ML023540120
| ML023540120 | |
| Person / Time | |
|---|---|
| Site: | Davis Besse  |
| Issue date: | 12/05/2002 |
| From: | Advisory Committee on Reactor Safeguards |
| To: | |
| References | |
| NRC-576 ACRST-3224 | |
| Download: ML023540120 (188) | |
Text
166 1 Some of the milestones in the review, very 2 quickly: We received the code and the documentation 3 in August of 2001, just a little over a year ago. We 4 have gone through the initial presentations to the 5 Thermal Hydraulic Subcommittee. We have asked for 6 additional information, and we have presented the 7 draft SER to the Thermal Hydraulic Subcommittee a 8 month ago.
9 MEMBER SIEBER: Which one is that, the 10 first one or the second one? I've got two different 11 ones.
12 MR. LANDRY: The second draft SER.
13 MEMBER SIEBER: Okay.
14 MR. LANDRY: We've gone through a couple 15 of iterations. What we have tried to do, in the first 16 drafting of the SER, we tried to go through and just 17 document what we had done in the review and then 18 realized that, well, we didn't like that format; we 19 didn't like all the material that we had in there.
20 So we went back and restructured the SER 21 to follow in the CSAU format. Much the same as what 22 Larry O'Dell just presented in the way the code work 23 is structured, we went back and restructured the SER, 24 all the steps of the SER, of the CSAU methodology.
25 The SER gives an overview of the PIRT NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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167 1 structure. We give an overview of the thermal 2 hydraulic phenomena. We went into more depth in the 3 thermal hydraulic phenomena than in some of the other 4 areas because we had a number of questions and a 5 number of areas of concern in reviewing the thermal 6 hydraulics.
7 We have included an overview of some of 8 the selected assessments that were performed. We gave 9 an overview of code examination which the staff has 10 performed and some of the parametric studies which the 11 staff has performed in review of this code. We gave 12 an overview of the uncertainty methodology and some of 13 the conclusions.
14 The part that has been presented by 15 Framatome presents the phenomena by transient phases.
16 Now the PIRT part is pretty much the CSAU-presented 17 PIRT in NUREG/CR-5249, with the exception that they 18 have filled the gaps that were in that generic PIRT 19 that was prepared for the NUREG report.
20 They have included a hot rod and a hot 21 bundle in their model. They have also used a 22 realistic linear heat generation rate rather than a 23 very low peak linear heat generation rate, as was used 24 in the NUREG report. They have used a frozen code 25 version, as was described this morning.
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168 1 The heat transfer modeling which the staff 2 looked at, we found basically to be pretty good. We 3 zeroed in very hard on the dispersed flow film boiling 4 modeling, the reflood heat transfer modeling, because 5 in the large-break LOCA the driving phenomena occur in 6 the reflood.
7 In that review we took some disagreement 8 with Framatome over the use of the Forslund-Rohsenow 9 correlation. We have had disagreements with them over 10 whether this is a wet contact, dry contact model; what 11 is the nature of the model.
12 We basically came down to the point of 13 agreeing to disagree. Because we went through the 14 review and had Framatome take their worse case and 15 specify from that worse case when the T-wall is 16 greater than T-min, they would multiply the Forslund 17 Rohsenow correlation by zero, take it out of the 18 evaluation. When that was done, we found that the 19 calculation had no effect on PCT. Forslund-Rohsenow 20 was not being invoked; it would have no effect on PCT.
21 Where it did have an effect was later in 22 the quenching period. The temperature that was 23 calculated going down towards the quench stayed 24 anywhere from 5 to 10 to 18 degrees above the 25 temperature that would be predicted using Forslund NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W.
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169 1 Rohsenow, and the time to quench was extended.
2 So we stepped back and said, okay, as far 3 as PCT is concerned, whether you're using Forslund 4 Rohsenow or not, whether it is right or not is 5 irrelevant because you are getting the same PCT.
6 MEMBER WALLIS: It seems to me some other 7 issues could be resolved the same way, the agreement 8 to do sensitivity studies around those issues.
9 MR. LANDRY: That's right. I am going to 10 get to another one of those in just a few minutes.
11 I would say that the issue over Forslund 12 Rohsenow really deals with the nature of the model, 13 the correlation. It is a correlation developed for 14 liquid nitrogen being injected into a tube. We are 15 talking about putting water into a bundle.
16 There is a research program underway right 17 now up at Penn State, which the Thermal Hydraulic 18 Subcommittee heard about when we talked about the 19 draft SER last month, which would be using water in a 20 bundle. That would produce data that would supposedly 21 be much more accurate and much more representative of 22 the phenomena one would expect to see in dispersed 23 flow film boiling in a bundle.
24 The model which Framatome has chosen, used 25 for decay heat is the ANS 1979 model. They have not NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N.W.
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170 1 gone to the full statistical decay heat modeling.
2 The assessment matrix which has been 3 provided by the applicant includes separate effects 4 and integral tests in their assessment. They did use 5 a lot of the latest information, the information 6 coming out of the 2D/3D program. This is information 7 that was considered when NUREG/CR-5249 was put 8 together.
9 When we did our review, we did a lot of 10 spot-checking of the assessments, but we went in and 11 looked at the results that were presented for the 12 2D/3D and, in particular UPTF, very hard. We felt 13 that since this is full-scale and far more 14 representative than some of the smaller-scale tests, 15 we made a very hard review of what was done by the 16 applicant in their assessment against the 2D/3D 17 results.
18 We did spot-checking of the coding.
19 Specifically, this is an issue which the Thermal 20 Hydraulic Subcommittee has been after us on for some 21 time, where we went into the actual source code 22 itself, looked at the lines of the coding and said, do 23 these lines of coding match what is in the 24 documentation?
25 We found that there were just differences.
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171 1 Well, when we started looking at what was in the code, 2 we said, okay, what is in the code is right, but what 3 is in the documentation hasn't been recorded exactly 4 right. This is one of the things that Jim Mallay was 5 talking about, that they are going back and looking at 6 the documentation and working on improving the 7 documentation for the code.
8 The staff ran a number of parametric 9 studies. We looked at a few of the phenomena that 10 were identified as unimportant phenomena that would be 11 imported. Some of the things that we found, when we 12 looked at phenomena such as the post-D&B forced flow 13 heat transfer, virtually unimportant. When we looked 14 at the effect of viscosity, of water viscosity, it was 15 of very little importance.
16 MEMBER WALLIS: Ralph, this is taking 17 their code?
18 MR. LANDRY: Using their code.
19 MEMBER WALLIS: Their input and 20 everything?
21 MR. LANDRY: Their input.
22 MEMBER WALLIS: Did you use an approved 23 platform?
25 (Laughter.)
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172 1 They haven't certified our platform, but 2 it is the same compiler and the same operating system 3 that they use.
4 MEMBER WALLIS: Was this a platform which 5 had previously been approved by the NRC for use for 6 this purpose?
7 MR. LANDRY: We don't always QA our work.
8 MEMBER WALLIS: Are you going to give me 9 a yes-or-no answer?
10 MR. LANDRY: We were using what is the 11 same, what we understand to be the same platform, the 12 same compiler, the same operating system that 13 Framatome was using.
14 MEMBER WALLIS: But you ran that code, 15 which is something we have been encouraging you to 16 do -
17 MR. LANDRY: It was their code.
18 MEMBER WALLIS: -- and you've wanted to 19 do. That is a step forward.
20 MR. LANDRY: Right.
21 MEMBER WALLIS: You did not run your own 22 code for purposes of an audit or a check or -
23 MR. LANDRY: No.
24 MEMBER WALLIS: -- an independent 25 verification?
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173 1 MR. LANDRY: We are still taking baby 2 steps along the way.
3 MEMBER WALLIS: Well, running your own 4 code is going to happen before too long, I hope.
5 MR. LANDRY: It's going to, and I will get 6 to that in just a minute.
7 But that gets to be very difficult to do 8 because our code has very significant modeling 9 differences. The RELAP5 mod 3.3, whatever it is, the 10 latest, 3.3.3, or whatever the latest version is, has 11 significantly different modeling in the reflood 12 package. There's quite a few differences versus this 13 code.
14 MEMBER WALLIS: Maybe that's a good reason 15 for running it 16 MR. LANDRY: We will be getting to that -
17 MEMBER WALLIS: And if you get the same 18 answer, then that would give you some confidence that 19 different modeling doesn't give you a different 20 answer.
21 MR. LANDRY: We're moving into that 22 direction now.
23 MEMBER WALLIS: I think that is something 24 that would really help the public confidence, if they 25 could say, yes, he's run all these vendor codes to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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174 1 you, but now you've done something independent 2 yourselves and it gives the same answer. Therefore, 3 you have real confidence in it.
4 MEMBER LEITCH: Could you explain what the 5 three curves are? What's the heavier curve versus the 6 two lighter curves?
7 MR. LANDRY: That's what I'm trying to get 8 to.
9 MEMBER LEITCH: Okay.
10 (Laughter.)
11 MR. LANDRY: We took the three-loop 12 Westinghouse plant, that which Framatome supplied to 13 us, and looked at the effect of wall drag, multiplying 14 wall drag to increase the rod rate, which, in effect, 15 as you increase rod rate, you retard reflood.
16 What we found was, where we had taken the 17 viscosity term, where we had taken the heat transfer 18 term, and multiplied those by two, five, and ten, we 19 found almost no difference in the base curve. When we 20 went into the wall drag model and increased wall drag, 21 we found that the dark curve is the base case where 22 wall drag is multiplied by one. When we increased the 23 wall drag by two, we got a slightly higher PCT and a 24 slightly later quench. Of course, you are delaying 25 reflood; you would expect that.
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175 1 When we multiplied wall drag by ten, we 2 got a totally different transient. So that said to us 3 wall drag is a very important phenomena. It gets back 4 to, yes, reflood is a very important phenomena, which 5 we had expected.
6 MEMBER WALLIS: Would that be acceptable, 7 that sort of comparison? Just on the basis of PCT, it 8 doesn't make all that much difference?
9 MR. LANDRY: It doesn't make all that much 10 difference on PCT, but the occurrence of PCT is 11 significantly different.
12 MEMBER WALLIS: It is quite different, 13 yes. It is qualitatively different in several ways.
14 So that would not be an acceptable prediction if that 15 were -- in comparison with data?
16 MR. LANDRY: Right.
17 We have taken these analyses a little bit 18 further, and this is brand-new. This was just done 19 the end of last week.
20 We decided to look at the effect of 21 momentum, since momentum keeps coming up as a 22 question. We went into the code and simply put a 23 multiplier on the virtual mass term, so that we would 24 increase the momentum through the virtual mass. By 25 increasing by a factor of ten, you see only a slight NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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176 1 difference in momentum, the PCT and in heat 2 transfer -
3 MEMBER WALLIS: Well, virtual massing 4 increases the coupling between the phases. So in big 5 virtual mass they tend to move together as a 6 homogeneous mixture.
7 MR. LANDRY: Right, and we are making a 8 much more homogeneous mixture.
9 MEMBER WALLIS: It doesn't really change 10 the momentum.
11 MR. LANDRY: That's right.
12 MEMBER WALLIS: It changes the coupling 13 between the phases.
14 MR. LANDRY: Right.
15 So this is just a first shot at trying to 16 see what the effect of momentum was.
17 MEMBER WALLIS: It shows that when a 18 question is raised about, say, virtual mass 19 coefficient, which is not known very well for these 20 systems, you can run a test and see if it matters?
21 MR. LANDRY: Right.
22 MEMBER WALLIS: It seems very appropriate.
23 MR. LANDRY: I said before when you 24 asked -
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177 1 put in for the density in the virtual mass term?
2 MR. LANDRY: We kept it the same.
3 MEMBER WALLIS: They have a density which 4 is the mixture density or it should be the continuous 5 phase, which could be off by a factor of 50 or 6 something?
7 MR. LANDRY: We left all that the same.
8 We wanted to make as few changes as possible. This 9 was only a first shot. We did this with the FLECHT 10 SEASET test, then decided, well, that wasn't a good 11 test to look at because it was a forced or fixed 12 reflood rate. So if you change momentum, what are you 13 doing with a fixed reflood rate? You're not making 14 any change. So we went into the three-loop plant and 15 made the change.
16 Our next step, since this is a large-break 17 LOCA in a large plant, we want to go back and look at 18 what is the effect if we get into a system that has 19 much lower driving heads, such as a passive system.
20 MEMBER WALLIS: You made it ten times 21 bigger? You made the coefficient of area mass ten 22 times bigger than assumed by Framatome? You didn't 23 make it ten times smaller as well?
24 MR. LANDRY: No. We're running out of 25 time. We're trying to -
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178 1 MEMBER WALLIS: Well, maybe next week 2 you'll have that one.
3 (Laughter.)
4 Because if you are uncertain, you should 5 go both ways.
6 MR. LANDRY: In the next few weeks we do 7, intend to go back and look more; plus, we intend to go 8 into our own codes in the next couple of months, 9 depending on how our time is allocated. We want to 10 look at some of the passive designs, run from the 11 passive designs, and see with a plant that has a very 12 low driving head what is the effect.
13 MEMBER WALLIS: This is a wonderful 14 development.
15 MR. LANDRY: We're taking baby steps 16 still.
17 MEMBER WALLIS: Well, soon you'll be 18 running.
19 MR. LANDRY: Well, we have to walk first.
20 As Larry described, the methodology that 21 they have used for uncertainty is non-parametric order 22 statistics, and they have taken a variation on break 23 type and size statistically, rather than fix the break 24 size and then use all your parametric studies for one 25 particular break size.
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179 1 When that is done, the 59 cases which have 2 been run, the staff looked at this and said at first, 3 "Well, we have questions about using break size as a 4 statistically-treated parameter." We looked very 5 carefully at what Framatome had done and asked them to 6 do another study for us.
7 Then we finally said okay, because what 8 they have done is they have treated binomially the 9 break type, whether it's a double-ended or a slot 10 break. They have applied a uniform distribution to 11 the size from double-ended guillotine down to their 12 smallest-sized slot.
13 So they have not biased the break type or 14 biased the break size. They are covering the entire 15 spectrum on size. When that is done, they run the 59 16 cases, each with a different size. As you might 17 expect, all the slot breaks end up at the lower size; 18 all the double-ended breaks end up with a larger size.
19 They again end up with a double-ended 20 guillotine as the worse case, which turns out, when we 21 talked to them in-depth, this is pretty much the same 22 case, the same break size as an Appendix K run on this 23 plant would give, a different temperature, but the 24 same break turned out to be the worst.
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180 1 break and we want you to fix that break size and now 2 go back and run 59 cases; vary all your other 3 parameters, Monte Carlo method on all the variation of 4 parameters, and rerun all 59 cases for only one break 5 size.
6 When they did that, they found two points 7 that came above this temperature and fifty-seven cases 8 that came below that temperature.
9 MEMBER WALLIS: How far above did the two 10 come?
11 MR. LANDRY: The two that were above were 12 20 degrees Fahrenheit above and 76 Fahrenheit above.
13 So we felt that, looking at what they had 14 done, yes, they have captured the worst-break size.
15 When you vary the parameters only on that one size, 16 you don't go a very large amount above the predicted 17 temperature.
18 So the staff's conclusions is that, okay, 19 this is a different approach than we had anticipated, 20 running break size as a statistical parameter. But 21 because of the way they have done the study, and 22 looking at what they have done, they captured the 23 entire spectrum. They haven't biased the spectrum.
24 They haven't truncated the spectrum at any point.
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181 1 break as the worst case. We have decided that, yes, 2 we agree, that is an acceptable approach -
3 VICE CHAIRMAN BONACA: You have a 4 guillotine break at about 2.8 or 2.7 square feet that 5 is close to the limiting case. Does it mean that if 6 they go into a smaller break size for the LOCA 7 analysis requirement, you still get the same negative 8 value?
9 MR. LANDRY: We weren't even addressing 10 that. Our concern was, have they covered the entire 11 spectrum?
12 VICE CHAIRMAN BONACA: I understand.
13 MR. LANDRY: Because they have covered the 14 entire spectrum, this is a different issue than the 15 question of, is it valid or not to restrict the size?
16 MEMBER WALLIS: Now, Ralph, I think they 17 used a uniform distribution of break size, a 18 probability distribution which was flat.
19 MR. LANDRY: That's right.
20 MEMBER WALLIS: And if they had better 21 information about the likelihood of these large breaks 22 or small breaks, they could feed that in, too. If 23 that were based on good arguments and substance, you 24 would perhaps accept that.
25 MR. LANDRY: Well, that's a different NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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182 1 question, and that is a project that is underway in 2 the Office of Research at this point.
3 We had looked at what Framatome has done 4 and said, this does not impact and that does not 5 address what is being done in the Office of 6 Research -
7 MEMBER WALLIS: Right, but the next step 8 might be to say: Well, how likely are these breaks?
9 And let's put in some better instruments of 10 probabilities.
11 MR. LANDRY: That's right.
12 MEMBER LEITCH: Is the .1 square foot, is 13 that the definition of a large-break LOCA?
14 MR. LANDRY: That's the definition that 15 they have taken.
16 MEMBER LEITCH: So that's why there is no 17 datapoints to the left of that .1?
18 MR. LANDRY: That's right. They had taken 19 their lower limit as .1 times the area of the double 20 ended.
21 MEMBER LEITCH: Okay, okay.
22 MR. LANDRY: Staff SER conclusions: The 23 staff concludes from the review of the documentation 24 submitted by Framatome A and B that the S-RELAP5 25 realistic large-break LOCA methodology is structured NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W.
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183 1 consistently with the guidance of the CSAU 2 methodological process and addresses the licensing 3 requirements for a variety of similarly-designed 4 nuclear power plants; specifically, three-loop and 5 four-loop Westinghouse and the 2x4 CE designs.
6 MEMBER WALLIS: Ralph, we had this 7 discussion before. Don't you want to say, 8 "satisfactorily addressed" or something? Just the 9 fact that it addresses the requirements doesn't mean 10 it meets them.
11 MR. LANDRY: Yes, it does 12 satisfactorily -
13 MEMBER WALLIS: You're going to put in 14 something that says "adequately addresses" or 15 something like that?
16 MR. LANDRY: Yes.
17 MEMBER WALLIS: So you are positively 18 reviewing -- your review reaches a positive 19 conclusion -
20 MR. LANDRY: Right, we have reached a 21 positive -
22 MEMBER WALLIS: -- on the adequacy of 23 this -
24 MR. LANDRY: There is a positive 25 conclusion, yes. It applies to bottom reflood only.
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184 1 This does not apply to upper head injection. This 2 does not determine long-term coolability. This 3 methodology does not address long-term coolability.
4 That is an issue of specific hardware requirement. We 5 agreed that long-term coolability is something that 6 must be determined by the individual licensee, that 7 they have adequate hardware.
8 That concludes the presentation.
9 CHAIRMAN APOSTOLAKIS: Graham, you're in 10 charge.
11 MEMBER WALLIS: Well, it is nice to see 12 the evolution of your review, the way it improves 13 every time we see you.
14 MEMBER POWERS: The challenge that I'm 15 still confronting here a little bit is I looked at the 16 methodological aspects, and that's what he said on 17 this slide, that it was methodological, but it is not 18 evident to me that in formulating the treatment of 19 large-break LOCAs that we haven't done that in the 20 past in the conservative case to hide phenomena we 21 just couldn't handle very well. Now, as we become 22 more realistic, suddenly that hiding is no longer so 23 easily done.
24 Now the one that I brought up more as an 25 example than anything else is the spallation of oxide.
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185 1 You know that when clad oxidizes, sooner or later it 2 will spall. It simply cannot do otherwise. I, 3 myself, have no idea when that spallation occurs. It 4 won't occur when the oxide is very thin. It certainly 5 will if it's very thick. But where it exactly occurs 6 I don't know.
7 I do know that we are using fuels of 8 higher burnup. They are more extensively oxidized to 9 begin with. When that spallation occurs, of course, 10 your oxidation kinetics are different; your heat 11 temperatures are going to be different; your heat 12 generation is different. But we don't seem to be 13 looking at that.
14 MEMBER WALLIS: Well, I think one payoff 15 from a realistic approach to these models would be 16 that it would reveal areas where you need to know 17 more.
18 MEMBER POWERS: Well, how would it ever 19 reveal that you need to know more if you say, well, 20 gee, I'll just use a parabolic oxidation model with no 21 breakway in it?
