORD: When you say "mechanisms," you don't mean mechanisms the way I understand mechanisms. You understand the degradation process by which things happen, but you don't know the mechanism and you can't predict it. You don't know whether it's a generic issue or whether it's a one off issue.
MR. HISER: Right.
CO-CHAIRMAN FORD: And if it's a generic issue, when is the next one going to be? You know it's not a major thing out there right now based on what's come out of Bulletin 202, whatever the number is, 01, but you sure as heck don't know what the situation would be in, say, a year's time.
MR. HISER: Right, and that's what we want to do is have the comfort of being able to predict how things will occur.
CO-CHAIRMAN FORD: And that's what these guys are going to do urgently.
MR. HISER: Well, hopefully in order to reduce uncertainty we need these things to occur. You know, otherwise the inspections are going to have to assume worse case kind of conditions.
MR. HISER: In order to back off of that, you know, with the necessary conservative assumptions we need to have a greater understanding.
MR. HISER: As we discussed, the industry proposal does need a sufficient technical basis, and I think that will come over time. The staff is considering a generic communication with Bulletin 2001-01 and 2002-01. We provided sort of a one cycle approach to inspections, and that was sufficient. It gave us the data that we needed to be able to go forward.
We're still not able to go forward. We're still not in a position to lay out any long-term criteria. So this is a generic communication that will probably be a bridge from the first two bulletins to what I would call the more permanent requirements that would go in the ASME code or in 10 CFR, Part 50.
We are working with the staff to develop a technical basis for these longer term inspection requirements. We don't have that ready now. I mean, that's going to take time. I think within our action plan that's targeted for later this year. That may be overly optimistic at this point.
And to put another idea on the table, I think that we believe that the Davis-Besse experience has raised the bar, that the level or the type of cracking that is I don't say acceptable, but that you really have to guard against has changed from circumferential cracking a year ago to now even axial through wall cracking. That's really the emphasis that we have at this point, is trying to preclude through wall axial cracking.
CO-CHAIRMAN FORD: But to come back to my question, when are all of these issues going to be resolved?
MR. HISER: Hopefully around the end of the year or some sort of time frame like that is what we have worked out with the industry.
CO-CHAIRMAN FORD: This is very important. I mean if you're starting to just do away with volumetrics and won't go through any of these kind of studied process of when you use volumetric versus visual and you just go to visual because it's an easy thing to do, it's major, major assumptions.
MR. HISER: I would expect that as I stated the generic communication will have conservative assumptions. Until we have a firm understanding of things, such as Davis-Besse, we will not take potentially non-conservative assumptions.
MR. HISER: From the standpoint of visual detection and visual inspections, I think things will be different than what was laid out in Bulletin 2001-01 significantly.
CO-CHAIRMAN FORD: We will hear about that before it becomes a done deal?
MR. BATEMAN: I'm not sure about that. I think we're moving pretty quickly with trying to get some generic correspondence out.
I think you can take some comfort from the fact that you're going to hear what the industry's proposal is, but I think our proposal at this point in draft stage is it's going to be more rigorous than what you're going to hear from industry. I think as Allen said, I think it will be a bridge. It will probably be more conservative than what we may ultimately end up with, but we have to do something. We can't wait until we're through with all of this, Dr. Ford.
I mean, if we're talking about rule making, if we're talking about getting something in the ASME code, that al takes time.
CO-CHAIRMAN FORD: But let's see what the industry have got to say.
MR. BATEMAN: Yeah, I think that's the best bet.
MEMBER APOSTOLAKIS: This is the last presentation. This must be an important issue. Are you guys going to do this quickly?
MS. KING: We'll do this as quickly as you would like.
(Pause in proceedings.)
MS. KING: The slides for this are the las part of our original packet. And in the interest of time, we won't be covering every individual slide that you have.
MS. WESTON: Starting at slide number 102 for the MRP part of the presentation, yes.
MS. WESTON: The numbers are right beside ACRS 6502 and then there's a number.
MEMBER APOSTOLAKIS: Or it's four pages from the end. Go to the end and count four pages back.
MS. KING: Okay. Peter, one thing I wanted to comment on is we have been meeting with the staff fairly frequently, and we plan on continuing that frequency of meeting with them on a technical level as we develop our research to get comments, and to incorporate that in so that we don't just shop up with the final answer.
MR. LASHLEY: My name is Michael Lashley. I'm from South Texas Project.
And the first slide that we have here basically just says, yes, we met with the NRC staff. We heard their comments, and we're actively dispositioning those comments.
