Plant License Renewal-March 28, 2001
Official Transcript of Proceedings NUCLEAR REGULATORY COMMISSION Title: Advisory Committee on Reactor Safeguards Plant License Renewal Subcommittee Docket Number: (not applicable) Location: Rockville, Marylad Date: Wednesday, March 28, 2001 Work Order No.: NRC-136 Pages 1-174 NEAL R. GROSS AND CO., INC. Court Reporters and Transcribers 1323 Rhode Island Avenue, N.W. Washington, D.C. 20005 (202) 234-4433. UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION + + + + + ADVISORY COMMITTEE ON REACTOR SAFEGUARDS (ACRS) PLANT LICENSE RENEWAL SUBCOMMITTEE + + + + + MEETING + + + + + WEDNESDAY MARCH 28, 2001 + + + + + ROCKVILLE, MARYLAND + + + + + The Subcommittee met at the Nuclear Regulatory Commission, Two White Flint North, Room T2B3, 11545 Rockville Pike, at 8:30 a.m., Dr. Mario Bonaca, presiding. Plant License Renewal Subcommittee Members Present: MARIO V. BONACA, Chairman F. PETER FORD THOMAS S. KRESS GRAHAM M. LEITCH WILLIAM J. SHACK ROBERT E. UHRIG ACR Consultant Present: JOHN BARTON ACRS Staff Present: SAM DURAISWAMY ROBERT ELLIOTT Also Present: RAJ ANAND HANS ASHAR RAJ AULUCK RAY BAKER WILLIAM (BUTCH) BURTON JOSE CALVO GENE CARPENTER JAMES DAVIS ROBIN DYLE BARRY ELLIOT WILLIAM P. EVANS JOHN FAIR GEORGE GEORGIEVE DAVE GERBER CHRIS GRIMES MARK HARTZMAN DAVID JENG MEENA KHANNA W. KOO Also Present: (cont.) MARGIE KOTZALAS P.T. KUO CAROLYN LAURON CHANG-YANG LI Y.C. (RENEE) LI WAYNE LUNCEFORD KAMAL MANOLY KENNETH McCRACKEN DONALD P. MOORE JEFF MULVEHILL KEITH NICHMAN K. PARCZEWSKI ERACH PATEL CHARLES PIERCE FRED POLASKI JAI RAJAN JANAK H. RAVAL PAUL SHEMANSKI JOHN STEVENSON KATHRYN SUTTON DAVID TERAO BRIAN THOMAS HAROLD WALKER DOUG WALTERS I-N-D-E-X AGENDA ITEM PAGE Opening Remarks, M. Bonaca, ACRS . . . . . . . . . 5 Staff Introduction, C. Grimes, NRR . . . . . . . . 6 Overview of SER Related to Hatch License Renewal, W. Burton, NRR. . . . . . . . . . . . . 7 Southern Nuclear Operating Company, Inc., Presentation, R. Baker, SNC. . . . . . . . . . .16 Background, C. Pierce. . . . . . . . . . . . . .16 License Renewal Application Scoping and Screening Process (IPA), R. Baker. . . . . .20 Aging Effects Aging Management Programs. . . . . . . . . . . .98 Time Limited Aging Analyses SER Section 2.0 - Structure and Components Subject to an Aging Management Review, W. Burton, NRR. . . . . . . . . . . . . . . . . . .60 SER Section 3.0 - Aging Management Review, NRR Staff. . . . . . . . . . . . . . . . . . . . . .98 Operating Experience Summary SER Section 4.0: Time-Limited Aging Analyses, J. Fair, NRR . . . . . . . . . . . . . . . . . 153 Discussion, M. Bonaca, ACRS. . . . . . . . . . . 156 Adjourn, M. Bonaca, ACRS . . . . . . . . . . . . 174 . P-R-O-C-E-E-D-I-N-G-S (8:30 a.m.) DR. BONACA: Good morning. The meeting will now come to order. This is the meeting of the ACRS Subcommittee on Plant License Renewal. I am Mario Bonaca, Chairman of the Subcommittee. ACRS Members in attendance are Peter Ford, Thomas Kress, Graham Leitch, William Shack and Robert Uhrig. We also have John Barton attending as a consultant. The purpose of this meeting is to review the Southern Nuclear Operating Company's application concerning the license renewal for Edwin I. Hatch Nuclear Plants 1 and 2 and the associated NRC staff Safety Evaluation Report. The Subcommittee will gather information, analyze relevant issues and facts and formulate proposed positions and actions as appropriate for deliberation by the full committee. This meeting is being conducted in accordance with the provisions of the Federal Advisory Committee Act. Mr. Sam Duraiswamy is the cognizant ACRS staff for this meeting. Mr. Robert Elliott who is on rotational assignment to the ACRS staff from NRR is also present. The rules for participation in today's meeting have been announced as part of the notice of this meeting previously published in the Federal Register on March 8, 2001. A transcript of this meeting is being kept. It will be made available as stated in the Federal Register notice. It is requested that speakers first identify themselves and speak with sufficient clarity and volume so that they can be readily heard. We have received notice of comments and request for time to make oral statements from members of the public. We will now proceed with the meeting and I call upon Christopher Grimes of NRR to begin. MR. GRIMES: Thank you, Dr. Bonaca. My name is Chris Grimes. I'm the Chief, License Renewal and Standardization Branch and we've organized the presentation today to discuss the staff's Safety Evaluation Report for the Hatch License Renewal Application with an emphasis on identifying in the Safety Evaluation Report some of the uniquenesses of the first BWR review. We're going to start off with an overview by the Project Manager, Butch Burton and then Southern Company is going to provide a presentation on the application. And then we'll get into the specifics of the safety evaluation. The staff's presentation will identify where there are open items and we would appreciate the ACRS views on the open items, but I want to stress that beginning tomorrow, we're going to have the first of what I consider to be a series of meetings in which Southern Company is going to appeal staff positions on these issues and we're going to work that process to develop final staff positions and the resolution of the open items. And with that, I'll turn the meeting over to Butch Burton. MR. BURTON: Can everybody hear me okay? I'm going to be using the mobile mike here. As Chris said, my name is William Burton, but as you probably -- Chris probably clued you in I prefer to go by Butch. I am the Project Manager for the Hatch License Renewal Application Review. Let me get this mike situated here. I'll start with a little bit of background here. I'll go through this briefly. We've had the application in-house with the staff for a little over a year. It was actually submitted by application by a letter dated February 29th. As you, I'm sure, most of you know, this is a Boiling Water Reactor, the first to come in for license renewal. It is a BWR/4 design, and two units. The plant is located on the Altamaha River. I hope I pronounced that right, in Appling County, Georgia. It's about 11 miles north of Baxley and I believe, as the crow flies, it's probably about 70 miles from Savannah, Georgia. Unit 1, the current license is due to expire in 2014 and they have asked for an extension of that additional 20 years to 2034. Likewise, Unit 2 is currently scheduled to end its license in 2018 and they're looking to extend it to 2038. One thing that I did want to do, this is not in your package, but I did want you to see the review schedule very briefly so you can see ware we are. March 16th, we completed the second of the three scheduled inspections, the V inspection where primarily the inspection team went to the site to confirm that some of the commitments that are currently in the Aging Management Programs are properly being implemented at the site. And as a result of that inspection we have pretty good confidence that they are identifying their commitments as identified in the Aging Management Programs and properly implementing them on site. Right now, all of the changes that they have to make to the current procedures are pretty much in draft or proposed form, but they are u them. It was my understanding that one of the committee's main interests was to compare the Hatch Plant being the first BWR with some of the previous applicants, in particular, to see if there was anything materially different between what we're seeing at Hatch and what we have seen at some of the other plants. And having taken a step back and taken a look at that, we really do not see any new technical issues. As Mr. Baker from Southern Nuclear will go into detail in a few minutes, Hatch took a commodity approach to their evaluation and as such, what we do is -- what they did was they identified materials of construction, the environments that those materials operate in, and then identify any applicable aging effects. And in fact, what we found is that there are no unique materials, there are no unique environments, and so we do not have any new or unique aging effects. So in that respect, which is the primary technical issue, we really don't see any difference between Plant Hatch as the first BWR and any of the previous applicants who are all PWRs. Most of the differences that I'll talk about between Plant Hatch and some of the previous applicants is really, it's really a matter of process and formatting and that's primarily what you see with the remaining bullets. It is the first to use the Boiling Water Reactor Vessel and Internals Project Reports. Now my plan today was not to go into a whole lot of detail about that since you all covered it pretty well yesterday. So what we'll do is as we talk about it, the appropriate points, we'll point out where BWRVIP reports were applied in the review. Plant Hatch was the first to use the functional approach versus the system approach in the scoping process. I was going to go into a fair amount of detail about this, but Mr. Baker is actually going to be coming up after me and he's going to go into substantial detail on the scoping and screening process. So if you don't mind, I'll hold off on that. Then finally, they were the first to apply the Aging Management Program attributes to demonstrate adequacy of aging management as opposed to the Aging Management Programs themselves. I do have another supplemental graph here, vu-graph here to show you what I mean by that. Again, this is not in your package and I know it's hard to read, so I'll try and explain. What Southern Nuclear did was they took the 10 attributes that we're all familiar with and what we're used to seeing is having those 10 attributes applied to each Aging Management Program. And they took a unique approach which actually the staff found good. And what they did was they took the 10 attributes and at this point in addition to applying them to each Aging Management Program, they actually looked at, for instance in this case, they created what are called Aging Management Program Assessment Tables. This particular one I have up here is for copper and alloys within a river water environment. That's the commodity group and the specific aging effect is flow blockage due to aging mechanism fouling. And what they did was they said, for instance, the scope, how do we ensure that we capture everything that we need to capture for this? And they say here are the Aging Management Programs that do that. And what they did was they actually went through each of the attributes and actually showed programmatically how they captured that. And that was unique and the staff found that really very helpful in our review. That was another unique aspect. MR. LEITCH: Butch, I notice that there seem to me, at least, to be an unusually large number of RAIs associated with this. Would you say that some of these four differences that you've just listed are primarily what caused this large number of RAIs? MR. BURTON: It was -- MR. LEITCH: First of all, was there an unusually large number of RAIs? MR. BURTON: It was hard to judge. We didn't go in to the review, because it was the first BWR. We didn't go in with any preconceived notions of how many RAIs would be appropriate. Obviously, we saw with the PWRs, because we had some familiarity with them, we expected the RAI account to drop which we pretty much saw. If you compare the number of RAIs for Plant Hatch, we had more. DR. BONACA: It seems to me on the same issue that many of them are tied to the ficklety on the part of the staff to ascertain if certain components were or were not part of the license. In fact, in many cases it was more of a question of why is the component not in and then the answer was yes or no. I mean in many cases the component was ins the scope. So there was an issue with the ficklety of checking scoping? MR. BURTON: Yes. I'd say the majority of the RAIs fell into two groups, one was as Dr. Bonaca mentioned because of the unique approach and the formatting of the application, there were a number of RAIs that were -- had to do with clarifications of things. In the beginning, the staff had a little bit of trouble understanding how to navigate through the application. And we had a number of RAIs that were related to that. The second thing and what accounted for approximately one third of the total RAIs and there were some 400 and some odd RAIs, I can't remember the exact count, 428. Approximately, one third of those had to do with -- I put up the vu-graph before of the assessment table and how they applied the 10 attributes. As I said, our guidance applies to 10 attributes to each Aging Management Program. In the initial submittal of the application, as I mentioned before, the 10 attributes were actually applied to a demonstration of adequate aging management. So what happened was we had a lot of RAIs that came in very repetitive for each Aging Management Program to say what is the scope, what are the parameters being monitored, what is the monitoring and trending? Because initially, we didn't see that clearly in the Aging Management Program descriptions. So what you'll find if you go over the RAIs, you'll see, as I said, fully one third of them very repetitive in asking those kinds of questions. Had we not asked those questions, and if we had not had the trouble with the navigational problems, the RAIs probably would have been in line with the previous applications. MR. GRIMES: This is Chris Grimes. I would like to on a very gross basis compare the questions on Hatch with the Calvert Cliffs and Oconee. Calvert Cliffs and Oconee were in the range of 430 to 450. And as Butch pointed out, by virtue of the packaging technique, we did end up with a lot of duplicative questions on Hatch. And if you account for those, I'd say we were on about the same level as we were on Arkansas and we did -- I did feel as I looked through the feedback that we got from the applicants on the nature of the questions that there is evidence the process improved and that we're learning and to the extent that we learned some lessons in terms of communication techniques, those were fed back into the Improved Renewal Guidance for future applicants. So on a very gross basis, I'd say that I'm very comfortable that the level of questions for Hatch were not out of line for the first BWR. MR. LEITCH: Thank you. MR. BURTON: Now in terms of the comparison to some of the previous applications, those are really the major differences, primarily process. But in terms of technical differences, we really did not see much because as I said, they used the same materials. They generally operate in the same environments and so therefore we have the same aging effects. So we really did not see much technically different. That's pretty much it for my overview. I wanted to answer any questions, any comments you may have and then after that, I'll turn it over to Mr. Baker from Southern Nuclear. Questions? Comments? Okay, I'll turn it over to Ray. MR. BAKER: Good morning. Charles Pierce, who is the manager of the License Renewal Section at Southern Nuclear is going to do the background and introduction for our part of the presentation. MR. PIERCE: I just wanted to start by saying it is a pleasure to be here this morning before the ACRS Subcommittee and Ray and I are going to spend probably the next 45 minutes or so discussing our license renewal application with you. I'm just going to start with more or less the background and Ray's going to get into some of the details. For my part, I just wanted to open it up by saying that I think Ray will mention and I just wanted to mention for my purposes that I've been in nuclear power for about 20 years. I started with some that probably the ACRS is very familiar. I started my career in environmental qualification and moved on to a number of other areas and now I'm in license renewal. So I began license renewal activities back in 1991-1992 time frame with the first rule, and so I've been working in license renewal ever since. Southern Nuclear has also put a lot of resources into the license renewal through the years as well. We've put a lot of time and effort into developing the revised rule and Southern Nuclear actually participated in the license renewal demonstration project with the NRC in 1996. Next slide. (Slide change.) MR. BAKER: I'm not going to go into any details on this next slide. I think Butch covered an overview of the Hatch information and background adequately. I'll just mention that I've always liked this picture with the rainbow overhead. I think that's a nice touch. MR. BARTON: Is there a pot of gold at the end of it? (Laughter.) MR. PIERCE: The renewal, right. Next slide. (Slide change.) MR. PIERCE: With regard to some of the things that I just wanted to touch on here, Hatch was the first utility to effectively file an electronically formatted application and drawings. I think the NRC found that very useful. The application and drawings were hyperlinked for ease of use. We also -- as we heard earlier, worked to develop an alternate application format and we filed that format using an early version of the standard application format. The reason I mention that is because that standard application format effectively was developed between the NRC and industry in the last few months in the development of our application. We had to do a significant rewrite, but we felt it was important to do so. I think it benefitted both sides, the NRC and us, to go through that process. We did follow in great detail the development of the BG&E and Duke processes as they went through their activities. We actually had either directly attended almost every BG&E and Duke meeting here at the NRC or had contractors attend on our behalf and write detailed meeting minutes for us. We followed their letters and docket interactions and we incorporated those activities into our application as we felt appropriate. Finally, in the 1999, late 1999 time frame, as the application was nearing completion, we brought together a group of what I call key industry experts to perform a peer review of our application. We actually brought with our internal resources and the industry experts, the review staff amounted to about 30 individuals, 25 and 30 individuals. MR. BARTON: Who are these industry experts? MR. PIERCE: People like Bob Nickell who is the ASME president. I don't know if you know Bill Denny, electrical -- he's the individual that worked at Ogden that helped develop the spaces approach in the early stages with -- that we applied. I think everybody knows Jack Roe. He used to work here at the NRC. There were some structural integrity folks as well that supported us at that meeting. So there were several people of that stature there, along with some individuals from individual utilities like PECO and so forth that actually reviewed our application. And basically the review went along procedural and legal lines, mechanical, structural and electrical. We basically had those four areas that were looked at. We divided the group up, people up into different groups and actually had them look at the information in that light. So we broke the application down in four different areas for their review. And we incorporated the comments from that peer review as well. So that is the background that I really wanted to go through here and now I'm going to turn it over to Ray and let him continue with some of the discussion, detailed discussion on our application. DR. BONACA: At some point I would be interested in hearing something about this functional approach rather than the system approach because it's unique for use, at least. This is the first time we see that. MR. BAKER: I'll try to address that. DR. BONACA: To understand why you took that direction rather than the approach taken by the other applicants today. It would be interesting. MR. BAKER: All right. Good. Thank you, Charles. As I go through the presentation this morning, please feel free to interrupt and ask the questions as they occur and we'll endeavor to answer them to the extent that we have that knowledge here today. My name is Ray Baker and let me say that I appreciate the opportunity to speak to you today on behalf of Plant Hatch. I'd also like to thank the NRC staff for the hard work, for the professional and thorough review that's gone on to this point. The fact that all the milestone dates have been met to this point indicates a significant effort on their part and getting the application to this point in the review process. I first saw Plant Hatch as a brand new junior engineer right out of college in 1972. At that time, Unit 1 was pretty much structurally complete. Unit 2 was coming out of the ground. So I've been involved with Hatch for a very long time. My entire career of almost 30 years at Georgia Power and now Southern Nuclear has been associated with Hatch. It pleases me that at this point I'm able to be involved in the re-licensing activities for the plant that I participated in the original licensing activities on some 30 years ago. As Chuck noted in his comments we began discussions with the NRC License Renewal Branch regarding a suitable application format, actually fairly early in the review cycle of the Calvert Cliffs and Oconee applications and we -- and I believe along with the NRC staff were interested in finding ways to improve on the review process and we were encouraged to explore different approaches. Chuck mentioned that somewhat in his presentation. About six months, as I recall, prior to the scheduled submittal date for Hatch, we, that is, the industry, NEI and the NRC, began to settle on an early version of what has become known as the standard application format. We agonized over the decision whether to convert at that stage in the application preparation, but finally we did choose to adapt the application to match the standard format to the extent possible. The principal impact produced by that format conversion was the production of summary table results and Sections 2 and 3. In retrospect I view that as a good decision to format, to change the format. The summary table format is a clear and concise way to present a lot of information so I think that on balance, the format conversion resulted in an improved review and so again, I think it was a good decision. Perhaps the one place where the Hatch application format is most noticeably different from the current standard format is in the presentation of programs. Butch mentioned one aspect of that and we may talk a bit more about that later. But the standard format assumes program descriptions will be provided in Appendix B. The Hatch application that we provided originally placed those program descriptions in Appendix A which is generally called the FSAR supplement. There was also additional significant information on how those various program elements fit together to demonstrate adequate aging management for each commodity group in our Appendix C. The level of detail that you find by combining those two areas is really not significantly different from the level of detail you would expect in Appendix B. They were just in several places. So early in the review, we concluded based on feedback from the NRC that in order to facilitate that review, a stand-alone Appendix B would be useful and we provided that supplemental document as part of our