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Official Transcript of Proceedings NUCLEAR REGULATORY COMMISSION Title: Advisory Committee on Reactor Safeguards 491st Meeting Docket Number: (not applicable) Location: Rockville, Maryland Date: Thursday, April 11, 2002 Work Order No.: NRC-325 Pages 1-407 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) 491ST MEETING + + + + + THURSDAY, APRIL 11, 2002 + + + + + ROCKVILLE, MARYLAND + + + + + The Committee met at the Nuclear Regulatory Commission, Two White Flint North, Room T2B3, 11545 Rockville Pike, at 8:30 a.m., Dr. George E. Apostolakis, Chairman, presiding. COMMITTEE MEMBERS PRESENT: GEORGE E. APOSTOLAKIS Chairman MARIO V. BONACA Vice Chairman F. PETER FORD Member THOMAS S. KRESS Member GRAHAM M. LEITCH Member DANA A. POWERS Member VICTOR H. RANSOM Member STEPHEN L. ROSEN Member WILLIAM J. SHACK Member JOHN D. SIEBER Member ACRS STAFF PRESENT: JOHN T. LARKINS Executive Director SHER BAHADUR SAM DURAISWAMY I N D E X Opening Remarks by the ACRS Chairman . . . . . . . 4 Final Review of the Turkey Point License Renewal Application. . . . . . . . . . . . . 7 Advanced Reactor Research Plan . . . . . . . . . 116 CRDM Penetration Cracking and Reactor Pressure Vessel Head Degradation Peter Ford . . . . . . . . . . . . . . . . 206 Larry Mathews. . . . . . . . . . . . . . . 207 John Wood. . . . . . . . . . . . . . . . . 257 Ken Byrd . . . . . . . . . . . . . . . . . 278 Staff Presentations Mr. Jack Grobe . . . . . . . . . . . . . . 295 Ken Karwoski . . . . . . . . . . . . . . . 333 Westinghouse Owners Group (WOG) and Electric Power Research Institute (EPR) Initiatives Related to Risk-Informed Inservice Inspection of Piping Allen Hiser. . . . . . . . . . . . . . . . 337 Andrea Keim. . . . . . . . . . . . . . . . 357 Stephen Dinsmore . . . . . . . . . . . . . 367 Adjourn. . . . . . . . . . . . . . . . . . . . . 407 P-R-O-C-E-E-D-I-N-G-S (8:30 a.m.) CHAIRMAN APOSTOLAKIS: The meeting will now come to order. This is the first day of the 491st meeting of the Advisory Committee on Reactor Safeguards. During today's meeting the Committee will consider the following: Final Review of the Turkey Point License Renewal Application; Advanced Reactor Research Plan; CRDM Penetration Cracking and Reactor Pressure Vessel Head Degradation; Westinghouse Owners Group (WOG) and Electric Power Research Institute (EPR) Initiatives Related to Risk-Informed Inservice Inspection of Piping; and Proposed ACRS Reports. This meeting is being conducted in accordance with the provisions of the Federal Advisory Committee Act. Mr. Howard Larson is the designed federal official for the initial portion of the meeting. We have received no written comments or requests for time to make oral statements from members of the public regarding today's sessions. A transcript of portions of the meeting is being kept and it is requested that the speakers use one of the microphones, identify themselves and speak with sufficient clarity and volume so that they can be readily heard. I will begin with some items of current interest. First of all, we are welcoming back Mr. Graham Leitch. MEMBER LEITCH: Thank you. It's good to be back. CHAIRMAN APOSTOLAKIS: That's good. I would like to inform the members that Chairman Meserve will be here tomorrow at 11 a.m. to welcome our newest member. And at 1 o'clock tomorrow afternoon we are all going as a group to have our picture taken individually because eventually we will get new budgets. MEMBER SHACK: I'll need to dress up for that. (Laughter.) MEMBER SIEBER: Would that be possible? (Laughter.) MEMBER SHACK: That's the problem. CHAIRMAN APOSTOLAKIS: You all have this handout, items of interest. There are five speeches by the Commissioners at the recent Regulatory Information Conference. Also, we have summary of the Reactor Oversight Process Inspecting Findings that should be of interest and also you will see on page 27 a news item that Westinghouse Electric Company has submitted an application for design certification of the AP-1000 design. And Dr. Kress has a tape perhaps we should all see? MEMBER KRESS: Yes, I have here in my hot little hands a copy of a copy of a copy of a copy. Sandia at work, mostly, that I obtained by nefarious means and what this is is a tape showing a lot of the things they did to show the robustness of spent fuel casks, like running trains into them and dropping them off of buildings and etcetera. So if anybody is interested in seeing this and I have it and I guess Theron can set it up and show it at noon time some time. CHAIRMAN APOSTOLAKIS: How long is it? MEMBER KRESS: It's not very long. CHAIRMAN APOSTOLAKIS: Okay, so maybe we can do that at 12:30 or so? MEMBER POWERS: After members have watched it and convinced themselves that the casks are incredibly robust, I'll them what's wrong with the tests. MEMBER KRESS: Okay, great. CHAIRMAN APOSTOLAKIS: Okay, so I think we are now -- do the members have anything else to add by way of introduction? Okay, so the first item on the agenda is the final review of the Turkey Point License Renewal Application. Dr. Bonaca is our lead member. Dr. Bonaca? VICE CHAIR BONACA: Yes, good morning. On March 13, the Subcommittee on License Renewal traveled to Turkey Point and at that time we visited the site. We were able to observe on the simulators the ability of the plant to interconnect the emergency diesel generators from one unit to the other unit for station blackout concerns. We also heard from the plant about the way that they addressed closure of the open items. There were only four open items in the SER for license renewal. We had an opportunity to observe the site and note the excellent physical conditions of the equipment on the site. In the afternoon on the 13th we met in Town Hall of Florida City and there we had a public meeting and we heard from the staff how the open items had been addressed and closed. During that meeting we also had some observation from a member of the public. We also had in writing some concerns raised by another member of the public. The two concerns really echoed each other. One of the concerns that was raised had to do with voids in the concrete structure of the containment identified at Turkey Point, both units, in the early 1980s. We heard from the site personnel on how the issue had been addressed. We felt reasonably confident that they had been addressed properly. We asked questions regarding the generic implications, how they had been addressed and for those we have asked the staff to come today and tell us how they were handled for the other sites. And so with that in mind, we have a presentation this morning both from the Turkey Point people and from the staff and at this point I turn the meeting to PK Kuo who is here to present us on that. MR. KUO: Thank you, Dr. Bonaca. Good morning, members of the Committee. My name is PT Kuo, the Program Director for the License Renewal and Involved* Impacts Program. This is my first week on the job. Chris Grime has moved on to take on new challenges and we all wish him good luck. I also want to introduce Mr. Frank Gillespie on my right. Mr. Gillespie is the Deputy Director for the Division of Regulatory Improvements Program. Today, after the Applicant's presentation, the staff will brief the Committee on the review results of the Turkey Point license renewal applications and specifically, the staff will address in detail the questions raised by Mr. Oncavage in their letter to the Committee on concrete voids and the hurricane damages. We are going to have an assembled panel to brief the Commission. We also have a technical staff sitting in the audience ready to answer any of your questions. With that I will ask whether Mr. Gillespie has any opening remarks? MR. GILLESPIE: Yes. Let me just address the concrete void issue because we may not have done as much research on it as we would like relative to everything from the old Oyster Creek problem with spalling concrete on the outside to the voids that were identified in the 1980s and going back and saying did we consider this generically at that time? The staff is going to be prepared to address it for Turkey Point where we think it's been plant specifically resolved and I'm going to tell you right now we might have an IOU to have to come back as we were kind of talking about this last night, prepping for the meeting. We might not have done the generic research on the other aspects of it quite yet and we're kind of still in a process. The other thing is hopefully between the staff and the licensee's presentation, we will address things like Part 21 on analysis and decision points that are in Part 21 on is it significant, is it generic? And the lack of -- and it's a question of documentation for convenience. While the letter you got from this individual was, in fact, an open letter, the Agency did enter it and Region II is going to be on the phone to try to address this. They did enter it into the allegation system. Even though it was an open question it got put in the allegation system to make sure we followed up and got with the person and got back to them and got letters to them and did an inspection. Unfortunately, that system gives the appearances because it, in general, was designed to protect people's identity of being kind of private and therefore the link to the plant-specific issue and what was done might not be obvious in public documentation because of that. So Region II is going to be on the phone to try to address that to the degree they can. We put ourselves in a procedural box when we put a public issue in a private system. MR. BLANCHARD: Yes. I realize just for the benefit for those members who were not in the meeting, this is all because in their mind there was an expectation that since this was a potentially generic issue, maybe the licensee had initiated a Part 21 which speaks of a defect to a significant component. And Part 21's intent is the one of making the issue known, available to all plants so that people can look at their own plant and inform the NRC that there is an action to be taken on that. And that's why we raise these kind of issues and we will hear from Region II how it's handled. MR. GILLESPIE: So we'll take our best shot at answering all of the questions, but we may have a little something. I talked to Goutam here and depending on how it all comes out when we get all the facts on the table, we might have an IOU still left. VICE CHAIR BONACA: Yes, it's important, however, today that we also separate Turkey Point and how it was addressed at Turkey Point -- MR. GILLESPIE: Yes -- VICE CHAIR BONACA: From the generic issue because that may have to be handled actually -- they should be handled differently. We want to make sure that there isn't any outstanding issue to the drafting of a letter of the report at Turkey Point. MR. GILLESPIE: Yes. And PT told me last night, he said "I'm the license renewal guy." And he says, "this is an operating question." I said, "Yeah, but you're stuck leading the meeting." So -- (Laughter.) Thank you. MR. KUO: And if I may add, we also have a Region II representative who will be tied up in the telephone line and to here and to answer any questions you may have. VICE CHAIR BONACA: Thank you. MR. KUO: Thank you. CHAIRMAN APOSTOLAKIS: Okay, the Applicant can go ahead. MR. HALE: Can everybody hear me okay? Hi, my name is Steve Hale. I'm the Project Manager for License Renewal for Turkey Point in St. Lucie. I thank you for the opportunity to talk to you all today. I know I've met several of you when you came to the site, as well as the ACRS subcommittee meeting we had last September. What I'd like to do today is give you an overview of the application and then talk specifically about two of the open items which were a little more complicated to address than say some of the others and I'm going to talk about the closure of the nonsafety related which can affect safety related category of scoping and the license renewal rule, what we call Category 2. Then I'll talk about field-erected tanks and the program that we propose for field-erected tanks to close that open item. When we began the license renewal application effort for Turkey Point, a lot of the guidance that's in place today was really in draft form, so we had to drawn on multiple sources. While we had Part 54, we have a draft standard review plan, but it was under major revision at the time. We had a draft GALL report. We tried to address and look at GALL as part of our overall process, but that was also in the developing stage for Turkey Point. We had a draft Reg. Guide, but we had 95-10 which was issued, I guess the final rev. was in the 1996 time frame which had undergone somewhat of a demonstration program, so we utilized the methodology that was in 95-10. Additionally, we tried to use the lessons learned from previous applications, RAIs and RAI responses which were on-going with Calvert Cliffs and Oconee at the time. And as generic issues were being resolved between NRC and NEI, we tried to factor those also in co-application as they were available and as they were applicable to Turkey Point. One of the efforts NEI underwent in 1999 was working with the NRC staff and trying to come up with a format that we both could agree on so we could get used to the information being presented in the same places. This was, I believe, in the 1999 time frame and essentially, based on the draft SCs that were issued for Calvert Cliffs and Oconee, plus some lessons learned through those reviews, we structured, we came up with a format that both the staff and NEI agreed to and ANO was really the first to follow that standard format and then we followed Hatch because of where they were in the development of their application, attempted as best they could to address that format, but based on where they were, they really had a difficult time in trying to comply with it totally. And then I think the subsequent applications that have come down the pike, Dominion's applications, Duke's other applications as well as Peach Bottom, followed the standard format. It's broken down into four chapters. The first chapter addresses the administrative information requirements of Part 54. Chapter 2 goes through the methodology we utilize for scoping and screening and presents that results. Chapter 3 is where you do your aging management review and Chapter 4 addresses time-limited aging analyses. Now I hadn't intended to go through scoping and screening methodology today. We went through that in great detail with the subcommittee on September 25th of last year. Also, as part of that standard format there were several appendices. One was the UFSAR supplement. The second is Appendix B where we have summaries of our aging management programs presented in the ten element format addressing staff requirements on how they want aging management programs presented. We included an Appendix C and this was really to address some of the, what we call generic type RAIs, RAIs regarding positions, regarding aging effects and that sort of thing. It wasn't required by the standard format, but this was an intent on our part to address some of the RAIs we had seen in previous applications and we felt Appendix C did a good job of addressing some of those. Appendix D would include any of the technical specification changes that would be identified by the overall process and then as an adjunct or really an attachment with the application comes the environmental report. When you look at the scoping criteria in the rule there's a criteria of safety-related components that -- and there's three criteria stipulated for safety-related. Non-safety related which can affect safety-related, based on our review of this, we saw two types of non-safety which can affect safety. One is where the non-safety system has to function in order not to affect a safety-related component. And the other is one for potential of interactions, where the failure of the non-safety system could potentially affect the function of the safety-related system. And then category 3 is the five regulated events: fire protection, PTS, EQ, ATWS and station blackout. In the application, you'll find in Section 2.2 a summary of all the systems at the plant and the ones we had identified as in the scope of license renewal and we do the same with structures. As you can see, about half the systems in the plant have at least some portions that fall within the scope of license renewal and a little less than or a little more than a third of the structures at the site. I have to note that the structures at the site include anything in the protected area so you have a lot of the administration buildings and that sort of thing as why not essentially comes into play is the power block buildings. For screening, this is where you really get down to the nuts and bolts of the components and structural components that support the functions that were identified in the system and structure level of scoping. And going through screening, the first step you do a component level scoping. Then you look at whether the component performs its function without moving parts or change configurations, essentially what we consider to be passive and/or they're not subject to replacement based on a qualified life. So you take each major system or structure in the plant that falls within the scope of license renewal. You break it down into its pieces, parts, you determine which ones support the functions and you establish which of those components are passive and which ones are not replaced regularly. The results of screening are presented in the six column tables in Chapter 3. One of the lessons learned that we had with the Oconee and Calvert Cliffs applications was the fact that it really makes it good to see the entire IPA on one set of tables, so you have the scoping and screening results essentially in the first two columns and then you have a balance of the aging management reviews, so rather than including duplicate tables in Chapter 2 and Chapter 3, we simply provide a summary in Chapter 2 and refer to Chapter 3 which lists the scoping and screening results and then you can see the rest of the IPA stacked up with each one of those components. The mechanical sections, again, this is consistent with the standard format that was developed. You had a reactor coolant system, connected systems, emergency safety features, auxiliary systems and steam and power conversion. In the structural area, we chose to break it up between the containment and other structures and in the electrical and I & C section, it essentially looks at all the electrical components of the site and it follows a slightly different process than the mechanical and civil sections. We also submitted license renewal boundary drawings along with our application. Again, the staff has indicated that really facilitates their review in the mechanical area and lets them see what the boundaries were and what equipment was included in scope based on the actual drawings generated from the PNIDs at the plant. Aging Management Reviews are presented in Chapter 3 and Appendix B because really the Aging Management Review not only consists of identifying the aging effects, but demonstrating the aging effects are adequately managed for the extended period of operation. To facilitate the review, we grouped the items in the Aging Management Review the same way they're grouped in the scoping and screening section so you had a one to one correlation through the application. Again, the results are presented in the six column tables including identifying the aging program that manages any aging effects that requirement management. For nonclass 1 components, again in Appendix C, some of the technical positions we took regarding certain types of aging effects are presented there for non-Class 1 mechanical as well as civil structural. In the Class 1 area, we develop and discuss the aging effects specifically in Chapter 3. One of the things that we felt was mandatory as part of our review for license renewal was doing an extensive review of both industry experience as well as plant-specific experience at Turkey Point. We reviewed INPO and NRC generic communications and also our responses and any of those that really were related to aging we went back and relooked at those to see if we'd addressed them appropriately. In terms of plant-specific history, we went back and looked at the nonconformance reports and condition reports, I think all the way back to the early 1980s. We looked at event response teams. These are teams we form when we have a significant event at Turkey Point like a plant trip, those sort of things. We form teams whose goal is not only to identify what needs to be done to get the plant started up, but also root cause and this type of thing. One of the great source of information we have, we have a metallurgical lab and all of the nonconforming conditions or condition reports that require metallurgical analysis are submitted to the metallurgical lab for determination of root cause and the type of aging effects. We also drew on that population. Those were available, I think, at Turkey Point we had over 200 metallurgical lab reports so we used as another major source of information for operating experience. And as also part of our process, our procedures and the way we developed our Aging Management Review had us go and specifically talk to the system engineers and the component engineers. My team was located on the Turkey Point site, so we had quite a bit of interface with the engineers that deal with the systems on a day to day basis. CHAIRMAN APOSTOLAKIS: Now from the metallurgical laboratory reports, I don't understand what benefit you had from those. Is it possible that you would decide to do something by looking at one of those reports that you had not already done? MR. HALE: One of the issues that has been identified as the one -- hey, we don't think aging effects are occurring, but you need to go in and do one-time inspections to verify. Pitting is a good example. But if you go back and you look at metallurgical and you sort on things like stainless steel systems with chemistry control, you can look as whether you've ever had any specific failures related to pitting or stress corrosion cracking. We use metallurgical lab reports when they determined that we've had loss of material due to MIC and we folded those -- we developed tools for doing aging management reviews on the non-Class 1 mechanical systems because those are the ones where you get the wide variety of materials and environments. And one of the things you use is hey, the tools the industry may develop may say that you have to address stress corrosion and cracking in the system, but if we can go back to the metallurgical lab reports and say we've never had stress corrosion cracking in this system and we can develop a technical basis for it, it provides a good source of information. Again, on the other hand, the tools the industry develops may say you don't get MIC in these kind of systems. Where we have experienced MIC and we discovered that through our interface with the metallurgical groups as well as the metallurgical lab reports. So we're not saying that we just use it carte blanche. What we're saying we use that information as additional research in some of the technical positions we may have taken with regards to aging effects. CHAIRMAN APOSTOLAKIS: Okay. MR. HALE: Any other questions related to that? Okay. Time Limited Aging Analysis. These were the major TLAAs at Turkey Point: EQ, class and balance of plant fatigue, containment tendon relaxation, reactor vessel irradiation embrittlement. We had a couple of cases wear/erosion where we had TLAAs associated with that. Containment liner fatigue, crane fatigue. Also as part of the rule we have to do a review of time bound exemptions whether we had any and our review determined we didn't. With regard to the UFSAR supplement, we submitted a markup with the application. In addition to that we included a new chapter in the SAR which includes all the AMPs that are committed to for aging management, as well as a description of every one of the TLAAs that were identified. Also, in the FSAR supplements our commitments related to programs are included. Now additionally, one of the things we did with the staff, we've updated the SAR supplement to include all the commitments that were identified as part of our review of the application. In other words, with RAIs, responses to RAIs, we included any additional commitments that came out of that interchange into a revised SAR supplement that we issued late last year. With regards to Appendix B where Aging Management Programs are located, for each aging effect requirement management an Aging Management Program is identified. We presented these programs in the 10 attributes following the guidance issued by the NRC. We've got three categories of Aging Management Programs. We have those that are existing, those that need to be adjusted and those that are brand new. You see we have pretty equal distribution. Again, I described Appendix C, non-Class 1 component, Aging Management Review Process,it's not required by the regulation, but we did submit it to address some of the previous RAIs we had seen and other applications. And Appendix D was technical specification changes. We did not have any for the Turkey Point license renewal application. I just wanted to mention the environmental report because there is an environmental piece. Some of the unique things about the Turkey Point site, we have thousands of miles type of cooling canal system and you see it from satellite photos, in fact. We do not identify the need of any major refurbishment which is one of the issues that needs to be addressed in the environmental report. We do not use wells at the site. We essentially, the only water we use from the local community is domestic water. And the evaluation we performed against the alternative show that license renewal is the lowest impact option under the environmental review. MEMBER LEITCH: Steve, I have a question. I'm not sure if this is the right time to bring it up or not, but the fossil units that are adjacent to the nuclear units -- MR. HALE: yes. MEMBER LEITCH: It seemed to me that -- and I'm going on memory of quite a few years back, but it seemed to me that during Hurricane Andrew there was some missiles from the fossil unit that damaged a part of the nuclear unit. I think it was in the fire protection pump house or something like that. MR. HALE: What happened was we had a high tower out in the water treatment plant area and the high tower fell over on one of our domestic water tanks. We have two tanks and the domestic water tanks are also what you credit for your Appendix R, I believe A-1, whatever, it's our fire protection water sources. So the tower actually fell over on one of the tanks and as a result we got into one of the start up issues we had related post-Hurricane Andrew was providing the water sources until we could reconstruct that tank. MEMBER LEITCH: I guess my question is in the 20 years extension period for this license, what assurance do we have that the fossil units wouldn't be retired and as many fossil units abandoned in place and that there might be missiles, if you will, created as a result of that that could in future storms damage the nuclear unit? MR. HALE: Well, for one, the safety- related equipment is protected from missiles as part of our design