One other aspect of this just to give you real briefly where I'm coming from, I also have the action within code space to bring these rules forward and try to write some rules in Section 11. So myself, and I know a member of the NRC staff, Wally Norris, is on that team. So we are trying to work together.
So we are trying to actively work it to a permanent solution.
Let me digress off of these slides real quick and show you one other slide that maybe bridges the gap to what we were talking about, and you saw it in Pete Riccardella's, but we have another line drawn in here that may not be obviously, but it does speak to the Reg. Guide 174.
This slide kind of does that and also one other one. From this one, you saw everything on this slide except this one purple curve right here. That curve represents a one percent probability of leakage.
So you see there is a big grouping of plants in that far left-hand corner with low head temperatures that are under one percent.
MEMBER WALLIS: One percent per year?
MR. LASHLEY: Probability of having that first leaker.
MEMBER APOSTOLAKIS: But can you explain the figure first?
MR. LASHLEY: This is the one that Pete discussed. Was that yesterday? Earlier this afternoon, and this has on the left-hand side the cumulative effective full power years. The red chain link that has over it the -- which color? I'm not sure. That's kind of green. The upper one is one times ten to the minus third, which approximately equals the 75 percent probability of leakage.
The moderate dividing line is the one times ten to the minus fourth or 20 percent probability of leakage. So that's how we've categorized or just used that reg. guide as a dividing line.
And then we divine an inspection program. Our attempt was to keep us under the ten to the minus six change, to come up with an inspection program.
Now, recognize that one of the punch lines at the very end is we still have inspection activities for this grouping in the lower left-hand corner that's under one percent. That's at least to go after the unknown, which does speak to defense in depth and speaks to some other issues that were brought up.
So I just wanted to show that. We'll come back to it if there's other question because this kind of tells a lot of the story.
CO-CHAIRMAN FORD: So this essentially is you will be addressing the thing that Jack brought up about the low susceptibility plants do visuals.
MR. LASHLEY: Yes. So we still have those elements in here. Now, at certain times Al brought up wastage, and it's really the time line for wastage is a different issue, and that's what wasn't explicitly addressed in our program, in our plan.
We had assumed right off the bat that generic letter 8805, it's in effect. It is a good rule. You go read it, and it tells you exactly what to do. If you implement it, and you all talked about this earlier; if it's implemented, there will be no questions, but there's a desire to package this together so that there's no ambiguity and you can see some of -- we have the ability to bring lessons learned, bring pictures, bring training, bring a lot of things to bear in one central document. So we're taking that feedback.
And the purpose, I mean, as we say, we assume the generic letter 8805, but we also came up with a graduated approach for early detection, to start with low risk, require something, require it repetitively, and then, you know, raise the bar continuously as we move to higher and higher levels of risk.
We also believe they're very conservative for just structural integrity or the safety issue of a rod ejection or a nozzle ejection.
This is where we start skipping a few because those have already been gone through, but we took the technical bases. We say that the staff did not have the papers. They were presented, and Pete presented basically the elements of it again today.
There was another technical paper that was presented by Glenn White today that's a part of this bases, and Steve Hunt has another one.
One that we really haven't gone through is EPRI's visual guideline also, but we bring together all of this probablistic fracture analysis, and we did sensitivity studies to bound them to try to come up with correct inspections and correct frequencies for the different ones to bring that to bear, and we--
MEMBER APOSTOLAKIS: Can you explain something to me? I'm missing something here. Maybe it's me. This is a standard technical approach, you know, in an inspection using PFM, Monte Carlo, and so on.
Then I go and I read the letter that transmits the AIT report. The first thing they say is the boric acid corrosion control program at the site included both cleaning and inspection requirements, but was not effectively implemented to protect leakage and prevent a significant corrosion of the reactor vessel head over a period of years.
And I'm sitting here trying to figure out how is this program addressing this problem.
MR. LASHLEY: And staff brought that point up, but what you can see from that other figure, that one again --
MR. LASHLEY: -- a lot of plants have done -- well, the other 68 plants have done inspections and generally said wastage isn't an issue at my plant.
MEMBER APOSTOLAKIS: Yeah, but if there is one plant --
MR. LASHLEY: Oh, I understand.
MEMBER APOSTOLAKIS: -- where this will not be implemented, as these guys are saying, was not effectively implemented, then the whole thing again fails. So is this --
MS. KING: Well, there are industry activities that have been undertaken to evaluate the implementation of generic letter 8805. We have scheduled a -- EPRI has undertaken a conference to bring together the people that do the boric acid walk-downs in the plant to talk about best practices, and INPO will be participating in that conference as well.