responses to the early round of RAIs that came in. (Slide change.) MR. BAKER: As you can see from this vu-graph, the organization of the application does follow familiar lines. Section 1 provides the general information that's specified pursuant to 10 CFR 54.19(a) and (b). Section 2 describes and justifies the scoping and screening methodology and the results, pursuant to 10 CFR 54.21(a)(1) and (2) and again, that's in a tabular format. Section 3 describes the process we use to merge component groups into commodities. And in addition, although not required by the regulation, it's useful and so we placed it here, a description of the Aging Management Review process that we employed. Finally, Section 3 includes also in a tabular format the summary results of the Aging Management Reviews. Section 4 presents the time-limited aging analyses and exemptions. Appendix A describes the programs and activities for managing aging. It also contains a summary description of the Time-Limited Aging Analyses and these items are as specified in the rule. Where Section 3 presents a tabular summary of the aging management results, Appendix C provides the meat of the application from our perspective. The appendix is divided into two sections. The first section systematically discusses combinations of fabrication, materials and external and internal environments as Butch mentioned. This generic presentation identifies aging effects requiring management for each combination of materials and environment. I will discuss that in more detail later in the presentation. The second part of Appendix C presents more detailed summaries of the Hatch specific Aging Management Reviews so the first part of Appendix C is a generic evaluation of materials and environments and the second part of Appendix C is on a commodity by commodity basis, a more specific Aging Management Review and again, this is grouped by materials of fabrication and environments for component groups that we call commodities. And I will describe the process for grouping those components in a few moments when I get to vu-graph 10. These detailed summaries in Appendix C provide the linkage of programs and activities to aging effects associated with the commodities and in that way demonstrating adequate aging management for each commodity group. That is our demonstrations were made in Appendix C. And lastly Appendices D and E contain the environmental report supplement and the technical specifications changes required for their renewal term respectively. MR. LEITCH: Ray, just before you leave the introductory material, I had a question on page 1.1-10. It says SNC requests a class 104 operating license for Plant Hatch 1 and a class 103 operating license for Unit 2. I don't understand that terminology nor distinction there. What's the distinction between a Class 104 and 103? MR. BAKER: This is, I believe, ancient history that goes back to the kind of operating license that was granted in the original term. MR. LEITCH: I see. MR. BURTON: In the very early days, so the Unit 1 license was a Class 104 as I believe you said, and the Unit 2, Class 103. Chuck, did you have more details on that? MR. PIERCE: The Atomic Energy Act, when it was promulgated specified basically two types of licenses. One was called a research -- I forget the complete name. It was a Class 104 license. The other one was a production reactor which was a Class 103 license. Actually, if you go back to some of the earlier applications that had recently been approved, they were typically 104 licenses, but Hatch sort of was in that in between time where the plants were now moving to ask-informed receiving 103 licenses, so we have the difference in 103 and 104. MR. LEITCH: I guess then my question is primarily for the NRC. Is that something we want to perpetuate? MR. GRIMES: This is Chris Grimes and I'll attempt to respond to that. As a matter of fact, my recollection is that the original licenses were called Demonstration Power Reactors, DPR licenses. MR. BAKER: Right. MR. GRIMES: And practically speaking for the purpose of the safety evaluation, there is no difference in the way that the safety evaluation is conducted. As a procedural matter, we've concluded that renewed licenses should maintain the same numbering scheme for simplicity of the way that we manage the licenses. And so you'll find that in the information digest as it lists the historical milestones of each individual plant, their class is 104 and 103 and it's legally important in terms of the basis for granting a license and it's nexus to the Atomic Energy Act. But I think for your purpose, you won't see any distinction in the treatment. I do recall that during the conversion of the Plant Hatch to the improved standard tech specs that having two very different licensing bases, I mean Unit 1 was reviewed prior to the Standard Review Plan and Unit 2 was fundamentally standardized and in trying to merge those two licensing bases during the design basis reconstitution efforts and subsequent tech spec conversions, that was uniquely challenging, but I don't think the two different license types will impede you in any way. MR. LEITCH: Okay, thank you. One other question on the introduction. I noticed there are several owners in addition to Southern Nuclear but I didn't see percentage ownerships. Are they clearly minority owners or what is the percentage of ownership? MR. BAKER: Southern -- Georgia Power Company is the majority owner of Plant Hatch by a few fractions of a percent. A large minority stake is held by Oglethorpe Power Corporation and somewhat smaller percentages by the Municipal Electric Authority of Georgia and the City of Dalton. MR. LEITCH: Okay, thank you. Those percentages are the same for both units? MR. BAKER: I believe for Hatch that is true. It is different ownership percentages between Hatch and Ogle, but the other Georgia Power Company plant, but Plant Hatch is the same for both units. MR. LEITCH: Thank you. MR. PIERCE: The other point I'll mention with that is that the operations authority has invested in Southern Nuclear by Georgia Power Company and the co-owners. So Southern Nuclear has filed this application on their behalf. MR. LEITCH: Thank you. (Slide change.) MR. BAKER: So this is how the application is organized, and now I'd like to discuss the scoping and screening process we used. We developed a comprehensive list of systems and structures and we identified functions for each system or structure on the list. Each function was evaluated against the eight scoping criteria in 10 CFR 54.4(a)(1), (2) and (3). On this vu-graph we showed that engineering and licensing documents were used in the evaluation of identified functions against the three safety-related criteria of 10 CFR 54.4(a)(1) and also in the evaluation of functions against the criterion of 54.4(a)(2) which is the nonsafety-related that would prevent safety-related functions. And I would note that with regard to this criterion, all functions were evaluated against this criterion, not just the nonsafety-related functions. We evaluated safety-related functions against the nonsafety-related function criterion as well. (Slide change.) MR. BAKER: And in a similar manner, engineering and licensing documentation was used in the identification of functions relied on for compliance with our Commission regulations specified in 10 CFR 54.4(a)(3). The four regulations that are applicable to Plant Hatch were EQ, ATLAS, station blackout and fire protection. Since Plant Hatch is a BWR, pressurized thermal shock is not included in that Hatch is exempt from that regulation. Three separate reviews were performed as a part of our scoping process. The primary review was a system and structure-specific review. To supplement the system-structure specific review, NRC Safety Evaluation Reports were reviewed to assure all functions relied on for compliance with the four Commission regulations were identified and scoped. And in addition, we called on in-house experts for further assurance that all the functions relied on for compliance with the four regulations were identified and scoped. These separate stand-alone reviews were conducted for additional assurance that the scoping relative to this criterion was complete and comprehensive. (Slide change.) MR. PIERCE: As I noted on the previous vu-graph, we have used engineering and licensing documents to perform the function scoping. The block on the left identifies some of the major document sources used. Obviously, our Final Safety Analysis Report was used. We also used our Equipment Location Index. We call this the ELI. It's an engineering database of components. It's not a Q-list, but it does provide quality and seismic class information for the components that are listed in that document. DR. BONACA: Did you use also the Q-list? MR. BAKER: There is not a specific Q-list per se at Plant Hatch. This is the equivalent of that. MR. PIERCE: The equivalent Q-list at Plant Hatch is actually, you go back and I think look at some of the earlier letters to the NRC is actually the Safety Evaluation Documents which is listed as well. MR. BAKER: It's the Systems Evaluation Document. MR. BAKER: The reason that we don't solely rely on the Equipment Location Index is that it's not a complete listing of components. For example, pipe segments are not listed in that listing. We used other documents. Chuck mentioned the System Evaluation Document which does, in one of the appendices of it contain the listing of safety- related components. You asked why function scoping and the Plant Hatch Maintenance Rule Manual was selected as a key document due to similarities between Maintenance Rule Scoping criteria and the License Renewal Scoping criteria. At Plant Hatch Maintenance Rule Scoping was done on a functional basis. The Maintenance Rule Scoping identified a large number of functions and then they scoped those functions based on the criteria applicable under the maintenance rule. We were able to use that as a starting point to have a ready-made source for most of the functions that we identified in the course of our scoping review for license renewal. And we recognized that there are differences in the criteria and one of the things that we did was to assess and reconcile the differences in results obtained by the maintenance rule scoping and our scoping review. For example, the safety-related criteria are almost identical and so we're able to make substantial use of those, but other criteria are just not applicable in license renewal space. So the set of functions that we identified using all of these documents, plus other sources, we did not restrict our reviewers to the set. This was the beginning set of documents for each person to use as they were doing their scoping evaluations. If their reviews led them into other information sources, we encouraged them to go to those sources to obtain that information. So as a result, each function that was identified was evaluated against the eight scoping criteria as stated on the previous vu-graphs and any function that met one or more of the eight criteria was classified as being in scope. In the language of the rule, these are the functions that are the intended functions. DR. BONACA: I guess where I've been trying to go was how did you assure that by this process you have addressed every safety-related component in the plant? That's the first question of the rule. So now you choose a function and approach, but you certainly want to verify that that is the outcome. That's important because then all the other applicable components are those that support? MR. BAKER: That's correct. DR. BONACA: Essentially those functions. How do you assure that you have the correspondence there and you included all those components? MR. BAKER: As Chuck noted the system evaluation document listing of the safety-related components was consulted and we made sure that every component in that listing is within at least one or more evaluation boundaries where we did the screening. DR. BONACA: Yes. The reason for me asking these questions, I'll be open with this, is that I have reviewed the application in some detail and I had some trouble at the beginning in understanding what was in scope. For example, I found things like Table 2.2.1, System F-16, fuel storage equipment not in scope. But then I go around and I find F.16.01 storage racks and they are, I believe, in scope. And then there is a statement in a note that says retained for continuated purposes. So I didn't understand whether it -- and that was under a different function. I could not trace it. So I was left with some questions in my mind about what does it mean to retain for continuated purpose? It is either in scope or it is not in scope, I guess. I'm looking at it simplistically, but -- MR. BAKER: You're right. DR. BONACA: And it was a little bit difficult and I guess so you're saying, your circumstances for the plant, whatever, led you not to use the approach that other system plants were using at the same time which is because all the ones we have seen today, they use the system approach. MR. BAKER: They used the system approach and I think everybody is familiar with that approach and comfortable with that approach. DR. BONACA: Yes. MR. BAKER: And as Butch mentioned during the review process early on, I believe that did lead to some difficulty in getting the reviews started. In retrospect, that's an area that is a little more complicated perhaps than first appeared. One of the things that we did do though is to generate the evaluation boundary drawings and try to provide those as an adjunct to the application so that if there was a question about a particular component, those drawings could be consulted to say is it within an evaluation boundary or is it not. And on that basis if it shows up outside any evaluation boundary, then the conclusion was that it was not in scope. DR. BONACA: Yes. Now the staff, I understand, we'll hear later, they audited the standby liquid control system, the high-pressure coolant injection system and the service water system and you found -- MR. BURTON: Yes. I was going to talk about that a little bit later. It's part of the scoping inspection, went through some of that. DR. BONACA: Okay, all right. MR. LEITCH: I guess I had a similar navigational problem in my review. Perhaps you could just help me with this. Table 2.2-1, the first two lines on there, A70 and A71, analog transmitter trip system and nuclear steam supply shutoff and then for in scope it says yes for both of those items. And the third one is reactor assembly, B11. So then I went back to 2.3-1 and I find the reactor assembly and then it seemed like all the others I found in this mechanical screening results, but I don't find A70 and A71. I just had a little trouble understanding what happened to this. MR. PIERCE: Okay. And I'd have to -- MR. BAKER: Chuck has the application. MR. PIERCE: I have the application in front of me. B11 is mechanical system and as such hit's listed under the mechanical system screening results. A70 and A71 are more directly related to an electrical. You should see those -- MR. BAKER: I would expect that this kind of navigational difficulty is really related to the conversion format effort that we went through to try to put this into a standard format relatively late in the process and I believe that even for us, sometimes we have to look to see what part, whether it was mechanical, electrical or civil, any particular item was placed in because sometimes they are somewhat counterintuitive. MR. LEITCH: In the SER, those first two items are listed under electrical. MR. BAKER: Yes, electrical. Those first two items are electrical, yes. MR. PIERCE: The electrical system because of the implementation of the spaces approach doesn't have the same component discussions in that same section as mechanicals do. That's why you don't see it there. MR. LEITCH: Okay. So these two systems are in scope, but then did they -- how do I find out whether they screened out or not? MR. BAKER: The electrical approach that we used is the same as was used by Oconee and ANO, so most electrical components, of course, are active in screen out and what you're left with is the same set of the passive long-lived electrical components that the other plants had. MR. LEITCH: Yes. I would expect that they would screen out. MR. BAKER: Yes, and it was a plant-wide spaces approach that was used. MR. LEITCH: Okay, thanks. MR. BAKER: Okay. So the output from the scoping review was a set of intended functions which are the, as we discussed, the end scope functions. These functions and again, this was a part of the uniqueness that was described, cross over traditional system boundaries and we allowed the function to go where it naturally goes and the best example of that function that crosses traditional system boundaries would be a containment isolation function which would be the active closing all lines and penetrations of containment. In our plant nomenclature, that's C61, but you find that that applies to components in many, many systems. Every line that penetrates containment with isolation valves has a part of that story, but the function went regardless of system designation. And so, as a result there's some overlap of these functions and you find some components showing up in multiple functions. DR. BONACA: Well, in part, it's because those, some components have multiple functions. MR. BAKER: That's right. DR. BONACA: And in your approach, you really identify a main function for it. MR. BAKER: Yes. DR. BONACA: And you followed through with that approach. Okay, but I understand now the example of the containment is a good one. MR. BAKER: Yes, okay. So I would know that while these functional boundaries cross the traditional system boundaries, all components that are required to perform or support the function once it's identified as in scope are in scope regardless of the system nomenclature. So a B21 function could have and I'm just saying this hypothetically, an E11 component supporting it. As an aid to the screening of the mechanical components, evaluation boundaries were produced for each in scope function. Mechanical components within the evaluation boundaries were screened to identify those subject to aging management review. The screening criteria used were those contained in 10 CFR 54.21(a)91)(i) and (ii), that is we screened for the passive long-lived components. Within each evaluation boundary we grouped the like components with similar environments. For example, within an evaluation boundary, all stainless steel valves with a demineralized water environment would be identified as a component group. Another component group within the same boundary might be carbon steel valves with a demineralized water environment and another might be stainless steel pipe and so on. Each component group within an evaluation boundary was designated as active or passive and as long or short lived. For review efficiency we performed additional evaluations during this stage of the process. Rather than revisiting each component group again later, during the Aging Management Review process we assigned component functions and identified materials of fabrication and the internal and external environments for each component group during the screening step. It was just for a matter of efficiency. The active-passive determinations for each component group were based on the original component list, arrived at from discussions between NEI and NRC and the NEI 95-10 document. During our review, we created additional component types and assigned active-passive determinations based on similarity to other components or specific NRC guidance because during the process resolution was achieved on some components that in the original NEI 95-10 list has an asterisk. That resolution was achieved during the process and we applied that NRC guidance to those. Long list components were those not subject to periodic replacement based on qualified life. By repeating this screening process for each evaluation boundary, we produced nearly 2,000 component groups. These component groups were then consolidated into commodities prior to performing the Aging Management Reviews. (Slide change.) MR. BAKER: This is a figure from the application. This figure illustrates the process used to consolidate component groups into commodity groups. In this example, we start with two systems that are very similar from a materials and environment perspective, the high-pressure coolant injection system and the reactor core isolation cooling system, E41 and E51 in the Plant Hatch system designation. Several in-scope functions may be primarily associated with system E-41 HPCI and I've just for illustration purposes indicated that there are four functions here and similarly, that there would be four functions for in-scope functions for E51. In fact, that's not the case. It's just for illustration purposes. As I described on the previous vu-graph an evaluation boundary then is established for each of the in-scope functions. And the components are screened into component groups. Thus, on the third level, which is this level here, you see examples of stainless steel piping and stainless steel valves and as I said, the environments associated with each component group were identified for convenience during the screening step, so we have that information developed here. For simplicity, we only showed demineralized water as an environment on this vu-graph. But you can visualize component groups of stainless steel piping, demin. water, stainless steel valves, demin. water, from the evaluation of boundaries developed out of this E41 path and similarly, out of the E51 path. And obviously, other groupings also exist due to different materials, components and environments. This example is only intended to show the process and it's complex enough without adding the additional clutter of other materials and environments. The heavy line across the middle of the page in this example is adjacent to the examine environment and materials label. This pictorially represents the output of the screening step. At this point, each component type, for example, stainless steel piping associated with E41 function 1 is a component group because it has a material and environment associated with it. So I have a component group of stainless steel piping, demin. water at this point. Subsequent to screening, but prior to performing the Aging Management Reviews, we further consolidated the groupings by collecting like component groups associated with all in-scope functions into commodity groups. That is, all component groups having the same materials and environments were collected into a single commodity group and the example here shows that being collected into a commodity group of various stainless steel components with a demin. water environment. This commodity grouping was performed to fully utilize a review and evaluation process that systematically evaluated research information and industry operating experience. Based on those evaluations, it was possible to identify for each combination of materials and environment, a set of aging effects that might be detrimental. DR. BONACA: Did you use the GALL 2 report? Because in draft 4 there is a lot of information there. MR. BAKER: It was under development and actually we were observing and then watching the process, but we did not -- we were not able