22 MEMBER WALLIS: Well, it may be that that 23 leads to questioning whether you should use such a 24 simplified model. You realize that there are some 25 things that are being hidden by assuming that model.
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186 1 Hopefully, the models can advance. I have never found 2 the one to answer the question. Maybe Ralph should be 3 answering the question.
4 MR. LANDRY: I'm more than willing to let 5 you answer it.
6 Well, the models can be varied. We can 7 always go in and vary the model. But the question is, 8 what is the basis for the variance? Do you have data 9 to support the variation that you are doing?
10 We can go through and determine which 11 models are important pretty easily just by making 12 computer runs, but what is the basis on which we would 13 say this particular model is not valid or this model 14 should be used instead? Without adequate information, 15 I would have a real hard time with an applicant 16 saying, "Well, we're not going to accept this model.
17 You have to use this model."
18 I have to have a basis for doing that.
19 Plus, even though this is a realistic modeling, it 20 still does have conservatisms in it, and if there is 21 an area that we have uncertainty, we can always go in 22 and restrict, put in limitations, put in conditions -
23 MEMBER POWERS: You can go in and you can 24 work with the code all you want to. If it doesn't 25 have the physics that's pertinent, you've got no NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N.W (202) 234-4433 WASHINGTON, D.C 20005-3701 www nealrgross com
187 1 answer. I mean, can you tell me that forming an oxide 2 on a convex surface won't eventually spall, that it's 3 thick enough? The answer is, yes, it will eventually 4 spall.
5 What I can't tell you is how thick it is 6 because I've never worked on it.
7 MR. LANDRY: And how do I model it?
8 MEMBER POWERS: Well, there are certainly 9 things in the literature on how to model it. I mean 10 this is not a completely unknown phenomena.
11 The question here that I am asking is, is 12 it a new phenomena that has to be incorporated into 13 these codes because the conservatisms that we had in 14 the past, and are now going to be giving away, no 15 longer hide the effects of these new phenomena?
16 MR. LANDRY: At this point, Dana, I don't 17 know. I would have to have some basis for looking at 18 the modeling, have to ask, perhaps ask the Office of 19 Research: What do they know? Have they addressed 20 this? Are they doing any work to address this 21 question? What is their recommendation?
22 At this point I don't have a basis from a 23 regulatory standpoint to move in that direction.
24 MEMBER SHACK: I think the Office of 25 Research program on the LOCA will address that. I NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross com
188 1 mean, they will be taking high-burnup fuel; they will 2 be running it out to 17 percent oxidation and 3 thermally shocking it, and one will then find out 4 whether that will, in fact, spall it out.
5 MR. WERMIEL: This is Jared Wermiel, Chief 6 of the Reactor Systems Branch.
7 Yes, we know the research program is going 8 to be looking at the effect of different cladding 9 materials in a LOCA, but I'm not aware, at least not 10 from what I can recall reading about their program, 11 that it is going to consider highly-oxidized materials 12 at all, particularly materials that would have been 13 oxidized to the point where, under these test 14 conditions, they may spall, at least not that I can 15 think of. That is something we can talk to them 16 about, though.
17 Getting such material is not going to be 18 easy, I wouldn't think. They may have access to 19 highly-oxidized cladding. I'm not sure. I don't 20 believe they do. But it is something we can talk to 21 them about. This issue that you're raising, Dr.
22 Powers, is I think something to think about.
23 MEMBER POWERS: I guess that's all I ask 24 for.
25 MEMBER WALLIS: Anything else for Mr.
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189 1 Landry?
2 (No response.)
3 Then I would like to hand this back to 4 you, Mr. Chairman.
5 CHAIRMAN APOSTOLAKIS: Thank you.
6 You're all aware of the fact that at 1:30 7 we have a foreign visitor. So we really have to be 8 here at 1:30. So we are recessing until 1:29.
9 There is a handout that I advise you to go 10 over before we meet.
11 (Whereupon, the foregoing matter went off 12 the record for lunch at 12:37 p.m. and went back on 13 the record at 1:30 p.m.)
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230 1 A-F-T-E-R-N-O-O-N S-E-S-S-I-O-N 2 (2:37 p.m.)
3 5) NORTH ANNA AND SURRY LICENSE RENEWAL 4 APPLICATION 5 CHAIRMAN APOSTOLAKIS: The subject is the 6 North Anna and Surry license renewal application. Mr.
7 Graham Leitch, please lead us through this complex 8 issues.
9 5.1) REMARKS BY THE SUBCOMMITTEE CHAIRMAN 10 MEMBER LEITCH: Okay. Let me just remind 11 the Committee that on July the 9th, I think it was, we 12 had a subcommittee meeting dealing with the license 13 renewal application for North Anna and Surry.
14 At that time, we had an SER with comments.
15 There were some open items and some confirmatory 16 action items. In the meantime, a final SER has been 17 issued which resolved those open items and 18 confirmatory items. And there was a fairly 19 significant rewrite of Chapter 4 dealing with TLAAs, 20 which is the one part of the SER that was perhaps 21 somewhat new since the subcommittee meeting.
22 So I would just remind the Committee that 23 we want to be sure to leave enough time to talk about 24 those TLAAs. Since they come near the end of the 25 agenda, we want to be sure that we don't run out of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W.
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231 1 time for that discussion.
2 So, with that introductory remark, then 3 I'll turn it over to P. T., who will lead us through 4 the discussion. P. T. Kuo. Thank you.
5 MR. KUO: Thank you, Dr. Leitch.
6 5.2) BRIEFING BY AND DISCUSSIONS WITH 7 REPRESENTATIVES OF THE NRC STAFF AND DOMINION 8 REGARDING THE LICENSE RENEWAL APPLICATION FOR THE 9 NORTH ANNA AND SURRY POWER STATIONS AND THE 10 ASSOCIATED NRC STAFF'S FINAL SAFETY EVALUATION 11 REPORT 12 MR. KUO: My name is P. T. Kuo, the 13 Program Director for the License Renewal and 14 Environmental Impacts Program. Before I turn over 15 this meeting to Dominion, I would just mention that 16 because of the heavy snow today and the treacherous 17 road conditions, some of our staff was not able to 18 make it here today. But they are on the telephone.
19 They will make their presentations and answer any 20 questions you may have on the telephone if there is 21 any.
22 CHAIRMAN APOSTOLAKIS: How can they make 23 a presentation on the telephone?
24 MR. KUO: We have people to flip the 25 charts for them.
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232 1 CHAIRMAN APOSTOLAKIS: They are not 2 flipping the charts at their homes.
3 MR. KUO: Right. But just in case that is 4 ineffective, we also have other staff here to back 5 them up.
6 Like Dr. Leitch said during the last 7 subcommittee meeting in July this year, we had a few 8 open items, confirmatory items, that were in 9 discussion. Subsequently the staff has been able to 10 resolve all of these issues and then, as you said, 11 rewrote the section considerably.
12 For the safety review, Mr. Omid Tabatabai 13 is the project manager. He is going to provide the 14 Committee with an overview first. And then we will 15 have the staff members to present the different 16 subject matter.
17 I also want to report to the Committee 18 that in the previous Committee meetings, I have said 19 that we are working on a post-renew inspection 20 procedure. I am happy to say that the procedure has 21 been completed already, and it will be issued shortly.
22 Currently in terms of North Anna and 23 Surry, we are working with the applicant on a 24 Committee list. Hopefully we would be able to include 25 in the SER a Committee list. That list will be used NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W (202) 234-4433 WASHINGTON, D.C. 20005.3701 www nealrgross com
233 1 for the post-renew inspection.
2 So, with that, if there is no question for 3 me, then I will turn the meeting over to Bill.
4 MEMBER LEITCH: P. T., that document, 5 those post-review or inspection procedures, is there 6 a document number associated with that yet?
7 MR. KUO: Not yet. That hasn't been 8 issued yet because we tried to put together the list.
9 And then we have that in there.
10 MEMBER LEITCH: Okay. Thank you.
11 MR. KUO: You're welcome.
12 MR. CORBIN: All right. I'm Bill Corbin.
13 I'm the Director of Nuclear Projects for Dominion and 14 would like to talk to you today a little bit about the 15 Surry and North Anna application.
16 I know that we have indicated we want to 17 make sure we save some time at the end for a 18 discussion on TLAA. So I will try to move through my 19 slides fairly quickly. Of course, if you have 20 questions, please.
21 The participants. I have also brought 22 some additional people with me today who are sitting 23 here. As you can see, their names are up here: Paul 24 Aitken, Mike Henig, Tom Snow, John Harrell, and also 25 Ian Breedlove. These individuals I may be looking at NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE. N W.
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234 1 over the course of the discussion depending on where 2 our questions go.
3 The purpose of the meeting, I want to give 4 you just an overview of the application. That was the 5 agenda item that we have. So, moving along to number 6 4, make sure I'm on the right page here, the license 7 renewal application itself was submitted on May 29, 8 2001. Our format wasn't such -
9 CHAIRMAN APOSTOLAKIS: Have you already 10 given an overview to the NRC staff?
11 MR. CORBIN: Yes.
12 CHAIRMAN APOSTOLAKIS: This is not the 13 first time they have seen this?
14 MR. CORBIN: No. That is correct.
15 CHAIRMAN APOSTOLAKIS: So you are just 16 using slide number 3 from another presentation?
17 MR. CORBIN: Slide number 3 from another 18 presentation? Really, we just put this together to -
19 CHAIRMAN APOSTOLAKIS: Provide NRC staff?
20 We are not staff.
22 CHAIRMAN APOSTOLAKIS: Right.
23 MR. CORBIN: Correct. Thank you very 24 much.
25 CHAIRMAN APOSTOLAKIS: You are so welcome.
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235 1 But the staff has seen this?
2 MR. CORBIN: Yes, they have.
3 On the background, page 4, the format is 4 consistent with NEI 95-10, Rev. 3, NUREG. And what is 5 really important about this slide I guess to recall is 6 the Class of '01, which we consider ourselves to be 7 members of, was not expected to use the draft GALL 8 report. Obviously we did read and review it, but 9 we're really not being held to it. We're one of the 10 last in that genre. You also see Duke and Exelon in 11 that same category.
12 With regard to the format, the sections 13 that we will discuss today are sections 2, 3, and 4.
14 This is strictly in accordance with 95-10, Appendix A 15 on the UFSAR supplement and Appendix B. Our Appendix 16 C is a little bit different in that it's an aging 17 management review methodology, really not specifically 18 required by any document, but we felt that it 19 contained fairly significant information that helped 20 to explain how we went about doing the aging 21 management reviews; and then, finally, Appendix E for 22 the environmental report supplement. There were no 23 tech spec changes; hence, no Appendix D.
24 Section 2, then, using the 10 CFR 54.4 25 scoping criteria, we did develop a set of individual NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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236 1 tables, four tables in all systems that were in scope 2 and structures that were in scope. Then, to be 3 complete, we also identified those systems and 4 structures in its separate tables that were not in 5 scope.
6 With regard to the methodology, we will 7 talk a little bit about how we did the mechanical, 8 civil, structural, and electrical; first, mechanical.
9 We reviewed the documentation sources that we had 10 in-house to identify intended functions. This 11 includes equipment database system, UFSAR maintenance 12 rule scoping, other documents that we already had 13 in-house to identify those intended functions, then 14 used our component database to identify specific 15 components that supported each of those intended 16 functions, and develop license rule boundary drawings.
17 Specifically now we are talking about the mechanical 18 portion of the review.
19 On civil/structural, we again reviewed 20 documentation sources, similar to what we did in 21 mechanical, although we did have some additional 22 sources to look at, and used that to identify 23 structural detail drawings to identify those members 24 that supported the intended functions.
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237 1 different approach here. The passive electrical/I&C 2 components were screened on a plant-level basis. This 3 is similar to what some previous applicants had done 4 sometimes referred to as the spaces approach.
5 MEMBER LEITCH: Bill?
6 MR. CORBIN: Yes?
7 MEMBER LEITCH: Were there not some issues 8 with scoping as far as the off-site power supply and 9 how much of that should be included in the scope?
10 Could you just refresh us on that discussion? I know 11 the issue has been resolved, but could you clarify 12 just what the resolution was?
13 MR. CORBIN: Right. When we initially put 14 the application together, we identified those 15 components that were specifically associated with the 16 station blackout diesel in the way it was 17 interconnected to our power supplies. We did not 18 include off-site power and those things that are 19 related to the switchyard in the scope.
20 As a result of the review performed by the 21 staff and the discussions we had with the staff, we 22 have included portions of the off-site power supply; 23 that is, components and the switchyard, as they relate 24 to getting back into the main power distribution 25 system for the plant.
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238 1 So that has been included. That was a 2 change.
3 MEMBER LEITCH: Thank you.
4 MR. CORBIN: Okay. On the screening 5 results, then, for all three areas, mechanical, 6 structural, and electrical and I&C, we tabulated that 7 in the application with a description; UFSAR 8 reference, which included a hyperlink back to a copy 9 of the UFSAR; license renewal boundary drawings, which 10 also were hyperlinked; -- this drawing is basically 11 for mechanical systems -- and the components subject 12 to an AMR. So that was how we summarized in the 13 application the results of the screening review.
14 Moving on to Section 3, make sure I'm on 15 the right slide. Section 3, we had a text section for 16 each portion of the application. In that section, you 17 can read the bullets here behind me or on the slide in 18 front of you.
19 We identified system and component 20 description. We identified an AMR results table, 21 which was hyperlinked, too; -- you can see that on the 22 next slide, an example of it anyway -- whether there 23 were generic topical reports that had been identified; 24 and then a little more specifically what was the total 25 set of materials for this particular part of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W (202) 234-4433 WASHINGTON, D C. 20005-3701 www nealrgross com
239 1 plant; the environments; the aging effects; and TLAAs 2 if they were applicable. This is all identified in 3 the application; finally, the aging management 4 activities.
5 With regard to the table, we used a 6 standard six-column table format. That obviously is 7 going to change as we get into newer applications and 8 the use of a GALL, but the time that our application 9 was in the six-column format was still in vogue, I 10 guess you could say. And you could see the component 11 groups, the passive functions, material groups, 12 environments, aging effects, and aging managing 13 activities identified.
14 Any questions on section 3, how that was 15 put together?
16 (No response.)
17 MR. CORBIN: Getting into time-limited 18 aging analyses, then, the generic TLAAs had to do with 19 reactor vessel neutron embrittlement; metal fatigue; 20 EQ; tendon prestresses, not applicable to us, Surry 21 and North Anna power stations, the containments do not 22 have tendons; and containment liner plate and 23 penetration fatigue.
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240 1 later, particularly on embrittlement and EAF. I know 2 that that is an area you want to look at.
3 We would be happy to answer questions as 4 the licensee if you have any with regard to some of 5 those items or we can wait for the staff.
6 MEMBER LEITCH: I think if you're still 7 going to be in the room, I think we could wait and 8 hear the staff's presentation. Then we'll get into a 9 discussion of this.
10 MR. CORBIN: Very good. Very good. Other 11 plant-specific TLAAs, then, you can read the list 12 here: the crane load cycle limit, flywheel 13 leak-before-breaks, spent fuel pool liner, piping 14 subsurface indications, and Code Case N-481 for the 15 reactor coolant pumps.
16 Moving on quickly, -- I'm trying to go as 17 quickly as I can here -- Appendix A on the UFSAR 18 supplements, a long sentence here, but basically it's 19 a summary of all of the programs. And the types of 20 programs can include prevention, mitigation, condition 21 monitoring, and performance monitoring. This follows 22 the NEI 95-10 format.
23 In Appendix B, we had a total of 19 24 programs that were existing programs. Examples of 25 that might be chemistry control, ISI, boric acid NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W.
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241 1 corrosion, et cetera.
2 We did identify, however, four new 3 activities: buried pipe and valve inspections, 4 infrequently accessed areas inspections, tank 5 inspections, and cable monitoring. We ended up adding 6 cable monitoring after our submittal as a result of 7 our discussions with the staff and in answering some 8 of their questions.
9 MEMBER LEITCH: Just a couple of questions 10 in that area. Could you review for us the one time 11 buried piping inspection? In other words, is this 12 just an opportunistic inspection or at the end of the 13 current license period if the opportunity has not 14 presented itself, did you look or could you just go 15 into that a little bit?
16 MR. CORBIN: Yes. It is our intention 17 that by the end of the period, the current license 18 period, the 40-year license, that we will deliberately 19 go and look at each of the types of buried pipe that 20 we need to.
21 However, we will be somewhat opportunistic 22 up to maybe a year before that time. If we are out in 23 the yard and digging, we will take it for that 24 inspection. But with T-1 year to go, if we have not 25 accomplished some of the buried pipe inspections, we NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE. N W.
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242 1 will deliberately go out in the yard, dig a hole, 2 uncover the pipe, and perform the inspection. So it's 3 not strictly opportunistic.
4 MEMBER LEITCH: Okay. Thank you. The 5 cable monitoring program, there is some testing there, 6 I believe, for treeing; that is, cable that has been 7 -- I guess, really, as I understand the situation, the 8 first line of defense is to seal the manholes and the 9 duct banks and so forth so that there is not moisture 10 there. But in some cases, you may find moisture in 11 spite of that or perhaps there are some cables that 12 have historically been exposed to moisture. That 13 leads to a testing program, does it?
14 MR. CORBIN: Yes, an evaluation. So our 15 first line of defense, just as you say, is correct, is 16 to try and inhibit the environment of flooded cables 17 from existing. We have identified activities that we 18 will perform to keep the water out of manholes, for 19 example, or other places where groundwater could leak 20 in.
21 But if we have a persistent issue with 22 groundwater, then we will evaluate those cables for 23 water treeing or other types of degradation for a 24 cable.
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243 1 that testing been established or is that something 2 that we hope for further developments before the end 3 of the current license period?
4 MR. CORBIN: We, like much of the 5 industry, are waiting to identify a set of tests or a 6 test that will be able to be performed that can 7 explicitly show the type of degradation from water 8 treeing or other mechanisms. We will follow the 9 industry in terms of trying to identify a type of test 10 that could be performed. Right now there really is 11 nothing out there that we're aware of that explicitly 12 tries to find that kind of degradation mechanism.
13 MEMBER LEITCH: Okay. Thank you.
14 VICE-CHAIRMAN BONACA: Regarding the 15 existing activities, do you have to enhance any of 16 them to address the license renewal or they are just 17 the same activities?
18 MR. CORBIN: No. In fact, on the existing 19 activities, in some cases, we do have to do 20 enhancements. We have identified those in the UFSAR 21 supplement and the commitments that go along with them 22 where we know we need to do additional activities.
23 One right off the top of my head that I 24 can think of is our civil/structural monitoring 25 program, where we know we have got to include some NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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244 1 additional inspections. That is just an example, but 2 that is an existing program we do have to add new 3 steps.
4 MEMBER RANSOM: Are you required to do 5 anything in terms of inspecting for internal corrosion 6 and buried pipelines or -
7 MR. CORBIN: The internal corrosion on 8 buried pipelines, we are taking credit of our work 9 patrol program in that buried pipe eventually will 10 surface somewhere in a building or at a valve or in 11 some other location, where we can as part of work 12 patrol, for example, take the bonnet off the valve.
13 And we have an opportunity to look at the inside of 14 the pipe.
15 The assumption here, of course, is that 16 the environment, the internal environment, is 17 consistent, whether the pipe is buried or whether it 18 has come up in a building.
19 MEMBER RANSOM: Well, in that line, do you 20 do any inspection of piping in general or is that 21 required?
22 MR. CORBIN: Well, on the line, yes, we 23 will have committed to whatever is appropriate for 24 that material in the environment. Carbon steel in a 25 condensate environment, we might pick up chemistry NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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245 1 controls in aging management activity. We might pick 2 up flow system corrosion, for example. So whatever 3 the line is, the material-environment combination, 4 yes, we will have to do inspections on interior 5 conditions.
6 MEMBER RANSOM: Is there any requirement 7 to do any pressure testing of those components 8 periodically or at relicensing?
9 MR. CORBIN: I am trying to think through.
10 I am trying to catalogue all of the pipes and 11 everything that we have got in the plant. I am not 12 sure if we committed to pressure testing or not.
13 Paul, do you know or can you recall?
14 MR. AITKEN: This is Paul Aitken.
15 Pressure testing would be related to Class I 16 in-service, what we call I think it is exam category 17 BP, where we pressure test at a set frequency and go 18 out and do visual exams, look for leakage. That would 19 be the incidence. I don't think we would so much see 20 it on the secondary plant as we would on the primary 21 plant.