MEMBER APOSTOLAKIS: Shouldn't that be an integral part of this inspection thing?
MS. KING: Well, as was stated in the purpose of this plan, and as the comment we received from the staff, when we initially wrote this plan, we were depending upon an effective implementation of the 8805 program.
As Michael stated, the words are good. It's a good rule, but we do understand that we need to potentially -- we are working to look at the implementation and best practices of an 8805 program.
MR. LASHLEY: And just to tag onto that, with boric acid, EPRI's guideline for how to do this was revised just as of November 2001. So we're going to bring all of these things back to bear at a workshop this summer, and we're going to take the feedback we receive from the staff, and those actions are underway.
I'm the chairman of an ad hoc team under this group to try to do that, and we're still working through that, and our time line is real tight. We would like to bring something back through our committees by the end of next week.
MEMBER BONACA: You showed us a curve before, and you show a bunch of plants below that purple line.
MEMBER BONACA: The lower purple line, and you said for those visual inspections are justified, something of that type. What about the other plants? What are you proposing to do for the more successful plants?
MR. LASHLEY: It is the last page of your handout. There's a flow chart, and we're going to get there.
MEMBER BONACA: We are going to get there. Okay. So then we will just --
MR. LASHLEY: And like I said, we weren't going to go through all of our different slides, but we'll just start doing it.
Modern susceptibility we already mentioned there was a 20 percent curve and ten to the minus fourth or ten to the minus seventh cumulatively.
High susceptibility was using that for ten to the minus third or 75th percentile, and that's what we meant by the Reg. Guide 174, keeping the probability under or the change of probability under a cumulative ten to the minus sixth, which by reg. guide standards, if you do that and a few other things, that is a risk informed or meets the basis for a risk informed --
MEMBER APOSTOLAKIS: I have another question. My problem is what is the change. This is a new, novel application of 1174.
MR. LASHLEY: Yes, and we're just using it to guide us. We had used probability of leakage, and we wanted to use -- we also didn't want to be outside of, I guess, in bad air space and risk. If I knew, you know, a rod ejection was ten to the minus three, I should take --
MEMBER BONACA: Well, the change is similar to what has been done with 5059 for the plants. When you discover a new condition, okay, and you want to leave with it and you want to management it and solve it immediately, then you have to value it under 5059 because you're changing your design basis.
MEMBER APOSTOLAKIS: But that has nothing to do with 1174.
MEMBER BONACA: Well, 1174 is in a certain way akin in that it's a risk informed approach to the same thing.
MEMBER BONACA: You have an event. You could do things. One, you go in and just absolutely replace the head and make a case that you have put back the plant in the condition in which it was originally and you don't have to worry about it for a period of time. Therefore, you don't have to do any risk evaluation. Nothing has changed.
The other one is you want to live with it. You want to be part of this pack. There is an increase in some risk factors there, and therefore, you are going to justify it under 1174.
So the change is not a true change, but a change came upon you.
MEMBER ROSEN: That is the battleship in the desert phenomenon. We don't know how the battleship got there, but now that it's there, can we live with it?
MEMBER ROSEN: And so what you do is do an analysis of what are the consequences of that.
MEMBER KRESS: What you have is a probability of the change. If you go in and actually find out that your probability was wrong and your detection process showed a leak, you'd do something else.
MEMBER KRESS: You would fix that.
MEMBER KRESS: So all this is is a way to deal with the probability that you might have approached that one time at ten to the minus sixth.
MR. LASHLEY: Right, and you'll see how once you're into the inspection program, the results drive you then.
MR. LASHLEY: And if you're in high once, you can't get out of it. You're stuck.
MEMBER KRESS: You're there. That's right.
MR. LASHLEY: Until you replace the head.
MEMBER KRESS: Yeah, you're there. That's right.
MR. LASHLEY: So we'll go into it that way, and we did look at the J-groove weld and put together -- because that was a concern, and it was brought up, just the crack growth rate and things of that nature. So we looked at it from almost the worst case to see if we needed to do something extra from what we were thinking, and we looked at it from a worst case.
And so we used these two conditions of a circumferential crack or lack of fusion, something that would free release that whole thing. For nozzle ejection we still knew that it still could provide leakage or provide the environment, and those were the comments Al said.
So we're still looking at the environment that it creates and the leakage and the wastage. We've got to put that aside, but we did look at these two conditions and saw that's not going to create anything worse than the circumferential crack at the nozzle.
You'd have a circumferential crack around the J-groove itself. It physically can't fit through the hole.