basis. In fact, the safety-related portions of the plant and even some of the nonsafety- related portions of the plant survive very well. We were back on line within a month after Hurricane Andrew. There were a lot of missiles during Hurricane Andrew, independent of whether the fossil unit was there or not. We had winds in the area of -- the eye passed over Turkey Point and we were in 150 to 160 miles per hour range. The South Florida building code is about 120 and so trees -- there was a missile that went through one of the oil tanks, what they call the day tanks that affected that particular tank. The nuclear plant fared very well with the exception of that high tower falling on the fire water tank and a materials warehouse that was outside of the protected area. The plant did very well. I think it's a proof test on the plant so to speak, but one of the things in terms of interactions that was identified some years ago and has been evaluated is the seismic capability of the smokestacks. And they have been evaluated. In fact, we've included them in the scope of license renewal for that very reason. MEMBER LEITCH: Okay, the smokestacks at the adjacent fossil plant? MR. HALE: Yes, yes. You'll find them discussed in the application, in fact. MEMBER LEITCH: That's good. Thank you. MEMBER SIEBER: Those stacks aren't very high though, right? MR. HALE: About 400 feet. I wouldn't want to climb to the top of them. There are some folks who do who have to work on the lights, that sort of thing. Okay now I'd like to go through the resolution of open items and Dr. Kress, I've tried to -- you had mentioned the criteria, so I've included some additional information there. I hope I address your question that you had. This is a presentation I went through with the subcommittee when they were at the site. The open item is entitled scoping of seismic II over I piping systems. It really goes beyond that. This is really interactions between nonsafety and safety-related system and the potential impact on safety-related. One of the things I wanted to summarize was go through the components we included in the scope of license renewal to start with: (1) any pipe segment beyond the pressure boundary which is included in the seismic analysis, we included that pipe segment in the scope of license renewal because it fit in that first category which is it's performing a function in support of the safety system. We included all piping component supports for nonsafety-related mechanical systems with the potential of seismic II over I interactions because Turkey Point is an older plant. We did this on an area basis. We basically went through each building of the plant and any room that contained both nonsafety and safety-related equipment all the nonsafety-related supports were in the scope of license renewal in that area, regardless of whether the stuff could follow effect or whatever, we just said this area contains both types, so as a result all the nonsafety-related supports associated with ductwork, cable trays, conduit and in addition to that we included the conduit itself, the cable trays and other structural components outside of the mechanical area, in these areas where you had both safety and nonsafety equipment. In addition to that, we had done a fairly extensive internal and external flooding analyses so anything related to that was included in the scope of license renewal and this basically included curbing. We have some sump pumps down in the RHR pump rooms and those sump rooms that were included in the scope of license renewal as well to accommodate flooding effects and in addition to that, we included all the pipe whip restraints, barriers, these type of things that we credit for jet impingement, effects of spray and pipe whip. That's what we included in the scope of license renewal to start with. After a lot of dialogue between the staff and ourselves, the issue that was identified is that the effects of pipe whip, jet impingement, physical contact, pipes falling on pipes and leakage due to credible and that's an important word, credible nonsafety-related pipe failures, beyond the current assigned break locations because we've evaluated breaks in certain places, but we haven't evaluated them across the board, need to be considered based on the industry operating experience. In other words, if you'd had failures of nonsafety-related piping, through operating experience, and you have a piece of a similar type piping routed above safety-related equipment, then that should be something that should be included in the scope of license renewal and managed from an aging standpoint. As a result of this issue, there may be some additional pipe segments that need to be included in the scope of license renewal and thus an Aging Management Review needs to be performed. During our ACR Subcommittee walk down to the plant, I showed the ACR Subcommittee an example of the kind of pipe we were talking about. What we did as a result of that and all these rooms where we had both nonsafety and safety-related equipment we did an evaluation assuming credible failures based on operating experience of nonsafety-related piping beyond what's currently in our current license basis. If there was an interaction with safety-related components as a result of this failure, we in turn included that pipe segment in the scope of license renewal. To address the criteria -- CHAIRMAN APOSTOLAKIS: Let me understand this. Something is credible if it has happened? MR. HALE: In operating experience in the industry. CHAIRMAN APOSTOLAKIS: Oh, in the industry at large. MR. HALE: In the industry at large. Not necessarily -- although a lot of this piping is not in the scope of license renewal and that sort of thing, we don't operate with leaks at the site and we manage that, but the real issue is when you're looking into the future, without doing specific aging management say on a piece of pipe, could it fail, such that it would affect safety-related equipment. So we used a fairly conservative criteria in establishing the interaction. Basically, what we said if we had a nonsafety-related piece of pipe in a room with electrical equipment and that electrical equipment is not qualified for outdoor service, then we said that pipe is in the scope of license renewal. We didn't do a rigorous evaluation or analysis of spray and see if the component could accommodate it. We basically just concluded whether it would actually affect it or not through analysis, we said that pipe segment was in the scope of license renewal from a leakage standpoint. From the pipe whip, jet impingement and physical contact and this was basically the high energy piping out on the turbine building, it really took walk downs and actual physical observation of the piping and essentially we took the criteria that if we could see the pipe and the safety-related equipment, that piece of pipe was in the scope of license renewal. It wasn't based on a rigorous analysis, but we took a very conservative posture on this. And in this case it was primarily conduit and cable tray routed out in the turbine building, so if we had to run a cable tray between two walls and there was high energy piping in the area, we said that high energy pipe is in the scope of license renewal. I don't know if that addresses the criteria question that you have, but we basically just took a conservative position on it. What was the results of all this? We included a number of pipe segments in five of the structures that contained safety and non-safety equipment. We identified the aging effects requiring management for those pipe segments and for those that require aging management, we included them in our chemistry control program, our systems and structures monitoring program and our Flow-Accelerated Corrosion Program. And we've already made al those changes in the program documents. In most cases, they were already included in the program to start with. We just had not identified the piece of pipes in the scope of license renewal. MEMBER ROSEN: What is the qualifier as applicable? MR. HALE: Well, this is just a broad statement, you know, you don't use FAC on a non-FAC system. It was just a broad -- if you locate our open-item response, I don't know if you all have copies of that. We highlight specifically what systems and what programs apply to which pipe segments. MEMBER ROSEN: But it's not an out -- all of the above is true except when we decide we don't want to. MR. HALE: No, no, no, no. The intention here is not all these programs apply to all the pipe segments, that's all. FAC applies to only certain types of systems. Chemistry applies to certain systems as well as the system structures and monitoring program. It's in a lot of detail in our open item response and we've incorporated it on a component level basis where we identify the specific programs that are required. Any more questions on II over I? Now this is one that I think the industry and the staff are working towards a resolution such that this will not become an open item on subsequent applications where the guidance gets clear, because a lot of it comes to communications and your ability to understand what the true issue is and I think once we understood, then it was easy for us to work through what it was we needed to do. VICE CHAIR BONACA: Do you think the guidance now is clear enough? MR. HALE: I think it's still going to be a challenge because for -- for older plants. I think newer plants, we've done an initial scoping review for St. Lucie. It's not going to be quite the same. The older plants have some unique design features -- VICE CHAIR BONACA: But the logic is pretty clear. Older, previous evaluation, II over I were based on concerns with high energy line break, so therefore you're looking for those kind of effects, not aging. MR. HALE: Right. VICE CHAIR BONACA: Whatever. Aging now introduces potentially some other locations for failures that are not already covered by previous, so it seems to me the logic is clear. I mean -- MR. HALE: Right. VICE CHAIR BONACA: The question is how is the guidance now because we're be looking for. We thought that the guidance provided in the SER for Hatch was quite clear. MR. HALE: Yeah. Once you understand what the true issues are, I think that -- again, these guidance and these generic interchanges we're having with the staff are a real positive step, I feel, get some of these down on paper, you know, so we can -- we don't get into the point where it's an open item. But the other item I was going to talk about was related to field-erected tanks. This was an item where the NRC had identified to us three times they wanted us to address regarding field-erected tanks. One, we had not supplied specific acceptance criteria in the application regarding inspection. They wanted us to include some additional provisions in our program that called for additional examinations if the one-time inspection we had proposed identified extensive loss of material. And also provide a little more information regarding why we felt we only needed to do one-time inspection on these tanks. With regards to the acceptance criteria and additional examinations, the acceptance criteria is any loss of material greater than the tanks corrosion allowance, okay, will require specific corrective action in our corrected action program and as part of that, we'll consider the use of any additional volumetric or service inspections and identify as well, whether we need to do follow-up inspections and that has been incorporated into the program requirements. Our basis behind one-time inspection and I'd like to point out in any of these cases where we say a one-time inspection is because we're going into it with the thought that we don't expect to find an issue. In any of these one-time inspections, if we do find problems we would be required under our corrective action program to follow up and establish future inspections and that sort of thing. So when we say one-time inspections, we're saying that this is something where we don't expect to find anything, but our corrective action process would require us to follow-on if we had to. VICE CHAIR BONACA: So if you find something when you do the one-time inspection, you'll convert that to a program? MR. HALE: It depends on the aging effect and what it may be, but if it's something that looks like it's going to be a continuing thing that we need to manage, then certainly we would institute follow-on inspections, but that would be part of our assessment and evaluation and what we saw. Again, the first plan is under the one- time we don't expect to find significant aging. Our plant operating experience has revealed no incidents of degradation of CSTs, RWSTs and DWSTs, other than some repairs we had to do to the condensate storage tanks were attributed to one, we had some poor coatings to start with on the tank and secondly, the tank was being subjected due to an operational problem to hotter basically steam fluid was blown into the tank which was causing some degradation around the top that it was never really designed for. This is a field-erected atmospheric tank and it was being exposed to some higher temperatures. Secondly, we went into the demineralized water storage tank recently to install a floating cover on it to help with oxygen control. We didn't find any degradation in that tank as part of that modification we performed. On top of that, the RWSTs, the CSTs and the DWSTs, we inspect those. Those are part of our on-going external inspection program so any problems with the tank, you would see corrosion that sort of thing on the outside of the tanks. When the ACRS Subcommittee was at the site, we pointed out a couple of the tanks as part of our walk down we did. Okay, that's all I had with regards to my formal presentation. Do you have any other questions? VICE CHAIR BONACA: Do you have anything to say about the statements from Mr. Oncavage or are they going to be at a later time? MR. HALE: I went back and as part of Mr. Oncavage's statements I looked at what we did as a utility, with regards to the discovery, analyzing it, evaluating any corrective actions. With regards to the Part 21 issue, our procedures require us to address defects under Part 21. It's a mandated requirement. It's in our quality instructions. One of the things that you have to do though is to do a significant safety hazards evaluation to establish whether it is reportable under Part 21. With regards to this particular event, the evaluation performed by Bechtel one, determined that the pressure integrity of the containment was never compromised and this is documented in the Bechtel evaluation after discovery of the event -- VICE CHAIR BONACA: The design capability of the containment? MR. HALE: Well, two things. One the pressure integrity, certainly the containment had undergone integrated leak rate tests as well as the structural integrity test previously and if you look where the void was, it was beyond the welded portion of the pressure battery. Secondly, in that evaluation that Bechtel performed they also demonstrated that the structural integrity of the containment was not affected by the voids. So for it to be reportable, at least from our procedures, under Part 21, it would have to represent a significant safety hazard and based on the fact that the pressure integrity and the structural integrity were not affected by the voids, it would not represent a significant safety hazard. VICE CHAIR BONACA: What I'm asking about is the design capability, I'm referring specifically to what you're committed to in your testing which is your testing the containment for your design capability which typically is lower, much lower than the overall structure -- ultimate capacity. MR. HALE: Right. VICE CHAIR BONACA: So the question I had, I guess, is that evaluation did not address the ultimate capacity. It addressed the -- MR. HALE: The design capacity. VICE CHAIR BONACA: Design capacity. Okay. Just to make that clear. And so because of that, it is now reported under Part 21? MR. HALE: Right. MEMBER LEITCH: I have a question about your ability to inspect the head as per this recent NRC inspection, NRC request, I should say. There are different insulation configurations throughout the industry which make it more or less difficult for people to get a good look at the head. What's your status as far as that response is concerned? MR. HALE: Turkey Point, we've completed bare metal inspections on both heads. Unfortunately Turkey Point was, if you recall back in 1987, we had a leak that we operated with -- MR. WILLIAMS: Excuse me, Steve? MR. HALE: Yes. MR. WILLIAMS: Is that the right slide? You've got station blackout up there? MR. HALE: I'm sorry, I apologize. (Laughter.) I'm sorry, I had a slide for the Davis-Besse. (Pause.) Excuse me. MEMBER ROSEN: It's going to be interesting to see you tie the two together. (Laughter.) MR. HALE: All right. As far as the -- as I was saying, Turkey Point had an event with some significant leakage in the reactor vessel head area. In fact, it's what prompted 8805. We had operated, I believe, about -- I believe it was about six months with a known leak in the reactor vessel. It was the conoseals. As a result of corrective actions related to that, one our insulation configuration was changed somewhat to where we had inspection ports. Additionally, we installed a radiation detector that actually sniffs the head area and so we can get some intelligence, you know, when we get high radiation and containment and can help maybe locate whether -- MEMBER SHACK: N-16? MR. HALE: Pardon? MEMBER SHACK: N-16s? MR. HALE: No, it's just radiation detector in the head region. It's in an enclosure, so we actually have a -- it's something we did to tell us. And we also instituted some very stringent leakage controls. We require specific evaluation if leakage reaches .5 GPM and if needed, we'll actually go in and do containment walk downs. So the combination of those things, although it was a negative event, I believe has created a situation that we're finding and what we did is we did a bare metal inspection as a result of bulletin in 2001 related to Inconnel 600 on Unit 3 in October of 2001 and we also did it in March of 2002. I would also like to point out we were able to do this and accommodate it within a normal -- we're doing refueling outages in a 25-day type time frame and we were able to accomplish this with that. We used remote TV cameras. I actually went through the report evaluation and they addressed each individual nozzles. We've got videos and pictures, but it was clean. There was no evidence of leakage and there was no evidence of boric acid accumulations. MEMBER SHACK: And you can literally do 100 percent inspection? MR. HALE: One hundred percent visual. With remote, television cameras and that sort of thing. I believe it was Framatone that's developed the -- but it's very detailed. MEMBER ROSEN: This radiation monitor you talk about, is it sampling the environment, the air and taking it through a filter and putting it in front of a detector? MR. HALE: Yeah. MEMBER ROSEN: Now those filters, are those looked at? MR. HALE: Yes. They're replaced periodically. MEMBER ROSEN: What do you find on the filters? MR. HALE: I'm not sure. You're asking a question that goes beyond -- MEMBER ROSEN: Well, I ask it because Davis- Besse found a lot of iron oxide on their filters and they had a similar system. I think you ought to be finding that the filters are clean. MR. HALE: They replace the paper periodically because they have to for the monitor itself. MEMBER ROSEN: They take off the paper to replace it because they analyze it. MR. HALE: Yes. MEMBER ROSEN: But not because it's plugged up or anything. MR. HALE: Yeah. MEMBER ROSEN: But you don't know? MR. HALE: No. MEMBER LEITCH: As a result of your operating with the leakage back in the 1980s whenever it was, did you find any wastage at that time? MR. HALE: Not very much, but I think the number that was quoted, like I said, I'm reaching here was in the hundreds of pounds, had accumulated on three of the reactor vessel studs in that stud area, so there was some wastage on the studs. There was no real wastage on the head itself, but again, this was a conoseal leak. MEMBER LEITCH: I understand. MR. HALE: And it was, I believe in the -- it was within tech specs, but it was just spraying over about six months it accumulated boric acid. MEMBER LEITCH: Okay, thank you. VICE CHAIR BONACA: Going back a moment to the issue of the concrete, what did you do? How was it repaired? What I am trying to understand is what is the condition of the containment right now for both units? I understand you repaired what you found. You did not open every part of the containment so you had the inspections to identify whether you had other void issues? MR. HALE: Bechtel essentially did a root cause on the issue that was discovered. The root cause determined it was a combination of a difficult area to get concrete into plus where they had established a construction joint. The repairs that were implemented called for -- we were actually putting in a heavier steel bottom to the equipment hatch to remove the steam generators, so they removed that. They poured the appropriate concrete and they put a thicker piece of metal which was the intent all along when they had pulled it off and discovered the void. In terms of generic implications, based on the root causes that were identified, Bechtel established based on that root cause that they wouldn't find similar type of areas like that based on that -- and so that's documented. VICE CHAIR BONACA: In other locations of your containment? MR. HALE: Right, right. And that's documented in there. It was a fairly extensive evaluation that they performed to demonstrate that. VICE CHAIR BONACA: So you do have confidence that there are no voids in your containment? MEMBER POWERS: It's an incredibly self- serving finding, isn't it, that everything is okay, we only made one mistake. VICE CHAIR BONACA: That's why I'm interested in hearing about -- what is interesting is that it happened in the hatch of one of the units and then they looked at the other one and they found the same problem right in the location. That's why we would be raising questions about the generic implications for other units. Now so there is a confidence that that was the only location in that containment that could have been affected by that and it was this position for the Turkey Point unit? MR. HALE: Right. VICE CHAIR BONACA: Containments. MR. HALE: And it was also communicated with -- communicated and inspected by the region. There was an LER on it. They came in and looked at the Bechtel evaluation as well as the disposition of the repairs, so I have confidence. We've also undergone, I think about seven integrated leak rate tests on both containments and I have full confidence in our containments. MEMBER LEITCH: We had the same problem with Limerick during construction. I think it was Limerick I in about 1977 when the forms were removed from the containment pour and this was above one of the containment hatches, a large void was found. It's right above the containment hatch. There was a real configuration, complex configuration of rebar in that area, but it was a very significant hole. That was also a Bechtel job, by the way, and it was a very significant hole. Were it for the rebar you could easily put a Volkswagen and maybe a Cadillac into this hole. CHAIRMAN APOSTOLAKIS: It saved a lot of concrete. MEMBER LEITCH: It saved a lot of concrete. But of course that was self-evident and it was all chipped out and replaced. VICE CHAIR BONACA: Because that was visible. MEMBER LEITCH: Yes. VICE CHAIR BONACA: I had another question regarding another point that Mr. Oncavage raised regarding hurricane? MR. HALE: Yes. VICE CHAIR BONACA: Capability of the site and he presented the fact that he didn't feel that Hurricane Andrew was really a category 5 hurricane and the ability of the plant to withstand a category 5 and you addressed that issue. MR. HALE: Yes, yes. In fact, the FSER highlights are design capability, the two aspects of a hurricane that you're concerned with is wind and tidal surge, but with regards to wind design, I think you'll find any FSER were designed for 225 miles an hour and all the way up to 300 some miles an hour without loss of structural integrity. So we are not concerned from -- wind design is not an issue. VICE CHAIR BONACA: Tidal surge was the issue. MR. HALE: When we look at tidal surge, we are designed -- the plant elevation is at 18 feet. We can -- we install stop logs as part of our hurricane preps up to 20 feet and all the safety-related equipment is located at 22.5 feet. I had some friends that were affected by Hurricane Andrew's tidal surge and so I had some witness accounts of trucks at the top of their garage as the thing came in and hit their house, but I think if you look at historical data and that sort of thing, 22.5 feet is plenty to accommodate any tidal surge that could be expected, even for a category 5 hurricane. VICE CHAIR BONACA: Thank you. MEMBER POWERS: Mario, in light of the Davis-Besse events, have inspections for these one- time inspections we do for license renewal, have they come under question? VICE CHAIR BONACA: I don't think so. First of all, the components like such as a head are really under a different kind of inspection program that clearly is not one-time inspection. MEMBER POWERS: I mean it's the mindset. If you go and inspect something expecting not to find it, you frequently don't find things. And there are an awful lot of inspections in license renewal with the predisposition not to find anything. And son of a gun, they don't. VICE CHAIR BONACA: Yes, if you look at the issue or components which are related to the one- time inspection, I'm not sure that they are the type where your ability to detect would be so challenged. For example, it's erosion, certain components or corrosion and so on and so forth. The presumption is that if you do the inspection close to the 40-years life and you do it once and you don't find anything, then you have -- and the first -- I think there is a good provision in the license renewal that says you can roll that inspection into your program until you find something and it then falls under corrective action. I think it's a good point you are raising. I think you have to be sensitive to that as we look at new license renewal applications in the future and see what kind of one-time inspection we have, if it is, in fact, an obvious thing that you would identify those kinds of degradations easily or if your ability to detect is being challenged. MEMBER POWERS: Since we've been talking about Turkey Point concrete, I've got to tell the Committee at least one anecdote about the Turkey Point concrete, but Turkey Point doesn't know. In 1976, the NRC asked me to look at the effects of interactions with concrete and they said use prototypic concrete, so I said well, what's prototypic concrete? I decided the FSARs probably had prototypic concrete described in them, so I went to our library attendee and asked him for an FSAR and they handed me a box of microfiche, all jumbled together and they said these are all the FSARs. So I went to sorting them out and the first one I sorted out so it was reasonably complete was Turkey Point and Turkey Point's FSAR has an excellent description of their concrete and I used that description of the concrete to