22 MR. CORBIN: Right.
23 MEMBER SHACK: You are going to replace 24 the vessel heads on the North Anna plant. What are 25 you going to do with Surry?
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246 1 MR. CORBIN: We're replacing vessel heads 2 on all four plants.
3 MEMBER SHACK: Four plants.
4 MR. CORBIN: And our current plan is to do 5 that before the end of 2003 in each of the next 6 outages for each unit.
7 MEMBER SHACK: That will involve you will 8 have to cut holes in the containment to do that?
9 MR. CORBIN: That is correct. As a matter 10 of fact, tomorrow we will start removing concrete on 11 North Anna Unit II as the first of our four vessel 12 head replacement programs.
13 MEMBER RANSOM: Why are they being 14 replaced? Is there corrosion on the heads?
15 MR. CORBIN: This is the inspections that 16 you do on the J-groove welds. I don't have a good 17 diagram for you. The inspections on the J-groove 18 welds are showing signs of -
19 MEMBER RANSOM: Cracking?
20 MR. CORBIN: -- cracking that will require 21 repair work. We made a decision that, rather than 22 spend the dose, time, and dollars to do repairs, which 23 would be possible, that it was really more effective 24 for us simply to go ahead and put a new head on.
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247 1 found a head in the Framatome factory in France and 2 were able to secure it. So that seemed like the 3 better approach, and that is what we are going to do.
4 MEMBER SHACK: Now, when you repair the 5 containment, how do you assure yourself you can meet 6 the design requirements?
7 MR. CORBIN: When we put the containment 8 back together, there really are two elements there.
9 One has to do with the liner plate. One has to do 10 with the concrete going back in. On the liner plate, 11 we will obviously weld that out and do local leak rate 12 testing as well as other forms of non-structured 13 examination to assure ourselves that that has been 14 welded back in. It is a fairly thin plate. I think 15 it's a quarter or three-eighths inch plate. It's not 16 all that thick.
17 Structurally, when we put the concrete and 18 rebar back in, we do intend to perform a structural 19 integrity test. It may turn in to be an integrated 20 leak break test. We currently have an action in to 21 the NRC for review to try and make sure that we 22 perform the correct test to validate the structural 23 integrity of the containment. But it will involve 24 pressing up containment.
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248 1 covers the repair of the containment or that is an 2 engineering design that you do on an ad hoc basis?
3 MR. CORBIN: Ad hoc? I'm not sure I would 4 go there, but we are doing it as part of engineering 5 design. And we are trying to satisfy code 6 requirements for both the liner and the concrete.
7 What we would do on the concrete, for example, in 8 accordance with IWL on the outside is look for any 9 signs of cracking or deformation or degradation as a 10 result of doing that, whether it is an SIT or IRT, 11 whichever test we end up performing.
12 MEMBER SIEBER: That's usually done in 13 conjunction with the design pressure test, where you 14 map the cracks in the concrete, integrated leak rate 15 test. This is a lower pressure.
16 MR. CORBIN: Right. We just have to 17 decide which pressure that we are going to press 18 containment to. There are still questions there. I 19 am not being as explicit as I could because I just 20 don't have all of the answers yet. We are still -
21 MEMBER SIEBER: I'm trying to help you.
22 MR. CORBIN: I know. And I appreciate the 23 help. But we aren't quite all the way there in terms 24 of exactly what kind of tests we are going to do.
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249 1 containment. I will say that.
2 MR. KUO: If I may, I just want to answer, 3 Bill, your question that yes, there is a code 4 requirement for doing this structure integrity test, 5 standard replant requirement also.
6 MEMBER SHACK: But we heard this morning 7 they were going to do the integrated leak rate test.
8 It doesn't seem to be a requirement, for example, 9 through the design pressure test, which I would have 10 thought that would have been my guess as to you have 11 to cut a big hole in the containment.
12 MR. KUO: You are right that the strength 13 integrity test and the leak rate test are being tested 14 at different pressure. One is at the 1.1 p and the 15 other is at design pressure.
16 MEMBER SIEBER: They are done for two 17 different reasons, too. The integrated leak rate test 18 is really testing the membrane, as opposed to the 19 concrete reinforcement rod structure.
20 When you go and cut a big hole in 21 containment, that is really what you are working with.
22 You are working with the rebar. And you are working 23 with the concrete and rearranging it as well as the 24 membrane inside, which is the liner.
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250 1 it would appear that the design pressure test would be 2 more appropriate when you're cutting a big hole in 3 there and changing rebar and you have old concrete and 4 new concrete.
5 MR. KUO: I'm sure the staff will review 6 it. There are requirements for that.
7 MEMBER SHACK: Well, I'll explain. People 8 have been cutting holes in containments now for some 9 time, whether heads or steam generators. I would have 10 thought by now we would have settled whether it takes 11 a leak rate test or a design pressure test.
12 MR. KUO: I think for those in those 13 cases, we did the leak rate test. Some of them are 14 still contaminated, by the way.
15 MEMBER SIEBER: And that's different.
16 MEMBER SHACK: That's different.
17 MR. KUO: That's different.
18 MR. CORBIN: Okay. Moving on, just one 19 comment we would like to emphasize about Appendix B, 20 we did deal with an operating experience in two kinds 21 of ways. First of all, our industry and in-house 22 operating experience really is rolled in as part of 23 our corrective action program. So that is an ongoing 24 process.
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251 1 goes, we also took a review of operating experience 2 looking for specific aging issues. We wanted to make 3 sure that specific aging issues out there were 4 addressed as part of our application, were built into 5 the way we addressed our programs.
6 With regard to Appendix C, again, not 7 required as a reviewer's aid, but it did offer some 8 good information with regard to grouping of systems, 9 short-lived components, and consumables, aging effects 10 and mechanisms evaluating, gave some methodology 11 information on how we went about doing the review.
12 Finally, Appendix E on the environmental 13 report. You can read here it was done in accordance 14 with the NEPA guidelines, NUREG-1437, and the GEIS.
15 Severe accident mitigation alternatives were 16 considered. In fact, the SAMAs was the area where we 17 received RAIs. Those were resolved. The net result 18 is environmental impacts of small and smaller than 19 reasonable alternatives. That was the result of the 20 review.
21 Closing remark simply is the effects of 22 aging associated with Surry and North Anna will be 23 adequately managed so that there is reasonable 24 assurance the intended functions will be maintained 25 consistent with the current licensing basis during the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W.
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252 1 period of extended operation. This was the basis of 2 our review. This was the conclusion we tried to 3 reach.
4 And that concludes my remarks. If there 5 are other questions?
6 MEMBER LEITCH: I had a couple of 7 questions, I guess, Bill. One concerned flow-assisted 8 corrosion. That is, I believe you were going to give 9 us some information about how much piping had to be 10 replaced as a result of being identified via the 11 CHECKWORKS program and so forth. Would this be an 12 appropriate time to talk about that?
13 MR. CORBIN: It can be. We did, as a 14 matter of fact, provide some information to the staff 15 to follow up. I think Omid is going to talk about 16 that.
17 MR. TABATABAI: This is Omid Tabatabai.
18 I am the project manager for North Anna/Surry. We 19 have a staff presentation on this issue. Dominion has 20 provided data, and the staff has verified and has 21 studied that information.
22 MEMBER LEITCH: Okay. We can defer that, 23 then, until we hear from the staff.
24 MR. TABATABAI: Sure. We will cover it.
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253 1 here who is our flow-assisted corrosion lead if we get 2 into some detailed questions who might be able to 3 assist.
4 MEMBER LEITCH: Okay. Good. And the 5 other issue I guess related to the method of Class I 6 piping inspection with regard to the Summer crack. In 7 other words, just what is the method going to be for 8 inspecting that pipe? I think that may be another 9 issue where the staff has a presentation.
10 MR. CORBIN: Yes. Again, we provided 11 information to the staff that they reviewed. I think 12 Omid is going to say the same thing.
13 MR. TABATABAI: Yes, exactly. We have a 14 presentation on that issue.
15 MEMBER LEITCH: Good.
16 MEMBER FORD: And the same with the PTS 17 question.
18 MR. CORBIN: And the PTS question, again, 19 the same.
20 MEMBER LEITCH: Okay. Are there any other 21 questions for Bill, then, at this time?
22 (No response.)
23 MEMBER LEITCH: Okay. Thank you very 24 much, Bill.
25 MR. CORBIN: I thank you very much.
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254 1 MEMBER LEITCH: Don't leave yet though.
2 You can leave there, but don't leave the room.
3 MR. CORBIN: Thank you.
4 MEMBER LEITCH: And we'll turn it over to 5 the staff for their presentation now.
6 MR. TABATABAI: Good afternoon. My name 7 is Omid Tabatabai. I am the NRC project manager for 8 the review of applications submitted by Dominion for 9 license renewal of North Anna and Surry.
10 I would like to go over the agenda for 11 today's presentation. We have presented our SER with 12 open items to the ACRS subcommittee back in July. We 13 were asked to provide more information and some data 14 on the specific issues. These are the items that we 15 have been asked to provide information.
16 The first topic that we are going to 17 present is license renewal inspection. Mr. Caudle 18 Julian, who is on the phone right now, will make this 19 presentation. I will not talk about the license 20 renewal inspection program.
21 The second topic is neutron vessel 22 embrittlement. Barry Elliot is on the phone and Mr.
23 Matt Mitchell, who will cover upper-shelf energy and 24 PTS evaluation. We have Mr. Simon Sheng here. He 25 will talk about the generic aspects of V. C. Summer NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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255 1 Mr. Leitch you asked and also its applicability to 2 North Anna and Surry plants.
3 The last item that we have, Mr. Parczewski 4 will talk about the trend of erosion/corrosion or 5 flow-accelerated program at North Anna and Surry.
6 These are basically the topics of our presentation 7 today.
8 I would like to go over quickly on the 9 North Anna and Surry power plants. They are all 10 three-loop Westinghouse design. The current license, 11 operating licenses, will expire on April 2018 and 12 August 2020 for North Anna Units I and II. For Surry 13 Units I and II, the operating licenses will expire on 14 May of 2012 and January of 2013.
15 As far as staff's review milestone and 16 schedule, we received the applications on May 29, 17 2001. The staff issued a safety evaluation report 18 with open items on June 6. We issued the safety RAIs 19 back in November 2001. And, as I mentioned, we 20 briefed the ACRS subcommittee back in July of 2002.
21 The staff has met all the milestones. And 22 according to the new review schedule, 22-month review 23 schedule, the Commission is expected to announce its 24 decision by March of 2003 if a renewed license is 25 approved.
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256 1 Safety evaluation with open item was 2 issued on November 5, 2002. The staff has divided 3 safety evaluation into four chapters. Chapter 1 talks 4 about a general discussion and introduction; Chapter 5 2, evaluation of scoping and screening methodology by 6 the applicant. Chapter 3 talked about the evaluated 7 and reviewed aging management programs. And in 8 Chapter 4, we performed a time-limited evaluation of 9 time and aging analysis.
10 The SER open items, we had one open item 11 in Chapter 2, scoping and screening. It was related 12 to the station blackout issue that Mr. Leitch asked 13 about, including off-site power into the scope license 14 renewal. That was one of the open items we had.
15 We had three open items in aging 16 management program, aging management review, Chapter 17 3, which related to non-EQ 18 cable program. And we had four open items in TLAA 19 issue, which related to fatigue and environment and 20 assisted fatigue issues. SER with no open item, in 21 fact, we saw all the open items. And there were no 22 outstanding issues in our SER right now.
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257 1 are any questions for me, I will be happy to answer.
2 Caudle, can you hear me?
3 MR. JULIAN: Very good. Can you hear me 4 okay?
5 MR. TABATABAI: Yes.
6 MR. JULIAN: Okay. I would like to run 7 through the presentation from start to finish, if 8 possible, since I can't see you. And then I will 9 answer questions at the end.
10 Our first slide, which the Committee had 11 seen before, describes our license renewal inspection 12 program. We are following our manual chapter 2516 and 13 license renewal inspection procedure 71002. We 14 provide a site-specific inspection plan for each 15 applicant, and this is done for the Dominion case.
16 The schedule we're following is the standard 30-month 17 model of NRR. And we can do the inspections at set 18 times.
19 The resources that are needed for our 20 inspection are a five-member team. We have been 21 carrying the same team as long as we can, but when we 22 lose them, which happens every once in a while, we 23 have a training program for replacement.
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258 1 inspection. The objective of that was to confirm that 2 the applicant tests included all appropriate systems, 3 structures, and components in the scope of license 4 renewal as required by the rule. It was one week in 5 length, conducted February 4th to 8th at the corporate 6 engineering offices because that is where they did 7 most of the work for building their application.
8 Some typical results from that inspection 9 are that we found that the applicant had significantly 10 expanded the scope of components to be considered for 11 aging management considerations due to the staff 12 concern over non-safety-related to safety-related 13 interactions.
14 I think we have talked about this issue 15 before. It is a concern that non-safety-related 16 piping might fail due to aging and do damage to 17 safety-related. We found that the applicant had done 18 a wide expansion of their original scope of 19 components, and we thought that was the conservative 20 thing to do.
21 Another issue was that we do a walk-down 22 and containment during a refueling outage as part of 23 our inspections. The only thing we found that was of 24 concern at all to us there was that the Surry 25 component cooling water piping inside containment had NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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259 1 a lot of corrosion. The applicant had known this for 2 a long time and periodically had put it in their 3 corrective action systems, but it didn't seem to be a 4 very organized program for looking at this.
5 While we were there, the applicant took 6 some ultrasonic measurements to confirm that the 7 piping is not corroded to below minimum wall. Since 8 then, they have developed a procedure as part of their 9 general condition monitoring program to continued to 10 monitor the corrosion of this piping to see that it is 11 not yet too thin.
12 The second inspection was the aging 13 management inspection.
14 MR. ROSEN: One question.
15 MR. JULIAN: The objective of that is to 16 confirm that existing -
17 MR. TABATABAI: Excuse me, Caudle. There 18 is a question for you.
19 MR. JULIAN: Okay.
20 MR. ROSEN: On the component cooling water 21 piping inside containment corrosion, does that extend 22 outside containment as well? And if so, what is being 23 done with piping outside containment? Can you 24 characterize the kind of corrosion it is? What is the 25 root cause? What kind of degradation is being seen?
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260 1 I understand it is not below wall, but I would like 2 more information than that.
3 MR. JULIAN: Okay. I had a real tough 4 time hearing the question, but I understood that your 5 concern is or question was about piping, both inside 6 and outside. Both of those pipings, inside and 7 outside, are included in their general condition 8 monitoring program.
9 The cause of this piping corroding is that 10 it's often chilled water. In fact, containment with 11 a fairly heated atmosphere, the chilled water tends to 12 have condensation on it all of the time. And that is 13 a common problem that we see at a lot of places.
14 MR. ROSEN: Okay. So now I understand it 15 is exterior corrosion?
16 MR. JULIAN: Exterior, yes. I'm sorry.
17 Exterior corrosion on the piping, rusty. It's rusty 18 looking.
19 MEMBER LEITCH: So though the program 20 includes both piping inside containment as well as 21 outside containment, -
22 MR. JULIAN: That is correct.
23 MEMBER LEITCH: -- the problem is really 24 just occurring on the inside containment basically due 25 to sweating of the pipe?
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261 1 MR. JULIAN: Yes, yes. And what we 2 thought would be a good thing that we see other places 3 is to establish set places to come back and monitor 4 periodically and have trending so that you can see how 5 not only what the current condition is but what are 6 the trends.
7 MR. ROSEN: And that's because only the 8 piping within the containment carries the chilled 9 water? Outside containment component cooling water is 10 not chilled?
11 MR. JULIAN: Well, it has to be cooled 12 down as it leaves the heat exchangers and has been to 13 the containment, but it's worse inside containment 14 because of the temperatures. With the pipe 15 continually wedded at an elevated temperature, it 16 tends to corrode worse than otherwise.
17 MR. ROSEN: How bad was the corrosion?
18 MR. JULIAN: Well, it looks bad. It looks 19 nasty. But, as I say, we did take some spots that 20 looked the worst and had the applicant to smooth them 21 up and take ultrasonic measurements to confirm that 22 they had not corroded to below min wall.
23 MR. ROSEN: Well, that is not very 24 comforting. Min wall is one thing, but how much 25 corrosion are we talking about? Are we talking about NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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262 1 surface corrosion or is it -
2 MR. JULIAN: Yes, surface corrosion.
3 MEMBER FORD: There was a question raised 4 at the subcommittee meeting about a difference in 5 materials between Surry and North Anna. You didn't 6 see the same problem and the same situation at North 7 Anna, I understand.
8 MR. JULIAN: No, I don't believe we did.
9 MEMBER FORD: Was that due to difference 10 in relative humidity or was it due to difference in 11 materials composition?
12 MR. JULIAN: I'm afraid I don't know the 13 answer to that.
14 MR. CORBIN: The significant difference 15 between Surry and North Anna in this regard is that 16 North Anna has a better coating system on their 17 component cooling water piping.
18 MEMBER FORD: So there's a reason for the 19 difference.
20 MR. CORBIN: Correct.
21 MEMBER FORD: Okay. Good.
22 MR. CORBIN: I'm sorry. Bill Corbin.
23 MR. ROSEN: And the solution to this 24 problem at Surry, I guess, is that it will be 25 monitored? Is that what I understand?
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263 1 MR. JULIAN: Yes. They have a monitoring 2 program and are going to continue to measure it, take 3 repeated measurements at set spots in the corrosion.
4 An alternate solution, of course, that 5 many people employ is to replace the piping, but 6 they're not going to want to do that until it gets to 7 the point where it is really necessary.
8 MR. ROSEN: So we're just going to watch 9 this piping corrode away from the outside at Surry?
10 Is that what the plan is? And the staff has agreed 11 with that? Is that what I understand?
12 MR. JULIAN: Yes. That's generally the 13 program that they're following, is to monitor the 14 piping and to take action to replace it before it gets 15 to the minimum design wall.
16 MR. JULIAN: Okay. May I continue on?
17 MR. TABATABAI: Go ahead, Caudle.
18 MR. JULIAN: Thank you.
19 The next inspection is the aging 20 management review. The objective there was to conform 21 that existing aging management programs are working 22 well and to examine the applicant's plans for 23 establishing new aging management programs and 24 enhancing existing ones.
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264 1 May. As with the Duke plant, which we told you about 2 earlier, we did one week at each site, one at Surry 3 and one at North Anna.
4 Two observations of interest there were at 5 Surry, the applicant was out looking at things ahead 6 of us. We went over and looked at some manholes in 7 the switchyard. The applicant was surprised to find 8 some water in those electrical cable manholes.
9 The solution to that as of now has been to 10 do periodic inspections. I understand now we're doing 11 inspections twice per week. They're looking for an 12 engineering solution. And that will probably be to 13 redesign a manhole to put in automatic sump pumps.
14 These manholes in question do not have automatic sump 15 pumps or drains in the bottom.
16 We also found that in the past both plants 17 had found containment concrete anomalies and had made 18 repairs. You have probably heard of those issues 19 where they started looking closely at containment and 20 found in the pieces of construction wood that was left 21 in the concrete. Those had to be removed and repairs 22 made.
23 The last and third, optional, inspection 24 that we did was one of open items. That was conducted 25 in September. We found that the applicant had made NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W (202) 234-4433 WASHINGTON, D.C. 20005-3701 www nealrgross com
265 1 some progress in making some of the plant procedures 2 changes to programs that needed to be done for 3 enhancing aging management programs.
4 And, most important to us, they had 5 established a tracking system to keep up with the 6 future actions that they had committed to do. That 7 was one of the concerns that caused us to do the third 8 inspection.
9 VICE-CHAIRMAN BONACA: I had a question on 10 the flooding of electrical cable manholes. Who found 11 those? Who found there was flooding there?
12 MR. JULIAN: Again I'm having trouble 13 hearing. I thought the question was who found those?
14 MR. TABATABAI: Yes, Caudle. The question 15 was who found the flooding cable manholes?
16 MR. JULIAN: The applicant did that. They 17 looked at a representative sample of manholes up at 18 North Anna before we got there. And then we also 19 peaked into them while we were there.