Pretty much the same thing for lack of fusion. You would have to go all the way to still that structural margin of 300 degrees to really free release it. So we felt we were bounded by the circumferential analysis, the deterministic analysis that Pete's done.
So let's go into the plan. There are several slides that --
MEMBER BONACA: but you're still focusing only on the probability of rod ejection, right?
MR. LASHLEY: That was what when we looked at --
MEMBER BONACA: I know, but now there is a new issue, which is --
MR. LASHLEY: Wastage,
MEMBER BONACA: -- one of wastage, yeah.
MR. LASHLEY: And the issue with J-groove, it will just bring it to the surface sooner, but if a visual technique is -- we would propose a visual technique can see it, can see the evidence, and if it's done at just the appropriate frequency, you still won't have the wastage issue.
MEMBER BONACA: But if I remember, at Davis-Besse they had one nozzle, nozzle number three, where they had large wastage.
There was another nozzle, number two, I believe, where there was very minute wastage along the CNDM. Would you see that?
MR. LASHLEY: My supposition would be yes. I think you heard the 900 pounds didn't get there overnight, and I know you saw pictures dating back further that saw the red rust.
MEMBER BONACA: No, I understand that. I'm saying there were two areas of wastage. One was a very large one, which may be the main source of the red. Then there was a very thin one that I don't think a visual inspection would be visible.
MR. LASHLEY: No, we have the visual exam guideline which takes all of the other events, the Oconees and everything. It has nice pictures and videos in there. This is one of our reference documents to implement, to use.
And you've heard that term "popcorn." You can still have the minute, you know, one cubic inch, the very small levels that that condition would easily bring out. That one I think you'd still see a flow.
MEMBER KRESS: Your concern that the one leak masks the other one and --
MEMBER BONACA: Yeah, because at some point--
MEMBER KRESS: Yeah, but I don't think they would ever tolerate that kind of leak in this system, and this is going to be so low that if you get individual nozzles leaking, you'd know it because they're not going to have this kind of massive leaks.
MEMBER BONACA: No, no, I understand. I'm saying in the second nozzle where there was an incipient erosion taking place, but it was very minor. It was just very close to the --
MEMBER BONACA: I'm just questioning --
MEMBER KRESS: Yeah, but that would be a leak that you could fix.
MEMBER BONACA: -- whether it is visible at that point. Yeah, but I'm saying that would it be so visible.
MR. LOEHLEIN: Maybe I should comment on that.
MS. KING: Okay.
MR. LOEHLEIN: This is Steve Loehlein again.
Nozzle two does have a cavity region that maximum depth was about three-eighths of an inch. It did extend to the surface, was visible at the surface, and through comparison to other test data that's been available from the EPRI testing and so forth, it's pretty conclusive that there would be significant formations of boric acid in the region of a nozzle that looked like that, and there would be some rust colored deposits as well because there is active corrosion products being expelled with the boric acid at that point.
So nozzle two is actually quite far along in terms of being able to be visible from boric acid.
MEMBER BONACA: I understand, but I'm not talking only about nozzle two. I'm talking about another hypothetical nozzle where corrosion is going only from the beginning of it to one third or one fifth of what we see in nozzle two.
Do you see what I'm trying to say? I mean, there is an incipient corrosion taking place, and I'm just asking if, you know, the only criterion should be their concern with nozzle ejection or also with incipient -- the beginning of erosion and corrosion that would cause some coloration, but not necessarily allow the popcorn effect.
MS. KING: I think that comment goes directly back to the work that we've undertaken, and we're still going on, and you saw the initial presentation from Glenn White.
Our initial read on that situation is that you would have visible deposits on top of the head prior to reaching nozzle two type wastage, and definitely prior to reaching the cavity formation at nozzle three.
But the definite time line on that, we still have some work to do.
MR. MATHEWS: We've had 30-some nozzles that have leaked that we know of, and every one of them has shown boric acid on top of the head, even the ones that have had no wastage at all. And so what we're saying is that if you do start to get wastage, you're going to start expelling stuff to the top of the head.
And it takes a period of time, and that's what we haven't quantified yet to go from the initial leakage to getting the high flow rates that's going to generate significant wastage.
But it's going to be visible, and if you do a visual inspection at a frequent enough basis, you'll catch it before then.
CO-CHAIRMAN FORD: But that's not what happened at Bouget.
MR. MATHEWS: Well, I'll be honest with you, Peter. I don't know what happened at Bouget. They weren't looking on top of their heads under their insulation.