to make use of it during the development of ours. But I will note that a number of the things that you see in this approach are similar to processes that you saw in some of the early development work of the GALL. DR. BONACA: Okay. (Slide change.) MR. BAKER: So based on the process described each structure or component subject to Aging Management Review was included in one or more in-house reviews. The Aging Management Reviews were performed on a commodity group basis and a total 112 Aging Management Reviews were performed, 96 mechanical reviews, 9 civil structural reviews, 5 electrical reviews and 2 reviews performed by our NSSS vendor, GE. The box in the upper right hand of this vu-graph depicts that aging effects requiring management were determined systematically for each commodity group from the set of potentially detrimental aging effects identified in the generic evaluation. I mentioned this generic evaluation earlier when I was describing the application format. This evaluation is summarized in Appendix C1 of the Hatch application and it's based on work that was performed initially in support of the Oconee application and that's subsequently been used by ANO and Hatch and this is now an EPRI report and is being used by other licensees as they prepare their applications for submittal. It consists of an extensive review of industry literature to identify potential aging effects for various materials and environments of interest and nuclear power plants. The resultant information is systematically arranged into flow charts that can be used by qualified engineers in evaluating the license renewal commodity groups. NRC Generic Communications formed a part of the industry literature examined and synthesized. In this manner, the industry operating experience is captured. Plant-specific operating experiences also reviewed during performance of the Aging Management Reviews to validate the determinations of aging effects requiring management specifically for Plant Hatch. So the output of the tool is a set of possible or potential aging effects for any combination of environments and materials as an engineer would work through the flow charts. And based on the review of the summary discussion in the report and a review of the plant specific operating experience and the review of other technical literature that the engineer may choose to go to, the engineer would then make an evaluation and determination of whether an aging effect that might occur would be an aging effect that would require management during the renewal term. The box in the upper left hand of this vu- graph depicts the assessment of aging management activities already in place, based on a survey of plant and support organization procedures. If necessary, program enhancements were proposed or new programs or activities identified. Appropriate program coverage for the structures or components comprising each commodity group was identified or established. And I would -- as you noted earlier, Dr. Bonaca, this process is similar to what you see in some of the GALL work. The demonstration of adequate aging management is made for each commodity group by the combination of programs or activities credited with managing each aging effect for each commodity group. The combination of aging management activity selected in an aging management review had to address all 10 attributes we established as descriptive of an adequate aging management program. The program attributes we chose are the same as those identified in the draft standard review plan for license renewal and Butch showed you a vu-graph of one table and how we assessed the programmatic coverage. There is a table like that for every commodity group for every aging effect that was identified as requiring aging management. As I said a moment ago, the generic identification of potentially detrimental aging effects was based, in part, on the review of NRC Generic Communications. So when all the AMRs had been completed at the end, we conducted another review of the Generic Communications that had been issued subsequent to the initial review and this served to validate that all potential aging effects were addressed by the process. (Slide change.) MR. BAKER: The output from the Aging Management Review is programs, programs and activities. DR. BONACA: These programs you are going to present, are they the existing one, or are they the enhanced one, part of this? MR. BAKER: This is the presentation that I show here is a combination of existing enhanced and new. DR. BONACA: Okay, because I mean your application shows five existing, five enhanced programs and seven new programs. But then there was an interaction with the staff and I believe there was a request by the staff for an additional one-time inspection. I would like at some point anyway to have a summary of the end of your presentation of where you stand right now insofar as enhanced programs and the one-time inspections or the new programs because I'm using application as a basis. I think there have been some changes there? MR. BAKER: Yes sir. MR. GRIMES: Dr. Bonaca, this is Chris Grimes. I'd also like to suggest that you be very careful about your accounting because the resolution of open items might end up changing the results. MR. BAKER: Right. MR. GRIMES: And we have -- we have promised to come back for the full committee meeting and the discussion of the improved renewal guidance and do the best that we can to do a consistent accounting of one-time inspections across all of the renewal applications. DR. BONACA: Yes, that is exactly why I was asking that question, so there is some flux going on. This is more -- accounting is purely on the perspective we see applications coming in. We see one-time inspections decreasing in number. We're trying to learn as a committee where the industry is going and why some of these programs are not necessary any more. In some cases, we understand and in others, we don't. Also, it gives us an idea of what additional burden license renewal imposes on applicants. And so that's why I asked that question. MR. BAKER: All right. This vu-graph does not break it down into existing, enhanced or new, but I will address that in just a moment. We have identified 30 programs or activities that will be relied on in the renewal term to adequately manage aging effects for the in-scope structures and components. On this vu-graph I depict two types of programs and activities. In these examples, we credit seven different chemistry activities and six different regulation-driven programs. (Slide change.) MR. BAKER: On the next vu-graph we have designated programs to implement the BWRVIP activities which Robin discussed with you yesterday afternoon and RPV monitoring. In addition, 11 plant-specific programs or activities are credited for managing aging in the renewal term. (Slide change.) MR. BAKER: And then finally on the next vu-graph, I illustrate four new one-time confirmatory inspections that we are crediting. Now another way to describe these programs would be 17 existing programs or activities that required little or no enhancement; 5 enhanced programs or activities; and 8 new programs or activities, half of which are these new one-time confirmatory inspections. The reason that there's a difference in the number from what you said of 7 and what I said is 8 is we have agreed to provide a non-EQ cable monitoring program that will be a 30th program and so it shows up in that listing. The distinction of existing and enhanced, I think is somewhat a blurred line as well because virtually every program will be touched and then some small changes made to it, but that doesn't necessarily rise to the level of being an enhanced program, enhanced in our perspective here I think means significantly altered. DR. SHACK: As I'm looking through your application, it seemed to me that although you're on hydrogen water chemistry, as hard as I looked through the application, I think I found it mentioned once and I assume that means that you don't think you're taking credit for hydrogen water chemistry, that you could justify the extension without it, even though you have chosen to implement it. Is that a correct interpretation of the way you've written the application? MR. BAKER: That's correct, yes. And in fact, the EPRI Water Chemistry Guidelines that we do credit have provisions for both the normal water chemistry regime and the hydrogen water chemistry regime and so as a matter of our operating flexibility you would want to maintain the ability to periodically for maintenance purposes or whatever other reason take the plant into a normal water chemistry regime temporarily while you affected those activities. Certainly, obviously, our intent and desire based on other considerations is to operate within the regime that is consistent with the BWRVIP guidance in this area. Robin, did you have anything more to add on that? MR. DYLE: Bill, I guess another way to look at it is we didn't want the HWC to be a condition of the relicensing process, but we absolutely intend to use it and because that program is structured for normal or HWC, if for some reason we had to stop using the hydrogen injection, we would still have the ability to manage the VIP program and do the inspections because it's structured for either option. So we simply chose not to take credit in the application for it. But we fully intend to use it. Once you invest that amount of money to protect the plant, it doesn't seem reasonable to stop. DR. SHACK: Okay, and your argument would be that, in fact, your inspection program would then flip back and forth to cover the -- if and some reason you ever stopped. MR. DYLE: Right. If for some reason we stopped hydrogen, we'd have to go to the normal water chemistry inspection programs. As we discussed yesterday, there's currently only two programs that we've got that HWC built in. The rest of them we're waiting on approval of VIP 72 and resolution of issues with the staff before we broaden the scope of that credit for HWC. DR. UHRIG: A question on the non-EQ cable management program. This would be the medium voltage and high voltage cables primarily since most of the low voltage -- maybe the low voltage cables are EQ? MR. BAKER: Let me ask Jeff Mulvehill of our staff to discuss the scope of that program. MR. MULVEHILL: This is Jeff Mulvehill of Southern Nuclear. The program would actually all types of cables. It will be mainly focused on identifying adverse localized environments or places where the cable could be experiencing accelerated aging. In normal plant environments, the cable is going to last 60 years. That's what our analysis told us. So it's mainly going to be focused on identifying those areas where cable -- DR. UHRIG: This is the visual and inspection time? MR. MULVEHILL: That's correct. DR. UHRIG: And some physical measurements? MR. MULVEHILL: We have not identified in the answer to the REI the exact test that we'll use at that point. Those types of things are still evolving. MR. BAKER: Jeff, is this consistent with the work that's being done in the industry electrical group working in the GALL arena? Is that correct? MR. MULVEHILL: Our cable mirrors the program in the GALL Report. MR. BAKER: Thank you. MR. BARTON: Under the new NRC assessment process, what's the NRC's assessment of your corrective action program? MR. BAKER: Butch, do you want to speak to that? MR. BURTON: I'll take a crack at that. I have to run back and look at the color. (Laughter.) MR. BARTON: Basically, that's all -- MR. BURTON: I don't know that we've got the results, but I know where the chart is posted and at the break I'll run back and check it. MR. BAKER: So in all, these 30 programs that I've put up on these three vu-graphs provide the attributes necessary to manage the aging effects that are identified for in-scope structures and components during the renewal term. (Slide change.) MR. BAKER: Finally, I'd like to describe our process for identifying Time-Limited Aging Analysis. The regulations provide six criteria, all of which must be met in order for a calculation or an analysis to be considered a Time-Limited Aging Analysis. As you can see on this vu-graph, we compiled a list of calculations to broadly include any with a time-limited nature. Because of the large number of calculations, more than 8,300, we initially screened them using the time-limited nature of the calculation criterion. Only those calculations that passed this first test were further screened in more detail using the remaining five TLAA criteria. More than 1,200 calculations passed this initial screening and more than 900 met all 6 criteria. In addition to the review of calculations, a separate CLB review was performed to assure all potential TLAAs were evaluated. In other words, we did a word search of our FSAR and other documents to try to find things that might also appear to be a TLAA and deal with those. (Slide change.) MR. BAKER: And so the final view-graph that I have in this part of the presentation is this view-graph identifies the TLAAs for Plant Hatch that were identified using the screening process that I described. They are fatigue, corrosion allowance, EQ, containment penetration pressurization analysis, RTNDT, upper shield energy and an analysis of a technical alternative to a code required inspection of RPV circumferential welds. The way it's broken out in the application is a little different. I've combined a couple of them in the first bullet. DR. BONACA: In the application you have identified them? MR. BAKER: Right, and the last one, I think, we're not -- is not a TLAA based on further discussion. That was in the application. This was the MSIV cycle items. DR. BONACA: So, okay, the stress analysis for thermal fatigue. Okay. MR. BAKER: Yes. DR. BONACA: Which one did you combine? MR. BAKER: The first one, stress analyses, I think is broken out as two items in the application. That concludes my part of the presentation. I'd be happy to answer any other questions if there are any. If not, I'll turn it back to Butch. DR. BONACA: Well, I have some questions about some of this. Maybe I'll wait for the NRC SER discussion because I have some questions. MR. BAKER: Okay. MR. BURTON: I guess we have a couple of options at this point. Normally, according to the agenda, we'd be taking a break. DR. BONACA: Why don't we do that. MR. BURTON: We're ahead of scheduled, do you want to do that? DR. BONACA: We're ahead of schedule a bit, but I think the best thing to do is to break now and then to start the NRC presentation after that. So let's resume again at 10 o'clock. (Off the record.) DR. BONACA: Okay, we resume the meeting now with the presentation by the NRC staff. MR. BURTON: Thank you, Dr. Bonaca. What we're going to do now is we're going to start through the Safety Evaluation Report and talk a little bit about some of the results that the staff has as well as a brief discussion of some of the open items that are on the table. Now one of the things that -- the way I had planned to do this was I wasn't going to go into a whole lot of detail if you didn't want me to, so at the appropriate times, please feel free to stop me. We have the appropriate staff members off to the side who will be able to handle any of the tough questions that I can't. So let's get started. Starting with scoping and screening, Section 2. In Section 2.1 in both the application and the SER is where methodology is discussed and as Mr. Baker pointed out in the last session, Southern Nuclear scoped at the function level. In other words, they looked at each system, identified all of the functions for the system and then took each function and ran it through a series of screens. And when I say that, what I mean is a series of eight questions to basically see whether it meets the scoping criteria as to whether it's safety related, nonsafety related, whose failure could impact safety-related function and needed for any of the four out of five regulated events. And anything that's -- in answer to any of those questions, anything that was a yes was considered an intended function and brought in scope. Screened at the component level. Once they identified the in-scope functions, then they looked at components in each system that were required to meet those functions. And as Mr. Baker said earlier, along with the submittal of the application, they also provided us with the evaluation boundary drawings which was extremely helpful to the staff. Basically, what they did was they took PNIDs and color coded them to help show us exactly where the boundaries were for each function. DR. SHACK: Was that in response to an RAI or was that part of the application? MR. BURTON: The drawings are not technically part of the application, but they were provided to us with the application. It wasn't in response to an RAI. Those turned out to be very helpful because as was mentioned in the last session and for some of you also, the staff, like you, experienced some what we call navigation problems. DR. BONACA: Those are not part of the application. I imagine they will be retained by the applicant? MR. BAKER: Yes, that's correct. DR. BONACA: So the traceability can always be verified for any issue. DR. SHACK: What is the documentation look like when you go back and you try to pull the string to find out how they went through the screening process with the eight criterion. Is there a checklist? What do you actually see when you go back and you inspect? MR. BURTON: It's actually interesting. Let me put this up. I'm actually going to explain it to you in reverse. (Laughter.) DR. SHACK: Everything's backwards for this application. MR. BURTON: Southern Nuclear started with the scoping and the screening and moved towards the Aging Management Programs. One of the things that we did as a staff is we started at the Aging Management Programs and worked out way back to see what were the aspects of the Aging Management Programs, for instance, what was in the scope of the Aging Management Program and we would go back to the Appendix C tables to see whether or not all of that had been actually been captured and then from there we took a step further back. So we actually worked in opposite directions and the fact that the application was electronic with point and click and it would take you to different places, we actually found that was one of the navigation problems that we had in that you could point and click in one direction, but it wasn't as easy to go in the other direction the way we were doing the review. So yes, in answer to your question, what we actually did was we actually looked at the Aging Management Programs and looked at what, for instance, what was the scope of this particular Aging Management Program? What commodity groups were included and then we would go from there to Appendix to confirm that there was proper cross referencing and things like that. So it was actually -- it's actually like a fun jigsaw puzzle. I guess that's how you would best put it. DR. SHACK: But that was on the up-front scoping. That is, when you're trying, you have a function and you're trying to see whether it obeys the A criterion in the rule, how is that documented? It's not in the application, but presumably when you go back and you do an inspection, you see some kind of records and what kind of record is actually produced? MR. BURTON: Actually, I guess the best way to explain that is to talk a little bit about what happened during the scoping inspection, because that is where we did some of the confirmative stuff. Let me put this up real quick. As I mentioned before, as part of the review process, we have three inspections that we do, the first being the scoping inspection which was actually scheduled for late October. We actually did in early September. What we did -- the purpose of that was to make sure that what we were seeing in the application in terms of what was identified as being in scope and what was identified as not being in scope was actually confirmed through looking at some of their source documents as Mr. Baker had identified before, the Maintenance Rule Scoping Manual, the Equipment Locator Index, things like that. So the inspection team actually went down and we took a sampling of several systems and actually walked through the process and what we found was that as a practical matter, the scoping was actually done in accordance with the way it was described in their application and in accordance with the rule. One of the things that we also found though was that the actual guidance documents at Southern Nuclear that was to explain step by step how to do it, it was results oriented as opposed to step by step, here's what you need to look at, things like that. And we had identified that in the scoping reports, inspection report, that that was one of the areas that needed improvement which they subsequently did. And in fact, the next time we visited them we took a second look at the procedures that provided the guidance for doing the scoping. We found that it was much more in line with what we had expected. So again, to answer your question, what we actually did was and again, a lot of it was driven because of some of the initial questions that we had as a result of navigational problems as we said well, let's sit down and actually take a look at this. Let's look at the evaluation boundary drawings. Let's see what functions are captured. Let's look at the things that are in the boundary. Let's look at the things that are out of the boundary. Let's see how they documented that and see whether it is in line and appropriate. And we found that as a practical matter, it was. Did that answer -- DR. SHACK: That helps. The other question I had was this Maintenance Rules Scoping Manual which would sort of strike me as a secondary source kind of thing. Somehow that meant that somebody went through an analysis, presumably from the FSAR, some more fundamental document and did that once and have other people used that as a kind of a primary source for this approach? I assume that everybody has something like that. They've done it as part of their maintenance rule implementation. MR. BURTON: Yeah, I really can't speak to how other applicants have done it. All I can say is and again, correct me if I'm wrong, the Maintenance Rule Scoping Manual, when you looked at what was scoped in and you compared that to what we were looking at for license renewal, there was a significant amount of overlap, so I think from -- again, correct me if I'm wrong, from Southern Nuclear's point of view, work smart, not hard. Let's start with what we have and expand from there. MR. BAKER: Butch, just to amplify on that and actually maybe clarify a question that was asked during my session, Chuck mentioned that we participated in a demonstration project with the NRC back in the early days of license renewal and one of the things that we did in that demonstration was to present a full plant scoping which was done from a system orientation. And the review at that time asked a number of very difficult questions related to comparing our results to maintenance rule scoping results and so we took out of that a task for ourselves to go back and redo the scoping oriented on functions, similar to the way that the maintenance rule scoping had been done. And so that was the genesis of that. In fact, the maintenance rule scoping that was done was an expert review panel kind of an approach at Plant