20 When we got to Surry, they had been 21 looking at some of those manholes. The ones we 22 selected to look at at Surry were not the normal 23 safety-related cable runs within the plant. We were 24 interested in the wiring that goes over to the 25 switchyard at Surry station, service tents. And those NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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266 1 manholes do not contain safety-related cables, but 2 they are brought into the scope of license renewal 3 because of the station blackout concern.
4 VICE-CHAIRMAN BONACA: Thank you.
5 MR. JULIAN: But they found it. One of 6 the issues that we discussed with them was that North 7 Anna has a very well-established procedure and program 8 for periodically going around and monitoring the 9 condition of manholes, but Surry has yet to develop 10 one of those. So Surry is now committed to do that in 11 their future as part of the agreement that we have had 12 with the staff.
13 MR. TABATABAI: Thank you, Caudle.
14 MEMBER LEITCH: I just want to be sure I 15 understand the total scope of the inspection program.
16 There was one week scoping and screening in the 17 corporate office?
18 MR. JULIAN: Correct.
19 MEMBER LEITCH: And then a physical 20 inspection at each plant, one week at each site?
21 MR. JULIAN: That's correct.
22 MEMBER LEITCH: And then two weeks in the 23 aging management review? That was in the corporate 24 office?
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267 1 the first part right. The scoping and screening was 2 one week long. And it was done all at the corporate 3 office because that is where all of the engineering 4 work was done. Then the aging management programs 5 were done one week at Surry and one week at North 6 Anna.
7 The reason, of course, for doing one at 8 each site is that we wanted to do a lot of 9 walk-arounds in the plant and take a look at a lot of 10 the plant equipment.
11 So it's not just a paper review. Our 12 inspectors have assigned systems. And they go out 13 with the applicant representatives and walk down those 14 systems.
15 MEMBER LEITCH: Then the open item 16 inspection, what was that, one week again at -
17 MR. JULIAN: That was just a few days, 18 just took two or three days, at the engineering 19 offices. Those are primarily chasing tracking systems 20 and changes that they needed to make to procedures.
21 MEMBER LEITCH: Okay. Thank you.
22 MR. JULIAN: One of the questions I think 23 we had last time that I wasn't able to make was about 24 the overall condition of the plant. We concluded from 25 our look that the plant was in good condition. And NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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268 1 what that meant to us was that the plant was clean and 2 everything was painted. There was little or no 3 corrosion of components wherever we went. There are 4 very few leaks and ones that existed are tracked for 5 repair. We thought overall that North Anna and Surry, 6 both plants, are being very well-maintained.
7 MR. ROSEN: That's with the exception of 8 the component cooling water piping in containment. Is 9 that correct?
10 MR. JULIAN: Right, with exception of 11 component cooling water, correct.
12 That concludes my presentation. Any more 13 questions?
14 (No response.)
15 MR. TABATABAI: Thank you, Caudle.
16 Barry, you are actually the next presenter 17 to talk about pressurized thermal shock.
18 MR. ELLIOT: This is Barry Elliot of the 19 Materials and Chemical Engineering Branch. I am going 20 to discuss the PTS evaluation that was done by the 21 applicant. First I am going to begin with a little 22 background. That is the first two slides.
23 The PTS evaluation is done in accordance 24 with the rule 10 CFR 50.61, the PTS rule. It requires 25 all licensees to determine whether the reactor NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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269 1 pressure vessel beltline materials exceed the PTS 2 screening criteria and to evaluate surveillance data 3 to determine the impact of the data on the PTS 4 evaluations.
5 The PTS screening criteria is a material 6 property. PTS screening criteria is 270 degrees 7 Fahrenheit for axially oriented welds and base metal 8 and 300 degrees Fahrenheit for circumferentially 9 oriented welds.
10 The RTps values are the sum of three 11 quantities: the unirradiated reference temperature, 12 the increase in reference temperature resulting from 13 irradiation, and margins. The increase in reference 14 temperature is a product of a chemistry factor and a 15 fluence factor. And the chemistry factor is dependent 16 upon the amount of copper and nickel.
17 When the Charpy test is performed, the 18 increase in transition temperature is equivalent to 19 the increase in transition to temperature from the 20 Charpy transition temperature.
21 The margin term is to account for 22 uncertainties in copper, nickel, neutron fluence, 23 unirradiated reference temperature, and calculation 24 procedures. The margin curve is a part of two sums:
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270 1 temperature, which is equal to 28 degrees for the 2 weld. This particular value is gotten from an 3 industry-wide surveillance database and also the 4 standard deviation for the unirradiated reference 5 temperature.
6 Next slide. Chemistry factor may be 7 determined from surveillance material or from the 8 chemical composition of the material. This is 9 according to the rules. Our chemistry factor is 10 determined from surveillance data if the surveillance 11 data meet the credibility criteria in the rule.
12 Chemistry factor can also be determined from tables 13 and rules based on the percentage copper and the 14 percentage nickel in the materials. And, finally, the 15 material surveillance data shall be evaluated to 16 determine whether the RTPTS value for the beltline 17 material is a bounding value.
18 Not in the rule but an important part of 19 the staff's evaluation and applicant's evaluation is 20 that the neutron fluence calculation should be done in 21 accordance with Reg. Guide 1.190. This is a staff 22 guidance document.
23 That is the background for the PTS rule.
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271 1 is going to be about the Surry-1 material surveillance 2 data. And it's limiting weld. The reason for that is 3 that this Surry-1 material surveillance data has a 4 weld, an axial weld, which at the end of the license 5 renewal term has an RTps value of 268.5.
6 The other three reactors are significantly 7 below that. North Anna I's value is 191. North Anna 8 II is 228. And Surry II is 219. And the highest 9 copper in any of those reactors is .19 while the Surry 10 I reactor axial weld has a .3 copper in its weld.
11 There were nine data points for the 12 limiting surveillance weld. They were done by three 13 different vendors. They were done in the '70s, '80s, 14 and '90s. And the applicant recalculated all of the 15 neutron fluences for all of the data using Reg. Guide 16 1.190, though all of the data would be on the same 17 methodology.
18 The applicant evaluated the data, and the 19 data did not meet the credibility criteria in the rule 20 because of large scatter in the data. The applicant 21 then used the methodology in the tables to calculate 22 the RTs value.
23 The staff was concerned that there could 24 have been a bias in the data. So we ran a z-test.
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272 1 indicating that the surveillance data are consistent 2 with the data used to develop the table in the 3 chemistry factor.
4 The conclusion from our z-test was that 5 the use of the chemistry factor from the table in the 6 standard deviation for the increase in reference 7 temperature of 28 is appropriate. That is the 8 evaluation of the surveillance data.
9 Next slide is the summary of the PTS 10 evaluation using the chemistry from the limiting weld.
11 The RTps value is 268.5 at that end of the license 12 renewal period. The RTPTS value is calculated using a 13 chemistry factor from the tables and is based on the 14 best estimate copper and nickel for the weld. All 15 neutron fluence for the weld was also calculated 16 according to Reg. Guide 1.190.
17 The staff confirmed that the RT~s value 18 was 268.5. And for Surry I, the unirradiated 19 reference temperature is -7, which is a generic value.
20 The increase in reference temperature was 206. And 21 the margin curve is 69.5.
22 The staff's conclusion is all materials 23 will be below the PTS screening criteria for the end 24 of the period of extended operation. That is the 25 summary of the staff's evaluation.
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273 1 MEMBER FORD: Barry, I've got a procedural 2 question for you. If that RTPTS value by calculation 3 had come to 270.1, then you would ask them the utility 4 to go into some remediation program. Is that correct?
5 MR. ELLIOT: I can't hear the question.
6 MEMBER FORD: The RTPTS value. Can you 7 hear me now?
8 MR. ELLIOT: Can you just tell me what the 9 question is?
10 MR. TABATABAI: Barry, the question is 11 what would happen if the RTps value were 270.1? What 12 would we ask them to do?
13 MR. ELLIOT: Okay. 270.1, the licensee 14 would have two alternatives. You can do flux 15 reduction so that the value would be below the 16 screening criteria, which is probably what they would 17 do if that were the case, or they can do an analysis 18 that demonstrates that operating above the value would 19 be acceptable.
20 MEMBER FORD: Okay. So you've got one and 21 a half degrees Fahrenheit margin by the current 22 calculations. Could you chew up that margin just for 23 the uncertainty in your copper and nickel contents?
24 MR. ELLIOT: The margin of one and a half 25 degrees includes margin and nickel. That would be the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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274 1 margin curve.
2 MEMBER SHACK: It's a magic number.
3 MEMBER KRESS: It's a speed limit. You 4 get a ticket if you go over.
5 MEMBER FORD: Does the staff have any 6 procedure? When you get to close margins at one and 7 a half degrees F., by the procedure, does the staff 8 have any second thoughts as to how safe this is? I 9 recognize that 270 degrees F. has got all sorts of 10 uncertainties in it and margins. At what point does 11 the staff start to look at these things the second 12 time or a second -
13 MR. ELLIOT: As long as an applicant or a 14 licensee is below 270 for the axial weld, no matter 15 how low it is, that is all they have to do.
16 MEMBER KRESS: I am concerned about 271.
17 MEMBER FORD: Yes. It seems very, very 18 arbitrary. I recognize the 270 criterion is a fairly 19 arbitrary number, but at what point should you start 20 to get worried?
21 MR. ELLIOT: What time do I start to get 22 worried?
23 MEMBER FORD: Yes.
24 MR. ELLIOT: I get worried every day about 25 7:45, when I get to work, but I am not worried about NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W (202) 234-4433 WASHINGTON, D.C 20005-3701 www nealrgross com
275 1 this plant. This plant has nine data points which we 2 looked at carefully, which the licensee ha evaluated, 3 which we evaluated.
4 We even did a statistical evaluation. We 5 don't normally do that, and it's not in the rule. But 6 because they were close to the screening criteria, 7 because of the large amount of data and the data 8 itself, we decided to make an extra step, which was to 9 do the statistical analysis.
10 That gave me more assurance that the value 11 is a pretty good value.
12 MEMBER SHACK: Barry, what is the 13 statistical test really telling you? What were you 14 trying to determine from the statistical test?
15 MR. ELLIOT: What we do is we compare the 16 measured value for the actual surveillance data points 17 to the predicted value for that surveillance data 18 point. And then using the z-test and the standard 19 deviation for the model, which is 28 degrees, we 20 determined that it was within the limits of the 95 21 percent confidence limit. It had a five percent 22 significance level.
23 MEMBER SHACK: Since you determined that 24 the surveillance data wasn't applicable, why wouldn't 25 you just calculate it from the tables?
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276 1 MR. ELLIOT: You do calculate it from the 2 table. What I was concerned about, in essence, the 3 rule says if the data is credible, use the data. In 4 this case, the data was not credible. So you couldn't 5 use the surveillance data according to the rule. So 6 you automatically fall back to the table. And that's 7 what they did.
8 I was a little concerned that there wasn't 9 a sufficient margin, that there was more scatter in 10 their plant-specific surveillance data. There are 11 nine data points, but the analysis shows that it is 12 what would be expected from the database.
13 MR. TABATABAI: Any more questions for 14 Barry?
15 (No response.)
16 MR. TABATABAI: Okay. Thank you, Barry.
17 MR. ELLIOT: Okay. I'm going to stay on 18 the line for Matt's presentation, and I am going to 19 get off after that.
20 MR. TABATABAI: The next presenter is Matt 21 Mitchell. He is a senior materials engineer, and he 22 is going to talk about upper-shelf energy.
23 MEMBER SHACK: Just before you start, 24 Matt, did they already run a low leakage core?
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277 1 the licensee to explain how they define their core 2 design.
3 MR. HARRELL: This is John Harrell from 4 Dominion, supervisor for nuclear safety analysis.
5 Yes, we do operate with a low leakage core. We 6 monitor peripheral assembly relative power 7 distributions. Those would be in the realm of, say, 8 .4 relative to the average power distribution that 9 constitutes what we consider to be a low leakage 10 pattern already for Surry Unit I. We have flux 11 impression inserts in those peripheral assemblies.
12 MR. MITCHELL: Okay. Then to proceed with 13 the discussion on the upper-shelf energy issue, our 14 first viewgraph is merely a background slide. Bullet 15 1 reiterates the specific regulatory criteria from 16 Appendix G to 10 CFR Part 50 regarding upper-shelf 17 energy requirements for reactor vessel beltline 18 materials.
19 Of course, the item of interest in this 20 discussion is criteria 2 regarding the end-of-license 21 upper-shelf energy. Hence, extending the license, 22 increasing the fluence will lead to a further 23 reduction in the projected Charpy upper-shelf energy 24 as we move forward.
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278 1 I will call the equivalent margins analysis clause, 2 which is found in Appendix G to 10 CFR Part 50. It 3 provides for the ability for a licensee or for the 4 applicant to perform a demonstration to show that 5 lower values of Charpy upper-shelf energy are, in 6 fact, adequate for continued operation, an operation 7 until the end of their license.
8 It is worth noting, I think, at this point 9 that the accepted technology for performing equivalent 10 margin analyses is what I would call sure technology.
11 We have been using this approach based upon 12 elastic/plastic fracture mechanics, J-integral tearing 13 modulist evaluations now for the better part of a 14 decade. It is well-documented in Regulatory Guide 15 1.161 and in Appendix K to Section XI of the ASME 16 code.
17 So what we have here is a case where we 18 have merely reevaluated the condition of the vessel 19 based upon the higher fluence values to be expected at 20 the end of the period of extended operation using an 21 established technique.
22 MEMBER SHACK: What will their projected 23 Charpy energies be?
24 MR. MITCHELL: Well, you've gotten me to 25 my backup slide. I'll go straight there. Based upon NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W (202) 234-4433
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279 1 the information that the licensee submitted and the 2 staff is in agreement with the values they provided, 3 for Surry Unit I, which actually has both the limiting 4 axial and limiting circumferential weld, when you look 5 at the Surry Unit I and Surry Unit II vessels. On the 6 circumferential weld, it is approximately 42 7 foot-pounds on the axial, limiting axial, weld, it is 8 about 43.6 foot-pounds would be what it would be 9 projected out to be.
10 MEMBER FORD: What am I missing? Isn't it 11 50 pounds? You can't go below 50 foot-pounds?
12 MR. MITCHELL: Per the specific criteria 13 in Appendix G to 10 CFR Part 50, 50 foot-pounds is the 14 limit. If you go beyond that limit, then you require 15 the equivalent margins analysis. And it was the 16 equivalent margins analysis that was performed by the 17 applicant for the Surry Unit I and Unit II vessels.
18 MEMBER FORD: Again, isn't it exactly the 19 same situation with the PTS situation that you're 20 nudging against what the current rules say?
21 MR. MITCHELL: In effect, you could draw 22 a parallel between the 270-degree screening criteria 23 in 50.61 and the 50 foot-pound limit in Appendix G.
24 If you wish to draw another parallel, this would be 25 akin to an analysis like a Reg Guide 1.154 analysis, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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280 1 which could be done if a facility went above the 2 270-degree screening criteria relative to 50.61. This 3 analysis is considerably less cumbersome, however, 4 than a Reg Guide 1.154 analysis would be for PTS.
5 Certainly there is parallelism between those concepts.
6 MEMBER SHACK: If it was 51 foot-pounds, 7 you're home free.
8 MEMBER FORD: You're okay. Just as kind 9 of a concerned citizen, professional engineer, does it 10 not make you feel uncomfortable?
11 MR. MITCHELL: I'll just suggest that -
12 and particularly the words are valid with respect to 13 the PTS screening criteria. It is a screening 14 criteria. It is a criteria at which it is sort of a 15 yellow caution light in a sense, if you will, to draw 16 additional attention to and warrant further evaluation 17 of.
18 It's not intended to be a hard stop, if 19 you will. The 50 foot-pound limit with respect to 20 upper-shelf energy is also not intended to be a hard 21 limit. So it is open to further -
22 MEMBER FORD: But Barry just said for the 23 PTS, for instance, 271, you have to start to go 24 through some gyrations in terms of annealing or 25 whatever you are going to do.
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281 1 MR. MITCHELL: Well, in terms of first 2 looking at issues or the possibility for flux 3 suppression further analysis, whatever methods would 4 be available to the licensee, what would be a 5 warranted step relative to a screening criterion.
6 VICE-CHAIRMAN BONACA: Now, these 7 speculations and the results of them, of course, 8 depend on certain assumptions of fluence at the end of 9 license that you will monitor or they will be 10 monitored by licensee to the specimens and all kinds 11 of stuff.
12 So when you get a result and it is closed, 13 the criteria, what kind of reputation does take place 14 during the 20 years' operation? How do you assure 15 that you are staying within those criteria?
16 MR. MITCHELL: Well, let me answer one 17 part of the question first. With regard to the 18 fluence values which are used in this evaluation, as 19 we were the ones used in the PTS evaluation, it was 20 confirmed that those values were consistent with the 21 staff guidance in Regulatory Guide 1.190, which was 22 recently issued. Therefore, the staff felt confident 23 that those values were accurate projections of the 24 fluence out at the end of the extended period of 25 operation.
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282 1 With regard to continued monitoring, we 2 also have provisions established for the licensee to 3 continue with a reactor pressure vessel monitoring 4 program moving forward consistent with the intent of 5 Appendix H to 10 CFR Part 50. So there would be 6 measures in place to continue to acquire data as 7 appropriate. And that should be documented in the 8 staff's safety evaluation.
9 VICE-CHAIRMAN BONACA: And that includes 10 a program, I believe, of collection of data and how 11 frequently comparisons will be performed in the 12 department. I mean, certainly you don't want to get 13 to the point where some time in the 20 years of 14 extended operation, you are crossing over that line.
15 MR. MITCHELL: Yes.
16 VICE-CHAIRMAN BONACA: Right?
17 MR. MITCHELL: It would be certainly the 18 intent of the surveillance program is to provide you 19 with information in advance of when you would be 20 projected. Again, keep in mind I guess we should 21 emphasize the numbers that we have here are those that 22 are projected to occur at the end of the extended 23 license. Data acquired before then should give you 24 lead time.
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283 1 at this data because we specifically said we wanted to 2 see it. Now we see it coming through and show some 3 results which are more borderline than I expected.
4 So I would expect from now on licensees 5 will be required to submit this information for all of 6 the applications.
7 MR. KUO: Yes, Dr. Bonaca. We have made 8 it clear that the applications should have this kind 9 of information.
10 VICE-CHAIRMAN BONACA: Yes. And you'll 11 let us know if that is within the existing guidance or 12 if we need to change the guidance to be able to secure 13 this information.
14 MR. KUO: Sure.
15 MR. TABATABAI: Actually, Dr. Bonaca, this 16 was one of the items we discussed during a workshop we 17 had a few weeks ago with the industry, asking specific 18 information on neutron vessel embrittlement.
19 VICE-CHAIRMAN BONACA: Thank you.
20 MEMBER LEITCH: Is the bottom line on that 21 chart intended to be Surry II?
22 MR. MITCHELL: No. Actually, it's also 23 intended to be Surry I because the two bottom lines 24 represent the circumferential/limiting axial weld.
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284 1 axial weld were actually found in Surry I relative to 2 Surry I and Surry Unit II.
3 MEMBER LEITCH: So Surry Unit II is above 4 those numbers there?
5 MR. MITCHELL: Yes.
6 MEMBER LEITCH: For both axial and 7 circumferential?
8 MR. MITCHELL: That is correct.
9 MEMBER LEITCH: Okay. Thank you.
10 MR. ROSEN: Is it above 50?
11 MR. MITCHELL: No. There are materials in 12 the Surry Unit II vessel which do also drop below 50 13 foot-pounds. However, since they are bounded by the 14 Surry Unit I materials, the evaluation or review of 15 the evaluation of the Surry Unit I materials would 16 bound those. If these pass, they would also pass, the 17 equivalent margins.
18 MEMBER LEITCH: The SER refers to 48 19 equivalent full power years, but we are licensing the 20 plant for 60 years. Is it conceivable that in 60 21 years, one could go above 48 full power years?
22 MR. MITCHELL: Depending upon the 23 operational behavior of the plant, the availability 24 and capacity factors of the plant operates at, it 25 would be conceivable. I am not at this point aware.
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285 1 And perhaps the licensee would be in a better position 2 to answer what the potential is for that to occur.
3 MR. HARRELL: Yes. This is John Harrell 4 again from Dominion. Each reload is evaluated for its 5 contribution of fluence in the place that it is 6 expected from approximately 488PY.