CO-CHAIRMAN FORD: N, as I understand it at Bouget, they detected by hearing during a -- well, they detected it during a hydrostatic test. There was no boric acid on top of that particular --
MR. MATHEWS: Well, that's what's not totally obvious to me, that there was no boric acid, because they had not looked under their insulation, as I understand it.
CO-CHAIRMAN FORD: Well, I'm only reporting what was written in the paper.
MR. MATHEWS: Okay. Well, I've been trying to chase that issue down. Did they look? And I'm not sure they did.
MS. KING: I'd like to make a further comment to what Larry was talking about with the experience to date. We'll take the Bouget comment under consideration. I mean, we need to get some more information.
CO-CHAIRMAN FORD: The reason why I'm bringing it up is, you know, this is a topic that comes up, you know, in cocktail conversation time and time again, and I keep hearing it, although we don't have any cocktails today.
Unfortunately this ugly fact destroys a beautiful hypothesis. If it really is true --
MR. HUNT: Steve Hung from Dominion Engineering.
At Bouget, the crack, the length of the crack above the top of the J-groove weld was two millimeters, which was less than a tenth of an inch. It was, you know, a 13th of the length of the cracks that you had at Davis-Besse. It may have been long enough for you to get water to create the circ. crack, the small circ. crack that was reported, but following the model that Glenn described, probably not large enough to create the volume of leakage necessary to create the wastage.
MEMBER BONACA: In any event, I don't want to pursue it any further. I just want to say that, you know, first of all, we thought that this nozzle would never fail. Then, lo and behold, some of them began to crack.
And then we believed that they would never have circumferential cracks, and lo and behold, we found circumferential cracks.
And then we believe that we had full control of it, and lo and behold, now we have a hole like this up there. So I'm not an easy believer anymore. I mean, I have to be a little skeptical about all of these promises.
MEMBER APOSTOLAKIS: This is my problem.
MS. KING: I guess I would like to comment along the lines of the experience to date and the repairs that have been done. Typically the repair that has been done is the Framatome what we've termed relocation of the pressure boundary, where they go in and take out the bottom portion of that nozzle.
And in that repair process, you have the opportunity to inspect the bore, and so far no one has identified wastage below that cut point, and you also do dye penetrant testing to validate that you have a good place to weld.
So we do have 34 data points in the industry where we have had boric acid on the top of the head and no known wastage behind the nozzle.
MEMBER BONACA: I understand. On the other hand, I mean, at Davis-Besse they found the hole by pure accident because there was simply the boring and--
MEMBER APOSTOLAKIS: Well, that's my problem. I see here traditional technical solutions to a problem that wasn't there.
MR. LASHLEY: So here's what we're going to propose --
MR. LASHLEY: -- to try to go after that.
CO-CHAIRMAN FORD: Are you going to go through these?
MR. LASHLEY: The flow chart. I'm going to go through the flow chart because that wraps up everything on one page.
CO-CHAIRMAN FORD: Good. That's the last one.
MR. LASHLEY: It's the last page.
MS. KING: It's the last page of your handout.
CO-CHAIRMAN FORD: Now, what's in those boxes essentially is what's written down on these low susceptibility, 100 percent reproducing --
MS. KING: Yes.
CO-CHAIRMAN FORD: The message that's in these here is important, but you're reproducing it on this.
MS. KING: Right. That is the text from the inspection plan, and this is the --
MR. LASHLEY: It's probably easier to look at that.
And so you come into the plan, and let's take the low susceptibility, which we define as less than ten effective degradation years. What we know is you look at that big grouping on the lower right-hand side. They're all virtually into their second tenure interval already, and we also have the rack-up of the 0201. Virtually every plant has done or is doing an inspection.
So we know we have this snapshot of that at least at baseline, and we're going to require an additional inspection. It could be a bare metal visual or a nonvisual, indeed, volumetric, once per ten years, and we say do that starting in your third interval.
And our concern is, if you remember, there's such a large gap that these plants may never cross over to moderate. If they're 560 degree head, you don't cross over until life extension, your 52 years of operation.
So we're still requiring that group that's less than that one percent probability of leakage to do something and to do it on a ten-year frequency moving forward.
CO-CHAIRMAN FORD: So the ten years comes from some kind of judgment. It's not based on some criterion of some sort?
MR. LASHLEY: It had a lot of engineering judgment, and that's probably where Al was speaking to. Like wastage in and of itself, we have evidence that we could have found Besse six years ago, and so there is where the disconnect that we're still working on the staff on because you don't expect the surprise down there, but we --
CO-CHAIRMAN FORD: It's not based on some sort of analysis where you say in order to reduce the risk by a certain amount if we need to inspect at a certain interval?