Hatch. You had a number of people that were assembled together that crossed the spectrum of experience, plant operations people, engineering personnel and so forth to cover everything from operating procedures to the FSAR in identifying the functions and then doing the scoping work in accordance with the maintenance rule. And so that was really the genesis of that document's use for us in license renewal. It was related to our experience in the demonstration that we did as well as having that ready made source of information available. And I think, also in answer to your question, what you will find in-house is, on a computer data base a record for each function that was identified that answers for each of the eight criteria yes or no, in scope or not in scope as a result of any of those being a yes. So the direct answer is, there is a data base that contains the results. MR. BURTON: And -- go on, I'm sorry. MR. LEITCH: I was going to bring up another issue. I thought there was -- it seemed to me there were some unique problems associated with scoping and screening of skid-mounted equipment. MR. BURTON: Yes. MR. LEITCH: Could you say a couple of words about that? MR. BURTON: That is, I believe, two vu-graphs from now. MR. LEITCH: Okay, fine. MR. BURTON: I'll hold on to that one. But I do want to say that given some of the initial challenges that we had with the scoping portion of the application, the scoping inspection was real critical. We made sure that all of the reviewers who were involved with the scoping had basically given us a list of tasks for the inspection team, in addition to the things that we had as part of our inspection plan and primarily, we did take a sampling of the systems and actually walked from the beginning of the development of the functions for that system and actually walked all the way through to see how they scoped it, how they established the evaluation boundaries and then ultimately how they did the screening. For the electrical portion, it was actually somewhat done in reverse as Mr. Baker had explained before. For that, they had identified all of the electrical types, regardless, just all of them. And then identified those that were passive and long- lived and then from that population identified those that met the scoping criteria. DR. BONACA: Now you said that you went in reverse, but I also saw in the SER that you reviewed resistance as I mentioned before. So you went more in reverse, you went -- MR. BURTON: Yes. Well, those were the three. The reverse process that I spoke about is what the reviewers pretty much did here at headquarters. DR. BONACA: And their review of two of those three systems showed everything that you would consider in scope was in scope? MR. BURTON: Yes, yes, yes. Okay, one area that I know has come up with some of the previous applications is the issue of design-basis events and what population of events was actually considered in the development. At the time that the application was submitted, Southern Nuclear was in the final stages of putting together what they call the Nuclear Safety Operational Analysis and that has subsequently been finalized and actually been incorporated into their FSAR, but at the time of the application, it was still in draft form. One of the things that we did during the scoping inspection was to take a look at this analysis and what the analysis was was a comprehensive consideration of all the design basis events and as part of that, if you recall from the rule, one of the things that's done is on an annual basis there is an update to the application based on changes to any changes that may have taken place to the CLB. What Southern Nuclear did was because it was in draft form at the time that the application was submitted, they did commit as part of that annual update to take a look at the results of that NSOA, Nuclear Safety Operational Analysis and to update the LRA based on any additional changes to the CLB that may have come up. And they did that and I think as a result of that there was maybe one additional, the rod block monitor that actually came in scope as a result of that. But as part of our inspection, we did take a look at that NSOA as to understand exactly what DBEs were considered in their evaluation. As a result of our review of the scoping methodology, we did come up with one open item having to do with seismic II/I piping. Seismic II/I piping current is not in scope. The staff had a disagreement with Southern Nuclear about that. We viewed seismic II/I piping as being part of the more general category of non-safety related SSCs whose failure could adversely, you know, the one scoping criteria. From what Southern Nuclear has done is they've identified the seismic II/I piping and have taken the step of seismically supporting that and their point of view is that given that it is seismically supported, the fact that it could fail or fall on safety-related equipment is basically hypothetical at this point. So it is one of the items that we have on the table and we are in continuing dialogues trying to resolve that. So that is one of our open items. MR. GRIMES: Butch, and this is one of the appeal issues. So for each of the open items that's on the agenda for the appeals session that we're going to have tomorrow, we'll identify those. MR. BURTON: Okay, that's right. That is one of four appeal items and I'll point those out to you as we go. DR. SHACK: And what exactly does that mean? MR. BURTON: Appeal? DR. SHACK: Yes. MR. BURTON: Good question. Appeal items are open items where at least on the face of it the staff and the applicant are fairly far apart and what the license renewal process allows for is an appeal process. The appeal process involves an airing of each side to -- I guess for lack of a better word, a panel. The appeal meeting that we're going to be having tomorrow is basically at the Branch Chief level so what we'll have is a staff and Southern Nuclear each giving their view of the open item and why they feel the way they do and we'll have several Branch Chiefs and Chuck Pierce from Southern Nuclear who will sit and listen to both sides and question and dialogue and hopefully reach a resolution. If not, the appeal process moves on where we will next schedule another meeting at the next higher management level and we will continue on through like that until we can reach a reasonable resolution. That's what I mean when I say appeal process. DR. SHACK: Now was this used with the other application? Somehow I don't recall hearing about it before. MR. BURTON: It's always -- MR. GRIMES: The answer is yes. We established this as part of the procedures for the conduct of the renewal review and it's consistent with the approach of the staff asks one round of questions and then drafts a safety evaluation with open items and then the resolution of the open items is either obvious by virtue of the staff's articulation of what needs to be resolved or the resolution is then appealed to successive levels of management and we use this technique for Calvert and Oconee and it was quite effective. Now for Arkansas, they had six open items, but there was only one appeal issue and that was on the scope of fire protection equipment. And that issue ended up being resolved at the first appeal. In the articulation of the issue, the staff and the applicant saw various lights and decided on a solution. And for Hatch, we've got four of the I believe it's 17 open items, Butch? MR. BURTON: Eighteen. MR. GRIMES: Eighteen open times. Four of the 18, there's a dispute and we need to air the dispute in order to understand how the open item is going to be resolved. If it's identified as an open item and we don't designate it as an appeal issue, then presumably you will gain some confidence that the staff and the applicant understand what the issue is and what it takes to get it resolved. (Slide change.) MR. BURTON: Okay, moving on to plant level scoping results, Section 2.2 of the SER. We did not have any open items, but I did want to take the opportunity to point out here and actually Dr. Bonaca had mentioned it in the last session. One of the things that we found as the staff in reviewing, in particular, Table 2.2-1 which several of you have mentioned in the last session is that there were several instances where when you look at a system and all the functions that that system performs, obviously, we know that there are certain things that we know a certain system performs and in the particular case I was going to bring up was containment isolation. We know, for instance, that main steam has a containment isolation function and yet when our reviewer looked at the Table 2.2-1, did not see that identified as one of the functions. This is getting to what you were talking about before. And so that naturally led to the question where is that function? Why do you not have it there? And in our dialogue with Southern Nuclear is when we came to understand that certain functions that cut across a number of systems, they chose to pull out and actually have it in its own place. In this particular example, it turned out to be under C61. But that's another navigational issue that the staff had had to deal with. So that's what I mean when I say grouping of common system functions. (Slide change.) MR. BURTON: Section 2.3.1 of the SER was just an introduction. And then we got into reactor and reactor coolant systems. I've identified the four systems that make up this group. Again, we found no open items. We found that the scoping and screening were appropriate. This is where we started to get into dialogue with them about some of the BWRVIPs and primarily many of the questions when we asked about why something not in scope and why it is or is not, we were referred back to some of the BWRVIP documents that would identify that this is not an event that we really think would happen and things like that and that's why you would not see it as a system or a component within a system that would have any aging effects that would requirement management. And we found some of the references to VIP in this section. MR. LEITCH: There are a number of VIPs referenced that are not yet approved by the NRC. How did you resolve that issue in your own mind? MR. BURTON: Yes, go ahead. MR. ELLIOT: Barry Elliot. I was going to address that later, but even though some of the VIPs were not approved, we reviewed them and the reviews were far enough along that we could look into them and see how they applied to Hatch. And some of our open items result from those reviews. And I'm going to discuss that later on. MR. LEITCH: Okay, thank you. MR. BURTON: Let's see, where am I? We're going to get to, Dr. Leitch, one of the things that I had asked you to hang on with me for a second. (Slide change.) MR. BURTON: The next section involved the engineered safety feature systems. There were eight of them and I have them listed here. We did have a couple of open items that came out of that. The first, scoping and screening of skid-mounted components for the hydrogen recombiners. This is a complex assembly issue if any of you are familiar with that. We wrestled with this issue of complex assemblies with Oconee and the emergency diesel generators. At this point in the review, Southern Nuclear has committed to actually doing the scoping and screening in accordance with what was agreed to and is now in the SRP that came about as a result of the review of Oconee. DR. BONACA: And it's also in the NEI document, right? There is addressing complex assemblies there. MR. BURTON: It does address complex assemblies. From what I understand the latest revision of NEI 95-10 has made some modifications, but I believe it is still basically there with a few modifications, yeah. So we are actually on our way to resolution on this one. The second issue, this is one of the issues that's going through the appeal meeting tomorrow. Scoping and screening of housings for fans, dampers and heating and cooling coils for the standby gas treatment system. This is actually going to come back again for a couple of systems in the next section for auxiliary systems. What this involves is housings for active components. Under license renewal, fans, dampers, these components are active. The staff's question is that's fine, but what about the housings for these components? We are looking at that similar to what is currently in NEI 95-10 where they make the distinction between valves and valve bodies or pumps and pump casings. NEI 95-10 specifically identifies valve bodies and pump casings as being passive and rightly so. The staff is saying in the same vein the housings for these active components are similarly, have similar functions in terms of pressure retention, structural integrity, things like that. So this is another item that's on our appeal meeting for tomorrow, on the agenda for our appeal meeting. MR. GRIMES: Butch, if I may, in order for you to understand our terminology distinctions, the first is called the complex assembly issue and that has to do with how groups of equipment are treated with respect to potential passive functions and the second one is we refer to as a piece parts issue and it's not, again, it's not a new issue. In fairness, from the applicant's perspective, it's how low do you go in terms of breaking active components looking for passive elements and we're going to hopefully learn some, another lesson in this exercise that will help us to clarify how you identify passive elements of active components. DR. BONACA: Yes. This already, these issues were discussed already for the previous applications. MR. GRIMES: Actually, not this particular twist. DR. BONACA: I understand, but I believe that housing for these kind of components for other applications were included. MR. GRIMES: They didn't come up in the -- this issue did not emerge in the previous reviews. DR. BONACA: Are they in scope for Oconee, for example? MR. GRIMES: I'm prejudiced to staff's findings. We thought the previous applicants had treated the housings for ventilation system components as part of the ductwork. And that's why it's at issue. The applicant contends they didn't. Before we go attack the other applicants, we're going to try to settle the matter on this application first. DR. BONACA: When I review this I thought that this issue, not in specific, but in general, but the components had been included. That was my -- MR. BARTON: That's the way I felt too. DR. BONACA: Now when you -- in the position of the staff, when you talk about, for example, the housing of a certain component, it identifies specifically a function for it and so you're recognizing other pressure attending function or obstruction contained in the function which is in this license renewal. MR. GRIMES: Correct. In order for the staff to prevail in its position, there has to be a passive function that -- passive safety-related function that we're attempting to manage aging for. DR. BONACA: Okay, thank you. MR. BURTON: One thing I should have pointed out before I got into all of this is how we as the staff approach the scoping and screening reviews which we've done from Day 1 is that things that the applicant identifies as being within scope or being subject to an AMR, we don't really question that. What we really focus on in our review are things that are not identified as being within scope or subject to an AMR to see if those were actually identified properly. And in fact, back in Section 2.2 with the plant level scoping results, the primary effort for that portion of the review was to go through that Table 2.2-1 and actually look at the functions that were identified as not being in scope and see whether or not we agreed with that and we understood that. So it's almost -- I don't know what you would call it, a negative consent kind of thing. I don't know what you'd call that. But that's how we worked through these. (Slide change.) MR. BURTON: Section 2.3.4, auxiliary systems. As you can see, we had 20 systems that were divvied up amongst our reviewers. MR. BARTON: Before you go past 2.3.4 are you going to talk about 2.3.4? MR. BURTON: No, it's in two slides. I'm going to talk about it now. MR. BARTON: Okay. (Slide change.) MR. BURTON: We did have some open items here too. The first two are actually analogous to what we had in 2.3.3, the issue of complex assemblies, that diesel was another one where we had the same issue. DR. BONACA: Is that being contested? MR. BURTON: No. This is as I said before, they've agreed to do it like Oconee. DR. BONACA: All right. MR. BURTON: The second one here is the same housing issue, in addition to standby gas treatment in Section 2.3.3 it also applies to the HVAC systems for the Control Building, Outside Structures and Reactor Building. So it comes up. It's all captured in one open item. DR. BONACA: Sure. MR. BURTON: But it's actually identified in several different places. A third open item in this section was scoping and screening of fire protection system in the radwaste building. Initially, this was not captured as being in scope. The staff went through the fire hazards analysis and disagreed with that being appropriate. And I think at this point we have actually gone through and Southern Nuclear actually is going to bring this suppression system within scope. MR. BARTON: That resolves one of my questions. MR. BURTON: Okay. DR. BONACA: I thought in addition to that was a proposal to have a one time inspection that the staff wants to see as a program, is it? MR. BURTON: That is going to come up in the discussion in Section 3 when we do the Aging Management Programs. And understand that as with anything, if the final resolution is that something is going to be brought in scope, we're also going to be bringing in the Aging Management Review and any applicable Aging Management Programs and assessment of the effects, all the things that go along with bringing that in scope. MR. LEITCH: While you're on the auxiliary systems, I guess I was a little confused about the river water intake structure. How is that done at Hatch? Not the circulating water, but the -- I don't know what they would call it, the RHR. MR. BURTON: I know, plant service water. MR. LEITCH: Plant service water. Okay. MR. BURTON: Okay, let me talk a little bit about that. Commodity-wise, what -- the way the application breaks down is they have an environment that they call raw water. Raw water is made up actually of -- consists of two different entities. One is river water from which -- which is the source for the plant service water. Another one is well water which is used primarily for fire protection. But they are both captured under the environment of raw water. So yeah, if you're asking about structural stuff, that comes up in Section 2.4. But in terms of the actual service water and that environment and things like that, we actually have plant service water that actually captures that. MR. LEITCH: I guess my question is really the pathway that leads to the ultimate heat sink. In other words, you've got the RHR heat exchanger that's cooled by plant service water. MR. BURTON: Oh no, I'm sorry. Yeah, and I don't have it listed separately out here, but there's actually a plant service water and an RHR service water. MR. BAKER: Butch, if I could interject. MR. BURTON: Please. MR. BAKER: RHR service water doesn't have a separate designation in Plant Hatch's numbering scheme. It's a part of RHR, so it shows up on the previous vu-graphs about the engineered safeguards features. MR. LEITCH: Okay, and what source does that RHR service water -- where does it take suction from? MR. BAKER: It's at the intake structure. The intake structure is a common structure for both units. It has both plant service water and RHR service water for each unit, specifically the Altamaha River. MR. BURTON: And it actually is called out separately as one of the titles for one of the Aging Management Programs. We actually have PSW and RHR service water both what, chemistry and inspections. MR. BARTON: Leave that on there, Butch. MR. BURTON: Sure. MR. BARTON: Maybe some of my problems here are navigational also. I haven't consulted a GPS on my boat that didn't help me. (Laughter.) Access door systems is talking about containment doors. Within the reactor building there are also, I would imagine, fire barrier doors and I didn't see those covered under access doors although I find fire doors and their management under fire protection or is it not included at all in the application? MR. BURTON: Probably the best thing for me to do is let them explain how they did it and then I can turn it over to our reviewers. MR. BAKER: Fire doors are covered under the fire protection activities. Some of the access doors may also be fire doors, so they may do double duty. MR. BURTON: And the actual commodity group is actually structural steel when you go to the Section 3 tables. MR. BARTON: All right, and also in this section control rod drive system? It's in this section some place. Page 256. Control rod drive system. I couldn't find where the Aging Management Program is for the SCRAM discharge volume. MR. BURTON: Oh, oh, okay, okay. That was actually -- I'm glad you said that because that helped clarify things for me. The SCRAM -- MR. BARTON: I'm glad it helped you. MR. BURTON: We actually, if you go into the SER, our scoping guy actually had a question about the SCRAM discharge volume and how that actually was captured, where is it, because it's not specifically identified. You're right. This is a navigational problem. It's very typical of many of the issues that the staff had. Now again, correct me if I'm wrong, but I recall that the SCRAM discharge volume was actually captured as piping, does that sound right? MR. BARTON: Yeah. MR. BURTON: It was actually captured as piping and we had a phone call about that which is documented in the SER. I can point that out to you. MR. BARTON: See, my problem is I only had certain sections of the SER to review, so it may be some place else. MR. BURTON: That's an issue. But I can show you where that is. But that's very typical of some of the navigational issues that we had. DR. BONACA: In fact, on access doors, by the way, you had request for additional information on seals because you thought that they were not in scope and then the answer was they were in scope, but the reality they were not subject to AMR because they were replaced or repaired based on the performance and conditions under the preventive maintenance procedures. And you accepted that answer that says they are in scope. That applies to any doors and seals, those that function as fire protection barriers? MR. BAKER: That's correct. It is both the access doors, the fire barriers as well. Those are -- all of the heavily traveled doors, especially see continuous use and require maintenance replacement of those seals. MR. BARTON: So they're covered under your preventive maintenance program? MR. BAKER: Yes. MR. BARTON: Cranes, hoists and elevators. MR. BARTON: You're going to be here a while. (Laughter.) MR. BARTON: I can't find where reactor building, polar crane, well, that's not a polar crane. The refueling crane, the 125 ton hook and the auxiliary hook, where in their program are they captured for tests? Don't you check the hooks for -- inspect them and do mag particle and crack checks or whatever? Aren't they covered in your program some place? You talk about the component, the structural steel and the