7 So there is an ongoing tracking mechanism 8 for evaluating the effect of a reload core design on 9 that, and that includes a consideration capacity 10 factor as well as the relative power distributions in 11 the core. Of course, it also considers the effect of 12 many power operatings that occur in the interim.
13 So there is ongoing monitoring of the 14 effect of full power years relative to the limitation 15 that is present in the TLAA.
16 MR. ROSEN: What kind of assumption are 17 you making for operating capacity factor?
18 MR. HARRELL: Currently 90 percent.
19 MR. ROSEN: So it would have to exceed 90 20 percent in order to push this up closer to the limit?
21 MR. HARRELL: More precisely, it would 22 have to exceed 9 percent on average.
23 MR. ROSEN: On average, right. Just 24 following along, Dominion in Surry and North Anna have 25 typically recently, at least, done better than that, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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286 1 haven't they?
2 MR. HARRELL: That is correct. Recently 3 they have. But prior cycles have not averaged to an 4 average of 90. Again, the reloaded evaluations of the 5 effects of relative power distribution and capacity 6 factor would evaluate the effects of capacity factor 7 in excess of the projected 90 percent average.
8 MEMBER LEITCH: But we're not licensing 9 the plant for 48 full power years. We're licensing it 10 for 60 years. Should we be?
11 MR. MITCHELL: Maybe as a point of 12 clarification, the staff expects that if the licensee 13 comes to possess information which would suggest that 14 they would need to update this analysis because they 15 are projecting now a higher fluence value at the end 16 of the period of extended operation, whether it be 17 because they have operated a higher capacity factor or 18 for some other reason, they would update their 19 analysis, as appropriate.
20 Any analysis of this type done at some 21 point in the future is subject to the assumptions that 22 go into it. Those assumptions may not be accurate or 23 found to be less than accurate at some point in the 24 future. Licensee applicant should revise their 25 evaluation if necessary.
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287 1 I think we have probably covered actually 2 the information that is on my second and third actual 3 slide. Obviously there were materials in Surry Units 4 I and II which did fall below the criteria. The 5 applicant performed their equivalent margins analyses, 6 which were provided to the staff in report BAW 2323.
7 The staff based upon the information that 8 we had available in our reactor vessel integrity 9 database and based upon information the licensee 10 provided was able to go through and to independently 11 perform our own equivalent margin analyses.
12 The conclusions of both the applicant's 13 and the staff's analyses were, in fact, the same, that 14 they did demonstrate acceptable equivalent margins 15 analyses for continued operation through the end of 16 their extended license.
17 MEMBER SHACK: When do they have to 18 recompute their pressure temperature limits for 19 cooldown?
20 MR. MITCHELL: Typically, they would have 21 to recalculate either upon expiration of the pressure 22 temperature limits if they are established at some 23 value less than the fluence value at end of license.
24 They would need to reevaluate whether they would need 25 to be recalculated if they come into possession of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W.
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288 1 surveillance data, fluence data, or other information 2 which could modify the period of applicability of the 3 pressure temperature limits.
4 I'll defer back to the licensee because I 5 am not currently aware as to where the pressure 6 temperature limits for the Surry units -
7 MEMBER SHACK: The answer is you don't 8 routinely calculate that for the license renewal.
9 That is considered an operation, a current licensing 10 operation.
11 MR. MITCHELL: It is currently a current 12 licensing basis. It is something they would be 13 carrying forward that they look at as they go into the 14 period of extended operation.
15 Are there any more questions?
16 (No response.)
17 MR. TABATABAI: Thanks, Matt. Our next 18 presenter is Simon Sheng. He will talk about V. C.
19 Summer.
20 MR. SHENG: This is Simon Sheng of the 21 Materials and Chemical Engineering Branch.
22 MR. ROSEN: Excuse me one minute. Could 23 you give us a copy of that backup slide?
24 MEMBER LEITCH: It's in here.
25 MR. SHENG: Okay. Now I am going to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N.W (202) 234-4433 WASHINGTON, D C. 20005-3701 www nealrgross.com
289 1 discuss the V. C. Summer issue involving Alloy 82 and 2 82 welds. The first thing that people may like to ask 3 is that, "Why do we want to attach the V. C. Summer 4 issue into the licensing renew domains through LBB?"
5 The answer to that is that I can't help it 6 because in the LBB application, there is a condition 7 that there should not have any active degradation 8 mechanism. And since the summer, V. C. Summer, event, 9 we know that it may be a potential active degradation 10 mechanism.
11 That's why we need to evaluate. Now let's 12 review the V. C. Summer issue a little bit. First is 13 that we have two findings in the primary loop of V. C.
14 Summer.
15 MEMBER LEITCH: Excuse me. Could you 16 remind me what LBB is?
17 MR. SHENG: LBB means leak before break.
18 MEMBER LEITCH: Oh, yes. Thank you.
19 MR. ROSEN: And what is the basis for the 20 finding that there should not have any active 21 degradation methods? Where did you say that was from?
22 MR. SHENG: That's from originally when we 23 made the LBB application, it appeared in the SRP. It 24 also appeared in several original documents so that 25 there are many, many conditions that we should not NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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290 1 apply LBB to certain piping and while these conditions 2 should not have active degradation mechanisms.
3 MR. ROSEN: So I can't apply for a break 4 to the component cooling water piping in the 5 containment, for example?
6 MR. SHENG: If it turns out that the PWSCC 7 is indeed a generic issue -
8 MR. ROSEN: It's external corrosion of 9 duly sweating. It's an act of degradation, I can 10 assume, on the component cooling water piping inside 11 containment. We were just told that. So what you are 12 saying is that they can't use leak before break on the 13 containment water piping, cooling water in 14 containment?
15 MR. SHENG: Probably because LBB, there 16 are so many lines in the reactor system. And there 17 are only several which have obtained approval from NRC 18 for their LBB application. So it does not apply to 19 every line.
20 So let's review the two findings. The 21 first is that we have the through-wall avail flaw in 22 Loop A. And then we have shallow axial and 23 circumferential flaws discovered in Loops B and C.
24 The shallow means that their depth was estimated to be 25 less than one-eighth of an inch.
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291 1 MEMBER WALLIS: Not only do we have a 2 flow, but I think we have a leak.
3 MR. SHENG: That's right. That is the 4 first scenario. We found axial flaw, through-wall 5 axial flaw. Another thing is that we did not find 6 anything in the cooler pipes. So we said difference 7 of operating temperature of only 80 to 100 degrees 8 Fahrenheit lower. And then we didn't find anything.
9 And also the implication of this is there may be 10 something wrong with Loop A, that hot leg only.
11 Something may be very special about that. That's why 12 we did not find axial flaws, through-wall axial flaws, 13 in the other two hot legs.
14 VICE-CHAIRMAN BONACA: But wasn't the 15 additional concern the one that the inspections did 16 not identify the existence of these flaws?
17 MR. SHENG: So I'm going to discuss it 18 later.
19 VICE-CHAIRMAN BONACA: The NRC's concerns 20 aren't regarding the flaws alone. I think my concern 21 is the one that we do perform inspections. They were 22 volumetric inspections and didn't see anything. And 23 that is my concern.
24 MR. SHENG: That's right. That's right.
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292 1 depends on this adequacy of inspections. And if the 2 inspections don't see things, then we have a problem.
3 MR. SHENG: Right. That is also my 4 concern, also the NRC's concern.
5 VICE-CHAIRMAN BONACA: Yes, I see.
6 MR. SHENG: We are going to address it in 7 a second viewgraph.
8 VICE-CHAIRMAN BONACA: Okay.
9 MR. SHENG: Okay? So basically I just say 10 NRC's concern is that are these findings generic or 11 plant-specific? That also answers your question 12 because we need to have a reliable inspection tool to 13 answer question one. Okay? So it's really tied into 14 the question.
15 Now, the second thing, that is really our 16 concern. Do deep and extensive circumferential flaws 17 exist? If I only have axial flaw, it is really not my 18 major concern because that is just a perfect example 19 of leak before break.
20 Now let's take a look. Let's just have a 21 digression from the generic concern to plant-specific 22 concern and see what is the situation of V. C. Summer 23 and North Anna. The report to us is on plant-specific 24 information.
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293 1 on either the hot leg or cold leg piping on the 2 primary loop.
3 MEMBER WALLIS: What kind of welds do they 4 have?
5 MR. SHENG: They just have the outstanding 6 steel welds, not using these -
7 MEMBER WALLIS: And you are saying that 8 that is somehow better than alloy 82/182?
9 MR. SHENG: Yes, yes.
10 MEMBER FORD: Is 308 weld?
11 MR. SHENG: I don't know. I don't know 12 the detail of that, but I think the licensee may be 13 able to. I can pull out this information to you.
14 MEMBER WALLIS: Do they have buttering of 15 the same kind of way or not, what they actually have?
16 I mean, you are saying it's not like Summer.
17 MR. SHENG: That's right.
18 MEMBER WALLIS: But does it have any of 19 the features of Summer?
20 MR. SHENG: Mature-wise, no. But if you 21 are talking about the welding structure and how they 22 weld it, as I said, if you are interested in that risk 23 factor, I can provide the information to you later.
24 So far the -
25 MEMBER WALLIS: I am just wondering.
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294 1 Maybe the materials people can reassure me whether 2 82/182 is somehow the villain or it's somehow the way 3 in which they made the welds at V. C. Summer, which 4 has probably contributed to what they observe there.
5 MR. SHENG: Yes, but right now we -
6 MEMBER FORD: The answer is yes.
7 MR. SHENG: We identify that for -
8 MR. SNOW: This is Tom Snow. Would you 9 like me to comment on that? I am with Dominion, 10 obviously.
11 The nozzles on the reactor vessel are 12 carbon steel, of course, with a stainless steel safe 13 end attached. The piping for the reactor coolant 14 system is all stainless steel. So we are going from 15 a stainless steel safe end to a stainless steel piping 16 with a stainless steel weld.
17 MEMBER FORD: And the weld is 308?
18 MR. SNOW: I do not know exactly whether 19 it is 308. I would have to check on that.
20 MEMBER FORD: Is there a stainless steel 21 liner in the piping, too?
22 MR. SNOW: The nozzle, carbon steel 23 nozzle, is clad with stainless steel, yes.
24 MEMBER LEITCH: And those comments apply 25 to both North Anna and Surry?
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295 1 MR. SNOW: Those comments do apply to both 2 Surry and North Anna.
3 MEMBER LEITCH: Thank you.
4 MR. SHENG: Okay. So the good news is 5 that they don't have the vulnerable welds on the 6 primary loop, but they do have these types of welds on 7 some other portion within the RCS system and basically 8 I think the LBB on the reactor coolant pump weld, I 9 think in that nozzle, the outlet nozzle, to the 10 reactor coolant pump. So basically we still have to 11 attack this issue, to resolve this issue, even if they 12 don't have that type of weld on the primary loop.
13 Now talking about how to resolve the issue 14 plant specifically under 10 CFR Part 50, first we have 15 to rely on the interim conclusion from the generic 16 investigation. And the conclusion from that is that 17 there is no immediate safety concern. The reason is 18 that the reason is because first the industry -
19 CHAIRMAN APOSTOLAKIS: So there will be a 20 concern at some point?
21 MR. SHENG: Yes, there will be.
22 CHAIRMAN APOSTOLAKIS: When?
23 MR. SHENG: Let me give you some comfort 24 about why we say there is no immediate safety concern.
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296 1 gradually.
2 CHAIRMAN APOSTOLAKIS: Sure.
3 MR. SHENG: Okay. The reason there is no 4 immediate safety concern, first we have the industry 5 has performed analysis because we don't know the 6 situation. Suppose that we have equal opportunity to 7 have axial flaw and circumferential flaw. Then how 8 about the driving force? Which one is going to have 9 a much, much bigger driving force?
10 So the industry performed a final analysis 11 basically assimilating that the welding process layer 12 by layer analysis and also reflecting the excessive 13 review work, which is very special to these Loop A 14 welds.
15 The result of this study shows that the 16 stresses, the residual stresses, are much, much higher 17 for the axial flaw. So the implication is that if you 18 do have a flaw created somewhere, then the axial flaws 19 tend to grow much faster.
20 MEMBER WALLIS: We heard all of this 21 before with the control rod drive mechanisms.
22 MR. SHENG: I understand. Yes, but the 23 situation may be a little different because -
24 MEMBER WALLIS: It's a bigger plant.
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297 1 analysis, NRC has also contracted Batel to do a 2 similar analysis but, of course, more extensive with 3 a lot of assumed cases with a different, say, wording 4 from ID and wording from OD because of the lack of 5 information assuming we have reworded this way and 6 that way. So we have like probably more than ten 7 cases to be analyzed.
8 The Batel result is able to put down some 9 kind of number in the conclusion, which said that the 10 axial flaw, the growth rate for the axial flaw, is at 11 least two times larger than the growth rate of the 12 circumferential flaw.
13 So based on this analytical work, you can 14 see that the role of these kinds of excessive reworks 15 will play in defining the residual stresses which 16 cause that through-wall axial flaw.
17 Now, this is the analytical side because 18 usually when you have a theory, you need something to 19 validate it, to support it. So let's now take a look 20 at what we have seen for the V. C. Summer. The V. C.
21 Summer only indicates a through-wall, also axial flaw.
22 In addition, we have two other four-ring 23 cases, which are RINGO 3 and RINGO 4. RINGO 3, we 24 discovered two axial flaws. In RINGO 4, they 25 discovered four axial flaws. So you can see that the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W.
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298 1 evidence that we have found so far from the industry 2 domestically and for foreign plants, they also show 3 axial flaws.
4 But, of course, in the V. C. Summer, V. C.
5 Summer is the only plant which also shows a 6 circumferential flaw. But they are not that 7 extensive.
8 MEMBER WALLIS: So you are arguing that 9 the axial flaws will incur first, and you will detect 10 them before you will get any circumferential flaws?
11 MR. SHENG: That's right.
12 MEMBER WALLIS: You have to detect those 13 axial flaws, as my colleague said over here.
14 MR. SHENG: That's right. That's right.
15 I should be able to do that. I think some of the 16 members had pointed out last time that they don't have 17 confidence in the UT methodology right now because you 18 learned that some flaws can be found in V. C. Summer 19 by ET, but it cannot be verified by UT.
20 I just want to point out that since the 21 discovery of the V. C. Summer issue, that the UT 22 methodology has been improved significantly. For 23 instance, when the second time, when V. C. Summer 24 personnel went to investigate those four flaws, at 25 this time they could detect two of them. So if it NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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299 1 would be better, they could have had all four of them.
2 But at least they now can detect two of them.
3 MEMBER WALLIS: These are all plausible 4 arguments.
5 MR. SHENG: So it's a qualitative 6 improvement, but the key thing is what the licensee is 7 going to do and what the industry is going to do in 8 their future inspections. Basically -
9 MR. KUO: Simon?
10 MR. SHENG: Yes?
11 MR. KUO: I'm sorry. I have to interrupt 12 you a little bit. Let's not sidetrack the issue. We 13 are talking about the North Anna and the Surry.
14 MR. SHENG: Yes. I'm going to address 15 that now. Yes. I just say that the licensee will 16 conduct future inspections using performance 17 demonstration. The key component of that performance 18 demonstration is a blind mock-up qualification per 19 ASME Appendix VIII required by 10 CFR 50.55a.
20 MEMBER WALLIS: Excuse me. What does 21 ten-year ISI program mean? Does it mean that you 22 inspect every ten years or does it mean something 23 else?
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300 1 piping at a certain time.
2 VICE-CHAIRMAN BONACA: Well, a given 3 location would be inspected over ten years.
4 CHAIRMAN APOSTOLAKIS: I think Professor 5 Wallis is right.
6 MEMBER WALLIS: So something could happen 7 in that ten years that is not detected.
8 MR. SHENG: That's right, but remember 9 that -
10 MEMBER WALLIS: So are you going to go 11 through the old argument that flaws grow so slowly 12 that in ten years, it's okay to wait ten years to find 13 them?
14 MR. SHENG: No. It's more than that 15 because -
16 MEMBER WALLIS: More than ten years?
17 MR. SHENG: No, no, no, no. Now we are 18 addressing the plant-specific issues now. That's why 19 you have these questions. Remember that we are also
.20 resolving these generically. For instance, in 2001, 21 some plants have conducted a thorough inspection of 22 their primary loop hiking, which is these three plants 23 are -- let's see. I have their names here. It's 24 McGuire I, Salem I, and Robinson II.
25 So basically you have V. C. Summer and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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301 1 RINGO 3 and 4. We have three plants, three additional 2 plants, which show no flaw similar to what we have -
3 MEMBER WALLIS: Are they younger or older 4 than Surry and North Anna, these older plants?
5 MR. SHENG: You are talking about the 6 vintage of the plants.
7 VICE-CHAIRMAN BONACA: And they have 8 cracks.
9 MR. SHENG: Yes, they have cracks, but 10 they have subsurface cracks.
11 MEMBER WALLIS: Are they older or younger 12 than Surry and North Anna, these three plants you 13 cited?
14 MR. SHENG: These three plants. Let me 15 see. I know that Robinson is -
16 MR. CORBIN: This is Bill Corbin with 17 Dominion.
18 Robinson is a similar vintage as Surry.
19 Surry is the older of our plants.
20 MR. SHENG: And McGuire, I don't know.
21 But, as I said, if I entirely rely on the North Anna 22 and the Surry inspection results, it may not be 23 enough.
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302 1 welds but also some other pipings involved in 82/182 2 welds. Then each year I will receive probably nine or 3 ten inspection results using much more reliable UT 4 inspections. Then maybe at a certain time we can make 5 a decision and say that, really, V. C. Summer is a 6 plant-specific issue.
7 MR. BATEMAN: Simon, can we please move to 8 North Anna and Surry now and stay off of Summer and 9 all of these other plants which aren't germane to this 10 discussion?
11 MR. SHENG: Sure.
12 MR. BATEMAN: Good. Let's start with 13 North Anna, please.
14 MR. SHENG: I have already said that -
15 MEMBER LEITCH: Is this a true statement 16 that North Anna and Surry have committed to use the 17 best industry practice that is available today?
18 MR. SHENG: Yes.
19 MEMBER LEITCH: And if in the future years 20 better practices are developed, they will use those 21 better practices. Is that true?
22 MR. SHENG: Well, by definition, they use 23 blind mock-up.
24 MEMBER LEITCH: That's today's practice, 25 today's best practice.
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303 1 MR. BATEMAN: Excuse me. This is Bill 2 Bateman on the staff.
3 The specific practice in 50.55a was 4 basically supposed to be achieved by the industry by 5 November 22nd. Industry did not make that date. So 6 we're dealing with that the present.
7 MR. SHENG: Yes, but the -
8 MR. BATEMAN: Simon, just finish up with 9 North Anna and Surry, please.
10 MEMBER WALLIS: Well, when you had all of 11 this discussion, how did you close the North Anna and 12 Surry issue before you got on to what was supposed to 13 be a red herring here?
14 MR. SHENG: Yes. As I said, we cannot 15 close it right now.
16 MEMBER WALLIS: You cannot close it right 17 now?
18 MR. SHENG: Right.
19 MEMBER WALLIS: Okay.
20 MR. SHENG: That's why I say that the only 21 conclusion I acknowledge is there is no immediate 22 safety concern. The conclusion, the interim 23 conclusion, is that there is no immediate safety 24 concern. So we are resolving it.
25 MR. BATEMAN: This is Bill Bateman.
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304 1 MR. SHENG: -- receiving reliable 2 inspection data the next few years.
3 MR. BATEMAN: This is Bill Bateman, NRR.
4 I think Simon made it clear in his 5 presentation that there are no Alloy 82/182 welds on 6 the hot or cold leg here. So the situation that we 7 are talking about here, the similar metal weld 8 inspection that Simon was referring to, really does 9 not apply to North Anna and Surry. We've got 10 stainless steel welds in these locations.
11 MR. TABATABAI: And, as you mentioned, Mr.
12 Leitch, Dominion is committed to perform the 13 state-of-the-art inspection program as it becomes 14 available as industry makes progress in that regard 15 and also they are committed with the next scheduled 16 inspection they have to use this improved and enhanced 17 duty inspection program. That is how the staff closed 18 the issue of V. C. Summer in North Anna and Surry.