create the concrete I was doing and since I wrote it down everybody else just used that as the specification and as far as I know every melt concrete experiment that's ever been sponsored by the NRC has used Turkey Point's concrete description. (Laughter.) Sand size. I believe your aggregate is oolite. I had to figure out what oolite was. And I know more about the Southeastern United States geology than I ever cared to learn trying to understand what oolite is. MR. HALE: Any more questions for me? VICE CHAIR BONACA: I don't think so. Thank you for the presentation. It was very informative. We'll hear from the Staff and the SER. MR. KUO: Yes. I will call on Mr. Raj Auluck, the Project Manager for the Turkey Point license renewal application review and his panel. MR. CHRISTIANSON: Nuclear Regulatory Commission, Chris Christianson speaking, may I help you? MR. AULUCK: Chris? MR. CHRISTIANSON: Yes. MR. AULUCK: Raj Auluck. MR. CHRISTIANSON: Hi, Raj. MR. AULUCK: Hi. We are just starting in a couple of places and I just wanted to make sure you are on the line. MR. CHRISTIANSON: Okay. (Pause.) VICE CHAIR BONACA: Be aware we have about 45 minutes left for the meeting, including discussions, so I leave it up to you to be -- MR. AULUCK: Okay. Good morning. I am Raj Auluck, Project Manager for the Turkey Point license renewal application review. With me around the table is Jim Medoff. He's from Division of Engineering and helping us so he'll assist me on a couple of the slides. Then we have some people from the technical division, Jim Lazeunick from electrical. And they will discuss some of the issues which were especially asked by the Subcommittee during our meeting last week. Hans Ashar from Mechanical Engineering and Barry Elliott from Materials. The purpose of today's meeting is to present the staff's review -- Chris, are you there? (Pause.) Chris? MR. CHRISTIANSON: I'm here. MR. AULUCK: I forgot to introduce Chris Christianson. He's the Branch Chief, Region 2 and he'll be helping us respond to some of the questions you have on the inspections or the allegations. I will describe the resolution of the open items and the basis upon which we'll move forward to make a recommendation to the Commission on this application. The application was received 18 months back, 19 months today exactly. This was the firth application received by the NRC. Four have already been approved. This is the first Westinghouse. It is two-unit site. Each is designed for 2300 megawatt thermal. The site is shared by two oil and gas fired generating units in Florida City about 25 minutes from the Miami, south of Miami. Unit 3 license expires on July 19, 2012 and for Unit 4, on April 4, 2013. The application is for two years' extension. The review schedule originally issued with an acceptance letter. As you can see, the next -- that line is completing the SERS briefing and preparing the Commission paper with the recommendation on middle of next month. The final SER was issued on February 27th and final environmental impact statement was issued on January 15th of this year. MEMBER LEITCH: I have a question regarding the length of the extension. I read that the PTS value is very close to the allowable 300 degrees. It's 297.4. And it's stated that that would be okay because that was the value, I guess after 48 effective full-power years. Now we're extending this to 60 years. Is it mathematically impossible to get a number in excess of 48, full-power years, or is there some kind of a caveat that says 60, but no more than 48, effective full-power years? MR. ELLIOTT: Well, you could get 48 effective full-power years corresponds to 60 years at 80 percent capacity factor. The plant could run higher than that and therefore it would exceed the -- before it reached 60 years it would exceed 48 effective full-power years. But it's not the 48 effective full-power years. It's the critical factor here. It's the neutron effluents received by the vessel and that's the critical factor and that's what they have to monitor to determine whether or not they're going to exceed the PTS screening criteria. As long as they monitor the neutron effluents and they stay below their projections, they'll stay below the screening criteria. According to the PTS rule, if they start exceeding the effluents values they projected, they're required to do another projection of where they'll be with respect to the PTS rule. So it's within the PTS rule there is a flexibility. MEMBER LEITCH: Okay, so there is no limitation then at 48 effective full-power -- MR. ELLIOTT: No, it isn't 48 effective full power. It's the neutron effluents. MEMBER LEITCH: And even although they go above -- if they went above 48 effective full-power years, presumably they'd be crowding that 300 degree -- MR. ELLIOTT: They would have to tell us the impact on the neutron effluents for the vessel and then from that they would have to project the RPTS value to determine whether or not they're still below the screening criteria at end of license to extend the license. MR. MEDOFF: Barry, may I add something? MR. ELLIOTT: Sure. MR. MEDOFF: I would like to add that in a reassignment they do exceed the screening criteria, the rule is written to require the licensee to take appropriate action including flux reductions and/or annealing of the reactor vessel. So the rule does incorporate corrective action should those screening criteria be exceeded. MEMBER LEITCH: Okay, thank you. MR. AULUCK: Continuing, we'll start with how we reviewed the application. There are two self-regulatory requirements that govern the review of any license renewal application. First is Part 54, the NRC staff conducts the technical review of the license renewal application to assure public health and safety requirements. A second is Part 51, then as the staff completes routine review of the license renewal application, focusing on the potential impacts of additional 20 years of plant operation. Now there are many programs which are routinely monitored and assessed plant operations, but the license renewal review focuses only on those which has the potential detrimental effects of aging and not addressed routinely by on-going programs. Part 54 requires the Applicants who demonstrate how these programs will be effective in managing the aging process during the extended period. Now staff's review consisted on reviewing of the Applicants' scoping and screening methodology, review of the aging management programs and review of the time limited aging analysis identified by the Applicant. These reviews are supplemented by the site audits and inspections by the NRC staff. There was one site audit done on this site and two inspections governing scoping, screening, aging and management reviews. Scoping and screening methodology review was done in two parts. And the first one is a desk top review which is basically initial review of the application supporting information and second is the on-site audit with a team of headquarters' staffs and regional participants in the review of the on-site documentation, review of the selected engineering reports, engineering procedures, design documentation and discussion with engineering staff. Incidentally, it was during this audit first done early in the review process which was in this case November of 2000 when the staff raised the issue of interaction of nonsafety systems, structures and components with the safety systems, structures and components. And then later on this turned out to be one of the open items in the SER. We had several discussions with the Applicant on this issue. Now this Part 54.29 describes the standards which must be met before the Committee issues a renewed license. We have talked a little bit already about the first two items on the slide. The last one relates to hearing and intervention on the license renewal application. There was no hearing on this application. There were two requests filed for -- filed to petition to intervene and request for hearing. On January 18, 2001, the Atomic Safety and Licensing Board Panel had a pre-hearing conference in Homestead, Florida to hear on the petitioner's standing and the admissability of their preferred contentions. In the order issued on February 26, the Board ruled that all -- both parties have standing to intervene. Neither petitioner proffered admissible contentions, so their intervention petitions therefore, must be denied. The Board ruled that these contentions raise issues that fall beyond the scope of license renewal and renewal proceedings. And on March 19th, one of the petitioners -- he appealed the decision to the Commission. On July 19, 2001, the Commission issued an order affirming the Board's decision. We have participated in several industry groups on license renewal including Westinghouse Owners Group and for that developed series of generic reports intended to demonstrate that aging effects will be properly managed. At the Subcommittee, they asked us as a staff to make a specific presentation on these reports and how staff intends to use them. Barry? MR. ELLIOTT: Yes, Barry Elliott, Materials and Chemical Engineering. The staff has reviewed all these WCAPs. The first four, in particular, are license renewal documents in which the Westinghouse Owners Group has done an aging management review to determine the aging effects for the components that are listed in the titles there for the reports and they listed the aging effects for the components and the aging management programs that we used to manage those aging effects. The staff has written safety evaluations for each one of those and they've identified license renewal Applicant action items. As far as Turkey Point is concerned, the staff was a little late in its safety evaluation, so they couldn't reference the actual staff evaluations in their report, so they wrote how their components fit the report and it was during the RAI process, the Applicant addressed the license renewal action items and the staff reviewed those and found those satisfactory. Those first four reports were discussed in detail at the Subcommittee meeting. The fifth item which is the WCAP-15338 deals with the time limit aging analysis for underclad cracks, specifically it has to do with reactor vessel forgings that were fabricated using a course screen, a head treatment and fabrication process and where the clad was applied with high heat input. This is in BWR and in Westinghouse plants and we've had two topical reports on this. This is an extension of a review that the staff did in the 1970s on this issue and what they've basically done here, Westinghouse, is extended the review that they did in the 1970s using 1990's technology and information. They've updated the analysis for new technology, new information and also extended it for 60 years. These are very small flaws on the order of 10 7-inch, the largest in-depth, the largest we've ever seen is like 3/10ths of an inch. The run in length from a tenth of an inch to like two inches. Very difficult to detect with ultrasonics. Therefore, we're relying on the analysis to assure vessel integrity. The amount of floor growth here from fatigue is very, very small. In sixty years, it's less than a tenth of an inch. We don't expect any growth from stress corrosion or a very small amount of growth from stress corrosion, cracking. This is borne out by the recent event this summer where the crack grew through the weld, reached the ferritic component and stopped. The allowable flaw size for this is much larger than the 3/10ths of an inch on the order of one in three tenths or one in four tenths of an inch. So there's a large margin here and for that reason there's no real concern about these cracks for license renewal. VICE CHAIR BONACA: So this WCAP actually was used to address one of the open items, right, the underclad? MR. ELLIOTT: They're required, licensees are required to identify time limit aging analysis. There's criteria in the rule. This would be one of them and this was used to address that requirement. VICE CHAIR BONACA: The reason I'm asking is that the first four were reviewed, but they were not referenced into the application. MR. ELLIOTT: Right. VICE CHAIR BONACA: Although for the fifth one, the review was completed before the open item was addressed. So I think it was credited for. MR. ELLIOTT: The fifth one was credited for. MR. AULUCK: That's correct. The Commission appeal prepared many internal license renewal documents under the QA program for use in the preparation of the application and training of their staff members. The NRC staff reviewed selected portion of these documents during our site audit and scoping AMR instructions. According to the Applicant, they had several discussions with the previous applicants and reviewed previously issued RAIs and had other experts look at the application. In summary, the staff generated about 215 requests for additional information on this application which was at that time substantially less than the previous ones of 300 to 400. And as I understand, the number is going down, which is expected as the experience, the quality and clarity of the application is improving. As part of this review, the staff review issued four open items in the draft SER in August of 2001. The first one was seismic II over I interaction of nonseismic safety-related piping because safety-related structures and components are known as seismic II over I. This was the same one that was identified early in the review process, but at that time the staff was in discussion with the Applicant to resolve the issue so we asked the FPL to just wait until the resolution is reached on the application and the staff position will be issued and then they can address that issue. So in the meantime the SER time came, so we issued the SER with open items. And I think basically, the Applicant has gone over the criteria of selecting which portion of the piping was not included in the first time and then included later on. All I'd like to add here is since that time, the staff has issued two positions on this issue. First one is seismic II over I which was a narrow scope of nonsafety-related piping closely related to the safety-related piping. The second position which is broader in scope, it relates to all nonsafety-related piping and components. I think in the future, the staff intends to work with industry to make it an issue to combine the two positions into one. The second open item is -- it relates to the field-erected tanks internal inspection. The reason it was an open item during the SER stage was it was a new program and the Applicant had not addressed all the attributes identified in our process, so we asked the specific questions in the RAI and the Applicant said it's applicable to five tanks, two condensate storage tanks, two refueling water storage tanks and one shared demineralized water storage tank. The Applicant responded in late fall and the response was unacceptable. So this item was considered closed. The next item relates to Reactor Vessel Head Alloy 600 penetration program and Jim Medoff, who was the lead reviewer for this issue when he was in Division of Engineering, he will speak. MR. MEDOFF: Good morning, I'm Jim Medoff. I'm acting as a backup project manager for the Turkey Point license renewal application. Prior to my rotation to the License Renewal Environmental Impacts Program I acted as a materials engineer for the Materials and Chemical Engineering Branch. Part of my responsibilities in that branch included the review of the Reactor Vessel Head Alloy 600 Penetration Inspection Program. Basically what I need to say about the program is that the license renewal application was submitted prior to the issuance of NRC Bulletin 2001-01 which was the bulletin written on the Oconee circumferential cracking that they detected in a number of their penetration nozzles in a couple of their units. We issued an open item to address whether the inspection program for the penetration nozzles was current with bulletin and whether the -- and whether they were going to update the program to include the bulletin and FPL's responses to the bulletin and any changes to the inspection program that might needed to result from the program. When the Applicant's response to the open item came in, we not only reviewed that, but we also, the Applicant referenced the bulletin and we looked at the bulletin response as well. Our review of the responses to both the open item and the bulletin indicate that FPL is committing to continue participation in the industry-wide program for inspection of vessel head penetration nozzles and to update this program as necessary based on industry experience and any further studies that the MRP or EPRI might conduct regarding vessel head integrity issues. Their response to Bulletin 2001-01 provided revised rankings for the plants and indicated that they were going to do bare-head inspections of both Unit 3 and Unit 4 vessel heads. FPL has completed both inspections and has not detected any visual signs of leakage or boric acids on the vessel heads for the units. I will say since Davis-Besse has been brought up that the NRC issued Bulletin 2002-01 to address the Davis-Besse issue and the impact on vessel head penetrations in pressurized water reactors in the industry and that FPL has provided its response to this bulletin. The response further indicates FPL's commitment to participate in the program and update the program as necessary based on inspection results. The next open item deals with reactor pressure vessel underclad cracking. I'm not going to talk in depth on this because Barry has just addressed what the contents of the WCAP were and the technical details of the issue of underclad cracking. What I will say is that when the NRC issued the safety evaluation on the topical report, they required two things. One was for three-loop plants of which the Turkey Point units are three-loop plants. They wanted the Applicants to indicate whether the number of design cycles for the transients assumed in the topical report bounds the number of cycles for 60 years of operation in terms of -- we're talking in terms of fatigue analysis for growth of cracks. The second item that the safety evaluation indicated was that Applicants referencing the topical reports as being applicable to their facilities would need to ensure that the TLAA for the valuation of the underclad cracks was summarily described in the FSAR supplement for their application. FPL submitted responses to the RAIs relative to both of the action items so we decided that the FPL took appropriate action and closed the open item up. MR. AULUCK: As you recall the Subcommittee meeting, one of the items discussed was station blackout and staff was asked how we are addressing that at Turkey Point. At that time we had stated that the issue is the position has not been finalized and when it is finalized it will be addressed like any other -- addressed by plants previously relicensed. Since then, the staff position has changed the final position on that station blackout was issued on April 1 and at that time they decided since the position has been issued, this must be addressed by the Applicant on this application prior to issuing the license, relicense. So we communicated this issue to the Applicant the following day and since that time we are having meetings, we had a public meeting yesterday. We're trying to resolve the issue from the perspective that certain components from the off-site power to the plant should be included as part of the license renewal. VICE CHAIR BONACA: This is a change from the discussion we had. MR. AULUCK: This is a change from the discussion we had before and that -- so our intent here is to resolve the issue and still meet the schedule date of sending the recommendation to the Commission. What we are thinking is we'll issue -- the FSAR has been issued with all items addressed. It will go to the printers at the end of this month, but we are in parallel, we'll be preparing a supplement to the SER addressing, focusing on the station blackout issue and our intent is to complete that in the time frame. VICE CHAIR BONACA: Okay, let me just for the benefit of the members who were not at the meeting at Turkey Point, the issue here is that there is a preferred station blackout recovery path and the guidance the NRC provided us before the meeting said essentially that that would include all the equipment that collects to off-site power. That includes all the equipment that collects to off-site power. That includes, for example, the start-up transformers which the Applicant has not included in the scope of license renewal. And the Applicant made the case that they did not rely on off-site power for recovery from station blackout and demonstrated to us that they can connect one unit to the diesel generators of the other units and one diesel generator out of four is capable of carrying all the loads for both units in case of a station blackout. They also pointed out that the experience from the Hurricane Andrew that that was, in fact, providing for them the most reliable source and they used it for that particular situation. Our understanding up to now is that, in fact, that was the way of Turkey Point to address the license renewal commitments. Now so irrespective of that, the staff is asking that Turkey Point includes all the collection to the off-site power? MR. AULUCK: Yes, that's why -- VICE CHAIR BONACA: This is a change to SER that we have in front of us? MR. AULUCK: That's why we're going to issue a supplement to the SER and we hope to issue that shortly, address this issue. Jim Lazevnick from Electrical will speak on this. MR. LAZEVNICK: Yes, the Turkey Point has an alternate AC power source as a means of coping with the station blackout and essentially the point of disagreement is whether that source is capable of recovering from a station blackout. In order to recover from a station blackout, each plant has to develop a coping duration based on total loss of all AC power at the plant and the duration for Turkey Point was determined to be eight hours and they utilize an alternate AC source to demonstrate that the plant could cope for that period of eight hours. These sources may have capability beyond eight hours, but the staff has not reviewed them to see if they, in fact, have that capability and the original requirements of the station blackout rule, the definition of an alternate AC source did not address that capability. It spoke of the alternate AC source being a means to cope with station blackout for the period of the coping duration. So based on other requirements in the station blackout rule, specifically Section 10 CFR 50.63(a)(1), the coping duration itself is based on four factors and one of those factors is the probable time needed to recover off-site power at the site. The four factors that licensees use to determine the specific required coping duration at their plant was developed into licensee guidance and this guidance was included in NRC Regulatory Guide 1.155 and an industry document that the NRC worked on the industry with which was NUMARC 87-00. And all the licensees essentially utilizes a guidance to determine their coping duration, relative to license renewal and age-related failures, it's our view that unless we control a portion of that off-site power system in terms of age-related failures, the licensee potentially might need a longer required coping duration if those age-related failures were not properly controlled and addressed under the license renewal rule. Our final position on this has been that the off-site power circuits between the switchyard and the safety buses should be included within the scope of license renewal. We recognize that the off-site power system actually is a source that the power source that extends all the way into the transmission system of the United States. We feel that this interface, this portion of the circuitry is an appropriate part to be included within license renewal because it's the portion of the off-site power circuit that feeds the plant and essentially has requirements only in the plant. It has no transmission system type requirements associated with this portion of the circuit. VICE CHAIR BONACA: So this says we have SER with one open item. MR. AULUCK: Out of this stage, right, and we met with them and there is agreement, close to an agreement. We have looked at the draft response and the Applicant believes they can finalize their response in the next couple of days and we have agreed to work with the Applicant and issue the supplement as soon as possible. VICE CHAIR BONACA: Well, we should hear from the Applicant what the Applicant thinks. They made a case for us and they made a demonstration of what they consider the ultimate power supply and as far as our review was concerned, we asked questions specifically about a standard for transformers in October and the answer was they are not in scope. And so I would like to hear what's happening there. MR. HALE: We still do not agree with the staff position. We had long discussions with the staff yesterday. We understand what their position is. We have nothing but confidence in the capability of our system and I think we demonstrated that for you at the simulator. But we understand what the staff position is. We have spent the last two weeks, I guess week and a half, based on being informed by the staff what their position was and that they had finalized it. So we have put together a response, draft response which they've highlighted the additional equipment. There's not a lot of equipment involved based on the boundaries that the staff is proposing. They're basically calling for the breakers and the switchyard that feeds the start-up transformer, the start-up transformer itself and the feed into the 4160 switchgear. VICE CHAIR BONACA: Which I'm sure you consistently maintained? MR. HALE: Yes, this equipment is maintained under the maintenance rule because the maintenance rule scoping criteria goes beyond our -- is different than license renewal. The maintenance rule considers things as trip hazards and that sort of thing. So this equipment is inspected under the maintenance rule, but base don our interpretation and our CLE documents which include our safety evaluation report, on-station blackout which we reviewed in detail as well as our design basis documents and our FSAR, we cannot find where we've specifically credited restoration of off-site power, but we understand the staff position. We think we're somewhat unique in that we have fully capable diesels. In fact, we have over 400 KW, 300 to 400 KW of excess capacity of a single diesel, so it's their position. That's the way they've interpreted it. They've issued it formal and so we've issued a response to address the specific requirements -- VICE CHAIR BONACA: So you have already issued a response? MR. HALE: A draft response. They are reviewing it. Once we factor in their comments, we will issue it formal probably within the next week. VICE CHAIR BONACA: Any other questions for Steve? Thank you. MR. AULUCK: Continuing, in February of this year, a public citizen, Mr. Oncavage, sent a letter to the ACRS identifying four safety concerns. The first one relates to the effects of wires on aging, degradation rates and structural integrity of the containment structures at Turkey Point. At the Subcommittee, we discussed this issue and you asked the staff to make a presentation as