crane, but how about the hooks? MR. BURTON: I have to turn over to him for those specifics. I'm not sure. MR. BAKER: The lifting function part of the crane was an active activity. The scope of our review focused on preventing the crane from falling on the safety-related components. MR. BARTON: You don't care about dropping a load, just that the crane doesn't fall? MR. BAKER: Interestingly, the hatch refueling floor, the main crane, the 125 ton crane is a single failure proof crane with redundant rigging and breaking in the CLB. It's probably unique in the industry. MR. GRIMES: Actually, I'm not sure -- this is Chris Grimes. I'm not sure whether it's unique, but I recall there are certain elements, the design of cranes that include linnets and stops and administrative procedures to reduce the likelihood of dropped loads, but it's an interesting question in terms of the distinction between active and passive features and so we can explore that further for you. But I don't know that it came up during the course of our review. MR. BURTON: I certainly know that NUREG 0612 and 0554 for single failure proof, I know they have a lot of provisions for just that kind of thing and I'm sure as Mr. Baker would verify, I'm sure that in the evaluation of a lot of these, where does active end and passive begin is sometimes a question. That's all I can say about that, but -- MR. BARTON: Drywell pneumatic system? MR. BURTON: Okay. MR. BARTON: I can't where air receiver and drywell pneumatic nuclear boiler system accumulator are subject to AMR. Are they someplace else or not in the program? MR. BURTON: That rings a bell as another navigational item and let me just double check that. (Pause.) The reason why I'm saying that rings a bell is I think that that was a question that our reviewer asked about those kinds of things. I know in several cases, I'm not sure whether drywell is one of them, but the issue of accumulators and tanks and how were they identified, because when you go to the table -- MR. BARTON: Air receiver is another example. I can't find air receiver. MR. BURTON: It's a tank. MR. BARTON: It's under tanks? MR. BURTON: Tanks. And we had a number of things like that. MR. BARTON: All right. MR. BURTON: The questions you're asking are not unusual. I mean it's the exact same kind of questions the staff had. Navigational questions. Go ahead. MR. BARTON: The question on insulation. It didn't -- I couldn't see where insulation within the drywell was subject to AMR. Is there a specific reason for that or did I miss it? You talk about insulation and what was in scope. I didn't see anything within the drywell covered in that section. MR. BURTON: All right, I promised I wouldn't do this, the person who actually -- go ahead, if you want to -- MR. GRIMES: Ray's volunteering to answer, so let's let him answer. MR. BURTON: Okay, go ahead, please. MR. BAKER: The insulation inside the drywell was initially scoped in during our review, but during the process before we submitted the application, Plant Hatch completed it's evaluation of ECCS suction strainer issues, clogging issues and we've determined based on the results of that that there was no intended function for the insulation inside the drywell and so we removed it from scope. MR. BURTON: Okay. MR. BARTON: The other system primary containment chill water, but the piping inside the drywell is covered in the program, but piping outside is not? Is there a reason for that? MR. BAKER: The purpose of the piping to the extent that it's in scope is to form a part of the containment pressure boundaries, to closed-loop inside containment in that respect. So the piping outside the isolation valves outside containment serves no function. MR. BARTON: This one is a little bit different than navigation. The traveling water screen and trash racks system, the SER describes screen and racks must remain structurally intact during an accident, but not required to move. My question is based on this statement, the applicant did not include screen wash lines and motors and scope. What happens to the service water flow as screens get plugged with debris during an accident? MR. BAKER: There are two aspects. You have the trash racks and you have the traveling water screens. MR. BARTON: Right. MR. BAKER: As I understand our CLB, the structure, the intact structure part of that was to protect against something like a barge impact or other impacts from things on the river. There is no indication of a problem with clogging due to the design of the structure and the bays, the way that that is arranged. It just is not an issue. MR. BARTON: Then why do you have a screen wash system? MR. BAKER: That's an operational, as I understand it. MR. BARTON: It's not to take care of grass or stuff that flows down a river after a storm which gets through the racks. The smaller it gets through the racks and it can't plug your screens and it can't impact your service water flow? That's an impossible scenario at Hatch? MR. BAKER: I would not say anything is impossible. I don't know the detailed -- MR. BARTON: I guess my question, why aren't the screens in the program? It seems if you've got them and they're there to remove debris so you don't impact service water flow, I don't understand how you exclude that from the program. That's my comment. MR. PIERCE: Well, one other aspect of that and I'm not that familiar with the technical discussion that you're bringing up, but I do know that the CLB specifically states that the only credit being taken for the traveling screens is the structural aspects of it staying in place. If you go back into our FSAR and look at that, that's specifically stated and I'd have to go back to my people and discuss the technical reasons of why that is. MR. BARTON: You may want to talk to people at Salem also. MR. PIERCE: We owe you one on that one. More? MR. BARTON: Yes. The condensate transfer system, pumps and piping are discussed as not being essential water sources for accident mitigation, but my question is aren't they a backup source and if they're a backup source why aren't they included in the program? MR. BURTON: Could you repeat? MR. BARTON: Condensate transfer system, pumps and piping, it's in the SER, says may not being essential water sources for accident mitigation, but my question is aren't they a backup source and if they're a backup source why aren't they included in the program? MR. BAKER: I don't believe they're a backup source. MR. BARTON: They're not a backup? MR. BURTON: The condensate transfer provides the transfer of demineralized water from the chemical plant to the condensate storage tank. MR. GRIMES: This is Chris Grimes and Mr. Barton makes a good point in terms of the scoping technique that's used for license renewal includes those things that are credited in the accident analysis as part of the current licensing basis. Particularly in a BWR where there are so many overlapping ECCS capabilities, we only capture for the purpose of the Aging Management Review, those things that are explicitly credited as performing intended safety functions. There are going to be a series of backup capabilities. They might not be captured in the review because they are not explicitly treated or relied on in preventing or mitigating accidents in the current licensing basis. MR. BARTON: That's all I've got. MR. BURTON: So I guess to piggyback on what Chris said, the thing that has really come through with all of the applications is how -- what's really come through is how important it is to really know your CLB. The better you know it, the better it is for all concerned. And we found that in particular where we've had problems like in fire protection, just the whole history of fire protection is that people have done a lot of different things with it and there have been all kinds of exemptions to things and the issue of the -- that I pointed out before about the fire suppression system and whether or not it was in scope. Being able to track through exemptions and changes to the FHA and things like that speaks to the importance of really knowing and understanding your CLB. And it has come up from time to time. DR. BONACA: Let me just propose that these are good questions. MR. BARTON: I'm done. MR. BURTON: These are very good questions. DR. BONACA: Because it provides some comfort to the committee that we can trace back some of these issues although the navigation issues may be there. Could we get maybe an answer next week? MR. GRIMES: Yes. I've noted the -- Mr. Barton's questions. And we are going to go back and explore each of those in terms of traceability for Hatch specifically and then all these questions about to what extent the current licensing bases capture these capabilities. And I've got crane hooks, the air receivers, the intake design and the condensate storage tank water source. Whether or not debris accumulation during an accident is considered as part of the design basis. MR. BURTON: Good, very good questions. Okay. Moving right along to steam and power conversation systems. (Slide change.) MR. BURTON: Again, no open items. When all was said and done we saw that the scoping and screening was proper. We did have a question on main condenser and why it was actually captured in scope, but at Unit 2, main condenser is credited as a hold up volume during accidents, sort of played out things like that. But no open items there. Next we went into structures and structural components. (Slide change.) MR. BURTON: We have 13 items in this category. No open items. Again, we had several requests for additional information. Some of them were navigational in nature, but bottom line is once we understood where the applicant was going, we saw that they had actually scoped and screened appropriately, so we had no open items in this section. The next section was electrical. (Slide change.) MR. BURTON: Fourteen systems were identified in the application. These first couple Dr. Leitch had already made mention of in terms of where you could find them and actually as you were looking in Section 2.3 you couldn't find them they were actually in Section 2.5 under electrical. Again, no open items, given that electrical -- the electrical scoping and screening was actually sort of reversed of how it was done with the mechanical and civil. They identified component types. Identified those that were passive and long-lived, in that population, looked at the ones that actually met the scoping criteria. That's pretty much what I have for Section 2, the scoping and screening. I've got to do list. Any other comments, questions on any of this? DR. BONACA: I don't think so. Any questions? MR. BURTON: Okay, moving into Section 3, I'm actually going to have some of the lead reviewers actually discuss their sections, so I'll have them come up and try and clear some of this out of the way. MR. GRIMES: While Butch is doing a set up, I think this might be an appropriate time to respond to Mr. Barton's question about the Quality Assurance Program and Rob, did you find -- MR. ELLIOTT: I couldn't find it on my -- MR. GRIMES: Okay, couldn't find it on the web, but the latest posted chart outside Sam Collins' office of the Reactor Oversight Program is dated January 25th and it shows to all of the performance indicators for Hatch Units 1 and 2 are green, except for one category and the EP03 category is designated as unique, so it's not color coded for Hatch. So they're green across the board on the performance indicators. For the inspection findings, there are seven categories of inspection findings and some have findings for one unit, but not the other. There are five greens on the chart for the inspection findings and nine no finding areas. So all of the oversight indicators for Plant Hatch are in the green. MR. BARTON: Thank you. (Slide change.) MS. KHANNA: Good morning. My name is Meena Khanna and I'll be talking to you about Section 3.1 which is the Aging Management Programs of the Hatch SER. SNC originally identified 29 Aging Management Programs. After a staff review, the staff identified the need for an additional Aging Management Program which is on non-EQ cables. Later, the applicant did agree to add this Aging Management Program on cables. I'll be discussing the significant open items that the staff has identified for the Aging Management Programs listed on this vu-graph. Then after my discussion, Jay Rajan will discuss open items on the Fire Protection Aging Management Program. Okay, the first one is Reactor Water Chemistry Control Program. The applicant based its Reactor Water Chemistry Control Program on EPRI TR103515 which is the BWR Water Chemistry Guidelines, Rev. 2. The staff is familiar with Revision 1, so what we're asking, we've asked the applicant to address the differences between Rev. 1 and Rev. 2 so that we can understand what the aging effects for the Reactor Water Chemistry Control Program, the differences in the aging management effects that are addressed in the reports. We're just asking for the differences, so that we know, you know, what we need to understand to review the program. Okay, for the Diesel Fuel Oil Testing Program, the applicant indicated that corrosion is an aging effect for these diesel fuel oil tanks. So therefore, the staff has requested that the applicant address corrosion and lack of inspection for the diesel fuel oil tanks. DR. BONACA: And here, if I understand the issue, the concern is -- MS. KHANNA: The one time inspection. DR. BONACA: -- stagnant water? MS. KHANNA: Right. DR. BONACA: In the bottom that may cause -- MS. KHANNA: Corrosion. DR. BONACA: Corrosion. MS. KHANNA: In these tanks, right. And actually, in the report, if you look at the SER, that's where we actually talk about the one time inspection. DR. BONACA: Yes. MS. KHANNA: Okay. DR. BONACA: If I remember, this was already an issue with previous application. MS. KHANNA: Right. We've done that with all the other applications, we've asked for that. DR. BONACA: This is an open item being appealed? MR. BURTON: No, this is not an appeal item. In fact, what has gone on since issuance of the SER is that Southern Nuclear has actually, I don't know if you want me to speak on that or if you wanted to -- they've actually done an inspection of one of their large diesel generator fuel oil storage tanks. Found no significant corrosion in the tank bottoms and so now the argument is how applicable is that result to the other three diesel fuel oil storage tanks as well as the two smaller fuel oil storage tanks for the diesel fire pumps. So we are in dialogue on that. MS. KHANNA: Okay, going on to the Torque Activities Program, the applicant did not identify stress corrosion cracking as an aging effect for high- strength bolting, however, high-strength bolting is susceptible to SCC if it has been heat treated to a high hardness. Therefore, the staff requested that the applicant address the susceptibility of stress corrosion cracking to high strength pressure boundary bolting. All right, for the Reactor Pressure Vessel Monitoring Program -- DR. BONACA: Again, I would like to -- every time you go through one of these I would like you to comment if it is, in fact, one which is being appealed or not. MS. KHANNA: Okay, I can do that. DR. BONACA: To give us an understanding. MR. BURTON: No, this is not an appeal item, and in fact, this was spoken on a little bit yesterday by Jim Davis with the high strength bolting. MR. GRIMES: This is Chris Grimes. This isn't a plant-specific appeal. This is an industry-level appeal. As Jim explained yesterday, the industry has challenged us in terms of the evaluation guidelines, making the high strength bolts or differentiating high strength bolts on a generic basis. But the applicant understands what our expectations are for our ability to get to a plant specific resolution of this. MR. BURTON: Let me just say that none of the items on this page are part of tomorrow's appeal meeting. MS. KHANNA: Okay, thanks. For the Reactor Pressure Vessel Monitoring Program, the applicant indicated that it plans to implement the ISP which is the Integrated Surveillance Program, but is currently under staff review. However, if the ISP is not improved by the staff or if it is modified such that Hatch is not going to be covered by the ISP, the applicant has indicated that it would develop an RPV Surveillance Program for the renewal period. Therefore, this will remain an open item until the ISP is approve.d Finally, the RHR Heat Exchanger Augmented Inspection and Testing Program, the applicant did not identify vibration-induced cracking as an aging effect for the RHR heat exchanges. The staff requested that the applicant provide details regarding how the RHR heat exchanger augmented-inspection testing program manages vibration-induced cracking. Okay, and if you don't have any further questions on these Aging Management Programs, Jai Rajan will continue on with Fire Protection Aging Management Program. MR. BARTON: Are you still on 3.1? MS. KHANNA: Yes. (Slide change.) MR. RAJAN: I am Jai Rajan and I will be discussing the two open items which were identified in the Fire Protection Program. The first item is related to the testing of sprinkler heads in the fire suppression system. And the second one relates to the sprinkler head inspections intervals. MR. BARTON: What was the second one again? MR. RAJAN: Sprinkler head inspection intervals. MR. BARTON: Intervals, okay. MR. RAJAN: The applicant routinely performs sprinkler piping float tests to check for clogging from corrosion products. And this is done as part of its normal fire protection activities. MR. BARTON: They actually run water through sprinkling systems? MR. RAJAN: Through the sprinkler header. The way they run this test is they open the sprinkler head valve and the farthermost sprinkler in the system and look for the flow through the valve to check for clogging. If there is unobstructed flow, the flow normally proceeds and that indicates there is no clogging in the system. The staff was initially concerned that these may not be adequate for demonstrating operability of all the sprinkler heads during the extended period of operation. However, as the staff position has evolved, the staff is no longer requiring additional testing for checking flow blockage and clogging in the piping headers, so this issue most likely is going to be resolved. MR. BURTON: Let me break in just for a second. We spoke in some of the earlier sessions about the impact of GALL, in particular, on the Hatch license renewal application and I think we had explained that due to the timing, they weren't always able to incorporate some of the lessons learned from GALL, but what we're finding is, as we're going through this stage, as GALL, as some of the issues related to GALL are being resolved, we're at a point in our review where we can actually incorporate them and this is one of them, the whole issue of the flow testing of the fire headers. DR. BONACA: And what's the solution that GALL suggests? The question that was raised here was that the testing of the just farthest most head in the system is not a demonstration that the other heads are working. MR. GRIMES: This is Chris Grimes. The way that the issue was described yesterday in relation to GALL, it was described to us -- I've forgotten the word. But it's the flow plugging issue where we made the distinction between the active features of system flow and the crud deposits' impact on corrosion and the attack on the pressure boundary and so we do not look at flow, loss of flow as a passive element, but we do look at the impact of the crud build up as its impact on an aging effect. And that's -- we've applied that conclusion in this case. And I don't know if you want us -- whether or not you want to pursue the question about how these tests -- how the active tests are performed relative to how they test, flow through the sprinkler without sprinkling safety-related stuff which is an issue that has come up before. DR. BONACA: Sure. MR. GRIMES: And Mr. Barton says no, we don't have to explain it again. MR. RAJAN: Okay, now with regard to the second open item, the sprinkler head inspection intervals, the applicant is proposing a one-time inspection at or before 50 years of service life. The staff is concerned that this may not be sufficient for an Aging Management Program throughout the extended period of operation. The staff position which is based on the National Fire Protection Association Codes and Standards requires that where sprinklers have been in place for 50 years, they shall be replaced or representative samples tested for field service operation in a recognized laboratory. And after this initial testing, thereafter every 10 years. So there is a clear distinction between the staff position and what the applicant is proposing and so this remains an open item. DR. BONACA: Is this being contested? MR. BURTON: Yes. I was going to say neither one of these items are on the agenda for the appeal meeting right now. DR. BONACA: So that would substitute a one-time inspection with a program? MR. BURTON: Yes. MR. RAJAN: That concludes my presentation. MR. BARTON: I have a question on 3.1, Butch. Torus Submerged Components Inspection Program talks about lots of components within the torus -- where is the torus itself covered? MR. BURTON: Yes, containment. MR. BARTON: It's under containment? Okay. DR. BONACA: I have a question on the embedded components. This is listed under passive component inspection activity. There is a program, I believe, the Passive Component Program. Okay, so it's an existing program right now. Right? Or is it a new program? New program. And if I understand it. It's similar to what we have seen in other applications which is essentially in case you have maintenance activities or design changes that will expose embedded piping, then you will perform inspections. Okay, so that's the same program that we have seen before? MR. BURTON: Yes. Let me speak to that very briefly, because that was one of the items that we looked at in our second inspection which we just completed a couple of weeks ago. The issue of buried and embedded components, both mechanical and structural, you know, our concern was -- and the purpose of the second inspection was to see how these things were actually implemented with the on-site procedures. And what is actually done is yes, the Aging Management Program that you mentioned also the Protective Coatings Program and the Structural Monitoring Program also have provisions to make sure that when structures or buried components are dug up for some reason that we take that opportunity to inspect them and take a look at them and we actually have looked at their excavation procedure on site and they have actually proposed changes to that procedure to make sure that when they do excavation, there's a heads up in the procedure to actually do that. DR. BONACA: Now this is an activity that takes place irrespective of whether or not you have indications from exposed piping that there may be some problem with that, right? MR. BURTON: That's correct. DR. BONACA: In case you do have indications, then you would have a more aggressive program, go after -- and there is provision under the program or is this separate provision, the one that says that should you have indication in structures that from exposed equipment that embedded equipment may be affected, I thought you had a specific program for that? MR. BAKER: I don't recall the