19 From the staff's point of view, the issue 20 of V. C. Summer is closed because it does not apply to 21 North Anna and Surry. The V. C. Summer issue is big, 22 reviewed and evaluated by the staff generically and 23 outside the license renewal issue.
24 MEMBER LEITCH: We're at a bit of a time 25 press here. We still need to talk about NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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305 1 erosion/corrosion.
2 VICE-CHAIRMAN BONACA: Let's note, 3 however, on the other hand, there is an issue about 4 the industry. This seems to me it has generic 5 implications to inspections because at least I am not 6 a collusional person, but I have always had trust that 7 these ten-year inspections were sufficient to identify 8 flaws.
9 I have a concern now because we hear that, 10 in fact, they are not going to be able to identify 11 flaws. So that is a real concern. I don't know to 12 what extent it is a generic issue, but it is.
13 MEMBER FORD: Can I just ask one question?
14 Which of the parts of the reactor cooling system have 15 82/182 in it? In your second bullet, you said -
16 MR. TABATABAI: No. They don't have any 17 82/182 at the primary system. They have others -
18 MR. SHENG: They have reactor coolant pump 19 or in that nozzle. So basically they have something 20 21 MR. AITKEN: This is Paul Aitken. The 22 other locations we have are at our North Anna facility 23 in our pressurizer nozzles and our steam generator 24 nozzles, not in our reactor coolant pump locations.
25 MEMBER FORD: And this is a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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306 1 low-temperature plant?
2 MR. AITKEN: Low-temperature, yes.
3 Correct. There may be low-temperature plants at both 4 locations. I mean, it's normal operating, 600 5 degrees.
6 MEMBER FORD: The location of those 82/182 7 welds, are they low-temperature or not?
8 MR. AITKEN: No, no, no.
9 MR. BATEMAN: This is Bill Bateman on the 10 staff.
11 Just a little comment there. I think you 12 may note, Dr. Ford, that North Anna II is replacing 13 their head because of the deteriorating of the alloy 14 82/182 welds in those vessel head penetrations. So 15 they are considered a high-susceptibility plant.
16 MR. AITKEN: But not to focus on the 17 coolant pumps as much as just at North Anna, it's in 18 our pressurizer and generator nozzle locations is 19 where we have those other situations.
20 MEMBER SHACK: You must have instrument 21 nozzles, too, also?
22 MR. AITKEN: Correct. That's correct.
23 That's correct. Spray nozzles.
24 MEMBER SHACK: Steam generator?
25 MR. AITKEN: At North Anna.
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307 1 MEMBER SHACK: At North Anna?
2 MR. AITKEN: And pressurizers in North 3 Anna.
4 MEMBER SHACK: You replaced the steam 5 generator at Surry. That was a 182 weld or that is a 6 308 weld?
7 MR. AITKEN: That is not a 182, but I 8 don't know the exact material. We do know that it's 9 not 82/182, correct.
10 MEMBER FORD: If someone could get back to 11 us as to is it 308 or is it 247?
12 MR. SHENG: We'll get back to you on that.
13 MEMBER FORD: Three forty-seven would give 14 me concern.
15 MR. SHENG: If there aren't any other 16 questions in the V. C. Summer area, I am going to turn 17 to Kristoff Parczewski, who is going to talk about the 18 flow-accelerated program.
19 MR. PARCZEWSKI: My name is Kristoff 20 Parczewski. I am a member of the Materials and 21 Chemical Engineering Branch at NRR.
22 I am going to talk about the 23 corrosion/erosion in North Anna/Surry plant.
24 Erosion/corrosion occurs in the components made out of 25 steel. If you have another type, it is completely NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE. N.W.
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308 1 immune to erosion/corrosion.
2 In North Anna/Surry plants, these 3 components are located in five systems. I made a 4 mistake. There should have been another, main steam, 5 I missed on the slides. Those components of this 6 system are crediting the flow facility to corrosion 7 program.
8 Flow-accelerated corrosion has two 9 aspects. One aspect is predictive. It predicts the 10 erosion/corrosion before they produce. The second 11 aspect is just try to reduce flow-accelerated 12 corrosion but change the operating condition. And 13 both are addressed by this licensee.
14 MEMBER WALLIS: Can I ask you about 15 CHECKWORKS? You've got some numbers from CHECKWORKS 16 later on.
17 MR. PARCZEWSKI: Yes.
18 MEMBER WALLIS: CHECKWORKS is not a very 19 precise predictive tool. It's a good one.
20 MR. PARCZEWSKI: Yes. I am going to just 21 mention it.
22 MEMBER WALLIS: Maybe when you present the 23 numbers, you can say something about how accurate they 24 are because you got very accurate numbers for the 25 predicted rate of wall thinning. I just don't think NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N.W.
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309 1 CHECKWORKS comes anywhere near giving that accuracy of 2 predictive.
3 MR. PARCZEWSKI: It's probably the best in 4 existence.
5 MEMBER WALLIS: That may be true, but 6 there are lots of things that are the best in 7 existence.
8 MR. PARCZEWSKI: I think from my 9 experience, I think the predictable is fairly reliable 10 and I think it is a very useful tool.
11 MEMBER WALLIS: I just want a number that 12 says how precisely they can predict.
13 CHAIRMAN APOSTOLAKIS: When will these 14 numbers be shown, next slide?
15 MEMBER WALLIS: Next slide, right.
16 CHAIRMAN APOSTOLAKIS: Okay. Let's wait 17 until next slide.
18 MR. TABATABAI: Dr. Wallis, I just wanted 19 to refresh my memory and the full Committee's memory 20 from the subcommittee presentation we made. We wanted 21 to reach the conclusion that the flow-accelerated 22 corrosion program at North Anna and Surry is working.
23 The trend is decreasing. All of these slides we are 24 talking about is going to conclude to that, that their 25 corrosion program is working, in fact.
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310 1 MEMBER WALLIS: You're predicting that if 2 you extrapolate the data, the rate of loss of material 3 is negative. Never mind.
4 CHAIRMAN APOSTOLAKIS: Well, you didn't 5 actually state it very well, but I know what you mean.
6 You said that you wanted to show. I don't know why 7 you wanted to show because there is no problem here.
8 You only wanted to reach some conclusion. And 9 probably that conclusion was that there is no problem.
10 MR. TABATABAI: Well, Dominion has put 11 another program in place which relates to pH program.
12 They have increased the pH program that caused 13 flow-accelerated corrosion to work effectively. And 14 they have replaced less piping over the years. That's 15 basically the -
16 MEMBER LEITCH: Can we try to bring this 17 discussion to a close by 4:30? I mean, we're really 18 pressing time.
19 CHAIRMAN APOSTOLAKIS: Go to the slide you 20 think is most important. Can you do that?
21 MEMBER WALLIS: We didn't get to the 22 table.
23 CHAIRMAN APOSTOLAKIS: The important two 24 slides that you want to use to convince the Committee 25 that what you are saying is correct.
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311 1 MR. PARCZEWSKI: All right.
2 CHAIRMAN APOSTOLAKIS: I am sorry to do 3 that to you.
4 MR. PARCZEWSKI: That is all right. Maybe 5 we'll start with the one which concerns the predictive 6 part. This is the one with the numbers.
7 CHAIRMAN APOSTOLAKIS: Yes.
8 MR. PARCZEWSKI: So this is the numbers 9 calculated by their flow-accelerated corrosion model 10 by CHECKWORKS. Maybe it is not everything. The 11 column on the right is the actual service time 12 projected to 2004. The second column -
13 MEMBER WALLIS: That's the only thing we 14 know really accurately perhaps.
15 MR. PARCZEWSKI: Yes.
16 CHAIRMAN APOSTOLAKIS: Give the guy a 17 chance.
18 MR. PARCZEWSKI: I'm sorry. Repeat the 19 question.
20 MEMBER WALLIS: No. It's okay. Go back 21 from there into the -
22 MR. PARCZEWSKI: So, I mean, the number is 23 predicted by the code, just to give you an idea of how 24 they look like, for the components in the feedwater 25 pipe. So this is the predictive part of the code.
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312 1 CHAIRMAN APOSTOLAKIS: But isn't it true, 2 though, that for straight pipes, the code does a 3 poorer job than it does for 90-degree angles? Is that 4 true? Does that show in this table?
5 MR. PARCZEWSKI: I'm sorry? I didn't -
6 CHAIRMAN APOSTOLAKIS: If I have a 7 straight pipe, my uncertainty is higher than if I have 8 a 90-degree or 45-degree elbow.
9 MR. PARCZEWSKI: Yes.
10 CHAIRMAN APOSTOLAKIS: Yet, the table does 11 not say anything about it. Is that irrelevant to the 12 conclusion that you are going to reach?
13 MR. PARCZEWSKI: You mean between the 14 elbow and the straight pipe, different as you have 15 seen, yes?
16 CHAIRMAN APOSTOLAKIS: The predictive line 17 that is critical for straight pipe is 376,000 18 something, for 90-degree elbow is 182,000.
19 MR. TABATABAI: Dr. Apostolakis, the 20 numbers, actually, if you look at the size of the 21 column, that is a factor.
22 CHAIRMAN APOSTOLAKIS: That is a factor.
23 What do you mean?
24 MR. TABATABAI: We are talking about the 25 same size piping here. If you look at the numbers for NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W.
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313 1 straight pipe, the size is six inches. For 90 2 degrees, we have six inches.
3 MEMBER WALLIS: Well, I'm concerned about 4 the 90-degree elbow, where the predicted time is 5 pretty close to the actual time. I don't believe you 6 predict average wear rate that accurately. I am not 7 sure that "average" is the right word to use anyway.
8 MR. BREEDLOVE: Excuse me.
9 MR. PARCZEWSKI: Yes?
10 MR. BREEDLOVE: This is Ian Breedlove. I 11 am with Dominion. I'm the FAC coordinator for Surry 12 and North Anna.
13 The actual service time, let's look at the 14 90-degree elbow where the actual service time is 15 176,920. That is the actual service time to what we 16 expect to be at at 2004. Since we used the model at 17 2004, the 182 and 18 go beyond that. They're not 18 close at all. In other words, the predicted time to 19 Tcrit starts at 2004.
20 CHAIRMAN APOSTOLAKIS: So 182,000 hours 21 from 2004?
22 MR. BREEDLOVE: Yes, sir. So we have 23 plenty of margin in this specific case.
24 CHAIRMAN APOSTOLAKIS: And that margin 25 presumably overwhelms the uncertainty in the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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314 1 estimation of the 182?
2 MR. BREEDLOVE: Yes.
3 CHAIRMAN APOSTOLAKIS: Do we have any 4 evidence that that is true?
5 MR. BREEDLOVE: We have done many 6 inspections on feedwater condensate at both stations.
7 We started in '87. We have done extensive. At Surry, 8 feedwater, we have done almost 100 percent 9 inspections.
10 CHAIRMAN APOSTOLAKIS: How small do you 11 think the 182,000 would be with some confidence?
12 MR. BREEDLOVE: I would be confident that 13 I would not have to worry about that. When the number 14 goes negative or is like 1,000 above the actual 15 service time, that is when you want to be inspecting 16 that component and making sure of where you are.
17 MEMBER FORD: I think the concern here is 18 the accuracy. I recognize that you normalize things 19 after each inspection. Just give the idea to the 20 community. Where is the average wear rate, which is 21 the average predicted wear rate presumably? You also 22 measure the wear rate. How different would those 23 numbers be? 4.16 mils per year. What would be -
24 MR. BREEDLOVE: Just go out and measure 25 it?
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315 1 MEMBER FORD: What would the wear rate be?
2 MR. BREEDLOVE: In some cases, the code is 3 right on. In some cases, it under-predicts. In some 4 cases it over-predicts.
5 MEMBER FORD: How much over-prediction?
6 MR. BREEDLOVE: It varies. CHECKWORKS 7 isn't the heart of the system. CHECKWORKS is a tool 8 that we use to predict. We back that up with 9 inspections. In our case, at both stations, we have 10 extensive inspections and will go with the one that is 11 the most conservative as far as do we need to 12 reinspect that component.
13 MEMBER WALLIS: It seems to me you are not 14 answering the question, though. The question was, 15 what is the uncertainty?
16 CHAIRMAN APOSTOLAKIS: His answer is that 17 he is comfortable that he is handling the uncertainty, 18 but he can't give you a number. Is that correct?
19 MR. BREEDLOVE: Yes, sir. The other thing 20 to keep in mind is there are two ways to model. One 21 is to just let it calculate and predict. The other is 22 when you enter the wear data, it self-corrects to your 23 actual plant conditions. So, in other words, in some 24 cases if CHECKWORKS says your wear is twice what it 25 should be, but it puts that on area.
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316 1 MEMBER WALLIS: I'm just wondering if 2 there is some way you can transfer your -
3 CHAIRMAN APOSTOLAKIS: Does the staff 4 agree with this assessment? Are you comfortable that 5 the uncertainties are handled reasonably well?
6 MR. PARCZEWSKI: Yes. To my experience, 7 they're doing the best they could calculating with a 8 fairly great amount of precision. It's my experience.
9 CHAIRMAN APOSTOLAKIS: Precision. I'm 10 just curious. How does your experience lead to that?
11 I mean, the code predicted certain time to, and 12 reality confirmed that?
13 MR. BREEDLOVE: Can you put up the slide 14 that shows the iron concentration, please?
15 MEMBER SIEBER: Well, let me ask you a 16 very fundamental question. It seems to me that 17 flow-accelerated corrosion occurs most rapidly in 18 lines that are two-phase, like extraction steam.
19 That's where Surry had the accident, 20 right?
21 MR. BREEDLOVE: No. Surry had the 22 accident on the condensate piping, the suction to the 23 feedwater pump.
24 MEMBER SIEBER: Well, in any event, 25 extraction steam isn't listed here.
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317 1 MR. BREEDLOVE: Extraction steam is 2 included in the FAC program.
3 MEMBER SIEBER: Okay. It's not on the 4 slide.
5 MR. BREEDLOVE: But it is included in the 6 program.
7 MEMBER SIEBER: It seemed to me that from 8 my experience, the CHECKWORKS was sort of on the 9 conservative side. As you put in each bit of data, it 10 ended to correct out.
11 MR. BREEDLOVE: Yes, sir.
12 MEMBER FORD: CHECKWORKS if it had been in 13 existence and Surry had its accident, would it have 14 predicted through-wall failure?
15 MR. BREEDLOVE: With the version I have 16 now, I believe so, yes.
17 CHAIRMAN APOSTOLAKIS: I have to interrupt 18 here. We're getting words that the roads are getting 19 very, very bad. The staff is very anxious to leave.
20 In fact, they were allowed to leave two hours ago, and 21 they agreed to stay on our behalf. So I would ask you 22 to summarize your conclusions in the next 17 seconds.
23 MR. PARCZEWSKI: Well, my conclusion is 24 that we felt that the flow-accelerated corrosion 25 program predicts in sufficiently accurate and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N.W.
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318 1 conservative ways that we can assume the results are 2 acceptable.
3 CHAIRMAN APOSTOLAKIS: Mr. Leitch, is 4 there anything else?
5 MEMBER LEITCH: I think that concludes 6 that. There is just one other question I had. That 7 is, what are the proposed license conditions? Do we 8 know at this point what they will be?
9 MR. TABATABAI: Mr. Weisman is here from 10 OGC, but as far as licensing condition, we have only 11 one issue in regards to scoping and aging management 12 of fuse holders. Dominion has agreed to comply with 13 what the resolution of the staff's position is 14 regarding the cooperation of fuse holders.
15 MEMBER LEITCH: Okay. Thank you.
16 Are there any other questions from the 17 members?
18 MR. ROSEN: Do you plan to go around the 19 table and give the applicant some sense of what the 20 members have?
21 CHAIRMAN APOSTOLAKIS: No, not today, not 22 now.
23 MEMBER LEITCH: Mr. Chairman, back to you.
24 CHAIRMAN APOSTOLAKIS: Thank you, Graham.
25 Thank you, gentlemen. Thank you very much.
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319 1 We have nowhere to go. So we'll stay.
2 We'll stay. But let me tell you what is happening.
3 There are a few decisions we have to make regarding 4 certain urgent matters after the break. The break 5 will be until 4:55. But there is something really 6 urgent right now, and I would like the members to go 7 immediately to the separate meeting only. Please do 8 that. And then you take a break, the staff, too, but 9 it is really urgent for the members to go. There is 10 a decision that needs to be made either way.
11 Thank you very much everybody else. Enjoy 12 the roads.
13 (Whereupon, the foregoing matter went off 14 the record at 4:35 p.m.)
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CERTIFICATE This is to certify that the attached proceedings before the United States Nuclear Regulatory Commission in the matter of:
Name of Proceeding: Advisory Committee on Reactor Safeguards 498th Meeting - OPEN SESSION Docket Number: (Not Applicable)
Location: Rockville, Maryland were held as herein appears, and that this is the original transcript thereof for the file of the United States Nuclear Regulatory Commission taken by me and, thereafter reduced to typewriting by me or under the direction of the court reporting company, and that the transcript is a true and accurate record of the foregoing proceedings.
RebccaDavis Official Reporter Neal R. Gross & Co., Inc.
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SFDominion Advisory Committee on Reactor Safeguards 498th Meeting Plant License Renewal Surry and North Anna Power Stations, Units 1 and 2 December 5, 2002 I
( (.~C (
SSurry and North Anna
+"Dominiona License Renewal Applications Participants
- Dominion
" Bill Corbin - Director, Nuclear Projects
" Paul Aitken - LR Supervisor
" Mike Henig- LR Supervisor o Tom Snow - LR Lead o John Harrell - NA&F Supervisor 2
C , C Surry and North Anna
,*Dominion- License Renewal Applications Purpose of Meeting
° Provide NRC staff with an overview of the license renewal applications for Surry and North Anna Power Stations 3
C C C Surry and North Anna
'Dominiou License Renewal Applications
Background
° License Renewal Applications submitted May 29, 2001 e Format consistent with NEI 95-10, Revision 3 and NUREG 1800 (SRP), Draft, August 2000
- Class of '01 not expected to use the Draft GALL report 4
S( (
Surry and North Anna
- Dominion License Renewal Applications LRA Format Consistent with SRP Draft, August 2000 and NEI 95-10, Revision 3
- Sections discussed today
" Section 2: Scoping and screening methodology and results
" Section 3: AMR results - Mechanical, Structural, Electrical
" Section 4: Time Limited Aging Analyses
" Appendix A: UFSAR Supplement
" Appendix B: Aging management activities
" Appendix C: Aging management review methodology*
" Appendix E: Environmental Report Supplement
C C C Surry and North Anna
~Dominioir License Renewal Applications Section 2:
Scoping Methodology and Results
- Used 10CFR54.4 Rule Scoping "Criteria" Criterion 1: safety-related Criterion 2: non-safety-related affecting safety-related Criterion 3: the five regulated events (FP, EQ, PTS, ATWS, SBO)
- Individual Tables:
Systems in Scope Systems not in Scope Structures in Scope Structures not in Scope 6
Surry and North Anna
" Dominion License Renewal Applications Section 2:
Screening Methodology Mechanical Screening Overview SReviewed documentation sources to identify system intended functions.
< Used component database in conjunction with other documentation sources to identify components supporting these functions.
SDeveloped license renewal boundary drawings.
7
C C C Surry and North Anna
-* Dominiow License Renewal Applications Section 2:
Screening Methodology (cont.)
- Civil/Structural Screening Overview
<> Reviewed documentation sources to identify structural intended functions.
<> Used structural detail drawings to identify structural members supporting these functions.