it may apply to some generic implications to the other plants. Before Mr. Hans Ashar will speak on that, before he starts, I'd like to go a little bit of when the issue was first raised and what has happened since that time. The issue was first raised by Mr. Oncavage at one of our exit meetings. We had gone for inspection there and at the exit we provided the results at a public meeting and Mr. Oncavage raised this issue that he understands there was some voids formed at Turkey Point containment during 1980s when during the steam generator replacement process. So at the meeting, the Region took this, considered this as an allegation and gave us a tracking number. And then they asked the Applicant forward the concern to the Applicant to respond to the NRC. The Applicant responded with information to the NRC and on August 10, Region II sent a letter to Mr. Oncavage summarizing the results of the review. But then in December 15th, he sent another letter to the Region stating that he's not satisfied with the results of the August 10 letter and NRC should ask FPL to start testing, looking for voids in the containment. Region II informed Mr. Oncavage, acknowledging the December 15th letter and stating that they will respond to him after reviewing the material again. So on April 5th, last week, a formal response was issued to Mr. Oncavage, summarizing the review, independent review by the NRC staff and the inspection reports, other documents. Thus Region II considers this issue to be closed for Turkey Point. Now Mr. Hans Ashar will speak on the general implications. VICE CHAIR BONACA: Now I imagine that the issue was closed for Turkey Point because the two identified voids were filled and those inspections were filled in the containment or was it simply some statement that said we don't expect to find any more? MR. AULUCK: I think it was review of other technical documents at the site and there was a technical member from Region II, went and spent a week there, earlier this year to review all the reports and results and discussions with them. MR. ASHAR: I am Hans Ashar -- MR. GILLESPIE: Excuse me, Mario, if we could close this out because I know one of your concerns was documenting the stuff that was done. Since we have Region II on the phone, if a person went to the site that means some place there's an inspection report which documents what he did. Is it possible to get that inspection report to the Committee? VICE CHAIR BONACA: Chris? Chris, are you there? MR. CHRISTIANSON: Hello, this is Chris Christianson, Deputy Director, Division of Reactor Safety. VICE CHAIR BONACA: Did you hear the question? MR. CHRISTIANSON: Is there a possibility to get a copy of the inspection report? We did not document this in an inspection report. We documented this as a memo to file in the allegation folder. MR. GILLESPIE: Okay, it's still the same question. Is it possible to get a copy of that, Chris? MR. CHRISTIANSON: Mr. Auluck can forward it on to the appropriate person. MR. GILLESPIE: Okay, we'll contact you off-line, Chris, and we'll get a copy of it and get it to the right people on the Committee and that might provide some closure to the issue for Turkey Point and that might be beneficial. VICE CHAIR BONACA: Yes, just to understand what was done to assure the issues of concerns with additional voids in the containment was properly addressed. Thank you. MR. DURAISWAMY: Mario. Raj, you sent another letter to Oncavage on April 5th? MR. AULUCK: Yes. MR. DURAISWAMY: From here? From the head office? MR. AULUCK: No, from the Region. MR. DURAISWAMY: From the Region. MR. AULUCK: Because Region II considered the December 5th letter from Mr. Oncavage as the end of the follow-up allegation. MR. DURAISWAMY: Yes. MR. AULUCK: So they tracked it and they responded to that to him and just closing the loop. The letter is April 5th from Region II to Mr. Oncavage. MR. DURAISWAMY: You guys don't have a copy of that thing? MR. AULUCK: Those are allegations -- MR. DURAISWAMY: I know what the allegation is. MR. LAZEVNICK: I think I have copies of it. MR. AULUCK: They can be made available. MR. GILLESPIE: This is why I say when you put stuff in the allegation system, it's a very closed system, even though this individual didn't ask to be treated that way and so we can deal with it and get you copies of it. VICE CHAIR BONACA: But before the allegation issue, there was a finding, was an open finding. There was an evaluation being done. There was a response by Bechtel. There were people that came in with concrete and poured it to fill those -- I mean there were things that took place and in addition to that, if anybody had any question, they would have looked someone else to find are there other voids. That's -- I would expect there would be some documentation that says yes, we did the following steps and then the committee can review it and feel confident that something was done that we can state today those containments were taken care of and there are no voids in containments to the best of our knowledge within the limitation of detection and so on. It's not only the file on the allegation, it's just simply the paper trail that led to the documentation of the actions taken to deal with the voids. MR. GILLESPIE: And I'm hoping a memo to file actually references it reviewed this, reviewed that and then when you get those things, those things contain the subject matter and address these actions. I'm just not sure having not seen the file how it strings it together, but that's -- the starting point, I hope would be the memo to file where they said okay, we reviewed all the existing information and existing actions taken to date and it appears to be satisfactory and I hope there's some reference to what those other documents were so we have a -- we should have the trail. It's just it's in a system no one has easy access to. So we'll take back the idea of working with Region II and copying the paper trail and trying to get it to you in the very near future here. VICE CHAIR BONACA: We asked for those in Florida City. We asked for -- so that -- and Region II was there, present during the meeting and when we asked for this information. MR. GILLESPIE: Yes, because if this was followed up in the 1980s and there was an inspection report from the 1980s, I'm hoping that research was done that we can just pull it together in this one memo to file was kind of the cap on top of that review. MR. HALE: Dr. Bonaca, this is Steve Hale, Florida Power and Light, we interfaced with the regional -- the fellow that came down to do the investigation. There were LERs on this event. There was initial LER plus supplements. There was also two inspection reports which documented the closure of those two LERs and the individual came to the site, looked at that information. So I think this memo to file or whatever should have all the specific documents, but I can tell you for sure because we were supporting him and he went in and actually was looking at the original pours, concrete pours documentation on the testing that was performed on that concrete, so he did a very exhaustive investigation, just based on the interfaced we had with the fellow when he was at the site. VICE CHAIR BONACA: Okay, so we'll see for this. MR. ASHAR: I am Hans Ashar from Mechanical, NRR. I had read your transcripts of my tech. team and concerns expressed by various members of the SEI subcommittee and based on that, I want to address only the generic implication at this time as to what I think about it because we had a very short time to prepare for any in-depth research, but I'll try to tell you as much as I can gather from my own experience as well as other people's input into what I thought. Now first thing, what I want to refer to is are the worse possible. First thing I want to emphasize is this, that having voids in concrete construction, in general, there is commercial application at nuclear power plant is not an acceptable way of constructing any structure. It is not an acceptable matter. People try very hard to make sure that the concrete that they pour is being consolidated very well through vibrators and the construction joints are being formed in such a way that this kind of voids can be avoided. I also would like to let you know that it is possible, it is possible that some of the plants may have existing concrete voids. Now my own experience, when I was a specification engineer at Burns and Roe and I was at Three Mile Island, Unit 2, and at that time we heard about voids in ring guard at Three Mile Island, Unit 1 and the United Engineers Construction was the constructor on that one and their engineer had found the voids and they took corrective action after that. So what I would like to emphasize here is that the way the quality control, quality assurance works in the industry and it worked at that time, at least, I know because ACRS had very strict quality assurance criteria. It had been in force because people wanted to keep their license and so there were attempts being made to award this kind of work being persistence in nuclear power plant structures. Now somebody might say that that means that there are no voids in it. I wouldn't say so. I thin in spite of all the precautions there could be sometimes back down in some other thing, like a concrete venting plant, the pumping of the concrete, the vibratory spin work on the particular areas, voids might be there in some of the plants. Okay? Now as I said before, core requirements require concrete voids -- impact of voids. What could happen to the containment if there are voids present? Now in a very narrow way I would say there will be a reduction in thickness of the thick part of the sections of concrete. MEMBER POWERS: Before you go on to the impact, your slide says voids can occur where vibrators can't reach. MR. ASHAR: This is why I explain to you in much more depth is to what are the factors that can influence the existence of voids. MEMBER POWERS: There are many other causes of voids. MR. ASHAR: Please? MEMBER POWERS: There are many other causes of voids in the concrete. MR. ASHAR: Yes. Well, in order to avoid voids in concrete construction, in general, the first thing to make sure that the construction joints that they are going to put in are in the right place, so that you can ensure that the oldest areas, very older concrete are accessible from the formwork. And the vibrators can reach into those areas. These are the items being made all the time. As I told you in my experience, the voids were in the ring girder of the containment construction and the ring girder is a very thick area. It is a liner plate coming down and again the voids were in the area of the liner plate was touching the concrete area. But they took out all the concrete. They rehashed everything. They put new concrete in there to make sure there are no voids existing in that particular instance. The other two you heard about were the Turkey Point and Limerick. So yeah, voids can occur in various places and due to various reasons. MEMBER POWERS: I mean what I'm struggling with here is for this particular instance, you got an individual saying there are voids in the concrete. How do you know there are not voids elsewhere? The guy that placed -- the architect/engineer went in and said yeah, there were voids in this concrete and here's how we explain them. He said it's because the vibrators didn't get there. That seems very convenient to me. MR. ASHAR: Well, it explained to you. I put one bullet, vibrators can't reach. It is not the only thing, okay? But the basic thing is to make sure that the old areas to be concreted out are filled up with concrete to make sure of that. And then to consolidate the vibrators to beat the -- now sometimes it can happen, the water may be a little higher or the weather might be such that the water can bleed. When it bleeds what happens the calcium hydroxide from concrete gets into that area instead of filling of with full concrete and integrate. Only the water part, calcium hydroxide stays in that area and it would look like you filled up the things. As the time goes by that water starts evaporating and the void forms. So those things are possibilities. I would not completely -- MEMBER POWERS: What I'm trying to understand is the firm went in and they came up with a hypothesis of why they had a void in Turkey Point. It was very convenient and it would not be something that would extend out of places in the containment. What did the staff do to look and see if there was alternate explanations for this? MR. ASHAR: Well, I will ask open forum for other people to answer to this particular question. As I said, the construction practice during that time, the time this plant was being built were such and the quality assurance requirements were very stringent because I know from my own experience on this side of the fence I was not with NRC. I was with consultants and at that time, as a matter of fact, after I heard about that void and the cause for those voids, I wrote my specification for Three Mile Island, Unit 2 in such a way -- as a matter of fact, it is not very common for a specification writer to write about where the constructors would put their construction joints. But in our case, we did write it. Okay, because we were concerned about the voids in construction of Three Mile Island, Unit 2. That's why -- so people -- MR. GILLESPIE: Dana, let me see if we can put our package of documentation together. I think this is getting to the point where it may deserve a different -- I'm going to suggest a separate meeting. VICE CHAIR BONACA: The other point I would like to meet, we are here now, general considerations here. I think that is on the right track. The issue is you find a void under the hatch in concrete. So now you say well, let's see if this is just one of a chance and you go to the next containment and you find you have a void in the same spot. And this seems to be almost like it's a design feature for this kind of containment, I guess. It's present in two, let's see how many you've got where you have a spot. I think you would want to go beyond. Now typically, you have mechanisms by which you raise an issue that could be, I thought, would be Part 21, but Bechtel says oh, it's okay, the containment is too capable, so it's under Part 21. I'm sure there was a paper trail by which the issue, the potential impact of being a generic issue was evaluated. I mean normally the agency is very aggressive in pursuing these kind of issues. That's why we've been looking for how did we address, how do we get confidence that other containments of Bechtel design do not have the same voids in the same location and other containments in general do not have that. And that is really what we're looking for when we asked for that information in March down in Florida City. And we really haven't gotten the information. MR. GILLESPIE: And I think that's exactly what we need to pull together. Because now we're all trying to project what happened in the mid-1980s. VICE CHAIR BONACA: Yes. MR. GILLESPIE: And I'm having a tough time myself remembering what I did last month and these people weren't there. How well were we documenting stuff in the mid-1980s? We need to pull the inspection reports, look at what the people looked at, look at what the fellow, the inspector from Region 2 that went in and re-reviewed the issue and then ask the question and look at other records and say now did we take that? What did we do with it generically? I just don't know. I think we're talking about something in 1985 or something like that, maybe and it's 17 years old at this time. I like to assume the staff did the right thing. We did pursue things aggressively at that time. I just don't have the documentation in front of us. We need to pull it together. Someone else from engineering -- MR. KUO: Goutam Bagchi, he's going to make a presentation on related issues. MR. GILLESPIE: But I would suggest the opportunity to come back would be also fine with us. VICE CHAIR BONACA: My proposal will be if we feel, first of all, this committee will decide whether or not we feel confident that the issues themselves for Turkey Point, so we can focus on the license renewal for that plant. If we feel it is dealt with properly, then we can say let's concentrate on that. That will result, probably with separate letters requesting that we look at the genetic implications, how they were handled for other units and that would open the path. MR. GILLESPIE: Yes, and that would be fine. I think we can get the Region 2 records pretty quickly for you for Turkey Point to kind of close that documentation issue and I'll tell you the truth. I feel more comfortable coming back to talk about the generic issue versus trying to do something where we're potentially kind of patching some things together. VICE CHAIR BONACA: I agree with you one hundred percent. MR. GILLESPIE: Goutam did have some thoughts of some basic engineering he covered with me earlier of about why this is a safety issue we can now look at in an orderly way and not necessarily assume we didn't look at it 17 years ago, but let's see what we decided then and what the basis was. So I'd suggest coming back and let Goutam finish what he's going to go and we'd be happy to come back. MR. ASHAR: If Goutam is going to speak, then I won't say anything -- VICE CHAIR BONACA: I would like to hear from the members, is it acceptable with you that we put this issue here, which is generic, separately and address it later or would you like through the presentation now? MR. BAGCHI: It's a very quick presentation. I just wanted to share with you some idea of load sharing, what is it that is unique in the containment structure of design. VICE CHAIR BONACA: Okay. MR. BAGCHI: And I think there is something unique in the design itself that gives it the robustness and the ability to withstand the design basis. And concrete, as you know, takes compression. It cracks and it doesn't take an tensile load and it maintains -- the effective purpose of the concrete is to maintain the reinforcing bars in the designed locations. Reinforcement carries all the load. Post-tensioning tendons keep concrete in compression. And very high quality, .2 percent ultimate elongation, ductile liner plates are provided as the leak-tight barrier. Design basis load is internal pressure, due to the postulated accident load. Containment structure goes into tension. Concrete cracks due to tension. Reinforcement bars take all tension loads and the liner plate maintains the leak tight integrity. If there is any local void, it deforms plasticly and then expands and bridges the gap, as we have experienced in the reactor vessel head at one plant. At the shell-mat and shell-dome junctions bending moment puts concrete into compression. But as you know, this was not the area where the concrete void was found. The concrete void appears where there is congestion of reinforcement and special provisions are sometimes lacking when putting in concrete. And this is the area of the ring girder near the equipment hatch. So only in those two junctions the concrete is put into compression. By code requirement, concrete is under reinforced. Crushing failure of concrete is prevented by code provision because the reinforcement has to yield first. Redistribution of load around any void provides the necessary strength. Structural Integrity Test would reveal locations of unacceptable voids by bulging, spalling or local failure. Every reinforced concrete structure passed the Structural Integrity Test satisfactorily the very first time. There are requirements to make predictions of deformations and measurements are made, observations are made, examinations are made afterwards and they have all been within the predicted limits. Post-tensioning puts the highest load during construction. Any weakness in concrete shows up at this time as we found in the delamination of dome. It was a weakness in the design. Reinforcement bars were not provided and later on they learned their lesson. Containment weakened by pervasive voids will not pass the SIT, the Structural Integrity test. So my conclusion is that the unique design of the containment structure, the high quality of construction, no matter the fact that there were voids found and these are construction areas those are imbedded in the code related factors of conservatism and the allowable stresses and so on, there are going to be voids and in a very thick structure 4.5 to 5-foot thick walls, you're not going to easily find the voids. If they were found easily, they will be taken care of and if there are voids, as I tried to point out, the load path and the behavior of the concrete is such that the reliance is not on the concrete. And this is -- the inside I just wanted to share with you and I feel that the containment structure is extremely robust as people have seen from the tests, although in the tests you wouldn't have expected any voids, but in a scaled condition, microvoids may well have been there in those third scale, quarter scale test models. But it's the load and the design of the structure that provides us with the assurance that there will be good performance function, certainly, after the design basis load and way beyond that. MEMBER SIEBER: I have a question. I recall during -- having witnessed a couple of Structural Integrity Tests of concrete containments that one of the steps was to find and map the cracks that appeared. Was that common practice for every containment? MR. BAGCHI: Absolutely. MEMBER SIEBER: That would reveal the presence of the voids because the cracks would appear around the area of the void as the loads redistribute themselves. Is that correct or not correct? MR. BAGCHI: I would like to agree first and then take away some comfort that I've agreed with you. If it's 4.5 foot thick wall and if this void is adjacent to the liner plate, you're not going to see it. MEMBER SIEBER: That's right, that's right. MR. BAGCHI: This is a conservatism -- MEMBER SIEBER: You will see it on the inside if it's adjacent to the liner because there will be a dimple there. MR. BAGCHI: It has to be a very large void to do that. MEMBER SIEBER: Yes, it does. MR. BAGCHI: yes sir. MEMBER ROSEN: So the conclusion is small voids you won't see, but they don't matter because the loads are being taken by the reinforcement steel and large voids, if they have occurred, you would see. MR. BAGCHI: Yes, that's my contention. MEMBER ROSEN: In the performance of the concrete. MR. BAGCHI: If you allow me to characterize what kinds of voids, I would not consider as extremely critical is something in the order of a thickness. MR. KUO: If I might add to it, the large void, if it is located in critical locations, in other words, it's a stressed location, void stress location, you will see during the test, as a result of the test. MR. BAGCHI: That point about crack, map cracking, mapping the crack is really intended for that purpose. MEMBER SIEBER: That's right. VICE CHAIR BONACA: Thank you for informative presentation. MR. GILLESPIE: Mario, now what I'm hoping is that we'll find that back in the 1980s someone as smart as Goutam wrote that down as a basis and I don't know if we will -- we need to look, but that's part of the reason I think some things didn't happen and how well did we document things in our actions, we need to do some investigation. VICE CHAIR BONACA: Okay. MEMBER RANSOM: A point of clarification, in Turkey Point, is it known that there are voids and do they know how big they are? VICE CHAIR BONACA: Oh yes. They found voids, as you know. MEMBER RANSOM: They have found them? VICE CHAIR BONACA: Well, they found them, yeah, sure. That's how the whole issue came up. They found voids under the equipment hatch when they were replacing the steam generators. They had to take off the hatches because they were not large enough. As they removed them, they found these voids right under because of the complexity there and the amount of the rebar that -- MEMBER RANSOM: So those presumably were remediated when they repaired them. VICE CHAIR BONACA: Absolutely. MEMBER RANSOM: This just led to suspicion that there may be other voids? VICE CHAIR BONACA: The concern of Mr. Oncavage was are there other voids in the containments and so we expected to find that there would be some documented trail that said yeah, we looked at it or we tested or we performed some assessment of the type that we received right now that gives us confidence that probably there are no voids or there are some that are not significant to the strength of the containment. And we haven't found yet this paper trail. That's what we're looking for. The other issue is the genetic implications. If you find this kind of issue in one location, in one containment and then you go to the next one and find the same thing as happened there, it tells us that very likely there is going to be something similar under the hatch in some other unit and so one will have to understand the significance of no remediation of that void and again, that may be some analysis done of this type that is sufficient, but we haven't seen any of that, so we're looking for how the generic implications of the issue were handled. MEMBER POWERS: I'll point out, Mario, that there were in construction of the McGuire plant that they found large voids in the concrete when they placed, had nothing to do with where they put vibrators. There are lots of reasons for voids. VICE CHAIR BONACA: Yes, sure, the timing of pouring of the concrete, the density, the liquidity of it, how it flows. Okay, so are there any more questions? Your considerations were still related to each other's presentation we had on the concrete, right? MR. ASHAR: Pardon me? What's your question? I didn't get you. VICE CHAIR BONACA: I'm saying what is the remaining portion of your presentation? MR. ASHAR: Yes, I can finish up with a few lines. Now Goutam very well described this as to the robustness of containment and how the voids cannot be that much of a significance in integrity of the containment at least to resist the design basis pressures. This is exactly what Goutam pointed out in the initial structural integrity testing, periodic leak rate testing being performed in the containment. Containment -- they also conformed intended function of the structure. Now one other question that I'd seen being asked was what would be the impact on LERF. What I would say more succinctly is condition probably of containment failure. That would be affected if there is any point in it. Now my judgment, it's my own judgment on this particular issue is that there are two model tests being performed at Sandia. One in 1995 or so on reinforced concrete model and one in 1999 on viscous concrete model which was being financed basically by NUPAC in coordination with the NRC. On the first test, what I want to point out is the failure of the model at 137 psig or so, and at that time the concrete was quite a bit cracked and heavily cracked, but at that time they did not go all the way up to the failure of the complete structure. They stopped when they saw the leakage was too high, but there was some stiffness left still at that time and now in the later test in viscous concrete containment in 1999, they did go a little farther than just leaking criterion. It was considered the containment fate, but then they went a little bit more and they saw that there was few strength left, stiffness of the concrete to hold the