MR. LASHLEY: We did do the analysis, but if you remember Pete's curve at the inspections, it would stay on the flat line. It would just keep bubbling up and never come off any risk, but we knew that, but we're still going to say you still have to do something for the unknown because we don't know what we don't know.
But the ten-year --
MEMBER ROSEN: Modeling uncertainty or modeling completeness.
MEMBER WALLIS: The ten years is based on your assessment of what you might not know.
MEMBER ROSEN: We require Defense in Depth. We require testing even for plants that would not otherwise require it.
CO-CHAIRMAN SIEBER: Yeah, but this is pretty modest for a low susceptibility plant, which is not unreasonable in my opinion. It's only ten percent.
MEMBER ROSEN: This is exactly what you were espousing, is the graded approach to the thing.
CO-CHAIRMAN SIEBER: Yeah. I just worry about the high susceptibility plant.
MEMBER ROSEN: We'll get to that.
CO-CHAIRMAN SIEBER: The faster we get there, the happier I'll be.
MR. LASHLEY: And I'd say don't forget that at least when we first proposed that, we still knew everybody does a boric acid walk-down every year or -- excuse me -- every outage, and we still assumed it was more robust. So we're going to take that. We have that comment.
Moderate susceptibility is at ten to 18 effective degradation years, and we required once every two, not to exceed five years, and this one was an engineered number to be less than the six that we knew about for Davis-Besse or that we suspected.
You're going to do a bare metal visual or you're going to do a non-visual once every four effective degradation years, not to exceed ten. And this is where we use Pete's model and his susceptibility -- not susceptibility. I lost the word.
PARTICIPANT: Effective inspections.
MEMBER KRESS: Some of those plants in that modern region are down near the bottom line.
MR. LASHLEY: Correct.
MEMBER KRESS: Some of them are up near the top, the one times ten to the minus six line.
MR. LASHLEY: Correct.
MEMBER KRESS: Now, are you going to treat those two plants differently or they get the same treatment? Because they're in the moderate region, both of them.
CO-CHAIRMAN SIEBER: You're profiling now.
MEMBER KRESS: I am profiling, yeah. I mean, it would make some sense to treat those two plants differently, how close they are to that line.
MR. LASHLEY: Right. We talked about that when we received that specific comment from the staff. I mean, there's the example of this week you're moderate. You start back up from your outage, and by gosh, next week you're high.
MEMBER KRESS: You're across the line.
MR. LASHLEY: You're across the line. So we have evidence.
If you look at the periodicity of the exams, and most of those plants are higher in temperature, the periodicity is two EDY versus every outage. So most of those plants, if you are greater than 600 degrees, two EDY is only one cycle, is one 18-month cycle.
So we thought about it, and that's why we're using EDY and not years.
MEMBER KRESS: Yeah, okay. That would help.
MEMBER ROSEN: Why are you switching from EDY to EFPY? I don't understand that.
MS. KING: Well, that was to put an upper cap on those plants that accumulate EDY very slowly, and so they couldn't go -
MR. LASHLEY: Do you want to go back to the figure?
MS. KING: Which one?
MS. KING: Oh, Lord. There we go.
MR. LASHLEY: All right. Remember he had a whole series of blue lines, but EDY goes like this. So to do one EDY it might take that long. I mean, it may take five effective full power years if you're way over here at 560 degrees. Remember all of these swooping -- those are EDY, the curve.
So when we used -- that's degradation years normalized to 600 degrees, but if we keep it at, sorry, you can't go past so many effective full power years, that was our attempt to go after the wastage.
MEMBER ROSEN: Regardless of the --
MR. LASHLEY: Regardless of it, it maxed out.
MEMBER BONACA: And, of course, it assumes susceptibilities, only temperature dependent.
MR. LASHLEY: It's using the simplified model, yes.
MEMBER BONACA: So we're hanging a lot of things on this assumption. Again, I'm a little bit --
MEMBER KRESS: Well, you might argue that one times ten to the minus six kind of takes care of that uncertainty to some extent.
MEMBER KRESS: Because that's a pretty low number.
MR. LASHLEY: And you can see from this 560 degree plant to go from moderate to high, there's still some 40-something years, effective full power years, but that's only eight effective degradation years.
MEMBER KRESS: Now, the ones I was concerned with were these down here on the high temperature end, say the red ones.
MR. LASHLEY: We'll get -- well, it's not on the flow chart. Let me jump in. Any time you find a leak and it says it in the plan, you are redefined--
MEMBER KRESS: Yeah, but I'm looking at the blue ones that are that close, too. It seems to me like some of them, a couple of those blue ones are pretty close to that line.