- Electrical/I&C Screening Overview
,o Passive electrical/I&C components screened on a plant level basis as commodities 8
C C C Surry and North Anna
, Dominlo- License Renewal Applications Section 2:
Screening Results o Screening Results Sections (Mechanical, Structural, Electrical/I&C)
" Description
" UFSAR Reference - hyperlink co License Renewal Boundary Drawings* - hyperlink SComponents Subject to AMR - hyperlink to table
- mechanical systems only 9
Surry and North Anna "Dominion License Renewal Applications Section 3:
Aging Management Review Each AMR Results Section
< System/Component description reference
" AMR results tables
" Generic Topical Report applicability, applicant action item response table if applicable - N/A for structures and electrical/I&C)
" Materials
" Environment descriptions
" Aging effects
" TLAA (if applicable)
" Aging management activities 10
( C C Surry and North Anna
- ' Dominion License Renewal Applications Section 3
AMR Results Table 3.2.1 Engineered Safety Features Systems - Quench Spray Passive Aging Effects Component Group Function Material Group Environment Requiring Man.gement Aging Management Activity Bolting PB Carbon and Steel (E) Air None None Required SteelLow-alloy oy Borated Loss of Material BErlC ,r.,d Cortftion SUeirierre Water Leakage Generat Condition MconitGoring Activities FiltersStrainers PBFLT Stainless Steel (E) Air None None Required (I Treated Loss or Material Chemristry Control Pregram for Primary Syr'!cms Water Flow Ebments P8,RF Stainlss Steel (E)Air None None Required (I)Treated Loss of Material Chernistry Coatrot Program for Primary Sys-ems Water Instrument Valve pa Stainless Steel (E)Air None None Required Assemblies (I Treated Loss of Material Cbemistry Control Program fir Primary Systems ater Instrument Valve Pe Stainless Steel (E)Atmosphere I Loss of Material General Condition MWL.ntorlrg A,*i-oles Assemblies Weather (I Treated Loss of Material Chemistry Control Program for Primary Sysirems Water Nozzles SP 2rass (E)Air None None Required (1)Air Nona None Required Pipe P2 Stainless Steel (E)Air Nona None Required (1)Air I-Ione None Required Pipe Pe Stainless Steel (E)Air1 Loss of Material GcniTat Condation Moni*oring ActiqtoS 11 (1)Treated Loss of Material Chemistry Cotrofl Plogram for Primary Syllems Water
C C C Surry and North Anna SDominion License Renewal Applications Section 4:
Time-Limited Aging Analyses Results Generic TLAAs
" Reactor vessel neutron embrittlement
" Metal Fatigue (including EAF)
" Environmental Qualification (EQ)
" Containment tendon prestresses (not applicable)
" Containment liner plate and penetration fatigue 12
C C C Surry and North Anna
'r Dominiour License Renewal Applications Section 4:
Time-Limited Aging Analyses Results (cont.)
e Plant-specific TLAAs
" Crane load cycle limit
" RCP flywheel SLeak-before-break SSpent fuel pool liner
" Piping subsurface indications
" RCP - Code Case N-481 13
Surry and North Anna SDominiowr License Renewal Applications Appendix A:
UFSAR Supplement This section provides summaries of the programs and activities credited for managing the effects of aging.
Each aging management program or activity accomplishes one or more of the four functions, as listed in the Standard Review Plan for License Renewal: Prevention, Mitigation, Condition Monitoring, and Performance Monitoring.
14
C C (
Surry and North Anna iDominio License Renewal Applications Appendix B:
Aging Management Activities
- Existing Activities - 19 o Chemistry Control, ISI, Boric Acid Corrosion...
° New Activities - 4
" Buried Pipe and Valve Inspections
" Infrequently Accessed Areas Inspections
" Tank Inspections
" Cable Monitoring (added after submittal) 15
( C C Surry and North Anna
"'Dominiow License Renewal Applications Appendix B:
Aging Management Activities (cont.)
Operating Experience "c Industry and in-house operating experience has been incorporated into aging management activities through the corrective action process
" Operating experience reviews were performed to identify specific aging issues that apply to structures, systems and components 16
C C C Surry and North Anna
- <Dominion License Renewal Applications Aging Management Review Methodology - Appendix C
- Not required- Reviewers Aid - Explains:
o Grouping of systems, structures, and major components - consistent with SRP and NEI 95-10
"< Short-lived components and consumables
" Aging effects and mechanisms evaluated 17
Surry and North Anna
ý"Dominion License Renewal Applications Appendix E:
Environmental Report Environmental Report and Review Process:
< Environmental Review performed IAW NEPA
" Environmental Impacts evaluated IAW NUREG- 143 7 GEIS ('96, '99)
" Severe Accident Mitigation Alternatives (SAMAs) were reviewed and results incorporated l Environmental Report Results:
o Environmental Impacts are Small and Smaller Than Reasonable Alternatives 18
(r-( Anna North and Surry
- Surry and North Anna "Dominion License Renewal Applications Closing Remarks The effects of aging associated with Surry and North Anna will be adequately managed so that there is reasonable assurance that the intended function(s) will be maintained consistent with the current licensing basis during the period of extended operation.
19
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o Davis-Besse Reactor Vessel Head Damage cNRC UPDATE November 2002 This is the third periodic update on the NRC response to the reactor vessel head damage at the Davis-Besse Nuclear Power Station. The updates will be available at public meetings of the NRC Davis-Besse Oversight "Panelwhich is coordinating the agency's activities related to the damage. Each update will include background information to assist the reader in understanding issues associated with the corrosion damage.
Findings of Completed NRC Inspections These inspections have been completed, and the Ongoing NRC Inspections:
reports are in preparation. When issued, the reports will be posted on the NRC's web site at: 1. Management and Human Performance http://www.nrc.gov - select "Davis-Besse" from Inspection is evaluating FirstEnergy's root the list of key issues. cause analysis associated with management, organizational effectiveness ContainmentExtent of Condition and human performance factors that are Inspection, Part 2, found that plant believed to have led to the degradation of personnel were properly trained and the reactor head. The inspection is also qualified to identify components and focusing on the licensee's efforts towards systems inside the containment building creating a more safety-focused environment.
that could be affected by boric acid deposits and corrosion. They used 2. The ProgramEffectiveness Inspection is adequate tools and followed adequate reviewing the plant's progress in creating quality standards and guidance. more effective programs for such areas as corrective actions, boric acid corrosion Before the NRC closes this issue, control, modification control and others.
however, FirstEnergy has to complete their analysis of some unresolved items, 3. The two NRC resident Inspectorscontinue such as corrective actions for boric acid their inspections of day-to-day activities at corrosion of the electrical conduit and the the Davis-Besse plant as well as supporting containment air coolers and resolution of the specific inspections underway.
the origin of the corrosion staining found on the bottom of the reactor vessel.
During the first part of the inspection, conducted in September, NRC inspectors found that, in some instances, plant personnel performing these inspections weren't properly trained and certified and found weaknesses in equipment used and quality assurance procedures. After FirstEnergy addressed these problems, NRC inspectors reviewed inspection methods, observed plant personnel performing inspections, and conducted independent examinations of components in containment.
Reactor Vessel Head Replacement Inspection found that the old reactor vessel head was safely removed from the containment and stored; the procedures and methods used to open the containment The NRC Lessons Learned Task Force will present Its findings and receive comments in a public meeting at 7 p.m., Wednesday, November 20, In the Auditorium of the Oak Harbor High School.
11
NRC Update: Davis-Besse Reactor Vessel Head Damagqe November 2002 - Paae 2 NR pae ai-es eco eslHa D mag Noebr20 Po and close it after the new head was moved into containment were adequate; and plant management used appropriate methods to ensure high quality of work being performed. As part of this inspection, the NRC also reviewed the technical part of Davis-Besse's root cause report for the boric acid corrosion of the reactor vessel head and found that the plant's analysis represented an acceptable scenario for the degradation.
The inspection determined that the replacement head meets the applicable American Society of Mechanical Engineers codes. Inspectors reviewed the material and welds on the head and found that it was an acceptable replacement.
Systems Health Inspection is reviewing the plant's assessment of important safety systems. NRC inspectors reviewed FirstEnergy's program for evaluating safety system health, observed and evaluated the implementation of the program by plant personnel, and conducted independent inspections of plant systems. The results of this inspection showed that the licensee's systems health program was effective and that the licensee had identified a significant number of problems requiring resolution.
NRC inspectors also conducted a design review of three plant systems and found substantive issues requiring further review by FirstEnergy. As a result, the licensee has initiated a "collective significance" review of the NRC's findings and the plant's own inspection results in the system health area to formulate an appropriate plan of action.
The Resident Inspectors' Report 02-10, issued October 30, documents inspections of activities such as adverse weather preparation, equipment alignment, plant modifications, and maintenance risk assessment. The findings included one low-level violation for an inadequate procedure dealing with scaffolding placement and several observations regarding implementation of the Return to Service Plan.
Results of Bottom Nozzle Tests Are Inconclusive FirstEnergy identified rust stains on the bottom of the reactor vessel earlier this year. The stains became visible in June when plant workers removed )))
the insulation from the reactor vessel in order to examine its condition. Reactor The licensee believes the stains probably resulted from previous cleaning Vessel of the reactor vessel head. A less likely possibility was that the stains resulted from leakage from the penetrations for incore monitoring tubes.
There has been no history of such leakage in other U.S. pressurized water reactors. There are 52 tubes, each less than one inch in diameter, which contain incore monitoring devices used to measure conditions in the- Area of reactor. corrosion staining The utility's consultant, Framatome, compared the chemical composition of the corrosion on the top of the reactor vessel head to the stains on the bottom. The testing showed some variation between chemical composition of corrosion products from the top of the reactor and stains'on the bottom. The analyses, however, did not provide a conclusive link to the upper vessel head cleaning, nor did they show evidence of leakage from the incore tube penetrations.
Davis-Besse is reviewing its options for definitive testing of the bottom nozzles for leaks. The NRC will review the utility's testing and inspection plans and monitor the tests. The issue will be resolved prior to the NRC considering whether the plant can restart.
NRC Update: Davis-Besse Reactor Vessel Head Damage November 2002 - Pace3 NR pae ai-eseatrVse edDmg Noemer02 Pa 3 NRC Denies Petition For Independent Review
-'- On October 15, the NRC denied a petition, submitted by several public interest groups under Section 2.206 of the agency's regulations. The groups sought an independent third-party review pf all reactor head issues at Davis-Besse. The petition was denied because such a review would unnecessarily duplicate the agency's activities. The NRC is addressing the technical and human performance problems at Davis-Besse raised in the petition through its Oversight Panel activities. Issues regarding the agency's regulatory performance were addressed by the Lessons Learned Task Force. The task force report and recommendations are currently under review by a special management review team which will formulate proposed actions by the agency.
The denial decision and the petition are available for review on the NRC's web site at: http://www.nrc.gov select "Davis-Besse" under key issues and then select "controlled correspondence."
Sump Screen improvement The NRC is reviewing a FirstEnergy initiative to increase the area of the sump strainers in the reactor containment at Davis-Besse. The sump is a collection point for water that would be recirculated for reactor cooling in the event of a loss-of-coolant accident. This sump modification, which was not required by the NRC, has been initiated by FirstEnergy to ensure that the -".
strainers do not get clogged by debris which might ,o collect at the bottom of the containment. The additional - -.
surface area of the sump strainers will provide a .
substantial improvement in the plant's design safety .- . v- , --
margin.
Background:
What Happened at Davis-Besse In March 2002 plant workers discovered a cavity in the head or top of the reactor vessel while they were L repairing control rod tubes which pass through the head. Sketch provided to NRC by FirstEnergy The tubes, which pass through the reactor vessel head, are called control rod drive mechanism nozzles.
Cracks were detected in 5 of the 69 nozzles. In three of those nozzles, the cracks were all the way through the nozzle, allowing leakage of reactor cooling water, which contains boric acid.
Corrosion, caused by the boric acid, damaged the vessel head next to Nozzle No. 3, creating an irregular cavity about 4 inches by 5 inches and approximately 6 inches deep. The cavity penetrated the carbon steel portion of the vessel head, leaving only the stainless steel lining. The liner thickness varies somewhat with a minimum design thickness of 1/8 inch. Subsequent examination by Framatome, FirstEnergy's contractor, found evidence of a series of cracks in the liner, none of which was entirely through the liner wall.
Earlier indications of the problem: Through-Wall Cracking of Nozzles in France and at the Oconee Nuclear Power Station in South Carolina In the early 1990's control rod drive mechanism nozzle cracking was discovered at a nuclear plant in France.
These cracks penetrated the nozzle wall along the length of the nozzle (referred to as 'axial' cracking). In 1997 the NRC issued Generic Letter 97-01 to gather information on the inspection activities for possible cracking in the control rod drive mechanism nozzles in plants in the United States. Subsequently, through-wall circumferential cracks -- around the nozzle wall -- were discovered in two control rod drive mechanism nozzles at the Oconee Nuclear Power Station, Unit 3, in 2001. While axial cracking had been found at several other plants and repaired, circumferential cracking had not been seen before. Circumferential cracking is more significant because it could lead to complete separation of the nozzle and a resulting loss-of-coolant accident.
November 2002 - Pane NRC Update: Davis-Besse Reactor Vessel Head Damaqe NRC Uodate: Davis-B esse Reactor Vessel Head Damaqe November2002 Pace 44 After the Oconee discovery, the NRC issued Bulletin 2001-01, requiring all pressurized water reactor (PWR) operators to report to the NRC on structural integrity of the nozzles, including the extent of any nozzle cracking and leakage and their plans to ensure that future inspections would guarantee structural integrity of the reactor vessel boundary. The NRC's Bulletin instructed nuclear power plants with similar operating history to Oconee Unit 3, including Davis-Besse, to inspect their reactor vessel head penetrations by December 31,2001, or to provide a Typical Pressurized Water Reactor basis for concluding that there were no cracked and leaking nozzles. cotiR FirstEnergy Nuclear Operating Company requested an extension of the inspection deadline until its refueling outage beginning March 30, 2002, and provided the technical basis for its request. The NRC did not allow the plant to operate until March 30, but agreed to permit operation until February 16, C,. ,6",
provided that compensatory measures were taken to minimize possible crack growth during the time of operati6n. The NRC 00",Sf was unaware that nozzle leakage or corrosion had occurred at Davis-Besse when it agreed to the February 16 date. 0~ NXZ%
Boric Acid Corrosion Control Procedure The water that circulates through a pressurized water reactor to cool the nuclear fuel contains a low concentration of boric acid. This borated water can potentially leak through flanges, pump and valve seals, and other parts of the reactor cooling system and cause corrosion. ° The NRC has taken steps to make sure that PWR operators are aware of and pay attention to the corrosion boric acid can cause in certain environments:
In 1986-89, the NRC issued a series of documents, called "generic communications," informing PWR licensees that boric acid can corrode and damage steel reactor components.
The NRC's Generic Letter 88-05 requested PWR operators to implement a program to ensure that boric accid corrosion does not lead to degradation of the reactor cooling system components. All nuclear power plants with PWRs, including Davis-Besse, reported to NRC that the Boric Acid Control Procedures had been established and would be implemented.
Barriers Built into Nuclear Plants to Protect Public Health and Safety The design of every nuclear power plant includes a system of three barriers which separate the highly radioactive reactor fuel from the public and the environment. The Davis-Besse reactor head damage represented a significant reduction in the safety margin of one of these barriers, the reactor coolant system.
The reactor coolant system, however, remained intact, as well as the other two barriers, the fuel and the containment.
- 1. Fuel Pellets and Rods The first barrier is the fuel itself. The fuel consists of strong, temperature-resistant ceramic pellets made of uranium-oxide. The pellets are about the size of a little finger-tip. They retain almost all of the highly K-> radioactive products of the fission process within their structure.
The pellets are stacked in a rod made of a zirconium alloy. At Davis-Besse, each fuel rod is about 13 feet long. The rods are assembled into bundles, with each assembly containing 208 rods. The reactor core
NRC Update: Davis-Besse Reactor Vessel Head Damage November 2002 - Pacie 5 NRC Update: Davis-Besse Reactor Vessel Head Damage November2002 Pacie 5 contains 177 fuel assemblies. Any fission products which escape from the pellets are captured inside the cladding of the rod, which is designed to be leak-tight. Small pin hole leaks do occasionally occur, however,
<._. and the operating license requires leakage monitoring and contains limits on the maximum allowable leakage of radioactive materials from the fuel rods.
- 2. Reactor Coolant System The second barrier is the reactor coolant system pressure boundary. The reactor core is contained inside the reactor pressure vessel, which is a large steel container. Thick steel pipes supply cooling water to the reactor and carry away the heated water after it passes through the reactor core. The pressure vessel, the connected piping, and other connected components make up the reactor coolant system pressure boundary. At Davis Besse, the reactor coolant system contains about 60,000 gallons of cooling water, circulated by four large pumps at a Simplified View of containment Building Interior rate of about 360,000 gallons per minute.
This system is designed to be leak-tight at operating conditions which include a water temperature of 605" F and a water pressure of 2,150 pounds per square inch. The operating license contains limits on the maximum allowable amount of leakage from the system, and it specifies requirements for monitoring any leakage. If a leak is . I,,
identified as being through any solid wall of the system ...... _o (reactor vessel, cooling pipes or other components) continued operation of the plant is prohibited, no matter how small the leak rate.
\'- 3. Containment Building The third barrier is the containment building. This is a large cylindrical building which contains the entire reactor coolant system. None of the piping that contains the high temperature and high-pressure reactor coolant water extends outside the containment building. The containment is a 1 1/2 inch thick steel cylinder, rounded at the top and bottom, which is designed to be leak-tight. This steel structure is surrounded by a reinforced concrete shield building, which is the round building visible from the outside of the plant. Its walls are 2 to 3 feet thick.
NRC's Response to Vessel Head Damage The NRC responded to the vessel head degradation with a series of actions, some specific to Davis-Besse
. and others aimed at other PWR plants. The agency began a review of its regulatory activities as well.
Davis-Besse On March 12, 2002, the NRC initiated an Augmented Inspection Team to examine conditions that led to the head degradation and on March 13, 2002, the NRC issued a Confirmatory Action Letter to Davis-Besse documenting a number of actions the plant needed to implement for the unit to be allowed to restart. On April 29, 2002, the NRC established an Oversight Panel under the Agency's Manual Chapter 0350, to coordinate and oversee NRC activities necessary to address repairs and performance deficiencies at the plant in order to k.._ guarantee that it can operate safely. The plant will not restart until the NRC is satisfied that plant operators have met all necessary safety requirements.
NRC Update: Davis-Besse Reactor Vessel Head Damage November 2002 - Pagqe 6 NR pae ai- ss eco eslHa Daag Noebr02-Pw Generic
<._ On March 18, 2002, the NRC issued Bulletin 2002-01, instructing PWR licensees to report on the condition of their head, past incidents of boric acid leakage and the basis for concluding that their boric acid inspection programs were effective. All plants sent their responses and indicated that no evidence of extensive corrosion of reactor vessel heads was found at these plants. On August 9, 2002, the NRC issued Bulletin 2002-02 advising PWR operators that more stringent inspection techniques may be necessary to detect head penetration nozzle cracks. Visual examination of reactor vessel heads and nozzles may need to be supplemented with other inspection techniques, such as the use of ultrasound, electric currents and liquid dyes. In October, the agency also requested PWR licensees to provide additional information on their boric acid inspection program with greater detail than initially covered in the responses to Bulletin 2002-01.
NRC Davis-Besse Oversight Panel An NRC Davis-Besse Oversight Panel was created to make sure that all corrective actions, required to ensure that Davis-Besse can operate safely, are taken before the plant is permitted to restart and that Davis-Besse maintains high safety and security standards if it resumes operations. Should the plant restart, the Oversight Panel will evaluate if Davis-Besse's performance warrants reduction of the NRC's heightened oversight and, if so, recommend to NRC management that the plant return to a regular inspection schedule. The panel was established under the agency's Manual Chapter 0350.
The panel brings together NRC management personnel and staff from the Region III office in Lisle, Illinois, the NRC Headquarters office in Rockville, Maryland and the NRC Resident Inspector Office at the Davis-Besse site. The eight-member panel's chair and co-chair are John Grobe, a senior manager from Region III and William Dean, a senior manager from NRC headquarters.
As part of determining if plant corrective actions are adequate to support restart, the Oversight Panel will evaluate FirstEnergy's return to service plan, which is divided into seven areas of performance that the utility calls "building blocks." A series of NRC inspections are being performed to verify the company is taking proper actions in each of the seven areas. These reviews will include the work by the FirstEnergy staff and, in addition, the NRC staff will perform independent inspections in each of the "building block" areas.
Issues to be resolved in order for Davis-Besse to restart The NRC Oversight Panel will only consider recommending that Davis-Besse resume operations when the plant has demonstrated its readiness to operate safely. Key elements will include:
- Davis-Besse management and personnel properly understand the technical, organizational, programmatic and human performance problems that led to the extensive degradation of the plant's reactor vessel head.
- Davis-Besse enhances programs for operating the plant safely, detecting and correcting problems, controlling boric acid corrosion, and is fostering a more safety-conscious environment among plant managers and workers.