liner in place and I think they went about 10 psig, more than what would consider as a failure, not the ability to -- so that was my judgment that the effects of LERF of the voids, in general, would not be that significant. CHAIRMAN APOSTOLAKIS: But the conditional containment failure probably in NUREG 1150 is extremely uncertain. I mean it's always between 0 and 1. MR. ASHAR: Yes. CHAIRMAN APOSTOLAKIS: I wonder, does it include the possible presence of voids? MR. ASHAR: Yes, this is what happens. Okay, that if the structure were intact completely, okay, the ideal structure, you find out one fragility curve occurred for containment probably so there is an FSAR and ordinate probably to a failure, FSAR used as pressure as a parameter. Okay, that will give you the medium design pressure. Point 5 failure could occur. That was taken in the LERF calculation later on for structural containment. Now if there is a degradation, a main degradation is not concrete, but the liner. In the case of concrete containments, liner would be the prime candidate for reducing the effectiveness of containment because it would leak. So if there is liner degradation of high level, then you can shift your facility curve in such a way that it meets with the damage assessment that has been performed. CHAIRMAN APOSTOLAKIS: My question is if I look at the -- not the fragility curve, but the final results of the NUREG-1150, they have very nice figures with various sequences and then the conditional containment is computed. MR. ASHAR: Right. CHAIRMAN APOSTOLAKIS: And this is a very uncertain quantity. It goes from 10 to the minus something, all the way to .9 sometimes or even 5. MR. ASHAR: Right. CHAIRMAN APOSTOLAKIS: So that's extremely uncertain. So I don't know what it means. MR. ASHAR: But normally the IPEs are performed with little more preciseness than those -- excuse me? CHAIRMAN APOSTOLAKIS: You mean the IPE is no better than your NUREG 1150? I doubt it. MR. ASHAR: Oh no, no, no. What I'm saying that the uncertainties which are being in NUREG 1150 considers number of uncertainties. When you start in plant specific IPE, that means they have precisely characterizing the sequences and then putting the -- they also have uncertainties, but not as much as what we see -- CHAIRMAN APOSTOLAKIS: Yes, but the IPEs also did not spend as much effort on the level. MR. ASHAR: I'm not saying I would put a lot of -- CHAIRMAN APOSTOLAKIS: My question is in the original 1150 studies, was the possible presence of voids included? You don't know? MR. ASHAR: I know that it was not. CHAIRMAN APOSTOLAKIS: Oh, it was not. MR. ASHAR: It was not. None of the damage condition or anything was considered in the 1150. VICE CHAIR BONACA: That's why I made a distinction between the design pressure that I believe, this condition is still allowed to meet as a requirement of the tech specs versus the ultimate containment. So we don't know and typically we are looking at penetrations as the weak link or something of that kind and here you have an unknown. CHAIRMAN APOSTOLAKIS: Is the effect not significant because we are so uncertain to begin with what can happen? MR. ASHAR: Well, only from the existing condition. It's not related to the insignificance. MEMBER FORD: Mario, you also managed to go about how we felt about this particular issue for Turkey Point as opposed to generic issues. I feel really uncomfortable. In all of the rest of the license renewal examinations we've been asked to comment upon, we've had detailed documents, ANPs that we can make good scientific judgments, our own independent judgments. Here we're hearing engineering judgment, anecdotes. We've got nothing to go on. So I don't see how we can make any advice or judgment on this as an issue. CHAIRMAN APOSTOLAKIS: Yes, I think this kind of discussion will take place in the afternoon part-- VICE CHAIR BONACA: But I would like to -- I know, we know pretty much what we heard already. My sense is that we should not write a report now. There are two issues here that need some closure. One is the station blackout issue. Although we know that the plant is taking a position, a direction of fulfilling the requirements, it is important for us as a committee for us to understand is it a capricious requirement in addition to what already they are doing at Turkey Point? Is it essential? I think we need to reflect on that and review it. Second, we also now need to look at this paper that will be provided to us and so my suggestion would be that schedule one hour meeting at the May meeting and we look at those two issues and then resolve them at that time. That will give us at least time next three weeks -- CHAIRMAN APOSTOLAKIS: Well, we have time this afternoon to discuss the letter. We have already agreed that there will be some additional information provided to us with a possible presentation. VICE CHAIR BONACA: Yes. CHAIRMAN APOSTOLAKIS: We're already behind schedule. VICE CHAIR BONACA: I was attempting to say in a way that you're right and a means of probably doing some closure, but I think that for us to jump to something today is going to make it enough. CHAIRMAN APOSTOLAKIS: Okay. So I'm wondering now is there anything else we need to discuss right now? VICE CHAIR BONACA: Any other questions that members would raise? MEMBER LEITCH: Not related to concrete, but I have a question about there's a figure in the environmental report. It depicts a 6-mile radius and usually when you see these figures they have a 10-mile radius. I don't know that this relates to emergency planning, but I'm just wondering -- CHAIRMAN APOSTOLAKIS: Which figure is this? MEMBER LEITCH: Page 2.1-3 in the environmental report. I'm just wondering is there any implication? Does Turkey Point have a 10-mile EPZ like everybody else? MR. HALE: Yes, we do. Steve Hale, Florida Power and Light. Yes, we do. That's not intended for emergency planning. MEMBER LEITCH: Okay and my other question is can someone tell me what's the CDF and LERF for these units and are they different from one another? MR. AULUCK: We'll have to get back to you. MEMBER LEITCH: Okay, I'm just looking for the CDF and LERF and are units, Unit 3 and 4 different from one another. MR. HALE: Unit -- I can't cite the specific numbers, but we're not an outlier or anything like that. We have reasonable CDF numbers. I can't speak to the specific numbers. MEMBER SHACK: Well, actually, your numbers reported int eh IPE are highest of anybody, but the discussion at Florida was that, in fact, that your updated PRA has numbers that are much lower. So I think it's close to four times 10-4 in the IPE and the reported number was like 1 times 10-5, some PRA person gave this in Florida, but that hasn't been documented. CHAIRMAN APOSTOLAKIS: So how did it go from four times 10-4 to 1 times 10-5? MEMBER SHACK: Divide by 40. (Laughter.) MEMBER ROSEN: This is fairly typically actually -- MEMBER SHACK: The discussion was that he was making some very conservative assumptions when they did the IPE. MEMBER ROSEN: That's the reason. This is fairly typical, you see it in most PRAs that the very first ones are quite a bit higher than the more sophisticated ones that are done over time. CHAIRMAN APOSTOLAKIS: So that's something that we have to discuss. VICE CHAIR BONACA: Any other questions? MEMBER POWERS: But George, I'll remind you the number is totally meaningless because it only considers operational events. MEMBER ROSEN: Because of what, Dana? MEMBER POWERS: It only considers operational events. It doesn't consider shutdown. MEMBER ROSEN: Plants generally have a shutdown assessment that considers the risk during shutdown which is additive to the internal events. It's not meaningless, it's just part of the question. CHAIRMAN APOSTOLAKIS: Okay, any other questions for the presenters? MR. AULUCK: Do you want us to go over the other concerns of Mr. Oncavage? CHAIRMAN APOSTOLAKIS: Well, it's too late now. VICE CHAIR BONACA: Let's just cover those. MR. MEDOFF: This is Jim Medoff again, Backup Project Manager for Turkey Point. Basically, when Mr. Oncavage sent his letter in to you, we did an independent review of its concerns and basically we categorized them into voids which we just discussed. The effect of hurricane windspeeds in storm surges, unsafe operation of the units. He also went into concerns about the effect of terrorist attacks on the safety of the plants and he had a concern about spent fuel capacity. Basically, what we did is we called up the National Oceanographic and Atmospheric Administration to discuss the hurricanes. Hurricane Andrew basically was one of the most severe hurricanes ever to hit the Atlantic coast. It had wind speeds of 149 to 150 miles per hour which puts it in Category 4, but with gusts above that which put the gusts into Category 5. The storm surges for the Hurricane Andrew were of the order of 17 feet maximum. As Steve Hale has indicated, the Florida Power Light units, the Turkey Point units, vital equipment are designed to withstand storm surges above 22 feet and all of the vital equipment such as emergency diesel generators, the reactor vessel, etcetera are put in design category 1 structures and they're designed to withstand differential pressures created by the hurricane of the order of 225 psi without any deformation of the -- MEMBER ROSEN: Now you said above 22 feet. I don't think that's what he said. I thought they said it was up to 22 feet. MR. MEDOFF: No, the location of the vital equipment is at 22 feet or higher. MEMBER ROSEN: Right. MR. MEDOFF: The maximum hurricane -- in our discussions with NOAA, the maximum surge ever recorded for the Atlantic Coast was 20 feet and that was for, I think, it was Hurricane Hugo on the North Atlantic coast. The maximum storm search for Hurricane Andrew was 17, so the vital equipment at Turkey Point are designed at levels currently to withstand the current storm surges for Category 5 hurricanes. That's not to say that you might get a really, really severe hurricane to create a storm surge above 22 feet, but I think the probability, my educated guess on that would be the probability would be low given the data that NOAA had given me in our discussions with them. The next one is the effective terrorist attacks on -- VICE CHAIR BONACA: We know that that's being handled. MR. MEDOFF: And the last concern was the -- Mr. Oncavage was concerned that they were going to expand the spent fuel capacity in the spent fuel building. Typically, they're covered by tech specs if they even come close. FPL will submit action to address it. MEMBER POWERS: It strikes me that the way you have approached storm surges is a bit different than we usually approach natural phenomena, especially when you're prognosticating for another 30 years or so. Don't we usually say what's the probability of storm surges of various elevations over that period? MR. MEDOFF: Not being the expert in that area, I'm not going to say yes or not, but I would expect that to be the case. MEMBER POWERS: Taking particular incidents since it got to 17 feet, it could get to 20 feet within the last 100 years we've had as high as 20 feet and this is at 23 feet strikes me that you're very close and I certainly listen to people, not too intently, that tell me that the weather is such that hurricanes are going to become more vigorous in the future. I know that despite the prognostications last year was a particularly hurricane deficit year, so maybe their predictions are not too good. But it strikes me that you need a little more quantified treatment of this. MR. AULUCK: I think the design of Turkey Point can handle Category 5 hurricanes. Steve, do you want to add? MR. HALE: Well, one, I think this is beyond Turkey Point, I mean if the issue is that historically in establishing your natural phenomenon and what you address in your SAR, you go back, I believe 100 years or something like that and then you establish some conservatism on top of that in the design of your structures. We are fully confident in the design of our structures of accommodating our design basis hurricanes which had margin well above 100 year storm that was identified. So I believe that in considering storms in the future, would be more in the generic arena than I would a specific Turkey Point issue. MR. AULUCK: So, in conclusion, we have completed our review. As I understand we owe you information on the documentation, how Region 2 closed the issue on voids. It's available. It's just a question of getting it to you. The staff recommendation will include the resolution of the SBO issue and applicant has met all the requirements required by 54.29. VICE CHAIR BONACA: So mean the second bullet is not correct, of course, at this stage. I mean there's one open item and we will -- MR. AULUCK: All open items identified in the SER were resolved. This is a new emerging issue. VICE CHAIR BONACA: You're right. MR. AULUCK: It just came last week and that's why I made a separate bullet in the staff recommendation. VICE CHAIR BONACA: Thank you. Any further questions? MR. KUO: And this concludes the staff's presentation on Turkey Point license renewal application review and we will take two actions back. The first one is try to put together the paper trail on the concrete voids inspection from Region 2. We will try to get as many copies as we can. The second action is to check the CDF and LERF values for the containment. VICE CHAIR BONACA: There's a third one which is the station blackout. MR. KUO: Station blackout. We issue the staff position on April 2nd on station blackout and the issue has been there for quite a few months. We have issued the first station blackout proposed position back in November of last year. Since then we have met with NEI and the industry three times and this position was supported by the NEI and the industry. VICE CHAIR BONACA: On the other hand, the staff was present during the walkdown of Turkey Point and the demonstration of the alternate path and there was no mention that this requirement would come up, so I think it's important for us to review it to understand if the requirement is appropriate. MR. KUO: Sure, sure. VICE CHAIR BONACA: Because I was very convinced by what I saw there and that it was adequate, so I would like to just -- MR. KUO: I understand. CHAIRMAN APOSTOLAKIS: All right, thank you all. MR. HALE: Just for my own benefit, so I understand these issues. I guess right now the current schedule for the Turkey Point license shows a letter from ACRS by -- what is it, April 19th? MR. AULUCK: The 19th. MR. HALE: And so what I understand that's not going to occur? CHAIRMAN APOSTOLAKIS: It looks like it will not. MEMBER POWERS: Let's make very clear that that's somebody else's schedule. That's not our schedule. MR. HALE: Oh, I'm not -- I'm not -- don't -- just for my own benefit in terms of where we stand with our license review. CHAIRMAN APOSTOLAKIS: There is a probability that it would get it, it went down by a factor of 40 as a result of today's -- (Laughter.) MR. HALE: Is there anything that we can do? Certainly, we can get our hands on the information ourselves with regards to the concrete containment. In fact, I brought quite a bit of information with me today. If there's some way with regard to the concrete void issue, we can resolve it by inspection of the information I have with me. The second item was with regards to station blackout. We met for an extended period of time yesterday with the staff and have come in general agreement to the approach. We also have that information available. And certainly, the CDFs for the plant can be obtained very quickly. MEMBER KRESS: I propose that the Subcommittee Chairman sit down with him and go over that information and see if it's enough to satisfy the Subcommittee Chairman and then he can report back to the full Committee. VICE CHAIR BONACA: There are Subcommittee member concerns, however, raised right here and I want to make sure that we satisfy those. I'll be certainly willing to sit down and review what you have and still there are a number of issues here, it seems to me that put the Committee under pressure to come to a determination when these issues are raised in Florida City, with the exception of the session blackout. And so it concerns me in the months, the elapse of time we haven't been able to find -- CHAIRMAN APOSTOLAKIS: Okay, why don't you then interact with the licensee and report to us maybe at 5:30 where we have some time to discuss this? VICE CHAIR BONACA: I'll do that. CHAIRMAN APOSTOLAKIS: And see how the Committee members feel then about writing a letter. Okay? MR. HALE: I would like for Dr. Ford, too, because he's the one that's voiced concerns with regards to -- if possible -- CHAIRMAN APOSTOLAKIS: Yes. We can do these things. But you have to remember, the letter is from the full Committee. MR. HALE: I understand. I understand fully. I just want to make sure that I have brought information today and anything I can do to facilitate your review I would like to do that. CHAIRMAN APOSTOLAKIS: Certainly. Okay, thank you all very much. We'll recess until 11:30. (Off the record.) CHAIRMAN APOSTOLAKIS: We're back in session. The next topic is Advanced Reactor Research Plan. Dr. Kress is the cognizant member. MEMBER KRESS: Thank you, Mr. Chairman. The staff is diligently working on a comprehensive research plan for advanced reactors. We have a draft, a proposed draft, copy of it which is incomplete. So I guess we could consider this kind of an interim briefing and I guess we're looking for any early feedback from us that we might be able to give them either orally now or perhaps in a letter. So with that minor introduction, I'll turn it over to Farouk. MR. ELTAWILA: Thank you, Tom. You are exactly right that this plan right now is in a very early stage, and as a matter of fact, we have not received the input from the user office like NRR and NMSS, so it's a work in progress and we'll continue to update this plan and we envision that we will be coming to the ACRS at Subcommittee level in the different areas of this program. But for the time being, the staff developed that plan to identify the issues that will be needed to develop the safety criteria against which this advanced reactor design will be judged. The plan is extremely comprehensive and includes a lot of information. Some of this information might already exist through international research that's conducted somewhere else. it is also available through the vendors and the old history of gas-cooled reactors, for example. So the plan should not be construed as research activities that the Office of Research is going to be conducting. As a matter of fact, a lot of the information that describes in the plant would be the responsibility of the Applicant of the new reactor design to try to make the safety case. So we will be receiving a lot of information from the industry on that. But regardless of where the source of information is going to come from, whether it's coming from NRC, from international cooperation or from the vendor or the Applicant himself, NRC will have the best information available to make its regulatory decision. MEMBER LEITCH: If it's not intended to identify research, would it be intended to influence research by the NRC? Maybe identify is not the right word. "Would influence" be the right word? MR. ELTAWILA: Influence research. I really consider it now as a gap analysis to try to identify the weakness or the lack of information at the NRC because we saw it in this advanced reactor, particularly gas-cooled reactor very recently. So we might identify an issue that there have been a lot of research being done somewhere else, so if I call it research or try to make it to influence research, it might be the wrong way of characterizing it. So it's really gap analysis right now and once we collect more information we are going to refine that and find out which part of the research would be provided by the industry, which part will be provided by NRC. Having said that, one more issue that the Office of Research, even though if the utility or if the vendor provide information research data to support their safety case, the Office of Research will be conducting confirmatory research to try to go beyond the information that's usually traditionally provided by Applicants like poking into the area of severe accident source term and the issue that not traditionally being addressed by Applicant and licensee. MEMBER LEITCH: So the operative word is "by the NRC"? In other words, you're identifying research that needs to be done by someone. MR. ELTAWILA: By someone. And eventually we'll try to narrow down to the research that will be done by the NRC. MR. ELTAWILA: Okay. MEMBER FORD: Can you put a quantitational thing on "eventually"? When are these decisions going to be made? MR. ELTAWILA: I think this decision -- we are supposed to go to the Commission in the fall of this year so we are planning to form inter-office task groups to look at the information in the research plan, identify which part of this information would be provided. The NRC is going to ask the vendor and Applicant to provide and then decide after that the balance of that will be performed by NRC and finalized that in the fall and send it to the Commission, of course, after coming to you here. MEMBER FORD: So there will be several meetings with the ACRS to comment on the various points along that time line? MR. ELTAWILA: That's correct, yes. CHAIRMAN APOSTOLAKIS: By fall? MEMBER KRESS: Oh yes, we will several by fall, yes. MR. FLACK: I think what's envisioned is that we would come back at least once to the Full Committee before we go to the Commission with the plan. And then Subcommittees as we feel are necessary or as the Committee feels necessary. CHAIRMAN APOSTOLAKIS: Maybe you need a better title though. When you issue a report that says "Research Plan" it seems to me most people would think research to be done by the NRC. Usually, these are technical issues. They need resolution before you license them. MR. ELTAWILA: George, I agree with you, but we are -- are embarking on an area here that we really don't have too much experience, especially in the gas-cooled reactor. We don't have much experience and we have, for example, we are having a hard time getting information from the international community. So the information might be out there, but we might still have to do the research because we are unable to get this information. CHAIRMAN APOSTOLAKIS: No, I understand, but I think the title of your report should be advanced reactor technical issues. MR. ELTAWILA: Information needs. CHAIRMAN APOSTOLAKIS: Yes, information needs, something like that. MR. ELTAWILA: We can change that. CHAIRMAN APOSTOLAKIS: Instead of Research Plan. MR. FLACK: Well, the reason why it's a plan is we're trying to build an infrastructure. CHAIRMAN APOSTOLAKIS: But you cannot plan for other people, John. MR. FLACK: No, no. I understand. That's when we exercise the plan. The plan is to build the infrastructure and then part 2 is well, we're getting a license application that at some later date we're prepared to support the licensing office in that area. So we have a plan to try to establish the infrastructure that will support the plan. CHAIRMAN APOSTOLAKIS: If you change the title you will not need a separate color for that bullet over there. MR. ELTAWILA: We'll change the title, how about that? Really, it's not a big issue right now. CHAIRMAN APOSTOLAKIS: The second bullet there, you know, why do you feel that you have to say that? Isn't that sort of understood that the Applicants are responsible for data? MR. ELTAWILA: It is -- well, traditionally, the NRC have been generating the data for all plans, you know, before the 1990s and things like that. The NRC generated all the thermal hydraulic database, all the severe accident and the fuel. So right now we are entering our strategic plan, put the burden on the industry for providing the data that's needed to justify the technical basis for the licensing of the plant. So it is important to identify that so people when they read the plan, they don't think that we are -- whatever we're going to call it, they are not going to reach the conclusion that NRC is going to do this work and then they will sit and not do any of the work themselves. MEMBER KRESS: I think that's worth saying. CHAIRMAN APOSTOLAKIS: But you also have a sentence in the actual report. I don't know if you want to come back to it, but where you say it is also recognized that an Applicant of a new reactor design has a primary responsibility to demonstrate the safety case of the proposed design. MR. ELTAWILA: That's correct. CHAIRMAN APOSTOLAKIS: And later on, you use a variation of this as well. It wasn't clear, I mean somehow it sent a message that we are really not part of this. We are setting the standards, aren't we, the criteria and the objectives. It's their responsibility to demonstrate they comply with the criteria, but not -- what does it mean to demonstrate the safety case? Are they going to also set the criteria? MR. ELTAWILA: No, no. I think it's very difficult to put everything in the first bullets, but if you go a little bit further in our discussion you will see that one of our responsibilities is to develop the data to set the safety limits for this plan. CHAIRMAN APOSTOLAKIS: Sure. MR. ELTAWILA: So that will be our responsibility. It's not going to be Applicant responsibility or anybody else. CHAIRMAN APOSTOLAKIS: Okay, but I think in the report it should be made clearer, because that was something that struck me when I read it. MEMBER KRESS: But when it comes to deciding what data and research that the Applicant needs to provide to you, do you have some sort of firm criteria for how to pick out of this comprehensive document so these are your guys and these are confirmatory and they're ours. Do you have a way to decide that or is that just going to be judgment? MR. ELTAWILA: I think it will be a lot of things: experience, judgment and our interaction with the user office about what are the information that they want independent capability from the staff to be able to do their job. And our own initiative in the Office of Research about how to build that additional infrastructure to be able to ask more intelligent questions from this Applicant and licensees. So it will be a combination of the three and the way we have developed this information and the past will play a major role in deciding which part will be ours and which part will be the Applicant's. But in the past, Applicant tends to focus on the operation of the plant. They have a safety envelope that they work within the safety envelope and they will provide the information to satisfy that need only. NRC wants to go beyond that and to try to challenge the system in a different way and we will generate the information for that. Although the plan itself is for AP-1000, IRS and GT-MHR and PBMR, you will see that most of our discussion will be on high temperature gas-cooled reactor because that's the area we don't have much information about. CHAIRMAN APOSTOLAKIS: Do you have sufficient information on IRIS? MR. ELTAWILA: Okay, IRIS, let me -- IRIS, we have very limited interaction with Westinghouse so it's not really a major part of our activities right now. The other points that I want to make is that we -- Jim Lyons from NRR and I attended a meeting with Framatome and Framatome is proposing to submit SWR application. So -- SWR -- honestly, I tried to look in the vu-graphs to find what -- simplified water reactor or something like that. MR. LYONS: This is Jim Lyons from NRR. It's the SWR 1000. It was designed by Siemens from Framatome and Siemens are now together. It's a plant that's being considered to be built in Finland. They're also looking at coming in. That would be a BWR design that they're thinking about. They're also exploring whether or not they'd want to come in with the EPR which is European Pressurized Water Reactor. That's another one that they're thinking, they're considering coming in with for design certification. CHAIRMAN APOSTOLAKIS: Now the SWR is not the same as the SBWR? MR. LYONS: No, it's not. It is a boiling water reactor. It was -- MR. ELTAWILA: It's almost the same principle, but it's different. So again, we're going to change our plant as Jim indicated. They are coming. They want certification. Next year, they submit application. They are serious about submitting application. We're having a meeting with them. MR. LYONS: We're meeting with them on -- they're going to present these two basic designs and they're trying to understand the design certification process and to make a business decision on whether or not they want to come forward. MEMBER ROSEN: This raises the whole question in my mind of how you pick the things that you need to get researched, however you get them researched. Because I was astonished in reading your report that the Generation IV program of the Department of Energy isn't mentioned until the 111th page which is the last page. CHAIRMAN APOSTOLAKIS: Because they couldn't do it after that. MEMBER ROSEN: Because they could not do it after that and still mention it. And in that program which is a very vital program with lots of effort going into it, hundreds of people working on it, many of the concepts that were just mentioned and lots beyond that are being considered seriously to be down-selected for development of a roadmap and some research, significant amounts of research from the Department of Energy. I know John Flack who's with you. He's aware of these things and has attended many of the meetings. So I would ask you why don't you even reference Generation IV in this report? MR. ELTAWILA: That's a good question. We are keeping informed with what's going on in Generation IV, but it's a Commission direction. The Commission directed the staff to work with this applicant at this time, and that's why we defined the work that will be needed for these four applications that we have, even though IRIS is at the very early stage. So we get guidance from the Commission about what to work on and what not to work on, and for advanced -- for the Generation IV to continue to interact with DOE, we're keeping abreast of what's going on, and we keep the Commission informed with what's going on. And once the Commission feels that the staff should be engaged in this process, I think the Commission will direct us to be working in this area. MEMBER ROSEN: I think perhaps the committee -- our committee ought to discuss this point. CHAIRMAN APOSTOLAKIS: It wouldn't make any difference, though, Steve. I mean, they are trying to be as general as they can. I mean, look at the very -- the penultimate arrow there. The regulations will be technology neutral. I mean, if they mention Generation IV on the second page, would it make any difference to what they're proposing? MEMBER ROSEN: Well, I think it would make a great deal of difference. CHAIRMAN APOSTOLAKIS: Really? MEMBER ROSEN: Oh, yes. CHAIRMAN APOSTOLAKIS: They are trying to be technology neutral. MEMBER ROSEN: Well, but I do think you have -- CHAIRMAN APOSTOLAKIS: Yes. Well -- MEMBER ROSEN: -- ever do that. CHAIRMAN APOSTOLAKIS: Then, they will have, they say, Regulatory Guides. MEMBER ROSEN: No. CHAIRMAN APOSTOLAKIS: So they will not have -- MEMBER ROSEN: For example, this report includes -- a third of the report is on the research to support nuclear materials, NMSS activities. The Generation IV program will be -- if it continues to evolve the way it currently is, will include a major research track on sodium-cooled reactors, but the fuel cycle of it mostly. CHAIRMAN APOSTOLAKIS: Yes. MEMBER ROSEN: With an emphasis on fuel cycle research. And that's not mentioned at all in this third -- last third of this 111-page report. And it would seem to me that it would be a major thrust of the nation's going-forward activity. MEMBER KRESS: Well, I think Farouk -- MEMBER ROSEN: So my basic -- MEMBER KRESS: -- I think Farouk appropriately answered, though. They've got constraints on what this report is supposed to look at, and it doesn't include that. MEMBER ROSEN: Right. And I'd say if those are the constraints that they were asked -- that they were working within, because the Commission directed that, then, well, that's certainly what they have to do. MEMBER KRESS: Sure. MEMBER ROSEN: But we can advise the Commission that maybe they ought to be thinking about some broader issues. MEMBER KRESS: Well, that's -- I think that would be another issue, another thought. MEMBER ROSEN: I'm not faulting them. I'm just -- MR. ELTAWILA: No. I think we encourage the committee to think about the reality of the budget situation, and things like that. We have to -- even that we are encouraging NEI and the industry to come with identification of what's really their priority. You know, if it is going to be AP-1000, PBMR, GT-MHR, we really need to get clear guidance from the industry about what's important, what's definitely going to be submitted for certification, and has a chance of continuing with the application here for review, because, as you can see from the report itself, the amount of information that needs to be gathered is tremendous. And given the staff limitation and even contractor availability and test facilities, and things like that, we need to plan in a much better structured way than trying to address everything at the same time. MEMBER ROSEN: I think there are major strategic issues that need to be addressed, and that one of them comes out of what you just said, which is wait for the applicant to come and then we'll get ready. I'm not sure that's the only way that research should get defined, and we can discuss that more in the committee. MEMBER KRESS: Yes. But surely you want to give priority to things you know are going to come in for certification, or at least you suspect very soon. So, you know, you can't -- if you've got a lot of stuff to do, you're going to focus on the ones that you need first. And I think that's what they've done. MEMBER ROSEN: Well, they've done what they were told to do, which is a good thing to do -- MEMBER KRESS: Yes. MEMBER ROSEN: -- when you work here. (Laughter.) MR. ELTAWILA: Okay. With the -- I think George alluded about to the new regulatory structure that we should be looking at. For example, some feature of the PBMR is not really covered by current regulation because -- which is developed for light water reactor. So Exelon has proposed a risk-informed approach towards defining the license basing event to supplement the current regulatory structure. And we are planning to build on Option 3, and that's why Mary is here, build on Option 3, try to provide -- maybe we need to develop additional supplemental risk metrics for the other type of reactor, and at a very high level for what criteria this design should mean that we can be technology or reactor design neutral. And then, in the specific Regulatory Guide, we'll try to see how well they should be measuring against meeting the acceptance criteria, and we'll provide that for each type of reactor, a Reg Guide or a set of Reg Guides to address these acceptance criteria. The overall objective of the research plan is to, as I mentioned earlier, to determine the critical information that is needed to establish the safety standard new reactor design is going to meeting. That's NRC responsibility. Although that we might get some data from the licensee -- from applicants, we have the major responsibility of developing this data. Again, another issue -- the issue of uncertainty, we are planning to explore uncertainties in this design and this information, and that's the responsibility of NRC. And, finally, is the issue of developing independent analysis tool and give the data to assess this tool. CHAIRMAN APOSTOLAKIS: Now, the uncertainties. You have in mind something, NUREG-1150? That's the only place where I've seen large uncertainties handled. MR. ELTAWILA: I think we will be looking at something like NUREG-1150. CHAIRMAN APOSTOLAKIS: With expert opinion elicitation and doing something about it and -- MR. ELTAWILA: For some of this new design which we're going to have, much of the experience or much of the data, that we will have to look into expert opinion. And you can -- maybe when John discusses the issues of fuel you'll find some of this in his discussion. I don't know if you were planning to discuss it. Again, because of the -- we are going to rely a lot on cooperative agreement, although we have been having difficulty entering into some of these agreements, but there is work in China and Japan, European community, and we are looking for cooperation of the Department of Energy to do some testing in the fuel area. I want to conclude my brief presentation here by saying that we looked at Dr. Powers' trip report. I think Dana identified very important technical and policy issues that the Commission needs to resolve before we can say this type of PBMR in particular is -- can be certified or not. CHAIRMAN APOSTOLAKIS: Did you find that report -- MR. ELTAWILA: So the issues are very important. CHAIRMAN APOSTOLAKIS: Did you find that report clearly written? (Laughter.) MR. ELTAWILA: If you heard Commissioner McGaffigan say, it's plain language, you know, and he was looking for something from us to say the same thing. But, unfortunately, he also admitted that our concurrence process will not allow me to write something like Dana Powers writes. So -- (Laughter.) CHAIRMAN APOSTOLAKIS: Well, it's not that -- I'm not sure this committee would think about -- (Laughter.) Yes, he certainly speaks with sufficient clarity and volume. (Laughter.) And volume. MR. ELTAWILA: Well, they are very important issues. We identified these issues and sent them to Exelon, and we are in the process of gathering information about it, and we actually use this information in the development in our research plan. In addition to Dr. Powers, we received other comments from Dr. Murley, for example, and all of this information is factored into our plan. CHAIRMAN APOSTOLAKIS: Now, why did -- I sense that you have some problems with international -- not problems perhaps, but you are not -- it's also clear how you're going to get information from the international efforts. Why do you need to understand the status? I mean, you send somebody there, you understand it. What's the problem? They are reluctant to give you information? MR. ELTAWILA: When you -- there is reluctance -- I think, for example, the European community is -- their system of working the everybody do -- does research, and the shared information -- there is no exchange of money. So for us to try to get information from the European community, we'll try to get consensus from all of the members of the community. And you know that that's extremely difficult, to enter into an ongoing program right now to try to get information. So each country has said yes or no to sharing information with NRC. When it comes to China, it is just -- we have limitations through the State Department and things like that about what level of interaction we're going to have with them. Japanese, again, the organization -- so it's just -- in a nutshell, it's not that easy. Yes, we're sending people to go and meet with them. We've been exchanging e-mail. We meet with them. And it sounds very promising, and it looks like we are on the right track, and we are going to get the information. But, unfortunately, nothing has materialized up to now. We have not signed a single agreement with any of these countries. You know, that's one of the most frustrating parts of this activity right now. MEMBER FORD: And do you have a backup plan should those agreements not take place? MR. ELTAWILA: Our backup plan is to go to the Commission and say, "We will have to develop this data, all of it, ourselves." And which I think that will be -- will put some of this, like the PBMR schedule, in jeopardy because some of these data are very crucial for -- CHAIRMAN APOSTOLAKIS: Do they have any incentive to cooperate with you? Is there any benefit to them? MR. ELTAWILA: The benefit is that we definitely -- we are going to be doing research, and we'll try to exchange the information. It's just government-to-government communication and the exchange of information is not that easy as a lot of people think it is, you know, including our Commissioner. Our Commissioner believes that we should have had all of these agreements signed by now, but it's just not happening that fast, you know. CHAIRMAN APOSTOLAKIS: It's still not very clear to me, but, anyway, let's go on. MR. ELTAWILA: Okay. With that, I will ask John to complete the presentation. MR. FLACK: Okay. My name is John Flack. I'm the Branch Chief of the Regulatory Effectiveness and Human Factors Branch, which also has the advanced reactor group. I know we're time limited, and Farouk covered a number of things, so I will briefly -- I will go quickly through the viewgraphs. And please slow me down if you need more information. CHAIRMAN APOSTOLAKIS: Don't worry. MR. FLACK: The plan was actually created with a number of -- CHAIRMAN APOSTOLAKIS: Does this committee have a reputation that it does not ask enough questions? Because every speaker who comes here encourages us not to hesitate to interrupt them. (Laughter.) Do we have a record of not interrupting? MR. ELTAWILA: For the record, I did not ask you to -- CHAIRMAN APOSTOLAKIS: Is our image so terrible that -- (Laughter.) MEMBER POWERS: We're very shy. (Laughter.) We're tiring. CHAIRMAN APOSTOLAKIS: Okay. John, we appreciate your -- MR. FLACK: Okay. CHAIRMAN APOSTOLAKIS: I know it was well meaning. MR. FLACK: Thank you. The plan itself had been created by -- over 20 authors actually wrote parts of the plan. Many of them you'll find in the room today, so what I'm -- I'm offering you an opportunity, if there's anything technical that you want -- you've seen in the plan or you hear here today, we have the people here that -- CHAIRMAN APOSTOLAKIS: Would you please introduce your colleagues? MR. FLACK: Oh, I'm sorry. Mr. Rubin to my left. Stu has been the -- in addition to work in the fuels issue on the HTTR, he is also the project manager on the pebble bed reactor. CHAIRMAN APOSTOLAKIS: Okay. MR. FLACK: And Joe Muscara to my right prepared most of the material and the plan on materials, primarily high temperature materials and graphite. Don Carlson also works in our group and has prepared most of the material on the nuclear analysis part of that, for both material and reactor safety. CHAIRMAN APOSTOLAKIS: Very good. MEMBER KRESS: When I read the plan -- by the way, I like the way it's organized. MR. FLACK: Oh, good. MEMBER KRESS: Yes. It makes it very, very well put together to know what the issue is and what it -- but when I read it, most of it sounds like it was written by one person, except when you get to the materials part that sounds like -- a little different. But did one person write most of that? MR. FLACK: No. Actually, well -- MEMBER KRESS: It was put together by a bunch of people, huh? MR. FLACK: We tried to establish a certain format I'll cover in a minute, but I'm trying to get that information out. But what was important about the development of the plan is we didn't want it to be issue driven; in other words, try to figure an issue and then what research you need to resolve the issue. What we were really focusing on is the infrastructure, the ability to ask the right questions. And so we started -- well, I'll get to it, but we started from that perspective, what are the tools, what is the expertise that we're going to need, rather than try to identify issues. But, in the end, I do have viewgraphs on some of the issues we see already -- technical issues that could bubble up to be safety issues, that could bubble up to be policy issues -- and we'll go through that towards the end. Farouk went over many of the objectives of the -- the reason why we put together the plan. Some of these I've just summarized on this viewgraph, trying to identify the areas, the expertise, having the plan as a communication tool, so people understand what we're trying to achieve. MEMBER ROSEN: But wait a minute. Now, it's not to build an advanced reactor research infrastructure. It's really to build an advanced reactor research infrastructure for three or four selected concepts. MR. FLACK: That's right. The scope is there, it's only limited -- the scope of the plan right now is limited to the four concepts that we have on the table. MEMBER KRESS: You should read advanced reactor as these four concepts. MR. FLACK: That's right. That's right. CHAIRMAN APOSTOLAKIS: And also -- MEMBER ROSEN: Which may change tomorrow if somebody else brings another concept in with an application. MR. FLACK: Well, the idea is to see what we'd need to do. We have an infrastructure in place. It's what additional work or additional tools above and beyond what we have already. So with these four concepts coming in, we already see that we're going to need new data, additional tools, and at that -- we're looking at it from that perspective. If another concept came in, we'll have to see what tools can be applied to that concept. And if there needs to be something new developed, then we would take it from there. MEMBER ROSEN: But, as you know, there were something like 19 concept sets in the DOE Generation IV program, which really meant that there were something like 75 or 80 concepts that were looked at overall. So there's lot of concepts out there. MR. FLACK: Right, right. MEMBER ROSEN: Some day -- so you need a program that -- a thinking process that sets you up to be ready to respond to whoever comes in with whatever concept. MR. FLACK: Well, you have to have that -- MEMBER KRESS: You can't do that for all of them. I mean, you just don't have the resources. MEMBER ROSEN: What I think is the list of the four has some of the things that we might have to work on in the next decade, but it certainly doesn't have all of them. MEMBER KRESS: Well, it probably encompasses a good many of them. MEMBER ROSEN: But it would be clearly a mistake to believe that because the Commission has picked those four that that's all that will ever be brought to the table here and -- CHAIRMAN APOSTOLAKIS: From 4 to 80 is a factor. MEMBER KRESS: Yes, but I don't think -- to think in terms of which ones of these others might make it to NRC, and then try to prepare -- MEMBER ROSEN: No, but you don't have to think about it. You can just simply ask -- go out and see what people are doing. MEMBER KRESS: Well, I think their comment that they try to -- try to make the -- at least the acceptance criteria in the regulations reactor type neutral is a good way -- is a good thing to do to anticipate that. MEMBER ROSEN: It is. I agree with that. CHAIRMAN APOSTOLAKIS: Now, the overall objective, is it really to build an advanced reactor research infrastructure, or is it to build the infrastructure that would allow you to license advanced reactors? MR. FLACK: Now, there's a distinction between the infrastructure, one being called regulatory infrastructure and one called research infrastructure. What we're talking about, at least aside from the framework, we're really talking about research infrastructure. CHAIRMAN APOSTOLAKIS: But the objective ultimately is to support licensing. MR. FLACK: That's right. Which will get us through the next phase of this plan that -- CHAIRMAN APOSTOLAKIS: So that's what you should say, actually, right? I mean, to build an advanced reactor research infrastructure, why? This is a regulatory agency here. MR. FLACK: Well -- CHAIRMAN APOSTOLAKIS: Only to the extent that it's required for licensing. We've been told by the Commissioners many times, they have said it in public, this is a regulatory agency. MR. FLACK: That's right. CHAIRMAN APOSTOLAKIS: It's not the National Science Foundation. MR. FLACK: That's right. CHAIRMAN APOSTOLAKIS: So the overall objective probably needs to be reworded. MR. FLACK: Yes. And it's driven a lot by regulatory needs. CHAIRMAN APOSTOLAKIS: Of course. MR. FLACK: In fact, that was my next viewgraph was to say, where are we going on the second phase of this plan? If I can jump to that, we can -- CHAIRMAN APOSTOLAKIS: Of course you can. MR. FLACK: -- talk to that issue a little bit more. The first phase of the plan was really to get out everything on the table as -- that we know it today, with no constraints to resources, and so on. And so we held workshops, we had the preapplication review to capitalize on, we had talked -- we went around the world looking at what was out there. So we're coming to the end of this first phase, and, actually, with this meeting, which will be the second phase of this research plan. And the second phase of this research plan is really what focuses on that particular issue that you just brought up, George. It's to set up working groups with the user offices now that we've seen -- and we gave everything -- put everything out on the table. What is it that we really need to do now? CHAIRMAN APOSTOLAKIS: Yes. MR. FLACK: Okay? And that's going to be the next phase, and we see this phase coming to completion. The next time we come to the committee we would be more focused on that particular issue of supporting the process, the regulatory process in the global sense, and then going to the Commission with that plan at that time. And then, the third phase is really to maintain it a living plan, to pick up new designs as they come in, see what delta needs to be done, what new tools we need to develop, and to state engaged in that Generation IV activity, to see if these things are materializing to the point where we need to start getting serious about something. MEMBER FORD: Now, how does the prioritization judgment come about? Given the fact that your resources are undecided, management resources like collaborative agreements, people, dollars. That's not a fixed amount right now. So your prioritization is going to presumably change with time, isn't that correct? MR. FLACK: Well, I think Farouk might want to -- MR. ELTAWILA: No. I think the -- our budget and resources has been established for the next three years, you know, that at least to -- our 2003 budget is fixed, and 2004 and 2005 is proposed to the Commission. And we will try to prioritize within these budget constraints. And if we're going to be using the same PPM process, and we'll be competing with other operating events that depends on the priority, we'll be funding this research based on the available budget. MEMBER FORD: No, I recognize that. That's how you're going to spend your money on your people and subcontractors. But what happens if one of the priorities that -- technical priorities -- work on graphite, for instance. MR. ELTAWILA: Okay. MEMBER FORD: That work has been done in Britain, for instance. And what happens if the Brits decide that they don't have to give you that data for whatever reason? What happens? MR. ELTAWILA: The first point, that we are going to be asking the applicants to provide us for the data to support their case, and then based on the information we're provided we'll see what additional information we will be -- we need to develop ourselves. MEMBER FORD: Okay. MR. ELTAWILA: It is not very easy for a regulatory agency to try to develop a research program. It has to be issue-driven, as George indicated, that we -- everything has to be related to the licensing process that we are working on. CHAIRMAN APOSTOLAKIS: I think the overall objective should be reworded to reflect that. I mean, I appreciate the phases, but you said overall objective. MR. ELTAWILA: Okay. CHAIRMAN APOSTOLAKIS: Ultimately, that's what you're going to do. MEMBER KRESS: I think it's implicit in everything already anyway. CHAIRMAN APOSTOLAKIS: Another thing I noticed when I read the report is that you list everybody's workshops except the ACRS. Was there any reason? Did you find it useless? MR. FLACK: No. There's no reason why we missed that. That was an important oversight. Thank you. CHAIRMAN APOSTOLAKIS: Maybe it was not very useful to you. MEMBER POWERS: Maybe they just didn't like our -- CHAIRMAN APOSTOLAKIS: That's I thought, too. MEMBER POWERS: Nothing useful emerged from it. (Laughter.) CHAIRMAN APOSTOLAKIS: You list everybody's workshops, the dates and this and that. Of course, it will never bias our views, but -- MEMBER ROSEN: You're too sensitive, George. CHAIRMAN APOSTOLAKIS: I am not too sensitive. I'm just sensitive. (Laughter.) MEMBER LEITCH: The second bullet is -- CHAIRMAN APOSTOLAKIS: Commissioner Diaz was there. He gave the keynote speech. Maybe the staff doesn't think much of what the Commissioner said. MR. FLACK: I think if -- you'll find -- I'm sure I've seen it in there somewhere. CHAIRMAN APOSTOLAKIS: It is not here. John, it is not here. MR. FLACK: It might have got scratched the last time. I don't know. (Laughter.) MEMBER LEITCH: The second bullet there, Johns, is there some reason the AP-1000 is not on that list or -- MR. FLACK: No, that should really be on there. It was for examples, and I was -- MEMBER LEITCH: It says "for example," and I was just wondering if it -- MR. FLACK: Yes, they're all HTTRs. I should have put a light -- yes, a light water reactor on there. Yes. MEMBER ROSEN: There's an astonishingly pervasive gas reactor focus on this, because of the -- MEMBER KRESS: Well, you're almost through with the AP-1000 preapplication review anyway. MR. FLACK: Yes. The preapplication is done, in fact. I think the -- MEMBER KRESS: Is that correct? MR. FLACK: But most of the gap that we see is in the high-temperature gas-cooled area, so, you know -- but we have an infrastructure in place pretty good for a light water reactor. Okay. I think we pretty much touched upon this. The meaning on infrastructure, again, is the staff expertise, the tools, the facilities, contractor support, and the scope being the four reactors as we see it today. And the structure -- and, again, we built the structure around not the issues themselves but on the technical areas, which you'll see in a moment. MEMBER POWERS: John, before you take that down, let me ask you a question about technical approach on this. The second item on your list there is called analytic tools and analysis methods. And one of the challenges that we repeatedly come up with when we look at things connected with current reactors and modest changes to those current reactors, like the AP-1000, is that many, many, many of our analytic tools going from simple neutronics through thermal hydraulics to fission product release had their origin in an era when the computing capabilities that people had were widely different than what it is now, and probably we'll see in the next 10 years even more dramatic changes. Yet your plan doesn't seem to act upon those things. I mean, it doesn't seem to take that into account. There is lots of things like, well, we can take TRACM and put another patch