detail of the Passive Component Inspection Program as to whether it has a scope expansion item in it. We'll go look and get an answer for that. DR. BONACA: I appreciate it. Thanks. MR. GRIMES: This is Chris Grimes. To try and avoid some further confusion in the Generic Aging Lessons Learned, we referred to this as inaccessible components and there was a distinction between those things that are covered by the code, the structural elements under IWE were treated separately from inaccessible -- other inaccessible features that are covered by the code, and then of course, anything that's not covered by the code we treat it as inaccessible in a broader way. DR. BONACA: Okay. Thank you. (Slide change.) MR. ELLIOT: I'm Barry Elliot, Materials and Chemical Engineering Branch of NRR. I'm going to discuss the reactor and reactor coolant system. The reactor and reactor coolant system is the reactor pressure vessel, the reactor vessel internals, the reactor recirculation loops, the reactor coolant system piping and valves which includes the main steam line, the safety relief valves, the main steam isolation feed water lines, feed water line check valves and instrumentation and control. There are 15 Aging Management Programs associated with these components. Two of them, the Boiling Water Reactor Vessel and Internals Program and the Reactor Pressure Vessel Monitoring Program reference the BWRVIP Programs. There are 12 BWRVIP Program Reports that establish guidelines for inspection during the license renewal period. The Reactor Vessel Report -- we have not completed review of the Reactor Vessel Report, however, we have reviewed it relative to Hatch and it's referenced in our safety evaluation how it affects Hatch and we're satisfied with what Hatch has provided to resolve the reactor vessels issues. The other BWRVIP Report that is not complete for review is Core Shroud Report and the Core Shroud Report for inspection, the inspections during the current license term are being carried over into the license renewal period and that's found acceptable by the staff for Hatch. And the last one that we haven't completed, but we really have completed, we just haven't put the SER on is the jet pump assembly and that takes care of all the ones that are as far as inspection is concerned. As far as open items, I would like to say that BWRVIP did a wonderful job of looking at all of the current issues that projecting them out into the future. However, we have two issues that we think they need to address. First, is a loss of fracture toughness resulting from neutron irradiation for the CASS jet pump assemblies and the fuel supports. The CASS stainless steel is composed of two phases, a ferritic phase and an austenitic phase and the ferritic is subject to thermal embrittlement and neutron irradiation embrittlement. And I mention neutral irradiation embrittlement here because I think that thermal embrittlement is not going to be a problem here, in particular, because the BWRs operate at much lower temperatures and that should make the thermal embrittlement less of a problem. The flip side of that is the lower the temperature, the more neutron embrittlement you get. So this is why we're concerned about this. And we think that this is an area where inspection -- if we don't see flaws, if we don't see cracks in the CASS stainless steel components, then we wouldn't be concerned about the loss of fracture toughness. And this is a case where an inspection of the limiting component, CASS stainless steel components would be appropriate. DR. BONACA: It's a one-time inspection you're asking for? MR. ELLIOT: Yes. DR. SHACK: Just on that very -- is the CASS part of that, has that ever been observed to have -- there's jet pump fatigue problems, but has it ever affected this CASS component? MR. ELLIOT: At the time we don't have a problem with CASS stainless steel components, but current inspections are of the welds and the adjacent material. So we're going to ask that it be expanded a little bit. DR. BONACA: And you can see that the jet pump assembly components as the limiting component for CASS assembly? MR. ELLIOT: Yes. DR. BONACA: Okay. MR. ELLIOT: The second issue is cracking of the small-bore piping. Our concern here is that we are giving a license for 60 years and in the first 40 years we're not going to do any volumetric inspection of small-bore piping and so we think that it's necessary to do a one-time inspection to convince ourselves that cracking isn't occurring on these type of lines and a sampling of lines would be appropriate of the small bore piping. We prefer -- the susceptibility here is to -- what we're worried about is stress corrosion cracking in and turbulent penetration and stratification, fatigue issues. And if we can get the most susceptible components inspected, we'd be satisfied and again, a one-time inspection. DR. BONACA: And it would be just for a specific limiting components? MR. ELLIOT: Right. If that can be judged. If it can't be judged, then we would just take -- we would look at the consequences and maybe take the components with the most consequence and inspect those. DR. BONACA: Are these open items being appealed? MR. BURTON: No appeal on these. DR. BONACA: I have a question -- MR. PIERCE: Let me -- there are some open items that we're still in the process of working out with the NRC and if we -- and at some later date we may take an open item into an appeals stage later, even though we're not appealing them tomorrow, they could come at a later time. DR. BONACA: I understand of the ones that you already are dealing with, I understand you have these options, sure. MR. GRIMES: Dr. Bonaca, this is Chris Grimes and I want to take this opportunity to point out this is another one of the GALL appeal issues that we discussed yesterday. DR. BONACA: Yes. MR. GRIMES: The industry has challenged the need for one time inspections on small-bore piping. DR. BONACA: Yes. MR. GRIMES: On a generic basis. DR. FORD: I have a comment. I agree with you that on the VIP reports relating to disposition of stress corrosion cracking of austenitic alloys, stainless steels, the nickle base alloys. It seems as though the disposition curves are reasonably conservative. I would have a bit concern, however, about the conservatism for the alloy steel stress corrosion cracking enunciated in I think VIP-60. It relates to -- if, in fact, those are not conservative curves for alloy steels, then we could have a safety issue for cracking at the H9 weld, for instance, or at the core penetrations and then the bottom head. What assurance do we have that as more -- if there is more data coming out, to show that those can't -- 60 disposition curves are not conservative, can we address those? MR. ELLIOT: Gene is coming to the microphone. MR. CARPENTER: Yes, Dr. Ford, just because of you, Dr. Ford, yes. Gene Carpenter of EMCB. As we discussed yesterday in the BWRVIP Program, the program is looking at the Aging Management Program consists of all the INE documents and those are supported by the crack growth and the various mitigation documents, including the BWRVIP 60 documents just referenced. If the staff finds or the industry brings to our attention that there are nonconservatisms that come along due to aging, we will revisit the programs. At this time, to the best of our knowledge, this 60 report appears to be accurate. But if it does not continue to be so, we will come back and relook at it. DR. FORD: And following on from that, what programs shall we have in place for monitoring the cracking of those very thick section components, H9 and the bottom head. How will we know if they're not cracking? MR. CARPENTER: And again, the inspection programs that are called out are the ones that will be doing those monitoring and as was pointed out yesterday, the industry provides to us on a semi- annual basis a listing of all the inspections that are done for every plant, so we would be able to see if there is any trending of cracking occurring. MR. DYLE: If I could, this is Robin Dyle for Southern Nuclear. Peter, the other thing that maybe I didn't make clear yesterday, one of the documents that we credit in our application is VIP-38 which is the document that requires the inspection of the H8 and H9 welds, so there are inspections being done. Because of some overseas incidents of cracking, we're evaluating the impact of that. Whether the document should be revised or not and will incorporate the appropriate results and we have on- going work with the staff. They're aware of the situation, we are and we're working on it, but the inspections are being done at H9. In accordance both with VIP-38 and it's currently required by Section 11 to be inspected also. DR. FORD: If there was cracking it would be a huge safety concern. And that's why I bring it up. MR. DYLE: And there's quite a few evaluations that have been done to assess that. It was done as part of the VIP-05 report which this committee has reviewed several times to look at the possibility of what happens if you have stress corrosion cracking that might propagate from clad into the reactor vessel. But it's been thoroughly investigated. MR. ELLIOT: Your question had to do with the internals or was it to the vessel? DR. FORD: Vessel. MR. ELLIOT: I'm going to answer the vessel question. That's my area. And we don't think that stress corrosion cracking of the alloy steel is an aging effect we have to be concerned about. Let me tell you why. We've had a few cases where we have seen cracks go through the clad and they just don't propagate. They go through the clad and they just -- we inspect them year after year, not year after year, but every 10 years. And they just don't go anywhere. They just stop right there, they blunt. The other case is a summer case, is whether the cracks went right through the Iconel 183, got to the carbon steel and stopped. So that was primarily more due to stress corrosion cracking and so we've seen in our experience that stress corrosion cracking of low-alloy steel is not an issue that we're concerned about. DR. FORD: I would agree entirely with you for 99 percent of the cases and you're absolutely correct. However, there have been at least one case as I know of, if not two where a crack has penetrated considerably into low-alloy steel underneath the cladding. MR. ELLIOT: And I would say this, when I say it's not -- we don't consider it an issue. We looked at it as far as the BWR VIP-05 which was the -- we talked about yesterday which was the circumferential welds and that -- in that analysis was done two ways. We did it one way and the industry did it another. The industry's way was a probability argument, a probability analysis. In their analysis they looked at the probability of a stress corrosion crack based upon their experience penetrating and then they grew the initial crack based on those probabilities and was able to through the Monte Carlo simulation technique, determine the impact of stress corrosion cracking on fracture of the weld and it turned out from their method of evaluation that it was not significant and the failure probability on the circumferential welds were very, very low. DR. FORD: I agree with you in principle, yes, but given the severity of a problem I would question whether the data upon which such statistical analysis such as experimental data is up to the quality for this severe a problem, potential. MR. ELLIOT: And I agree, it's a potential problem. What we're doing is we inspect the axial weld. They're at higher stresses than the circumferential weld, so they are sort of like the limiting material and if we see stress corrosion cracking of the axial weld, then we could go to the circumferential weld. I'm not saying we don't think it's significant. It doesn't mean we're not interested in it. We're interested in it and we have an inspection for it. But we just don't think, based upon our experience that it's a significant issue. DR. FORD: I won't belabor the point any more. DR. BONACA: It's a well-taken point and I think -- I have a question just regarding the void swelling. MR. ELLIOT: The what? DR. BONACA: Void swelling. The fact is of the problem. Now I agree that it shouldn't be a problem because the plants are not running at the temperature that would justify that, just in the SER it's confusing because it says since BWR reactor vessel has relatively low nuclear neutron fluence and the applicant would perform inspections in accordance with the -- I mean is it an issue or is it not? MR. ELLIOT: We don't think it's an issue because it's at lower temperatures. But even if it was an issue, even if it ever became an issue, they're doing inspections already of the critical areas of the core shroud. It would show up as cracking or something. DR. BONACA: Yes. Okay. DR. SHACK: They have much more likely problems to occur if they do have a strike force. DR. BONACA: I understand. I'm only saying that they're not specifically doing this inspection to look at swelling because swelling is a credible issue there. I think that's -- all right. I was trying to understand if it is will an issue and they're looking for it. MR. ELLIOT: No, they're not looking for it. It's lower temperature and it's not an issue. DR. BONACA: You are saying if it was active then something would be a problem. That's a different story. Thank you. MR. BURTON: Okay, next we'll talk about the ESF systems, the auxiliary systems, steam and power conversion systems and Carolyn Lauron will do that. (Slide change.) MS. LAURON: Okay, my name is Carolyn Lauron and today I'll be presenting the next three sections, the summary of the Aging Management Reviews for the Engineered Safety Feature Systems, the Auxiliary Systems and the Steam and Power Conversion Systems. Let me preface my presentation with a statement that the concerns identified by the staff during their review has been addressed in a previous section, the Aging Management Program Section which was discussed earlier by Meena Khanna. The ESF system consists of eight different systems and includes a wide range of materials and environments as noted on the slide. The staff did not identify any open items. The auxiliary system consists of 20 systems and encompasses, once again, a wide range of materials and environments and the staff did not invite any open items. The steam and power conversion system consists of the electro-hydraulic control system and the main condenser system and once again, the staff did not invite any open items. If there are any questions -- if there aren't any -- MR. GRIMES: Wait, wait, wait. (Laughter.) MR. GRIMES: This is Chris Grimes. Carolyn scores extra credit for really moving right along on the schedule. MS. LAURON: Thank you. (Laughter.) MR. GRIMES: I just wanted to make sure that the committee had ample opportunity. There were a number of questions that you brought up in scoping the screening and Mr. Barton's questions about the crane hooks, the intake design, we've noted those and we'll work to get answers on those, but are there any other questions related to the Aging Management Programs associated with -- MR. BARTON: I didn't have any in that area, Chris. MR. GRIMES: Okay. MR. BARTON: I don't know if the rest of the committee did. (Slide change.) MR. ASHAR: I am Hans Ashar, Mechanical and Civil Engineering Branch and I'm going to talk about SER Section 3.6, Structures and Structural Components. Thirteen structures/structural components are included in this area. Originally, I believe we had 46 open items in August of last year. The problem more was navigation and where is what kind of a thing more than anything else. I think we are left with three open items now and out of three, I think two of them we have closed them after you received your SER copies and I am going to talk about those two and the third open item is still open and it is one of the appeal items. Let me first talk about the items which have been closed since you saw the SER. First item is torus corrosion in which we requested applicant to tell us as to where the torus penetrations are being addressed and how the torus penetrations are being managed as far as the aging is concerned. Again, partly integrational and partly informational provided. There is enough Aging Management Programs to cover the torus corrosion as well as the penetrations within the torus corrosion and they provided us with -- it's been a very nice drawing which saved 10,000 words more or less saying that which area is called by what Aging Management Program below water, above water, so it was very descriptive and that item was closed. MR. LEITCH: Is the torus at Hatch, is it coated? Does it have a zinc -- MR. ASHAR: The torus is coated, yes. MR. LEITCH: And the inspection of that coating is -- MR. ASHAR: It's part of the Coating Management Program, yes. MR. LEITCH: Okay. MR. ASHAR: The second open item which we closed was related to the gears, latches and linkages which were mainly related to the access openings. Our concern -- now this was also in parallel with a GALL item and let me go into that. In GALL, we have the same items being recommended as part of the GALL evaluation. However, the basic reason why the industry complained that hey, it is an active item and they're going to be monitoring during the opening and closing of the doors and latches. The concern that we had was because the outages, you know, during operation of the plant, when anything can happen and if they don't properly close and they go to aging, what would happen to them? And I'm right now referring to GALL and then we'll come back to Hatch specifically. In GALL, we resolved this item when the safety reviewed a number of programs, particularly IS, due to IWE, IS program and then Appendix J testing during the time when they opened any equipment access opening and they inspect them and they close it. They go to 5B testing. So -- this particular answer is that there are enough things there, so what we did identify these three items such as IWE, IS, Appendix J and but in the evaluation we said no, so far as the programs is in effect. So on the same basis, we closed the open item in Hatch. Now the third item, this is still an open item -- MR. LEITCH: Excuse me, there's a term used in that discussion Nelson frames. MR. ASHAR: Yes. MR. LEITCH: I'm not -- it's a term I don't understand. What is Nelson frames? MR. ASHAR: Nelson frames are -- you want to expand on that? MR. BAKER: The reactor building penetrations for electrical conductors essentially consist of a large structural frame with then inserts that are used for the cables to penetrate through. That entire assembly is commonly called a Nelson frame. MR. LEITCH: Okay, thank you. MR. ASHAR: The third open item still is open and it is related to the reactor building controlled leakage characteristics. The applicant argues that we got a very in-depth instruments inspection requirements, structural monitoring and looking at all the access doors and we are going to make sure that on a periodic basis that the aging management is being conducted. However, the staff -- the secondary containment building including the SGT, the standby gas treatment system requires certain amount of vacuum in the building in order to make sure that the SGT will work or during an accident. And for that the staff is insisting that there has to be some kind of an Aging Management Program to make sure that the characteristics of the reactor building for secondary containment is maintained, the way it is in the current license. MR. GRIMES: This is an appeal issue. MR. ASHAR: I would like have some thoughts from you too because it's going to be an appealed and I would like some help or words from you guys. MR. BARTON: What, do you want a vote? MR. ASHAR: No vote, but just your opinions. DR. BONACA: Well, clearly, we will be looking at these things, but just because there is an appeal, it seems to me that it's important we reflect on that before we decide on one perspective or the other. I think we need to see how the members feel. MR. GRIMES: This is Chris Grimes. I'm sure that you'll give us a reaction when we tell you how we've disposed of the appeal issue. (Laughter.) DR. BONACA: That's right. MR. LEITCH: I had a couple of questions in that section. Yard structures, on page 3-180. I wonder if that goes as far as the switchyard. I'm thinking particularly about a transformer, tanks, circuit breaker tanks. Did the review go out into the switchyard and were those types of tanks considered as passive structures? MR. ASHAR: I would defer to David Jeng. Maybe he can -- he was the main coordinator in that entire area. MR. JENG: I am David Jeng. To answer your question, I think the yard structures in our section particularly covers the pad that anchors and the structure support elements. As to the components, the transformers, I think they should be covered within the system. So we did not review the component as I say, but we review the supporting anchors in the frames and so on and make sure they are properly married to aging effects. MR. LEITCH: Okay, so the transformer pads, so to speak -- MR. JENG: Anchor bolts. MR. LEITCH: Anchor bolts. MR. JENG: And supporting frames. These are the things we talk about. MR. LEITCH: Well, then is there someone that can address the issue of transformer tanks and circuit breaker tanks? MR. GRIMES: I would suggest the applicant respond. MR. BAKER: The scope of the electrical part of the plant is at the 4160 volt level as it comes into the plant from the supply from off-site. As a result, the electrical switchyard that you're referring to, none of the items in that electrical switchyard are in scope at Plant Hatch. Now the entire diesel generator building and this includes the ability to supply the alternate sources of AC, from there in is all in scope. MR. LEITCH: Now is the switchyard not in scope by definition or it's not in scope because it doesn't meet the criteria? MR. BAKER: We evaluated against the criteria and it did not meet the criteria. MR. LEITCH: Okay. I understand. And I guess I have a similar question on the end of the plant regarding the intake structures. Did any of that thought go out into the river, I'm thinking of silting that may occur over long periods of time or changes in the characteristics of river flow, river soundings and so forth. MR. BAKER: As I recall, we addressed siltation at the intake structure as a part of the application. MR. LEITCH: And there is a program then to sound that area periodically or how did that -- MR. BAKER: We send divers down. MR. LEITCH: Okay. MR. BARTON: Although the switchyard isn't a scope, who owns the switchyard? Does the plant own it or does something else in Southern Company own it? The maintenance programs in the switchyard are performed by who under what process, under what program, under what procedures? MR. PIERCE: I can check on that during lunch, but I am reasonably certain that currently today, the switchyard is being maintained by Georgia Power Company. MR. BARTON: Not the plant. MR. PIERCE: Right. MR. BARTON: And it's under Georgia Power Company's procedures, processes, programs and not the plant's? MR. PIERCE: There are some elements of it that I think the plant gets involved with, but I'll have to check on that. MR. BARTON: I'd like to know what the plant's involvement is. MR. BAKER: Just to follow up on that, this is an area that was discussed somewhat in the environmental review part of the