MR. LASHLEY: Being blue like that means they've inspected. They're less than probably two EDY away.
We say when you come into this plan, you're going to do this inspection. You're going to start off doing it, hit the ground running. So that's what it was geared for.
And we knew all of these will be moderate imminently.
MEMBER KRESS: Well, they're going to get there. I mean, that's the thing about time being your--
MR. LASHLEY: Right, and our graduated approach is to use that effective degradation years as the frequency, but cap it in real years so that you can't get too far off track without coming back.
MEMBER BONACA: You have a number of red triangles there that are below the separation between moderate and high risk. But you consider them high risk, right? Because they already have --
MR. LASHLEY: They will be considered high risk.
MS. KING: They will be considered high risk, but also those data points are one year old. We need to update our data points.
MEMBER BONACA: So that would go --
MS. KING: It's based on the 228 effective full power years at that count. It would be expected to be recalculated, and I guess I'd like to point out that those plants, well, spring '02 and the later Xes have inspections planned associated with their Bulletin 01-01 responses.
CO-CHAIRMAN FORD: Could I suggest maybe we start to wrap up?
MR. LASHLEY: Okay. Any questions? No.
CO-CHAIRMAN FORD: I think we're al getting a bit punch drunk here.
MR. LASHLEY: High susceptibility has the bare metal visual every outage, and it also has no matter what -- you're going to do a non-visual. You're going to do NDE within the first four EDYs to get --
MR. LASHLEY: You're going to do it, period, and that's just to go after the unknown.
What this also has in it if you go down below -- can you scan down? -- if you ever find the leaker, you're going underneath. This is standard code stuff now. You can characterize the flaw and find the extent of condition.
We do allow in this plan one cycle to complete the 100 percent look of every nozzle under the head. So this was for that plant that found a leaker early. You still have to go look at those, but we still felt like if you were moderate, you still had time. If you didn't show anything above, you still had time. You didn't have the wastage issue. You didn't have the safety issue. We could accept a cycle before you come back in and do 100 percent volumetric of everything.
So once you're a leaker, once you're high risk, you're doing that volumetric you're after, and you're going to do 100 percent within one cycle.
So then we would know the entire extent of condition and fix what we find. We're using the reference flaw characteristic that directs Strosnider, and it has virtually intersecting or circ. cracks you've got to fix, and that was the 75 percent through wall to the next inspection you have to fix.
That was short and sweet.
CO-CHAIRMAN FORD: Thank you very much, indeed. I appreciate it.
MEMBER APOSTOLAKIS: Is there a written document where all of these things are explained?
CO-CHAIRMAN FORD: The work on the probability, French mechanics, I don't think you were here for. The explanation for the curves --
CO-CHAIRMAN FORD: It's in the package though.
MEMBER APOSTOLAKIS: Is there a series of EPRI reports, or there will be?
MS. WESTON: There is a write-up on the inspection plan in your notebook, yes, under page 117, handwritten. It's already in the notebook.
CO-CHAIRMAN SIEBER: Would this end up in Section 11?
MR. LASHLEY: Like I said, I have the action to bring it to Section 11, but we also have a meeting this summer to try to write -- we've already presented it twice. We hope we can bring something to start voting on this September, and all of the intertwining, acceptance criteria and the other things that this would go after.
CO-CHAIRMAN SIEBER: Otherwise it would have to go in tech specs in order to make people do it.
MR. LASHLEY: Our desire in codes and fervent attempt is to get ahead of this and do something because there's a recognized inconsistency. This is a vulnerability that we didn't have any good inspection criteria for, none. I mean really none.
CO-CHAIRMAN SIEBER: Well, I have to think about it. This isn't really too far away from what I was thinking anyway.
MEMBER APOSTOLAKIS: What did you say? Too far away?
CO-CHAIRMAN FORD: It wasn't too far away from what he was thinking already.
CO-CHAIRMAN SIEBER: But in order to really be efficient and practical from a regulatory standpoint, Section 11 is the way to go, but that takes a long time.
MR. LASHLEY: I mean, we're well on a fast track. The Section 11 chairman, subcommittee --
MS. KING: I understand what you're saying, and, you know, we have direction from the PMMP steering committee to work fast and furious on the inspection plan. They've reviewed it once and as Michael indicated, they would like to see us address the staff's comments and come back out, get the technical basis pulled together by the end of next week, and that's what we're working to do.