on it, we can take MELCOR and gerry-rig it to handle something else, rather than saying, "Hold it. We really have undergone a computer revolution here." The way we do computing, the way people do coding now, it's just very, very different than what it was when our codes had their origin. Maybe it's an opportunity for us to bring our codes up and to recognize that the hardware has just changed, and what not. But your plan didn't seem to delve into that kind of an approach. MR. FLACK: You know, it's an excellent subject for a subcommittee, I think, to revisit this particular issue. You're right. We're really building on things that already have been developed and seeing where we're going to -- how can we extend them rather than go back to -- you know, and look and see is there a better way of doing this. And I think it's an excellent question. We just -- just built on what we have. I know TRACM is improving, of course, has come quite a way from -- just in the Fortran part of that. But as far as starting with something new -- and this may be an opportunity to do that for these gas-cooled reactors, where you may have one code, because of the nature of the beast, that you don't have the core melt and the accident progression and that -- you have a fission product release over time and temperature and using one code to deal with the whole spectrum, right out into the environment, might be a way to go. MEMBER POWERS: One of the things that it seems to me that -- you know, in trying to think about the future, and you put it right up front in your plan, you say, gee, you know, we're going to move to a probabilistic risk assessment kind of framework. And whereas I -- I know for a fact that a lot of our probabilistic risk assessment tools are kind of patchwork things. They work pretty well until you get to the questions of, gee, let's do some of these deterministic analyses for a bunch of scenarios. And then we run into a problem that our codes are fairly archaic. And if somebody wants to run 150 MELCOR sequences, for instance, you know, you're -- and that's an enormous number for a probabilistic risk assessment; 150 is actually a fairly modest number. You really are buying yourself a pretty big chore here. So if you -- you know, if you were looking to say I want to make bigger use of probabilistic techniques in my licensing process, I want to have more assessments of them, I want to take that probabilistic technique deeper into the accident sequences, rather than just looking at Level 1 I actually want to go deeper into Level 2, and things like that, then my phenomenological tools, both thermal hydraulic and structural techniques and things like that, have to be better. You might really come to the conclusion that you need to invest some in your tools, and that's regardless of what goes on in DOE land or in the vendor's land, that you really do need to encourage the Commission to get you the resources to develop your thing. I mean, I guess my thinking on this is that, for instance, the thermal hydraulic area you have some people that are pretty qualified getting TRACM as a consolidation. And that's going to be awfully useful for existing reactors, but I bet you they don't find it very satisfactory for looking at very innovative kinds of thermal hydraulics things where the analyses go, I think as you say in the document, instead of working on time scales of a few hours you're starting to work on time scales of days and things like that. MR. ELTAWILA: John, can I try to address this issue? Dana, you are raising a very good issue. But I just -- actually, our problem is not really the speed of the computer, because you continue to enhance that, and the machine speed itself will make up for the difference. But the biggest problem is trying to develop a code. You have to have a target that this code is going to be better than what we have right now. And we really don't have the data to support development of models that we'll be able to put in this code. So going -- embarking on a code development program, without having the supporting experimental data, will be just a waste of resources. And we face that issue early, you know, when we are thinking about either developing a new thermal hydraulic code versus consolidating the existing code into a single code. And we'll get a group of experts, and they all advise us against developing a code from scratch, because we're going to end up -- the code is going to be slow because of the limitation of the model, not because of the machine. So unless somebody is willing to invest a few hundred million dollars in developing the data to support this fast running code with accurate, better models, I think going into the development of faster code is not going to be the best way we put our money to work. MEMBER ROSEN: I'd like to add that, although it's probably true, that many of the codes that we'd be looking at using in licensing reviews are built on older, previously developed codes. There may be some pockets where there are new codes being developed in the current computing environment. And I would give as an example in the fuel performance area, the European Commission has a high temperature reactor fuels task group in place. And one of the areas that they are doing work in is to develop fuel performance models today. And those fuel performance codes will be developed, obviously, in the current computing environment. Also, INEEL, working with MIT, I believe, is developing fuel performance models and codes to predict fuel failure, etcetera. So there are a few examples at least where codes are being developed in this environment. MEMBER POWERS: Well, I, of course, have come to learn that fuel research is irrelevant, so -- (Laughter.) MR. ELTAWILA: That's the subject of another meeting. (Laughter.) MEMBER POWERS: I couldn't resist. MR. FLACK: We'll move right along on that. Basically, to your comment, Tom, on how we structured the report was around three questions -- why we -- why is it important for us to do this research, what it is we would actually do, and then how would we use the results. And we tried to keep each of the people focused. MEMBER KRESS: And I thought that was very good. It was very helpful in reading it. MR. FLACK: And the research plan structure, which is -- has been developed, and this was developed to sort of try to get the completeness of the work that we're doing. We actually started, again, not from an issue perspective but from the top down, and we began -- well, we started by looking at the arenas that we would be working in as far as research is concerned. Well, as you can see, most of it is reactor safety. We're looking and pressing into these other arenas to see what work can be done, since most of the work that we do involves reactor. So there is some of it discussed as far as nuclear waste and materials safety, and then, of course, safeguards. Again, we're pressing that area. But within the reactor safety arena, we laid out the work more or less along the lines of the cornerstones of safety. And bringing that down further, going from accident -- starting from right to left, accident progression to initiating events, which dictates the sort of scenarios we need to look at as an office on a particular plant design, and then from there -- which actually sets the stage for the rest, coming down to look at accident analysis and what area or what technical work needs to be done in that area. It's primarily driven by the PRA and those things that -- that influence the PRA, like human factors and I&C. And so in these areas PRA was generally that part of the research under Mark Cunningham, as you know, Mary Drouin, and Alan Rubin, and John Ridgely. And on the plant analysis it's primarily the human factors and I&C, which is Steve Arndt for I&C and Jay Persinski for human factors. Moving across from there, from left to right, the next large area is the reactor systems analysis, which is primarily in Jack Rosenthal's branch. And under that being the thermal hydraulics, the nuclear analysis, and the fission product transport work. MEMBER POWERS: You felt that it was -- that the computational tools you have available to you for doing probabilistic risk assessment -- the actual analysis itself, you know, calculating out the probabilities, that those were in such fine shape that they deserve no improvement at all? MR. FLACK: Well, no, I don't think that would be the case. There's really -- I don't know if Mary wants to respond to that, but there's really three areas there in PRA that we see as being -- pushing our needs, and that is initiating event frequency for the high-temperature gas-cooled reactors. MEMBER POWERS: Yes, but those are data things. I'm talking about the actual computational tools. MR. FLACK: Oh, the computational tools? Do you want to comment on that, Mary? MEMBER POWERS: The way you go about doing the analyses. MS. DROUIN: I agree that there is going to need to be some research in the development of some of these tools, particularly in the computational area. And that's -- CHAIRMAN APOSTOLAKIS: But the report I think says that SAPHIRE will be used for the PRA. Isn't that so? That's what the report says. MR. FLACK: Yes, that's right. MS. DROUIN: SAPHIRE is a starting base, absolutely. I mean, I would not like to think we would just start with a clean piece of paper and not take a tool that we already have and see where we can use it, modify it appropriately. MEMBER POWERS: At least through the classical Level 1 for normal operating events, the computational pathway is fairly straightforward, I think, Mary. MS. DROUIN: Yes. MEMBER POWERS: And adequately -- the blocks that you need are adequately there in SAPHIRE, maybe the computational way it's done. The issue, it seems to me, that's been raised so clearly by the eminent Dr. Kress is that that computational framework may not be adequate if we were to extend the way we do PRA from an operational events to include all plant operational states. I think that's a conclusion that has come from your own studies in looking at the other operational events, that the tool you have may not have all of the computational elements you need to do all operational states. MS. DROUIN: I don't disagree. MEMBER POWERS: And as we know, we trust you implicitly, because you're one of my heroes, right? MS. DROUIN: Absolutely. (Laughter.) MEMBER POWERS: I told you I'd get it on the record. (Laughter.) MS. DROUIN: But, you know, when you get into -- there's a lot of technical issues, particularly in the Level 2 when you start looking at the advanced reactors, and this will have a direct impact, then, on the calculational tools we use and where we'll be needing to do some work. And right now we are in the midst of trying to -- when you look at the RES plan, you know, that plan there, when it gets into the PRA part, is very high level. We are in the midst of trying to put together a very detailed plan of what we mean by that three-page plan in the RES-1. MEMBER POWERS: I'd like to see that. That would be interesting. CHAIRMAN APOSTOLAKIS: If I look at this -- MS. DROUIN: We do plan to come to the ACRS with it. CHAIRMAN APOSTOLAKIS: If I look at this figure, I see the acronym -- actually, it's initialism, right? PRA? It's an initialism. Down there on the left. But it seems to me that, you know, again, your report shows that the thinking is really that -- if you look at the out within the four boxes, and so on, you will be looking at the accident sequences all the way from the initiating event all the way to offsite protection or somewhere in between, and use that information in your decision-making processes. And that's PRA, is it not? So it is a little bit misleading the way it's shown there. MR. FLACK: Under "accident analysis," do you mean? CHAIRMAN APOSTOLAKIS: Yes. I mean, it's pervasive. It's -- MR. FLACK: Yes, that's true, very much so. There was another figure in the report that shows these loops of information, how it flows between the groups, which I don't have with me. But you're right, there is always this feedback mechanism, both within the groups and background PRA. In fact, that's the way the office does work. PTS is an example where you bring in, you know, the PRA people with the materials people with the thermal hydraulic folks and -- CHAIRMAN APOSTOLAKIS: Well, the biggest question, really, here would be, how are you going to use the PRA? I mean, right now, in the most important decisions the agency is making PRA is very peripheral. It doesn't really play any role. MR. FLACK: In your regulatory decision- making or the use -- CHAIRMAN APOSTOLAKIS: Yes. MR. FLACK: -- in the -- CHAIRMAN APOSTOLAKIS: Regulatory, like license renewal, power uprates, PRA really doesn't do much there. I mean, it's just, oh, by the way, this is the number we got from the CDF. MEMBER KRESS: And even in direct licensing. CHAIRMAN APOSTOLAKIS: And in what? MEMBER KRESS: Just licensing a plant doesn't seem to play a role. CHAIRMAN APOSTOLAKIS: Well, we're not licensing anybody. That's what -- MEMBER KRESS: Well, we will be. CHAIRMAN APOSTOLAKIS: Yes, that's what I'm saying, that this will be -- MEMBER KRESS: Same thing is the license. CHAIRMAN APOSTOLAKIS: I mean, so that will be a major challenge, I think, how to use that, how to actually use it. MR. FLACK: Yes, we're moving towards the framework box there, I think. CHAIRMAN APOSTOLAKIS: You're going to talk about it separately? MR. FLACK: If you'd like. Do you want to talk about it -- CHAIRMAN APOSTOLAKIS: Do you plan to talk about it? Are you planning -- MR. FLACK: Well, we can talk about it to a certain extent. CHAIRMAN APOSTOLAKIS: Well, that, it seems to me, would be a major challenge. MR. FLACK: Yes. CHAIRMAN APOSTOLAKIS: Because the Regulatory Guide 1.174 doesn't apply here. I mean, that's for changes in the licensing process. MR. FLACK: Right. That's right. CHAIRMAN APOSTOLAKIS: And you don't have a licensing basis here. So it's really using this as part of your integrated decision-making process. MR. FLACK: That's right. It is -- VICE CHAIR BONACA: They show Option 3 as a foundation for this. Option 3 has a very specific apportionment of certain goals -- CHAIRMAN APOSTOLAKIS: I understand that. I understand that. VICE CHAIR BONACA: -- which are really measurement for PRA. So there is some structure that you can put inside here already. MR. FLACK: Yes. But the point I think is that we're dealing with plants already built, and we're applying PRA concepts to those plants in the sense of changes. And now we're thinking, well, what are we going to do with respect to regulatory decision-making on future plants that haven't been built? CHAIRMAN APOSTOLAKIS: Right. MR. FLACK: And that gets us -- I think pushes us into this framework, what do we need? And there's really two pieces going on there. One is this blank sheet of paper starting from a clean approach, which is -- there is going to be work initiated next year, and there's work going on in NRR is -- how do we transition to that? And Mary can talk about the part about the research plan, and Jim Lyons could talk about the NRR approach that's now taking place, from that perspective. So they're coming together in some form. Mary, did you want to -- CHAIRMAN APOSTOLAKIS: Well, you are basing it on Option 3, right? MS. DROUIN: Well, if you remember, the Option 3 framework has, you know, three parts to it. It has -- started with, you know, what we call that hierarchical structure. CHAIRMAN APOSTOLAKIS: Right. MS. DROUIN: You know, a top-down approach. And then, because it is risk-informed, it brings in how you bring in defense-in-depth both at the hierarchical, from the top down and the bottoms up, and then brings in, how do you bring in your quantitative guidelines? And ultimately that is producing the criteria and guidelines that you would be using to help you in your decision-making process throughout your licensing. In terms of your earlier question, you know, the PRA and the framework and -- it's like they're all very intricately tied, and one of the ways that you do use your PRA, you know, would help in your decision-making also in terms of how much research, using that word loosely here, that you would need, because you certainly don't want to pursue an area that, from your PRA perspective, you don't need it to support the PRA, and you don't need it for -- it's not going to help you, and it's not going to contribute significantly to your risk is what I'm saying. CHAIRMAN APOSTOLAKIS: Well, the point, though, is -- I understand what you're saying, Mary. But this is really something that is an ideal situation. I can't imagine, for example, the guys who will be working on the reactor plant analysis and fuel analysis will be willing to take their criteria and objectives from the PRA guys. They will just -- MS. DROUIN: As an input. CHAIRMAN APOSTOLAKIS: That would be one of the angles to their integrated decision-making process which would have, I think, other major, major inputs. MS. DROUIN: Yes. CHAIRMAN APOSTOLAKIS: So the question will be, you know, to what extent will there be -- will the PRA inputs influence that, or they will say, no, you know, defense-in-depth and safety margins is really the name of the game. MS. DROUIN: But that's where you're -- I mean, what we're calling it, the framework or the decision-making criteria comes in and provides you guidelines on that and how you bring in your defense- in-depth, your uncertainties, your safety margins, and your risk insights, and how you blend all of those together in your decision-making process. CHAIRMAN APOSTOLAKIS: Which we don't have right now. We don't have those guidelines right now. MS. DROUIN: That is what we're going to be developing. CHAIRMAN APOSTOLAKIS: Right. MS. DROUIN: Where we're starting with Option 3. Now, you can't just adopt Option 3, because Option 3 is, how do you make current changes? CHAIRMAN APOSTOLAKIS: Right. MS. DROUIN: And so there -- you'd have other questions that you're going to have to answer, because we're not just making current changes, you know, in cases you're starting new. CHAIRMAN APOSTOLAKIS: Right. MS. DROUIN: So when you're starting new, you've got to -- CHAIRMAN APOSTOLAKIS: Well, frankly, I don't know how you can use PRA in light of Davis- Besse. That was, I thought, a major blow to the whole risk cause. I mean, unless we recognize that. I mean, 10-4 means nothing to me now. MEMBER ROSEN: In the case of PBMR, and we believe GT-MHR, they have proposed a licensing approach, which the staff has reviewed. And I think we have briefed the committee on the licensing approach, and it is very much PRA-based, in the sense that licensing basis events are randomized for probability and consequences. And they are put into the framework or approach that they utilize for operational events, design basis events, and beyond design basis events. And I think it would be useful to have a PRA -- the staff to have its own PRA to kind of review those applicant placement of those events within that framework. CHAIRMAN APOSTOLAKIS: But, you know, about I think three years ago or so, or maybe longer, there was a major issue that was raised. I think it was before 1.174 was published. People, especially from the industry, were complaining that PRA was just another burden, that we had to do everything, you know, the regulations said, plus a PRA, to get those additional insights. So if we are to use it now, somehow those other requirements will have to be effective, and maybe some of them should be eliminated. And I -- this is where I think will be a major problem, how to do that, because we're going to have, again, the same philosophical conflict. Okay? And I think the Davis- Besse incident gives arguments to the structuralist defense-in-depth. MEMBER ROSEN: If you're correct, George, that -- CHAIRMAN APOSTOLAKIS: They're about to win me over. (Laughter.) MEMBER ROSEN: I think you would be correct if all 100 plants had that problem. CHAIRMAN APOSTOLAKIS: Hmm? MEMBER ROSEN: If all 100 plants had that problem. We're talking about a plant. CHAIRMAN APOSTOLAKIS: Yes. MEMBER ROSEN: One of 100 or so. So -- CHAIRMAN APOSTOLAKIS: I missed that. MEMBER ROSEN: Well, I'm just responding to your point that the event -- that Davis-Besse invalidates all of the probabilistic thinking. CHAIRMAN APOSTOLAKIS: I didn't say it invalidates, but it creates serious questions in my mind. MEMBER POWERS: George, I -- VICE CHAIR BONACA: It goes back to the proposal. It has a means of filling the gap in the Code of Federal Regulations. I mean, in that sense, PRA has been extremely successful. Here we've attempted to see -- it could play a primary role, in and of itself, rather than defense-in-depth, and that's really where concern comes. Okay? Can it be the first, you know -- CHAIRMAN APOSTOLAKIS: Dana? MEMBER POWERS: Well, I guess I had two points. One, just to respond to Steve, all individual plants have individual peculiarities that can be problems. To your point, George, as one of the more ardent of the structuralists on the committee, I'll tell you that, no, I still think PRA has a -- despite Davis-Besse, and what not, has a really admirable place to play within any kind of reactor system. It's just that it doesn't play in the defense-in-depth argument from a structural point of view. It plays very much in the redundancy, and what not, within systems. I still think it has a strong place to play there, and I think it will be an even stronger place to play in the advanced reactors where we can relieve much more of the ad hoc determinism yet again. CHAIRMAN APOSTOLAKIS: I think unless the PRA guys do a better job on model uncertainty it will not play such a significant role in the process. MEMBER KRESS: I think you're right, George. That'll be a key. CHAIRMAN APOSTOLAKIS: I think the lambda stuff, the log normal stuff, is nothing. It's the model uncertainty that drives the decisions. VICE CHAIR BONACA: I think one thing that, you know, impresses me more and more as we go forth is the -- some of the wisdom in 1.174. You know, the whole concept of integrated decision-making, etcetera, that comes -- CHAIRMAN APOSTOLAKIS: It's an ideal document. But show me one case where it was applied. (Laughter.) There isn't a single case where this beautiful discussion on uncertainty was actually applied. VICE CHAIR BONACA: That's true. You're right. CHAIRMAN APOSTOLAKIS: It's model uncertainty. That's the name of the game. The distributions in lambda don't mean anything, and I don't think we're doing a good job there. I understand, you know, some of the tradeoffs that Dana mentioned, sure, they are meaningful, and so on. But it's really model uncertainty that does the trick. MEMBER POWERS: Well, I bet we see -- I certainly hope we see good uses of it in the PTS stuff. MEMBER ROSEN: In the PTS stuff? MEMBER KRESS: Pressurized thermal shock stuff, yes. CHAIRMAN APOSTOLAKIS: Even there I think there was more promise than actually done. MEMBER POWERS: Well, we haven't seen the final story there. But, I mean, that's -- well, certainly, you can't criticize a program because there's more promise than was actually done. I can't think of any program that that's not the case, so -- CHAIRMAN APOSTOLAKIS: There's no question about it, that it's a pioneering study. MEMBER KRESS: Well, Option 3, though, is still highly focused on light water reactors. It talks about CDFs and LERFs and sequence frequencies that are endemic to light water reactors, and it tends to -- to allocate risk among CDF and LERF and allocate it among sequences, actually. And you won't run into a difficulty when you get to the -- trying to apply Option 3 in that sense to the gas-cooled reactors, because you don't have the equivalent number of sequences, you don't have the same ones, you have a different set of frequencies that are important, and you don't have a well-defined CDF or even a well-defined LERF. And so I think one of the things that you're going to buck up against is you'll need more precision in your definition of defense-in-depth for these reactors. You just can't say anymore that it means a balance between containment and CDF. You're going to have to be more precise, and it's going to have to tie in the uncertainty some way, even though you could still keep the structuralist view. You're going to have to tie in to uncertainties in some way. CHAIRMAN APOSTOLAKIS: Well, that uncertainty has to be a realistic assessment of uncertainties, not just the stuff that's easy to do. MEMBER KRESS: Yes. MS. DROUIN: If you go back to Farouk's slide, one of the things that we have identified in developing, you know, this -- taking the Option 3 framework and, you know, modifying it for advanced reactors, the primary thing was to look at the surrogates of CDF and LERF. CHAIRMAN APOSTOLAKIS: Yes. Yes. MS. DROUIN: And that's one of the critical items there, that those may not be sufficient, and we may need to come up with different, you know, figures of merit here than just those surrogates, and come up with some others. So that's one of the big items that we have ticketed to look at. CHAIRMAN APOSTOLAKIS: Now, coming back to this figure -- oh, I'm sorry. I can understand, and I agree, that this thing, you know, by and large is an effective -- contributing to an effective regulatory process. I just don't know that it's efficient. You say effective and efficient. How do you know it's efficient? MR. FLACK: Well, it's something you strive for. CHAIRMAN APOSTOLAKIS: But how? I mean, if you ask the guys who were developing all of these rules in the late '60s/early '70s, I'm sure what they wanted to do was also be efficient. And here we come 20 years later and say they are not. VICE CHAIR BONACA: I think if you compare it to the existing system, I mean, probably the inclusion of the PRA considerations, the risk considerations, are making it more effective and -- CHAIRMAN APOSTOLAKIS: I'd like to see that happen. VICE CHAIR BONACA: Well, no, because I think in some cases you will limit the -- the necessary burden, okay, that's the only -- I mean, to the extent -- CHAIRMAN APOSTOLAKIS: Mario, you will be told it's defense-in-depth, period. Do it. Okay? It's a new system, we don't know, we don't want to be surprised again. And I think there's a lot to that argument. VICE CHAIR BONACA: Well, we have seen some, you know -- CHAIRMAN APOSTOLAKIS: If in a mature technology we get things like Davis-Besse -- VICE CHAIR BONACA: Yes, I know. CHAIRMAN APOSTOLAKIS: You know, I'm just putting myself in a situation of the poor PRA guy who says, "Your inspections will fail with probability .2 over a number of years." He's going to be crucified. My inspectors never fail. Are you kidding? My inspectors will go there and find it in a minute. Okay? That's exactly what you're going to get. It's the same thing you were getting before 1978. My operators know what to do, and it's always my -- I don't know why they put that "my" in front. (Laughter.) I remember. I was in a PRA, and we said, you know, how about if the operators don't know how to -- VICE CHAIR BONACA: See, but let me just say this. CHAIRMAN APOSTOLAKIS: Are you kidding? They will not know? VICE CHAIR BONACA: Yes. But I don't think we can make too much -- in a Davis-Besse event, we have to learn more. There were a lot of indications for a long time that something was wrong. Now, at some point -- CHAIRMAN APOSTOLAKIS: And where is that in the PRA? VICE CHAIR BONACA: Well, I'm only saying that there is a burden