discussions as to who performed the routine procedures for the switchyard and for the transmission lines. So we have that. DR. BONACA: I have a question regarding the unit. Does the plant have a program to monitor building settlement, if any? And at what point do you feel that during the life of this plant settlement may affect somehow structures or impingement on piping and -- MR. BAKER: In the original licensing of the plant, building settlement and differential settlement between structure and soil was considered. There were technical specification requirements to monitor that. That monitoring showed that the consolidation settlement was essentially complete by the time construction was finished. There were some concerns at one time regarding a possibility of differential settlement between structure and soil at the intake structure. There was some remedial actions that were taken there. Subsequent to that there's been no indication of any additional settlement issues. MR. JENG: This is David Jeng. I'd like to supplement this answer. Settlement is a general issue. If the structures are in the scope in the design CP, OL review has been reviewed and accepted to determine to be adequate, there's no concern. In the license renewal, we did not come across any special concern from the standpoint of RAI. DR. BONACA: Okay. I was more curious than anything else. The other thing I would like to do, by the way, we're close to the end of the Section 3 presentation. I would appreciate at some point if the applicant could give us a very brief summary of operating experience. If you look at the application and then the SER, there is substantial information provided in different sections regarding particularly the operating experience for crackings and so on and so forth, but it would be good for us to have a feeling about what are the major issues that the applicant is tracking right now that they consider, they focus on mostly. So just for our benefit. (Slide change.) MR. BURTON: Just briefly, the next section was 3.7, again electrical components. We looked at 14 systems and again, we found that the Aging Management Review and the Aging Management Programs seemed to be appropriate to manage the aging effects associated with this. The only issue which we had already talked about before was the additional Aging Management Program that came into play for the non-EQ cables. That's it. MR. BARTON: Butch, I know yesterday in the discussion in the electrical area, that electrical cabinets were in scope, but switch gear was excluded from aging management. Is there a logic for that? What in switch gear is not -- is excluded from the program? MR. BURTON: Okay, this was part of yesterday's discussion? MR. BARTON: Yes, I believe so. MR. BURTON: I probably need to call in our electrical person. Paul? Paul Shemanski. MR. SHEMANSKI: Paul Shemanski, Electrical Branch. Basically, switch gear are excluded by the rule. MR. BARTON: Okay. MR. SHEMANSKI: And the basis is that they contain for the most part active components which are -- MR. BARTON: How about the cabinets themselves? MR. SHEMANSKI: Well, the cabinets would be in scope because they're the -- they would be in from a structural standpoint. MR. BARTON: That's why I'm confused. You talk about electrical cabinets in scope and switch gear not in scope. When you talk about electrical cabinet, how about a 4160 switch gear room that's contained within a cabinet and you've got breakers and dials and indicators and meters. Is the cabinet itself an electrical cabinet that's in scope or not? MR. SHEMANSKI: My understanding is that the structural -- MR. BARTON: The cabinet that's bolted to the concrete. MR. SHEMANSKI: That would be in scope and that would evaluated for aging effects such as corrosion, whatever else, but the internal components -- MR. BARTON: I understand internal components. They all move in something. I thought the definition that was given, the description that was given talked about breakers and switches, etcetera, as not being in scope and I can understand they're active components, but then it said switch gear. I'll have to find it. It was in yesterday's -- it said switch gears excluded. I was trying to determine what they meant by switch gear. Was that the cabinet itself and there's also electrical cabinets are in scope. What's electrical cabinets? Is that all motor control centers and switch gear, the outer envelope, the housing so to speak or is it more than that? MR. SHEMANSKI: Basically the housing, the structural cabinet would be in scope, the metal, okay, the enclosure itself would be in scope, again, the internals are out of scope because -- MR. BARTON: I can understand the internal. I understand that. MR. SHEMANSKI: But electrical cabinet, panel, enclosure, that would be in scope and would be evaluated for aging effects of corrosion, rust, that type of thing. MR. BARTON: Okay, thank you. MR. BURTON: Okay, that's pretty much it for section -- I'm sorry. That's pretty much it for Section 3. Comments, questions? DR. FORD: I have a much more general question. A lot of your argument for the aging managing, especially for environmental degradation problems, based on the VIP documents which are primarily deterministic based on data and you come up with a deterministic upper bound, admittedly disposition curves. I haven't seen anywhere and I'm talking from lack of knowledge because this is the first time I've been on this committee, I've seen very, very little reference to use of extreme value statistics, bearing in mind that we're really concerned about the first event. That's what's going to kill us. So has this a place in all of these evaluations? When will a first event occur which is going to kill us all? MR. GRIMES: Somehow I have a feeling that question is in my job description. And I would emphasize that if you look very carefully at the statements of consideration of the license renewal rule, I think the industry originally argued that -- we don't need to do anything for license renewal by virtue of we've got regulatory processes and look at operating experience and when stuff breaks, we fix it and we've been doing that fine for 25 years and let us have another 20 years. The Commission concluded that while we've got maintenance rule and we do have confidence in active components because they break a lot and we've got a large data base from which we can draw reliability information. And it's that data base that led us into the maintenance rule and its requirements in order to monitor very carefully the information that's used to derive reliability and failure rates and core damage frequencies and other information that's used to try and be informed about risk. But for passive things like the fracture toughness of the vessel or sprawling -- did I say that correctly? Spalling. Sprawling was probably Freudian in terms of my vision of structural inspections. (Laughter.) But the Commission concluded that because these are rare events, we do not have large -- we don't have a large data base to draw on for the failure rates of tanks and pump casings and structural elements and they do not get challenged in the way that they will be challenged if an accident occurs. And for that reason we will look to ensure that there are Aging Management Programs that are going to monitor the condition that are going to identify when applicable aging effects appear to the extent that they jeopardize the intended safety functions. So the entire focus of this review is almost the inverse of your question and that is because there is a lack of data and reliability values associated with these functions, we concentrate on the inspection and maintenance practices that are relied on in the current term and to what extent do they need to be modified, adjusted or augmented for an extended period of operation so that as new failures occur in the future that there's a process in place that's going to account for new information and adjust according to aging effects in such a way as to continue to maintain the condition of the system structures and components so that we have reasonable assurance that they'll perform their intended functions for the period of extended operation. Did that answer your question? DR. FORD: Yes. You've been proactive, to a certain extent proactive. MR. GRIMES: Right. DR. FORD: You're going to hope to see it before it becomes -- MR. GRIMES: We're going to hope to see it and if we haven't seen it we've got a process in place that by through the corrective action process it will reveal an aging effect that was not considered in this revised licensing basis and then we would expect a corrective action process to say we don't have a procedure to manage this aging effect. Now we need one. And I think that the issue is more clearly illustrated in some of the industry comments on Generic Aging Lessons Learned where you see these one time inspections. They're aging effects that the industry believes don't warrant an aging management program, but at the same time they're not so out of the question that we could simply dismiss them as not applicable and in those cases, we've insisted on a one-time inspection in order to provide a benchmark in time that says is there any evidence that it's occurring. if there is any evidence, then the process will account for that. DR. BONACA: Okay. Before we take a recess for lunch, it will be interesting to us to hear just a brief summary of the operating experience and all you had, for example, cracked sparger. It wasn't clear to me that you had both at Unit 1 and Unit 2. You also had indication of -- so just a summary of operating history and what is -- which is focusing mostly on inspections right now? MR. PIERCE: Yes, I think Robin could probably answer some of the discussions on some of the internals in operating experience. At a broader level, we do have an individual that is calling down at the plant to make sure that we give you the right information. So it might be better to do that right after lunch and just go through the whole thing, including what Robin has, if that's okay with you. DR. BONACA: Okay, sure. No problem. And again, remember I'm asking you for just a summary in the application, interspersed in so many locations operating experiences. At times you lose a little bit sight of what are the major issues that right now we are facing or you are concerned with. Some of them seem to be disposition, once and for all, so that kind of information. MR. PIERCE: Right, and that's why we wanted to go down to the plant and make sure that we had a good understanding of they viewed the major issues were for operating experience. DR. BONACA: Okay, with that I think we'll take a recess for lunch and I would like to start the meeting at 1 o'clock. We don't need an hour. I have to catch a plane pretty early, so why don't we just start the meting again at 10 of 1. Okay? (Whereupon, at 11:57 a.m., the meeting was recessed, to reconvene at 12:50 p.m., Wednesday, March 28, 2001.) . A-F-T-E-R-N-O-O-N S-E-S-S-I-O-N (12:50 p.m.) DR. BONACA: Okay, we're going to resume the meeting now and first of all, we will ask the licensee if they have received the information to give us a brief update. We don't need a lengthy one, just a summary. MR. PIERCE: Okay, I think during lunch we worked on basically two questions. One was on Mr. Barton's issue on the switch yards and secondly the operating experiences. Regarding the operating experience, I'm going to let Robin start and then turn it over here to Wayne Lunceford to continue with some of the switch yard discussion, I'm sorry, the operating experiences discussion. On the switch yards, I'm going to let Jim Mulvehill speak briefly to that. MR. DYLE: This is Robin Dyle. You did mention the sparger and I guess the first thing that popped into mind which sparger. So instead of going that path, I'll just discuss both of them. The core spray spargers, there has been an occurrence in Unit 1 years ago where there was IGSCC detected, a mechanical clamp has been put in place and that is inspected as part of initially the IEB 8013 inspections that were required and then when we implemented VIP-18, VIP-18 replaced those inspections. So we continue to do that. Also, and I do not remember exactly when, three to five years ago, there was actually a full- flow functional test performed on core spray where they injected through the sparger and looked at that clamp before and after and looked at the general conditions. So that's been evaluated. In regard to -- Unit 1. Excuse me. In regard to feedwater spargers and the feedwater nozzle issue, we've been performing inspections in accordance with NUREG-0619 for years. It had to do with the thermal fatigue initiation of a flaw in the inner radius and the propagation of that. Unit 1 was originally a slip fit sparger. That was replaced with the triple sleeve double piston sparger. Unit 2, as the problem had been detected was still in construction and it was replaced in the field with a welded in-place sparger with a single thermal sleeve. So those are the issue on the two spargers. Since we've done the replacements and implemented the NUREG-0619 program, we've had no problems, nor has any other BWR in the industry, so we believe that's been handled generically and that's addressed in some of the VIP documentation. MR. BARTON: You said no other plant has had a problem since when? MR. DYLE: Since -- there was a series of changes that were made as part of the NUREG-0619 process. Not only were spargers changed out, but in some cases, spargers weren't changed, but operating procedures were changed to minimize the effect of the on-off flow of the cold feedwater, so you eliminated the thermal cycling and the initiation mechanism at the inner radius. So there was a generic report that was published. The staff has reviewed that and that's the new position that all the BWRs use for inspection that has shown that there has been no cracking throughout the feedwater nozzles in 15 plus years. In regard to other internals, we've inspected the jet pumps. We've replaced the jet pump beams and put in the newer heat treat versions so we've got the newer generation jet pumps. We do the inspections per the VIP. We have done inspections at the top guide. We've seen no evidence of cracking. As I mentioned yesterday, the only plant that has has been Oyster Creek. We did do a preemptive repair to the shroud as I've briefly mentioned. And that was an economic decision where we knew the repair replaced all the cirumferential welds so instead of spending the money to do that, we preferentially, from a financial standpoint just installed the repair and now inspect that on a routine basis consistent with the SE that the staff provided. We replaced access hole covers. There was indications detected several years. We were not sure they were IGSCC and the reason is you couldn't actually track the indication to the water surface, but plant management conservatively decided to remove those and they've been replaced with mechanical devices and we inspect those at a regular period also. And I believe that's everything as far as the internals and the vessel goes. The mention was made of the open item, the Integrated Surveillance Program. We're lucky there because if the VIP Integrated Surveillance Program is not implemented, Hatch 1 and 2 or 2 of the 7 plants that were in the program, so we have capsules available that we can withdraw. So we have a backup available for that. MR. LUNCEFORD: Wayne Lunceford, Southern Nuclear. All I'm going to do is describe to you some of the general issues that the Plant Hatch is dealing with right now regarding components that are in the scope of license renewal. The first one would be CRD cap screws or control rod drive housings. Those are -- Hatch has detected corrosion and stress corrosion cracking on some of those cap screws. GE issued a SIL subsequent to that. I don't recall the date or the number suggesting an improved design, upgraded material, a different washer design that doesn't college fluid leakage so it tends to mitigate that type of corrosion. Plant Hatch currently is replacing any CRD cap screws with any sort of noted damage as they pull out CRD drive housing at the replacement process, it's in progress right now. Second item, and probably the most significant that the plant's dealing with is corrosion and reduction of flow in plant service water piping. Currently, this phenomena is restricted to small bore piping. The failures we've seen are in 4-inch and under lines. We have replaced some lines with 304 or 304L stainless steel an upgrade from the carbon steel that was originally installed. There have also been failures in plant service water minimum flow lines, discharge lines due to corrosion and we've replaced some of those lines with 304. The failures in plant service water had been in both safety-related areas of the plant and nonsafety-related. I believe that's all I'll say about that. MR. BARTON: They were flow erosion problems? MR. LUNCEFORD: We have had both erosion problems on the minimum flow lines off the plant service water pump and discharge lines and we have had corrosion problems in areas of low flow where under deposit corrosion occurred and we have also had flow blockage in drain lines. DR. SHACK: This is erosion is essentially a room temperature line? MR. LUNCEFORD: Right. There is no -- it is not FAC-related. It is simply an elbow, high energy line flow rate going through a relatively small line and it just tends to wear away the carbon steel. We replaced those with stainless steel to mitigate that problem. It's happened in more than one of the minimum flow lines. DR. SHACK: How fast is this going? MR. LUNCEFORD: I don't know right off hand. All I know is they had problems and replaced them. MR. BARTON: What was your question, Bill? DR. SHACK: Just how fast was the flow rate? I was zipping through? MR. LUNCEFORD: It was obviously significant enough to erode the carbon steel. The next item for license renewal, a FAC item would be a failure we've had in a HPCI, an RCIC drain line downstream of the drain pipe. Steam supply to the turbine, you've got a drain pipe. You've got that line that's just going to the condenser. It's -- they have noted some FAC in that area and the response was to include portions of RCIC and HPCI in the FAC program. It was originally excluded from the FAC program based on low usage. Less than 2 percent usage under normal operating circumstances. But we've included that in. They don't model it, but they will periodically go out and look at those areas that will be most susceptible to FAC. Torus corrosion. The inner shell of the torus, there have been instances of minor corrosion pitting on that surface where the originally installed inorganic zinc primer and coating has broken down. We have an aggressive coatings program that currently not only trends and tracks certain areas we've mapped out on the torus shell to see the rates of pit depth growth, the rates of corrosion, but we've also got an aggressive program to desludge the torus, to recoat. They're using an underwater epoxy coating right now for repairs and are considering in the future what they may have to do to ensure the long-term viability of that coating. MR. BARTON: Do you inspect that coating every outage to your knowledge? MR. LUNCEFORD: They inspect, I forget which unit is which but currently, one unit is inspected every outage with divers. The other unit, due to reduced corrosion rates, that we observed, is inspected only every other outage. MR. BARTON: Why is the corrosion rate different there? Is it different coating? MR. LUNCEFORD: I believe that the Unit 2 is holding it better and it may be due to improved water chemistry controls implemented. I don't know that they've established exactly why that coating is performing somewhat better. Also noted, this was an issue that came up in a recent inspection for Aging Management Programs at Plant Hatch was general corrosion in exposed areas of the plant such as the intake structure, valve pits for service water, the EDG building roof area where the inspectors noted excessive rust on components, supports, etcetera and the plant has made that an issue to improve their identification and corrective actions in those areas. One other item I'll mention is particulates in our diesel fuel tanks. There have been instances of high particulates above the 10 milligram per liter limit required by tech specs and those were all properly corrected by filtration or draining, cleaning the tanks and the plant is pursuing what methods they need to ensure that reduced occurrences of high particulate in those tanks. I believe that is all the current items identified. MR. BARTON: Back to service water or erosion problem you had. MR. LUNCEFORD: Yes sir. MR. BARTON: Did your erosion/corrosion program pick it up or was it a failure that led you to discover it? MR. LUNCEFORD: Service water, the service water line, if you're talking of the FAC program. MR. BARTON: Whatever you use for erosion/corrosion program. Is that pick it up or did you have a piping failure, an actual leak and then you found out you had a problem? MR. LUNCEFORD: It is not an erosion/corrosion problem per se. It's simply an erosion problem. If you look at it from FAC -- MR. BARTON: But don't you have a program in place that looks for that kind of stuff and picks out susceptible areas or potential areas that you could have this problem? Don't you have a program like that? MR. LUNCEFORD: Correct, that's our plant service water piping inspection program. I do not believe they identified all of those failures prior to leakage. MR. BARTON: Prior to, okay. MR. LUNCEFORD: Once they -- MR. BARTON: What makes you have confidence that the program is effective? What confidence do you have in your erosion program that it's effective? If you're finding failures -- MR. LUNCEFORD: The service water inspection program, one line was identified, they implement inspections of the other lines, trended those corrosion rates and the engineer at the site who is responsible for that, actively goes out and tries to identify. If they do identify a failure, he will review other areas of the plant where similar materials, environments could exist and we include those in routine inspections. DR. SHACK: But that's not included in what you call your FAC program? MR. LUNCEFORD: That is correct. It's covered by the plant service water inspection program. DR. SHACK: In other words, they really didn't expect it. MR. BARTON: I gotcha. MR. LUNCEFORD: It's not FAC is the point. DR. SHACK: A rose by any other name -- (Laughter.) MR. BAKER: I think the point we're making, the distinction is, there's an industry program that might get confused with that in terms of the scope. MR. LUNCEFORD: That's all I have unless there's any other questions. DR. UHRIG: Question. MR. LUNCEFORD: Yes sir. DR. UHRIG: Are the two plants identical, even though they're several years difference? MR. LUNCEFORD: No. DR. UHRIG: What are the substantial differences? MR. LUNCEFORD: I'll let Ray address that. MR. BAKER: Unit 2 has a hydrogen recombiner associated with containment. Unit 1 does not rely on hydrogen recombiner. That's one difference. DR. UHRIG: Well, of course, those kinds of things, but in general, the types of systems are very similar. The same power level. MR. BAKER: Yes. DR. UHRIG: Are you involved in this large PWR upgrade