0 Davis-Besse improves the performance standards of its managers and workers, including their "ownership" of the quality of work products and the safety focus of decision-making.
- The replacement of the vessel head is technically sound and all reactor components are inspected, repaired as necessary, and demonstrated to be ready for safe operation.
Plant safety systems inside and outside containment are inspected, repaired as necessary, and have been confirmed to be ready to resume safe operation of the plant.
NRC Update: Davis-Besse Reactor Vessel Head Damage November 2002 - Paae 7
- Plant operators demonstrate appropriate safety focus and readiness to restart the plant.
Any organizational or human performance issues resulting from the ongoing investigation conducted by the NRC's Office of Investigations are addressed.
All licensing issues that have arisen as a result of the reactor head replacement have been resolved.
Resolution of radiation protection issues associated with the radiation exposure to workers during steam generator work and the particle contamination found in offsite locations.
Modification of the strainer system for the containment sump, which would be the source of cooling water for recirculation in the event of a loss-of-coolant accident.
What Happens If the Plant is Allowed to Restart If the facility is permitted to restart, the NRC Oversight Panel will continue to monitor plant activities and operations until panel members are confident that the root cause(s) of the problem have not recurred. Should FirstEnergy achieve that performance level, the NRC Oversight Panel would recommend to NRC management that responsibility for the plant oversight be transferred back to the Region III line organization for monitoring under the Reactor Oversight Process. The panel would then cease to exist. Should FirstEnergy not demonstrate sustained improved performance, the panel will recommend appropriate regulatory actions.
Public Participation in the Process The NRC's experience is that members of the public, including public officials and citizens, often raise questions or provide insights that are important to consider. If you have questions or want to provide information or a point of view, please contact us. For feedback on this newsletter, contact Viktoria Mitlyng 630/829-9662 or Jan Strasma 630/829-9663 (toll free 800/522-3025 - ext -9662 or -9663). E-mail:
opa3@nrc.gov. Extensive information about the Davis-Besse reactor vessel head damage and the ensuing activities is available on the NRC web site: http://www.nrc.gov - select "Davis-Besse" under the list of key topics.
I
C C C Briefing for the Advisory Committee on Reactor Safeguards December 5, 2002
- 1% *
- Update on USNRC Oversight of the Davis-Besse Nuclear Power Station Jack Grobe, Chairman Davis-Besse Oversight Panel
C C (
SDavis-Besse Oversight Update Previous Briefings of The Committee
- April 9 and 11, 2002
- Presented the NRC's Augmented Inspection Team results
- June 5 and 6, 2002
- Described the charter and membership for the NRC's Davis-Besse Oversight Panel
- Summarized FirstEnergy's return to service plan 12-05-2002 2
C C (
1* T nr) ,4 Davis-Besse Oversight Update Objectives of this Briefing
"* Update on activities of the NRC's Davis-Besse Oversight Panel
"* Summarize the results of recent inspection activites
"* Describe several significant plant equipment issues 12-05-2002 3
( C (
0 0i*0 n Davis-Besse Oversight Update Restart Checklist
- Issued August 16 and updated October 30, 2002
- Identifies significant issues requiring action before restart 12-05-2002 4
Davis-Besse Oversight Update Restart Checklist
- Key Areas for Review
- 1. Adequacy of root cause determination
- 2. Adequacy of safety significant structures, systems and components
- 3. Adequacy of safety significant programs
- 4. Adequacy of organizational effectiveness and human performance
- 5. Readiness for restart
- 6. Licensing issue resolution
- 7. Confirmatory Action Letter resolution 12-05-2002 5
( ( (
a Davis-Besse Oversight Update Restart Checklist
- 1. Adequacy of Root Cause Determination
- Penetration cracking and reactor pressure vessel corrosion
- Organizational, programmatic and human performance issues 12-05-2002 6
(I ( (
I~k , Davis-Besse Oversight Update Restart Checklist
- 2. Adequacy of Safety Significant Structures Systems and Components
- Reactor pressure vessel head replacement
- Containment vessel restoration
- Structures, systems and components inside containment
- Emergency core cooling system and containment spray system sump
- Systems outside containment 12-05-2002 7
(7 Ci C q Davis-Besse Oversight Update Restart Checklist
- 3. Adequacy of Safety Significant Programs
- Corrective action program
- Operating experience program
- Quality audits and self-assessments of programs
- Boric acid corrosion management program
- Reactor coolant system unidentified leakage monitoring program
- In-service inspection program
- Modification control program
- Radiation protection program 12-05-2002 8
C ( (
- . Davis-Besse Oversight Update Restart Checklist
- 4. Adequacy of Organizational Effectiveness and Human Performance
- Adequacy of root causes
- Adequacy of corrective actions
- Effectiveness of corrective actions 12-05-2002 9
Davis-Besse Oversight Update Restart Checklist
- 5. Readiness for Restart
- Systems readiness for restart
- Operations readiness for restart
- Test program development and implementation 12-05-2002 10
6 C (I
- .u!Davis-Besse Oversight Update Restart Checklist 6.&7. Licensing Issue and Confirmatory Action Letter Resolution
- Resolve three limited ASME code relief requests
- Meet with the NRC to obtain restart approval I1I 12-05-2002
( C C Davis-Besse Oversight Update Inspection Accomplishments
- Completed and Ongoing Inspections
- 1. Augmented inspection team follow-up
- 2. Reactor vessel head replacement
- 3. Containment health assurance/boric acid extent of condition
- 4. System health assurance
- 5. Program effectiveness
- 6. Organizational effectiveness and human performance 12-05-2002 12
C C, C
' ADavis-Besse Oversight Update Inspection Accomplishments
- 1. Augmented Inspection Team Follow-up Findings
- Violation of pressure boundary leakage requirements (Technical Specification)
- Failure to take corrective actions (10CFR50, Appendix B, Criterion XVI)
"* Boric acid buildup on reactor head
"* Boric acid accumulation on containment air coolers
- Contaminant clogging of radiation element filters
"* Installation of service structure access modification for inspection and cleaning
"* Adverse trend in reactor coolant system unidentified leakage 12-05-2002 13
Davis-Besse Oversight Update Inspection Accomplishments
- 1. Augmented Inspection Team Follow-up Findings (Continued)
- Failure to have adequate boric acid corrosion control procedures (10CFR50, Appendix B, Criterion V)
- Failure to follow boric acid corrosion control and corrective action procedures (10CFR50, Appendix B, Criterion V)
- Failure to provide complete and accurate information (10CFR50.9) 12-05-2002 14
Davis-Besse Oversight Update Inspection Accomplishments
- 2. Reactor Vessel Head Replacement
- Results
"* Replacement head meets ASME Section III N-stamp requirements
"*Replacement head non-destructive examination adequate (several code relief requests under review)
- Outstanding issues
- Reactor coolant system pressure test e Containment integrated leak test 12-05-2002 15
( ( (
4 ,
A1'. Davis-Besse Oversight Update Inspection Accomplishments
- 3. Containment Health Assurance/Boric Acid Extent of Condition
- Results
- Evaluation of structures systems and components adequate
- Repair and refurbishment activities ongoing
- Outstanding issues
- Reactor pressure vessel bottom head integrity
- Environmentally qualified splice maintenance concern e Electrical conduit corrosion ground path concern 12-05-2002 16
( C C Davis-Besse Oversight Update Inspection Accomplishments
- 4. System Health Assurance Inspection
- Results
"* Davis-Besse review process adequate
"* Davis-Besse design and operational review identified several issues
"* NRC design review identified several issues
"* Davis-Besse evaluating need for scope expansion
- Inspection approximately 50% complete 12-05-2002 17
' C C Davis-Besse Oversight Update Inspection Accomplishments
- 5. Program Effectiveness Inspection
- Results
"* Davis-Besse review process adequate
"* Review of boric acid corrosion management and corrective action program adequate
- Inspection approximately 25 % complete 12-05-2002 18
C ( C S Davis-Besse Oversight Update Inspection Accomplishments
- 6. Organizational Effectiveness and Human Performance Inspection
- Results
"*Davis-Besse completing root cause assessments
"* Corrective actions initiated for identified causes adequate
"* Safety culture and safety conscious work environment corrective actions initiated
- Inspection approximately 25 % complete 12-05-2002 19
C ( C Davis-Besse Oversight Update Plant Equipment Issues
- 1. Reactor Pressure Vessel Bottom Head
- 2. Containment Sump
- 3. Decay Heat Valve Pit
- 4. Coatings Inside Containment 12-05-2002 20
C ( C w u Davis-Besse Oversight Update Plant Equipment Issues
- 1. Reactor Pressure Vessel Bottom Head
- Accumulations on bottom head in-core detector nozzles
- Chemical analysis not conclusive
- FirstEnergy planning a leakage test at normal operating temperature and pressure 12-05-2002 21
( C C "Davis-BesseOversight Update Plant Equipment Issues
- 2. Containment Sump
- As found condition
"* Screen mesh size
"* Gaps
"* Non-permanent modifications Approximately 50 square foot screen
- Modification to increase screen area to approximately 1,200 square feet 12-05-2002 22
C C C Davis-Besse Oversight Update Plant Equipment Issues
- 3. Decay Heat Valve Pit As-found condition Valve operators not qualified for submersion
"* Plate closure sealing challenge
"* As-left and as-found testing Modification to enclose and .$
properly seal valve pit 12-05-2002 23
Davis-Besse Oversight Update Plant Equipment Issues
- 4. Coatings Inside Containment
- Containment walls and dome
- Conduit
- Core flood tanks and reactor pressure vessel .0 12-05-2002 24
C ( C 4
O Davis-Besse Oversight Update Conclusions
"* USNRC oversight activities well organized and focused
"* FirstEnergy's restart reviews ongoing
"* FirstEnergy's actions appear adequate and safety focused
"* USNRC activities fulfilling Performance Goals 12-05-2002 25
United States Nuclear Regulatory Commission Davis-Besse Reactor Vessel Head Degradation Lessons-Learned Task Force Briefing for ACRS December 5, 2002 I
Overview
Background
- NRC has taken the initiative to conduct lessons-learned reviews for significant issues Self-critical Improvements made Examples:
"*Indian Point 2 steam generator tube failure (2000)
"*NRC inspections at the South Texas Project (1995) 2
Overview Objectives and Scope
"* Perform independent evaluation
"* Review:
SReactor oversight process Regulatory processes Research activities International practices Generic Issues program
"* Identify and recommend improvements 3
Overview Composition and Attributes
"* Multi-disciplined, experienced team
"* No previous significant involvement in Davis-Besse Nuclear Power Station (DBNPS) oversight
"* Observation by State of Ohio
"* Stakeholder input to task force review activities
- 1. Solicited input at two public meetings 4
Overview Review Methods
- Comprised of two groups
- Performed document reviews and conducted interviews
- Conducted fact finding at DBNPS site
- Conducted reviews at NRC Regional Offices and Headquarters 5
Overview Report
"* The report is available on ADAMS (the NRC electronic document management system)
,. Accession number: ML022760414
"* The report is also available on the NRC's public website:
http://www.nrc.gov/reactors/operating/ops experience/vessel-head-degradation/news.html
"* The report issuance was coordinated with other NRC offices because of ongoing NRC-related reviews DBNPS plant-specific issues were provided to the NRC's 0350 Oversight Panel for follow up, as appropriate.
6
Results Overall Conclusions
- NRC and industry recognized potential for this type of event nearly 10 years ago
- Initial conclusion was that vessel head penetration nozzle cracking was not an immediate safety concern P Further reviews became protracted
- NRC and DBNPS failed to learn key lessons from past boric acid-induced degradation events 7
Results Overall Conclusions (continued)
- The leaking nozzle and vessel head degradation was not prevented The NRC, DBNPS, and the nuclear industry failed to adequately review, assess, and follow up on relevant operating experience
- DBNPS failed to assure that plant safety issues would receive appropriate attention The NRC failed to integrate known or available information into its assessments of DBNPS's safety performance 8
Results Overall Conclusions (continued)
Other contributing factors Guidance and requirements Staffing and resources DBNPS communications Licensing processes and implementation 9
Results NRC, DBNPS, and Industry Review, Assessment, and Follow up of Operating Experience
"* Significant operating experience involving boric acid leakage and corrosion
"- Generic Communication Program implementation
"* Generic Issues Program implementation
"* Operating experience involving foreign nuclear power plants
"* Assessment and verification of industry technical information
"* NRC operating experience review and assessment capabilities 10
Results DBNPS Assurance of Plant Safety
"* Reactor coolant system leakage symptoms and indications
"* Boric acid corrosion control program and implementation
"* Owners group and industry guidance implementation
"* Internal and external operating experience awareness
"* Oversight of safety related activities 11 Results NRC Integration of Information into Assessments of DBNPS Safety Performance
- Reactor coolant system leakage assessment
- Inspection program implementation
- Integration and assessment of performance data
- Guidance and requirements
- Staffing and resources
- Davis-Besse Nuclear Power Station communications
- Licensing process guidance and implementation 12
Recommendations Recommendation Areas
- Inspection guidance
- Operating experience assessment
- Code inspection requirements
- NRC programs and capabilities (including training and experience)
- Leakage monitoring requirements and methods
- Technical information and guidance
- NRC licensing processes
- Previous NRC lessons-learned reviews 13 Future Activities Senior Management Review Team
- Team of senior NRC executives reviewed report and recommendations
- Action plan developed to implement recommendations 14
Closing Remarks Summary
- The NRC conducted a comprehensive, self-critical assessment of its regulatory processes as a result of the DBNPS degraded reactor vessel head.
- The NRC identified a number of areas for improvement and has initiated actions to address these areas.
15
Realistic LBLOCA Methodology Presenter: Larry O'Dell December 5, 2002 Rockville, MD A
- FRAMATOME ANP Realistic LBLOCA Methodology
Purpose:
Provide an overview of the complete methodology, which conforms to the CSAU approach. Some selected examples will be discussed to illustrate how successful the model is in predicting key thermal-hydraulic phenomena.
> Agenda I m Requirements and Capabilities
. CSAU Element 1, Steps I through 6 n Assessment and Ranging of Parameters
- CSAU Element 2, Steps 7 through 10 n Sensitivity and Uncertainty Analysis
- CSAU Element 3, Steps II through 14 A _
FRAMATOME ANP I
Realistic LBLOCA Methodology -9
> Requirements and Code Capabilities (CSAU Element 1) m S'pecffy Scenario (CSAU Step 1) e Specified the large break LOCA scenario o Select Plant (CSAU Step 2) e Selected V 3- and 4-loop plants and CE plants o Identify and Rank Phenomena (CSAU Step 3) e Phenomena Identification and Ranking Table (PIRT) developed A
FRAMAT OME ANP Realistic LBLOCA Methodology
> Requirements and Code Capabilities (CSAU Element 1) n Select Frozen Codes (CSAU Step 4)
- RODEX3 and S-RELAP5 codes selected m Provide Complete Documentation (CSAU Step 5) e Models &Correlations, Programmers, &Input manuals developed
- Determine Code Applicability (CSAU Step 6)'
- Codes demonstrated to be applicable to selected scenario and plant types FRAMATOME ANP 2
.. Realistic LBLOCA Methodology J
> Assessment and Ranging of Parameters (CSAU Element 2) n Assessment Matrix (CSAU Step 7)
- 15 SET facilities and 130 tests evaluated
- 2 lET facilities and 6 tests evaluated n Nodalization (CSAU Step 8)
"*Selected based on experience, plant studies, peer review, and assessment evaluation
"*Final nodalization has 2D components for downcomer, core, and upper plenum
.A FRAMATOME ANP Realistic LBLOCA Methodology J
> Assessment and Rangirn4gof Parameters'(CSAU Element 2) a Code and Experiment Accuracy (CSAU Step 9)
"*Code model biases and uncertainties determined by comparison of code to SET experiments defined Inassessment matrix
- 23 phenomena evaluated
- 13 phenomena treated statistically I
- 10 phenomena found to be either unimportant or modeled conservatively
"*Code model biases confirmed through the performance of independent SET and lET analyses with biases applied
- CCTF, LOFT, and Semiscale FRAMATOME ANP 3
I 2 Code and Experimental Accuracy (CSAU Step 9) J LOFT LP-LB-1 S-RELAP5 ANALYSIS 15000 19400 14400 10000 a
L) 9400
- Measured Data
- PCT nodeC IZ
-S-RELAP5 base case
-- - S-RELAP5 biased rn*n I - 4400 00 110 22.0 330 440 550 660 Core Central Assembly Elevation (inches)
A FRAMATOME ANP Experimental Accuracy (CSAU J
90.0 A
FRAMATOME ANP 4
P Realistic LBLOCA Methodology
"*>Assessment and Ranging of Parameters (CSAU Element 2)
= Effects of Scale (CSAU Step 10) o Scalability of tests
- Tests generally demonstrated to be scalable
- Full scale UPTF tests used to address refill phase
- Scalability of code models
- Code models demonstrated to either be scalable, conservative, or validated on full scale tests
- Scalability confirmed in validation of code model biases
- Model biases generated on data from one set of SET tests and validated on different SET and lET tests of different scale A OMEANP Realistic LBLOCA Methodology.
> Sensitivity and Uncertainty Analysis (CSAU Element 3).
a Reactor Input Parameters and State (CSAU Step 11)
- Plant input and process parameter list developed m Plant Sensitivity Calculations (CSAU Step 12) 9 Over 250 sensitivity studies *performed for plant parameters and PIRT "phenomena ranked 5 or higher" -
- , Results confirmed PIRT rankingis nd defined Important plant parameters
- Plant parameters found to impact PCT included in statistical analysis
- Analy.is addresses plant speýific Technical Specification "FRAMATOME ANP 5
I I K], Plant Sensitivity Calculations (CSAU Step 12)
Senitivity Stuizes for .BLOCA Toa O-ange in Sestvty Tderae Toierno cae Descri+/-n (IF) M M 1 181 181 181 2 F, ard F... 147 233 52 3 Rhl Baling HTC 145 275 42 4 Srgle Riase Wr HTC 140 308 34 5 Core Intor-pse Fncdon 110 328 19 6 Gap Coniduclivty 96 341 14 7 RnW 130 89 353 11 8 Condesaton Inter-phase HTC i1Imw=mer 87 353 11 9 81 372 9 10 74 380 7 11 AiU*crTearmer~tre 65 385 6 12 Ira Loop Flow 63 390 5 13 ,axwurncator Presue 6O 395 5 14 Loop 57 399 4 15 Hot Leg Irteracial Dag 54 403 4 16 46 405 3 17 core P 43 408 2 44 CHF 2 437 0 A
N ___
Realistic LBLOCA Methodology
> Determine Combined Bias and Uncertainty (CSAU Step 13) m Uses uncertainties developed from assessments as input to analysis
- Unlike CSAU approach does not use response surface, instead uses non-parametric statistics
@Propagates uncertainties through transient using plant model e Allows statistical treatment of a large number of variables
- Provides 95195 PCT and associated maximum nodal, and total core oxidation
- Relies on the execution of 59 cases to determine a 95/95 condition e Each case defined by randomly selecting a value for each parameter being treated statistically I A FRAMATOME ANP 6
Realistic LBLOCA Methodology:
> Determine Combined Bias and Uncertainty (CSAU Step 13) n Define cases to be run
- Parameter Case 1...Case 2 .......................... Case N
-A
-B
-zzz A
F MTOME ANP "RealisticLBLOCA Methodology
> Total Uncertainty (CSAU Step 14) m The statement of total uncertainty for the analysis is given as a statement of probability for the limiting value of the primary safety criteria n For the sample problemis the limiting values for the primary safety criteria are: 4-loop 3-loop Criteria Case 22 Case 41 95195 PCT 1686 F 1853 F Maximum Nodal Oxidation 0.8 % 1.3 %
Maximum Core Oxidation 002 % 0 04 %
,50150 PCT - 1375F 1500 F FRAMATOME ANP 7
Realistic LBLOCA Methodology
> Conclusions n An overview of the complete Framatome ANP Realistic LBLOCA methodology has been provided
"*Demonstrated use of the CSAU methodology elements and steps
"*Demonstrated improved statistical treatment
- Non-parametric statistics allowed treatment of a large number of parameter uncertainties, eliminating the need to determine penalties
- Used SETs to remove biases from code models and to determine model uncertainties
- Used lET's to evaluate code model biases on Independent sets of data A
FRAMATOME ANP 9