CO-CHAIRMAN SIEBER: Well, the staff has a couple of people on the Section 11 committee anyway.
MEMBER ROSEN: What takes time about getting the code changed is when you're trying to get their attention with an issue, which they don't think is generic or interesting. In this case, you don't have that problem.
MR. LASHLEY: This is a special task group that reports directly to subcommittee Section 11. It doesn't go through working groups and such. It goes right to the main -- to this --
CO-CHAIRMAN FORD: Bill, could I ask you? You've heard some of the concerns from the group primarily because this is the first time you've been hit with it. Were there any concerns that you heard raised which you are not already considering in the list Allen put up on the board?
Do you understand the question?
MR. BATEMAN: I think I do, and I don't think there's any concerns we've heard today form you folks that we haven't -- that aren't similar to our concerns.
Can I just briefly --
CO-CHAIRMAN FORD: Yes, please.
MR. BATEMAN: -- give a few remarks here?
I think what we accomplished today is we've given the committee an update on the status of the two bulletins. You've got an update on the status of Davis-Besse from the licensee, an update on the 0350 panel and the lessons learned task force and other industry activities.
I think progress-wise since the last meeting, Davis-Besse has elected to drop the repair options and go with the replacement head.
You had asked for data. I think industry has supplied an abundant amount of data, and I think it's good data, a good basis for it.
I think we have from the results of the Bulletin 2002-01 inspection, which was the bulletin with respect to the Davis-Besse head degradation, I think we have gained assurance since we last met with you that at least at this point in time we do not have another Davis-Besse out there. We do have some time to take the action that I think industry has proposed here with respect to inspections and frequencies.
I think where we're at right now is, as I said earlier, we're contemplating some generic correspondence as a bridging document between now and when we reach a final conclusion, and I think it will be close, but not identical to what industry has proposed. I think it will be more conservative with respect to frequencies and maybe inspection methods.
But I can't speak any more on that because it's in a draft form right now, and we ave not finalized our position.
CO-CHAIRMAN FORD: Well, I would like to personally thank everybody who provided data. I know it was a pain in the butt. It really is to do this, but if you all recognize, the members around this table are not all experts in all subjects, and so we ask a lot of questions, and letters that come from us are from all of us, not just one person.
So it is invaluable that we can hear the complexity of the issues that you're all addressing.
Normally at this point we go around the table very quickly so that each of the members can say a couple of remarks about what they can advise and what to condense into two hours tomorrow, and you can pass if you don't want to say anything.
CO-CHAIRMAN FORD: Boy, this is easy.
MEMBER KRESS: It's seven o'clock.
CO-CHAIRMAN SIEBER: Well, I guess everything that I would say now I've already said.
MEMBER APOSTOLAKIS: Even if we make recommendations, they don't have time to do anything about it. It's seven o'clock. They're on in the morning.
CO-CHAIRMAN SIEBER: Just tell them what to say.
MEMBER BONACA: They should go through the same material in two hours.
MEMBER APOSTOLAKIS: Maybe they should leave time for Dr. Powers.
CO-CHAIRMAN FORD: Well, let me ask the people who are presenting tomorrow, Larry and Jim, please. Can you cope tomorrow?
MR. MATHEWS: I took our 118 slides from all of ours. I got it down to about --
MR. MATHEWS: -- 40.
MS. KING: Forty.
MR. MATHEWS: But I was intending since everybody here is going to be there tomorrow, and Dana I think is the only one who is not here that will be there --
CO-CHAIRMAN FORD: That's correct.
MR. MATHEWS: -- tomorrow, that I was going to go through them pretty fast. If somebody could keep their hand over Dana's mouth, we could -- you know, I'll go through them real fast.
I know, I know.
MEMBER ROSEN: Well, you've got half of the confusion and difficulty here, and the other half is--
CO-CHAIRMAN SIEBER: What about the rest of us, you and me?
CO-CHAIRMAN FORD: Okay. One last piece of business before we bang the gavel. Bill has asked for a letter from the meeting tomorrow. Do I hear a suggestion that we discuss it over dinner tonight?
MEMBER KRESS: Yeah -- no.
MEMBER KRESS: Not all of us are going to dinner.
CO-CHAIRMAN FORD: Okay. So is it all right if I write the draft and you can all butcher it tomorrow?
MEMBER ROSEN: And can we discuss it the remainder of the week through Saturday night or however long it takes?
CO-CHAIRMAN FORD: Right you are.
I thank everybody, the presenters especially. Thank you very much indeed.
(Whereupon, at 7:08 p.m., the joint subcommittee meeting was adjourned.)

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