program? MR. BAKER: We have done the extended power upgrade on both units. DR. UHRIG: You've already done that? MR. BAKER: Yes. Thank you. MR. MULVEHILL: Jeff Mulvehill, Southern Nuclear. Changing the subject to switchyard and maintenance. The plant is involved with monitoring and minor maintenance of switchyard components inside the protected area fence. Any large item of maintenance such as replacement of a transformer would be a joint effort between Georgia Power Company and the plant people. Inside the protected area fence, changes to the switchyard are controlled by the design change process there so and once you get beyond that fence into the transmission line area coming in and so forth, that's pretty much all Georgia Power. MR. BARTON: What control do you have over the work they do in the switchyard? MR. MULVEHILL: If they're working under a PCR, a design change request, they would have to follow the procedures that the -- MR. BARTON: Station procedures? MR. MULVEHILL: Right. DR. BONACA: Thank you. All right, then let's move on now to the Time-Limited Aging Analysis. MR. BURTON: This is Butch Burton again. I'm going to turn it over to John Fair from the staff to discuss the TLAAs. (Slide change.) MR. FAIR: Good afternoon. I'm going to go over the areas that were identified as Time-Limited Aging Analyses at Plant Hatch and I'm going to discuss the open items that we have in the draft SER. The first section is in the identification of TLAAs and we have two open items. The first open item involves the fatigue analysis of components. In the application, the applicant identified TLAAs for the reactor vessel and for the reactor coolant lube piping, but did not identify other major reactor coolant system components as TLAAs and did not identify the reactor vessel internals as a TLAA. The staff reviewed the Hatch FSAR, identified that the reactor vessel internals had been discussed and a fatigue evaluation of the internals was identified in the FSAR so that we ask a question as to why this was not identified as Time-Limited Aging Analysis. The response to our question was that the criteria of the vessel internals program, VIP-74 were used to identify items that are TLAAs. We really didn't understand what that meant in terms of response, so we held this as an open item and maybe some misunderstanding in the terminology, but since there isn't an identified fatigue evaluation of at least the internals, we want to know how that was dispositioned. And the second item there was really just a catch all, in case there's some other component that there was a fatigue evaluation. We don't know from review of the FSAR whether there are. But we'd like the applicant to identify if there's any other components they did fatigue evaluations on and how they dispositioned those. The second open item in the identification TLAAs is one of the items of contention and that's the high-energy line break postulation based on fatigue cumulative usage factor. Again, the staff believes this meets the definition of a TLAA per the 54.3 criterion and the licensee's response was that they just used this criterion to select break locations and they really didn't consider it a Time-Limited Aging Analysis. This particular item was identified as a potential Time-Limited Aging Analysis, this high energy line break postulation based on cumulative usage factor. In the statement of considerations of the rule, it's in the draft SRP as an item where there's a potential TLAA and I believe there was even an industry comment in the fatigue section of the SRP that this item should be identified as a potential TLAA. So we're still holding this open as TLAA and want to have a discussion on how we're going to resolve the issue with the licensee. DR. BONACA: Are these under appeal? MR. FAIR: This is an item that's under appeal. DR. BONACA: Not the second one? (Slide change.) MR. FAIR: Yes, the second one. The second item is under the fatigue analysis issue and really the heading in the license renewal application is pipe stresses, the way the applicant has labeled this. And the open item really is the resolution of environmental fatigue issue or the GSI-190 issue. In response to the staff concern on this item, the licensee has referred to generic EPRI studies that were performed previously to try to address this generically for BWRs. The open item that we have is really the applicability of these particular generic studies to specific locations at Hatch and we have on-going discussions, I believe, we anticipate with them to try to resolve this issue. MR. DYLE: If I could, John, just one thing to add to that. This is Robin Dyle. Not only are we working that between Hatch and the staff, this is also a generic issue that we're trying to work this particular resolution of environmental assisted fatigue with the MRP, so we're trying to develop not only the Hatch specific, but also a generic position, that others could use and this is on-going dialogue. (Slide change.) MR. FAIR: The next ones are just -- I'll go over the items that were in the license renewal application, briefly, but there were no open items identified. The first one was a corrosion allowance. There were some specific piping systems that they had evaluated for corrosion and they went back and dispositioned those. Environmental qualification, again, they dispositioned those. We had no open items. And they did have a calculation on containment pressurization cycles, a fatigue evaluation which they went back and dispositioned. (Slide change.) MR. FAIR: The next area was the reactor vessel and really there were a number of subitems under this, but the issue is the effect of neutron and irradiation embrittlement and one of the various items listed under this. And there were no open items again identified under this. (Slide change.) MR. FAIR: The last item was an interesting item. This is main steam isolation valve operating cycles. This was originally identified as a TLAA by the applicant because they had specified in the FSAR a number of cycles. They went back and reconsidered. They had put this number in a design specification, but did not have the actual basis of why it needed to meet this number of cycles, so they decided this really doesn't constitute a TLAA and that they do have on-going programs to refurbish these valves and restore them. So we accepted that resolution and there's no open item on this. MR. BARTON: Is this handled through the LLRT program and overhaul is needed? MR. PIERCE: That's one of the programs, that's correct. MR. BARTON: What's the other one? MR. PIERCE: There is a number of individual activities that are done on the MSIVs that I'd have to go back and refresh my memory on, but everything to tech spec., routine tech spec. surveillance, in terms of operating, testing, testing the valves for closure time and so forth are part of it as well. MR. BARTON: Okay. I understand. MR. FAIR: And that was the extent of the time-limited aging analyses done by the applicant. DR. BONACA: Are there specific questions from the members? What I'd like to do is to ask Mr. Grimes to give us a summary of the five issues that will be appealed tomorrow? MR. GRIMES: I think it's four. DR. BONACA: I thought it was five. MR. GRIMES: I'll go back and enumerate the issues that are on the agenda for the meeting that we're going to hold tomorrow. DR. BONACA: Okay. MR. GRIMES: But rather than summarize them which I think is the purpose of the meeting that we're going to have tomorrow, I would suggest that we'll be able to better articulate what the nature of the dispute is after we've had an opportunity to sit down with the applicant and compare notes. And just going through the agenda for -- the reactor building leakage, the use of the drawdown tests. DR. SHACK: Chris, on that one, they have a tech spec., right, so they have to test for that? MR. GRIMES: Yes. DR. SHACK: And you want an Aging Management Program as well as the inspection program and the test? MR. GRIMES: No. The issue, as best as I can characterize it, without prejudice to my position as judge and jury tomorrow, the applicant conducts inspections of the secondary containment and they go around and they check the condition of the penetrations. They have access controls to make sure that doors are closed when they're supposed to be closed. They check all of the individual parts of the building in order to make sure that the building is standing up properly. But they also perform a tech spec required draw-down test to demonstrate the leakage integrity of the secondary containment as a secondary containment. The staff wants the leakage test to be included as an element of the aging management program and the applicant argues that's an unnecessary regulatory burden because the inspection of the individual component should be sufficient for the purpose of the aging management purposes. I think I've fairly characterized the nature of the issue. Details to be explored tomorrow. The second issue is seismic II/I and that gets to the design basis for nonsafety stuff that could fall and prevent safety-related functions. The applicant has designed seismic supports for the nonseismic piping and the staff has said that the piping could fail so the piping needs to be included in the scope as well as the supports. And so we'll need to explore the extent of that scoping issue. Pipe break criteria is a time-limited aging analysis. There are -- the piping has a fatigue design and there's a fatigue analysis that's identified as the Time-Limited Aging Analysis, but there are also analyses that are performed to look at crack growths rates as it relates to where you postulate pipe breaks and so the pipe break criteria as a separate Time-Limited Aging Analysis is going to be discussed. And then, of course, the general question about housings as separate passive functions of active components. And that generally applies to all HVAC systems. So those are the four issues that are in dispute that are going to be discussed in an appeal, but as John Fair pointed out, the rest of the open items we think that there's a course of resolution and we understand what information needs to be exchanged, but that still needs to be verified. Our ability to be able to close all the open items and prepare a final safety evaluation in accordance with the schedule that Butch showed you earlier will still be monitored very carefully. MR. BARTON: The housing issues on HVAC systems plus standby gas treatment, right? MR. GRIMES: Yes sir. DR. BONACA: Thank you. MR. GRIMES: I would point out and I'm not sure that we can promise that the results of tomorrow's meeting will be a sufficient basis for us to be able to tell you what the answer is by the time that we get to the full committee. And so we'll need some guidance from the subcommittee in terms of what material you want presented for the full committee meeting on April 5th. DR. BONACA: Well, what I would like to ask you to do is to by some means to gather -- depending on how the meeting goes tomorrow, and what the closure on the items are, probably no closure, but progress and clarification and making available to the members say by Friday, if you could. And then I would like to have the members review these issues, what happens tomorrow and give me by e-mail to pass out to me during the weekend your thoughts. I would appreciate that because I think I'll try to put together these comments and then bring them back next week for our use so we can discuss them, look at our perspectives and then be ready then for the presentations we receive from the staff and the licensee next week. Okay, we may decide not to express an opinion or we may have an opinion at that point that we can express, but certainly that becomes an issue of agenda next week and you bring a position on the staff. We will consider commenting on those. So that would be helpful for me as a member to send me their perspectives on these issues, once we get the information from the staff. With that, I believe we have completed the presentations. I'm just asking now if there are any other comments or questions. I see none. So what I would like to do now is to go around the table and see if any one of the members has any comment at this stage regarding what we have seen. We have reviewed the application. We heard the support provided by the BWRVIP program to this application and so I would like to gather your thoughts, if you have any this stage. Bill, we'll go in this direction. DR. SHACK: No. You know I don't see any major stumbling blocks here. There are a number of open issues to be resolved. I would say that I found their approach to putting together the report to be more confusing, for example, than the last example we saw at ANO 1. The information may be there, but it just was more difficult to access. I really did sort of miss the Appendix B compilation which I thought was a very nice feature of the ANO 1 license renewal. If I see license renewals again I sort of hope they look like that. DR. BONACA: Okay. Graham? MR. LEITCH: No, I don't really have anything to add except to echo Bill's comment that I did find I guess the word we're using is the navigation a little difficult, but I think now that I understand a little more clearly the layout of the report, I think it's quite understandable. It was just somewhat confusing to me without some of the sort of tutorial we've had today. DR. BONACA: John. MR. BARTON: Well, I don't see any show stoppers, but I've got some concerns. I think I'm not going to be at the full committee meeting, but I think the committee ought to hear the results of the staff's looking into some of the questions that we raised and the committee ought to be satisfied that those components are, in fact, covered by the Aging Management Program or not and also I think we ought to weigh in on where we stand on the issues that are up for appeal, whether we've got a strong position one way or another on that. But as far as overall the application, I think, the committee gets satisfied with those and the answers that the staff will provide the full committee meeting. I don't see a problem overall. I think it was a harder process to review. Took a lot more time to review it because you try to figure out where were things that you had seen before or located in this application and from a technical standpoint, it's not detrimental. It's just from an administrative standpoint it was harder. DR. SHACK: We'll charge them for it. (Laughter.) MR. GRIMES: I wish you'd be careful with that. There is a fees issues on this plant as well. (Laughter.) MR. BARTON: Oh yeah? DR. FORD: My main concern as I said earlier on was the whole question of the conservatism or otherwise, the disposition curve, and the process was compliant enough to take into account new data, if and when it becomes available. I'm satisfied that that compliance is there. DR. BONACA: Tom? DR. KRESS: I agree with the comments on navigating through the documents and I agree with John Barton that we need to express our opinion, whatever it turns out to be on these appeal issues. I'm particularly interested in two of those, the reactor building leakage issue and the question of what constitutes passive versus active in terms of housings. I think there may be a need for some clarification of that and this may be a chance for the staff to clarify what the passive component really is. I didn't see any major show stoppers and I also found that BWRVIP documents provide a pretty good basis for referencing and I thought those were pretty good documents, at least the ones we've reviewed. So that's about all I had. DR. BONACA: I could pretty much echo the same comments. On the issue of navigation, navigating, that's why yesterday also, when we were talking about a generic approach, I felt that the earlier applications where you had scoping system and then the screening doggedly going to the outcome. It was really helpful in the review process and helping people to understand on their own without searching. So what I would consider the scrutability of the documentation that allows for the public as I said yesterday, we are the public in many ways, to feel the confidence that we know this stuff has reached a position if the audits hadn't taken place and you found that in fact the methodology was implemented as stated. So I do believe that not specifically on the Hatch application, but maybe on the others, we may express some preference in that sense or direction in that the next applications have the opportunity to be clear or less clear. I also have some -- I feel we need to express an opinion on these open issues because those are issues we have reviewed for other plants. I mean clearly, we looked at II/I. I thought we had looked at those at casing components. You're right. We would not have looked at them. I assume that they were being treated just like equipment on skids. But there's a need for clarification on that particular issue. In the context, I still feel, that's personal opinion that the rule specifically talks about passive components and active components and not inactive systems. But -- DR. SHACK: It looks a lot like an electrical cabinet to me. DR. BONACA: Yes. So I think we should be open about resolution that there will be reached on this. I think we should look at them positively also because they're going to bring resolution to some issues on a generic basis and they're going to help finalizing the guidance documents that we have and making it easier for the industry. And certainly we will look for answers to the questions that John raised and for which we have no answer. They were good questions. Good questions particularly because they give us some feeling about the scoping issue for which we have various questions. I would like to just briefly now ask the members about what we should ask the staff to present next week. There is a limited amount of time there. MR. BARTON: Bob wasn't here when you asked the question. DR. BONACA: Yes. MR. BARTON: How much time is on the agenda? DR. BONACA: Oh, I didn't see a question. We skipped you. DR. UHRIG: I was out. DR. BONACA: Okay. DR. UHRIG: I don't have anything of major concern. I spent most of my time concentrating on the electrical components and I see those resolved, essentially the same as the previous plants have been and it's satisfactory. DR. BONACA: Right. Yes. MR. DURAISWAMY: Did somebody ask a question of how much time we've got? We've got two hours, scheduled for the agenda. But that's for both the staff and -- MR. BARTON: And the applicant. DR. BONACA: And the BWRVIPs. We have to be parsimonious about how we spend the time. DR. KRESS: That includes the BWRVIPs, that two hours? DR. BONACA: Well, we're not going to have a specific view of those. We're simply going to discuss the part of how they support particularly the internals and the vessels, some of the TLAAs and the other inspections. MR. DURAISWAMY: I don't think we're going to spend too much time on that thing, Tom. I think primarily we're going to spend most of the time, I think I split them between the applicant and the staff. So now we've got to get on about the agenda. DR. SHACK: You'd better let Gene Carpenter know that. MR. DURAISWAMY: Gene knows that. We told him yesterday, unless he was sleeping. (Laughter.) MR. GRIMES: Actually, this is Chris Grimes. In Gene's defense, we were hoping to convince you to let Robin do 25 of the 30 minutes allotted for VIP and Gene could have the last 5. You mentioned yesterday about half an hour's worth of VIP. I would also suggest that you look at the way that you treated the BWR topical reports for the Oconee review as a model of what the desired outcome looks like. DR. UHRIG: Ar you going to spend time on the results of the appeals? DR. BONACA: Yes. It seems to me that the first thing we need to talk about, the scoping and screening because this has been probably one of the places where we had some difficulty in reviewing, not because there is anything wrong with that fundamentally, but because we had some trouble with that issue. Then, I think we need to understand the open issues as a summary with specific focus on those which have been appealed right now, understanding that others may be appealed in the future. That doesn't preclude that. But right now those are the ones on the table. So and then I think we need to, as we talk about TLAA or even management programs to see how the BWRVIPs fit. That will be the half hour dedicated to that. It will be interesting to have again the perspective on how one-time inspections and the new problems have gone from application to application. MR. BARTON: You need the mike. DR. BONACA: Sorry, how they have gone from application to application, so we have an understanding of how that is evolving as we come closer to final documentation of GALL. MR. GRIMES: Dr. Bonaca, if I could suggest, we've committed to provide you with the cross cut of one-time inspections for the following session on improved renewal guidance. DR. BONACA: Okay. MR. GRIMES: So I would suggest for the purpose of the full committee meeting on the Hatch application, that if we could have the applicant simply decide on how they want to account for what's existing, what's modified, what's new in a very broad way. DR. BONACA: Exactly, and only as it fairly relates to Hatch. MR. GRIMES: Correct. MR. GRIMES: Okay, good. I think that if you include all those items you pretty much will run out of time, so my suggestion is to stay with that and with whatever else you feel you want to communicate to us at that point and that goes for both the staff and the applicant. MR. LEITCH: Maybe you mentioned this, Mario, but I think Butch's slide that's labeled overview, the four important distinctions, first BWR, first use of the BWRVIP program, functional approach versus systems approach, that slide, I think -- DR. BONACA: It's a good introduction. MR. LEITCH: That's a good introduction, exactly. DR. BONACA: One thing that I suggest is if the applicant finds a way to fit it in, the brief communication he gave us on the experience of the plants I think was very important because I mean it told us a pretty good story about the plants and the recent history of travel and the plants and a good history and so -- I think also that slide we saw yesterday where the capacity factor has improved so significantly through the years, I think is a demonstration that the initiatives of the BWRVIPs have been effective. The other point we have noted yesterday in the presentation was that this is not only one plant operating and gathering information, but is three plants, before including maybe including foreign plants. So therefore, there is substantial experience being gathered of every year that is really applicable to every plant out there, so that gives a lot of additional confidence in the BWRVIP. I would probably present that point as part of the BWRVIP element to the presentation. Any other thoughts? So if I remember now next week is going to be practically the whole morning first of all on Hatch and then -- MR. DURAISWAMY: First two hours, 8:35 to 10:30 on Hatch and then go the license -- DR. BONACA: Okay. Any other comments or questions for the members? Comments or questions from the public? None, the meeting is adjourned. (Whereupon, at 1:37 p.m., the meeting was concluded.)
Page Last Reviewed/Updated Tuesday, August 16, 2016
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