on operations to, in fact, respond to the indications that you have. And in this case, we may have a case where they did not respond for years to this indication, that they had plenty of those. And so I'm saying that you cannot address everything in your PRA. CHAIRMAN APOSTOLAKIS: It seems to me that you will never make progress unless you punish people for the mistakes they make. (Laughter.) The PRA should be penalized now for that. MEMBER ROSEN: The PRA should be penalized? CHAIRMAN APOSTOLAKIS: Well, or the PRA practitioners on the use of the PRA. MEMBER KRESS: You're just going to change -- you're going to change the frequency of medium break LOCAs. That's all you're going to do. CHAIRMAN APOSTOLAKIS: How about the efficient, though? How are you going to make sure it's efficient? MR. FLACK: Well, that was the -- the question is using these risk insights, which you think or believe at this point aren't doing what they should be doing, to utilize those and focusing your resources on the right things and being efficient by doing that. I mean, without that, I don't know, it's just judgment. I mean, I -- CHAIRMAN APOSTOLAKIS: Well, one way to do that is to really put a lot of meat to what Mary just said. I mean, if you start from the top and with a PRA structure you go down and you put objectives, then you know why you are putting them there. But the moment you start saying, "No, I'll do it because of defense-in-depth, then you are deviating from efficiency." MR. FLACK: Yes, it could be. CHAIRMAN APOSTOLAKIS: It may be for a good reason, but -- VICE CHAIR BONACA: I still believe that the use of PRA in many areas where you don't have this kind of grayness is going to really yield much more efficiency. CHAIRMAN APOSTOLAKIS: How do you decide when you have grayness? VICE CHAIR BONACA: Well, I mean, you know, an area, you know -- I mean, certainly you have some indications where you have balance with information and mitigation that you do not want to compromise, and you're going to be very committed to defense-in-depth. There are a lot of decisions, however, in the design of a plant where, you know, the inclusion of consideration of probabilities will help you be more effective and have less of a burden. MR. FLACK: I think in that role of knowing what's not important, I mean, we are always focusing on the PRAs, trying to point out what is important, which is a good thing. But it also points out things that are not important, and for certain reasons, then, justify that. I mean, you have to have a technical basis for it. But, I mean, it's a thinking process that allows you to do that. So, you know, I don't think we should throw the baby out with the bath water, I mean, on this. CHAIRMAN APOSTOLAKIS: You're more optimistic than I am. (Laughter.) VICE CHAIR BONACA: But there was really practical terms. And in the 15 years or 20 years of use of PRA in this approach, it has paid off tremendously for the utilities that use it in those kinds of decisions where you are not only affecting defense-in-depth, but you are making intelligent decisions on imposition of your requirements or elimination of those. And we have seen some proposals that have been approved, and 1.174 -- they were really acceptable, have not been, you know, undermined by the experience with Davis-Besse. VICE CHAIR BONACA: I think there's got to be some efficiency brought in by that. MR. FLACK: Moving right along -- MEMBER KRESS: Please continue. VICE CHAIR BONACA: I'm trying to convince you that PRA is -- (Laughter.) MEMBER KRESS: I can't believe we're having this discussion. Continue, please. MR. FLACK: Okay. So this is the process we use. It's clearly -- it's a matrix approach. We use the entire office resources as input to the plant. Now, the next few viewgraphs I go through and identify the different technical areas. I don't know if we need to spend much time on that. It's in the plan. Those are the areas that are being hit. And that kind of leads us on to what the technical issues are that we're seeing now. Maybe we can, for the sake of time, jump to that viewgraph. MEMBER KRESS: Well, let me ask you a couple of questions about the technical areas first. MR. FLACK: Okay. MEMBER KRESS: You know, you're asking us for -- whether you think you have the right scope or you're missing anything or something. I thought it was very comprehensive. In fact, there's so much in there I don't know how it could ever get done. But there were a couple of areas I was going to ask you about that I really didn't see in there. And one of them was the issue of licensing by test. MR. FLACK: Licensing by? MEMBER KRESS: Test. MR. FLACK: Test. MEMBER KRESS: For PBMR. I didn't see that discussed in there anywhere, and I was thinking there might be a section talking about the -- where would that fit into the regulatory structure at all, if at all, and is it part of the thinking, or is there any research need? Like, you know, research in the sense of how that would affect your decision-making process, or what licensing by test actually means. I didn't see anything on that. MR. FLACK: Well, we have been thinking about it. I don't know if -- MR. LYONS: This is Jim Lyons from NRR again. This is one of the areas that we've looked at. There is certainly the ability within Part 52 to license a prototype reactor, and then you would -- you know, and then you would perform tests on that prototype reactor, and then you could continue on with using that reactor as a way of developing your I guess licensing by test. I don't know if we've really completely looked at how we would do that. One of the things that may happen if we do a license by test or a prototype reactor is that we may put extra features or have -- you know, request extra features be placed on that plant to provide us any, you know, assurance that there wouldn't be any real problems. But it's part of our process. It's something that could be done, but I don't think that we saw any real need in the research area to address that. MR. FLACK: Yes, it's a difficult question to deal with until we actually get a plant in as well. MEMBER KRESS: Well, along this same line, one of the issues that is sure to arise with PBMR and GT-MHR, GA, just in general, is how do you know that you actually have the fuel quality that's required when you -- after you load it into the reactor. And one way to do that is what you do with light water reactors -- you look at the level of activity in the primary system, and you infer the quality of the cladding or the quality of the fuel from that. And the question I would have is: isn't there some concept like that being thought of for the pebble bed modular reactor and the others? So that during start-up of the operational phases you can say, "All right. Based on what we see now, you don't have the fuel quality you said you were going to have in your licensing basis, so you've got to do something." Is that part of the plan? Is that in there? MEMBER ROSEN: It's not in there as explicitly as you just described it, but it is in there implicitly. The way I like to refer to it is a defense-in-depth on fuel performance during operation and postulated events. And you can think of that defense-in-depth as building in quality absolutely correctly every time, and that focuses you on the manufacturing part of the process, to look at the process and the product specification, make sure you're doing it right every time. MEMBER KRESS: You would look at process versus product. MEMBER ROSEN: And that's in our plan. MEMBER KRESS: Now we're wanting to look at product, too. MEMBER ROSEN: Okay. Then, look at the products. But before it ever gets put into a reactor and starts operating, then you get to the next defense-in-depth place, which is monitoring operations, and looking at activity and monitoring conditions. The question comes up, though, is that method qualified? Is that method reliable? MEMBER KRESS: Yes. MEMBER ROSEN: Is there data that shows that -- MEMBER KRESS: That's exactly my question, yes. Is there something in the plan that will answer that question? MEMBER ROSEN: Yes. Yes. MEMBER ROSEN: Well, I think you have some advantages here, if you're thinking about pebble bed, that you don't have in light water reactor. You could do destructive examination on the fuel. MEMBER ROSEN: That brings me to the third -- MEMBER ROSEN: And you could afford it. MEMBER ROSEN: Yes, that's right. MEMBER ROSEN: But you couldn't do that in the light water reactor, say, I'm going to destroy this assembly and say, therefore, the other 80 are okay. You know, that wouldn't be -- it wouldn't make any sense. But if you're talking about thousands of pebbles, you can statistically sample them and do destructive evaluation and gain some real confidence as to the quality of the pebbles. MEMBER ROSEN: Right. And that's -- MEMBER KRESS: You can't, because they have to be irradiated. And you're not going -- that's the problem. You've got to run through the irradiation first. MEMBER ROSEN: That's the research issue is how do you identify, from looking at the destructive evaluation of a non-irradiated pebble, how an irradiated pebble is going to work. MEMBER KRESS: Yes. You can't make that judgment. You have to irradiate them, and that's where your statistical problem shows up. You just can't irradiate enough of them to get the right statistics to qualify the level of failure or pebbles that you think you have to have. MEMBER ROSEN: So that's the answer to the research program, Dr. Kress? I mean, I was suggesting that there ought to be a research program to get to that answer. But if you already know it -- MEMBER KRESS: Well, you have to -- you just can't irradiate enough pellets over the timeframe to do that. You can't do it. MEMBER ROSEN: Well, the approach that's taken when you have billions, literally billions, of fuel particles in the reactor is to test hundreds of thousands in a materials test reactor to qualify them, and then, even if you -- MEMBER KRESS: Yes, to the right irradiation level. MEMBER ROSEN: To the right conditions, temperature, fluents, burnup, whatever it is, and even if you have zero particle failures you don't extrapolate if you have zero in the billions. There's a statistic that you can use to project what the number would be. MEMBER KRESS: But it's an extremely difficult task. MEMBER ROSEN: But the question comes up, are the test statistics going to hold true in the fuel that you make later? MEMBER KRESS: That's right, because you're only testing one batch. MEMBER ROSEN: In a sense, that's true. So you need to show that that's going to continue over the life of the fuel supply and the life of the plant. And so you're stuck with, well, how do I then monitor later on fuel that's coming off the assembly line and put in the reactor? MEMBER ROSEN: Well, these are good questions. MEMBER KRESS: But you're saying that's implicit in -- MEMBER ROSEN: Yes. And if you look at the plan, and you look under the fuel performance piece, you see something called fuel manufacture. And our plan is to try to understand as best we can what are the really critical aspects of fuel manufacture to get quality in the product and also performance in reactor and in accidents. And there is work going on internationally to try to understand what it is that in the process and the product specifications that will do just that. So we're following that. And the question comes up, should there be a regulatory footprint in some sense on that piece as a way of assuring defense-in-depth? I think there's a general belief that we ought not to regulate the product but the performance, which puts you into the next step, which is looking at operating performance. If you're going to have -- MEMBER ROSEN: It would be preferable to -- in my view, to regulate the performance. But in the case we're talking about, because of the importance of the product protocols, it seems to me that the regulatory footprint in the processing of the fuel is crucial. MEMBER ROSEN: Yes. And part -- MEMBER KRESS: And I think it's analogous to digital I&C for controls and -- MEMBER ROSEN: And part of the preapplication review, a big part of the fuel performance review, is to look at the tradeoffs of, where do you put your regulatory imprint. Do you put it in the manufacturing piece and/or also in operation and/or testing fuel after it has come out? I mean, you can put it anywhere you want. The data I have seen on monitoring operation and looking at some examples going back to the German testing program, there are failure modes that will not be caught by monitoring coolant activity. They don't -- MEMBER ROSEN: Stu, why do you think it is only one answer? Why do you think that? MEMBER ROSEN: I'm not saying there's one. MEMBER ROSEN: Whatever answer you come up with now is the answer forever. I don't think so. MEMBER ROSEN: I'm not saying one. I'm not -- MEMBER ROSEN: I think the answer is something you -- in the beginning you do almost all of what you've talked about, until you begin to get confidence that you don't need to -- that you do not need to do pieces of it and can begin subtracting away pieces. MEMBER ROSEN: And we very much believe that this whole area will be a Commission policy decision. And what we plan to do in our SECY paper at the end of this -- not so much the advanced reactor research plan development process, but the end of the preapplication review, is to lay out those defense-in- depth opportunities for catching fuel that may not perform well in an accident, and talk about the advantages and the disadvantages in each one, and lay out our -- those options and lay out our recommendation, and then the Commission will have to make a decision. But I'm not going to say what that final answer is, but it is, we believe, very much a Commission policy decision on where that imprint or multiple imprints need to be. MEMBER KRESS: Well, while I'm on a roll here, I want to have one complaint. There's a statement in the document -- now I don't have mine with me, so I don't know what page it's on, but it's to -- the statement says that the -- I won't be able to find it, because I've got it dog-eared -- that the evolution of severe accidents and source terms will be similar to current operating plants. Now, I just think that's flat-out wrong for IRIS, and it may be wrong -- I mean, you can't even relate it to PBMRs. But for IRIS I think it's flat-out wrong, and I think there's contrary evidence, especially for high burnup fuel, and IRIS, of course, is going to go to really high burnups. And I just don't think you can make that statement. And I didn't see in the plan, Dana, anything on research for core degradation and fission product releases for high burnup fuel of the LWR type. MEMBER POWERS: It's totally irrelevant, Tom. MEMBER KRESS: I know it is. Yes. So that's a complaint. That's the one major complaint I have. CHAIRMAN APOSTOLAKIS: You have commented on the whole report now, because I want to do that, too. You are not just commenting on the -- MEMBER KRESS: Yes, that's right. CHAIRMAN APOSTOLAKIS: Okay. MR. ELTAWILA: I agree with you on IRIS. And as I indicated earlier, we have very limited interaction with Westinghouse on the design of IRIS. So we really -- this plan does not really address IRIS in any extent. So your points are well taken. And once we -- we are going to keep that plan as a living document. Once we get information about IRIS, we will modify to address this plant design. MEMBER KRESS: Yes, okay. Well, another question I have is you had a section in there discussing -- I don't even remember where it was either -- discussing underground siting. CHAIRMAN APOSTOLAKIS: Yes, I remember that. MEMBER KRESS: It's a good idea, but I don't think anyone is seriously considering that, are they? I mean, is that -- that wouldn't be a priority in my research. MR. FLACK: Underground is pretty much the GA design, the GT-MHR -- MEMBER KRESS: Well, that's partly underground. MR. FLACK: Yes. MEMBER KRESS: Okay. One other thought. You talked about, for the PBMR and the pebble -- the gas-cooled reactors that severe accident issues include water ingression and air ingression. I'm not so sure water ingression is a severe accident issue. I think it's a long-term degradation issue and not a severe accident issue, so you might want to rethink that one a little bit. I guess that's my list of items, George. CHAIRMAN APOSTOLAKIS: Well, I have a -- I mean, if we are talking about broader issues now, it looks like -- first of all, you mentioned PIRT some place. I can't find it now, but I remember. I know it's a major deficiency on somebody's part not to know what it is. But I've been on this committee for five years, and people use the word "PIRT" as if everybody knew what it was from birth. Is there any place where I can go and find out what it is? I don't know what PIRT is. MEMBER KRESS: There's a document called CSAU that -- CHAIRMAN APOSTOLAKIS: Oh, is that part of CSAU? MEMBER KRESS: Yes. CHAIRMAN APOSTOLAKIS: Can you -- I know what it is, but I'd like to know how it's done. MEMBER KRESS: Well, I don't want -- CHAIRMAN APOSTOLAKIS: And I know that the thermal hydraulicists are ecstatic about it. (Laughter.) MEMBER KRESS: I don't know what the NUREG number is. CHAIRMAN APOSTOLAKIS: So I'm very suspicious. (Laughter.) Now, that brings me to another point, which is related to my question about efficiency and the use of risk information. It's a matter of style, of tone, how to write this rather than really substance. I know what you mean, although the substance is effective. I'm willing to bet that what's going to happen is you're going to have the PRA at the high level, and then you're going to use a hell of a lot of defense-in-depth arguments to really preserve most of the criteria you have now. And here is the sentence that justifies that. I'm editing now as I go. However, until appropriate models can be accurately developed for these new designs to define and prioritize these issues, conventional methods will -- may need to be applied." So this is dismissing now PRA. This gives you a way out. I would say -- I would change the tone of this and say the following. Yes, we've had all sorts of -- I'm reading from the human factors, but I don't want to single them out, because I don't think it's unique to them. Yes, you've been looking at task analysis, at procedure development, training program development. Please tell us how important these things are in the risk environment. I agree -- you see, now they are putting the burden on the reliability analysts. Until the HRA models are accurate, we will continue doing what we're doing. I'll reverse that. Show me why what you're doing is important to risk, and then you put a hell of a lot of pressure on a lot of people to actually quantify, because if that pressure is not there they will never quantify, and I say that with a license -- I mean, the power uprates. The answer was, we have an engineer who looks at the -- who looks at it. You know, the available time was 42 minutes, now it's 39, and he says it's okay. Now, where is the incentive of quantifying if that's the easy solution? An engineer looks at it and decides it's okay. So it seems to me it's a matter of tone rather than really substance. Ask all these people to tell you why all these requirements are important from the risk perspective. Now, they may come back and say, well, gee, not everything is important, you know, from -- with respect to CDF, but there are other criteria. Well, that would be progress in itself, because I do know there are other criteria that are not specifically stated. MR. ELTAWILA: If we sound quiet on this side, it's because Mary keeps saying, "I agree with you," so I -- we are really -- CHAIRMAN APOSTOLAKIS: She agrees with me or you? MR. ELTAWILA: No, with you. So we are agreeing with you, and I think that's a good point. CHAIRMAN APOSTOLAKIS: I think that if you say that clearly here, then I think you are well on your way of having an efficient -- I'm not saying that it will always work, but at least you are shifting the emphasis now. MR. ELTAWILA: Okay. CHAIRMAN APOSTOLAKIS: You have to tell me why this particular requirement is important from the risk perspective, whatever "risk" means in this context. You know, it's not -- nothing is important with respect to CDF, by the way, unless you demolish the reactor. There may be other intermediate objectives that are effective, and at least we will have them on paper. Ah, come on, Steve. You know you have to do big things to see a big change in the CDF. MEMBER ROSEN: Abolish the reactor? MEMBER KRESS: Almost. CHAIRMAN APOSTOLAKIS: Almost. MR. FLACK: Well, there are sensitive issues like, for example -- that would be difficult to quantify. And since you brought up human factors, it would be like a question of whether an operator is qualified, what would be the risk from an unqualified operator? I mean, these are -- CHAIRMAN APOSTOLAKIS: All I'm doing is I'm shifting the emphasis. MR. FLACK: No, I understand. I understand. CHAIRMAN APOSTOLAKIS: See, as long as you say it's the problem of the HRA analyst, they will never get anywhere. If you say, "No, it's your problem, you tell me whether what you're doing here is risk-significant," then you will see a very different attitude. I repeat, I don't want to single out the human factors. I mean, it applies to I&C, and I am sure it will apply to other things with the new reactor. I&C, too -- I mean, you look at it, there is a lot of work, and this is -- at the end it says, "Oh, by the way, we really ought to quantify it, too." Well, yes, sure. MEMBER POWERS: John, let me ask you a question. Since, obviously, we've blown your presentation completely to hell, we might as well just continue this trend. Teach you to make viewgraphs, by God. (Laughter.) We have just had the IPEEE insights document given to us, and with arguable exceptions we find two things. One is the estimates of risk that the licensee has submitted for fire were surprisingly high comparable to operational risks. And the techniques that they used to derive those were relatively crude. And, okay, so you can argue that maybe the risks are not as high; they were just very conservative when they went through and did it. On the other hand, you can take them at face value and say, "Hey, one of the features of our current crop of reactors is there are very susceptible to fire and is an accident initiator." And maybe we don't want that for advanced reactors. I mean, it does seem kind of a crude thing to have a sophisticated, high-technology device like a nuclear reactor susceptible to fire as an accident initiator. Why, then, wouldn't you want to put priority on having good technologies for evaluating fire and advanced reactors? MR. FLACK: I guess you looked through the report for that piece and didn't quite find it there. Fire is a difficult issue. It's a spatial interaction type of issue that you need to deal with almost on a plant-specific level. So it's difficult to understand what that risk would be until a plant actually comes in and says, "Here is what I got, and here is where things are," and then you can study it from that perspective. But I guess, again, this comes back to the code issue, whether or not our codes -- MEMBER POWERS: I'm looking at -- I mean, I'm taking your lead in saying you're trying to create an infrastructure here, a capability -- MR. FLACK: Right. Exactly. MEMBER POWERS: -- and so I'm asking, isn't this a capability that you want to have? MR. FLACK: I would -- the answer is, of course. I mean, it's certainly an important risk contributor we see in these plants. How they play out in advanced plants, passive designs, is yet to be seen in what we'll have -- how we'll approach that problem. Again, it's a difficult issue to deal with without seeing a plant. But no, it's certainly external events. Seismic and fire are two that's part of that. MR. RUBIN: Can I just -- John? This is Alan Rubin from the PRA Branch and also the IPEEE External Event Program. As part of the advanced reactor research plan, we do include external events in the PRA -- different operational states as well as external events, fire, and seismic. So we -- MEMBER POWERS: We don't doubt that you include them. I'm really asking a question on the quality of tool that you have available to include them. For instance, a noted member of this panel, an exemplary member of this panel, devised a code some time in the past, and he recount for you the details of it, called COMBURN, and we universally find COMBURN gets used beyond its stated limits of applicability, because there's nothing else available. And the problem I see that you have is just what John outlined for you. If you're going to analyze fire, you're going to have to do it on a plant-specific basis. If you wait for a plant to come along in order to do a fire analysis, then there isn't time to develop a better tool, because you're under the gun and people are yelling at you to do it faster, better, cheaper, and things like that. And so COMBURN lives forever. And though I know the author of COMBURN is an exemplary individual, a noted phenomenologist in this world, I don't think even he thinks that it deserves to live forever. MS. DROUIN: Dana, let me just also interject something. We have a huge research initiative going on in the area of fire that would support this effort. I mean, that's looking into things -- you know, the models. I think they've been in front of the ACRS. MEMBER POWERS: I get confused, Mary, over the strategy in preparing the report. It's all well and good that you have a research effort going on there, but shouldn't you lay it down here to say, "And we need that research effort"? I mean, this wasn't a litany of things that you're supposed to do. It's the things that are supposed to be done. MR. FLACK: No, that's a good comment. MS. DROUIN: I mean, the whole intent was to take advantage of what was going on in that program, and, yes, we probably shouldn't have been so silent on it. MEMBER KRESS: I think we have reached the end of the allotted time for this subcommittee meeting. I would like to, you know -- lest you go away thinking we were too negative, I think -- I think you're on the right track with this thing, and you did a magnificent job of identifying the -- what the needs are and the gaps that might exist. And it's a comprehensive, well-written document. So I think you're on the right track, and, you know, we got some specific comments. I don't know if those were sufficient for feedback or should we have a letter or not. Probably -- MR. FLACK: No, we weren't looking for a letter at this point. MEMBER KRESS: Okay. Well, the other question I wanted to ask is: when should we think about having you back again on this same issue? July meeting, is that too soon, or is that too late, or what do you think? MR. FLACK: Are we talking about subcommittee or full committee? MEMBER KRESS: Well, probably need a subcommittee and a full committee, too. MR. FLACK: On this subject. MEMBER KRESS: Yes. When do you think it would be worth thinking about another meeting? That's my question, I guess. MR. ELTAWILA: We are ready any time you want, Tom, so just set the schedule according to your -- the availability of you and other members of the committee. CHAIRMAN APOSTOLAKIS: There has to be some evolution. MR. ELTAWILA: So I think we will have to start scheduling all of these meetings between now and to end by August, to be able to finalize the plan to go to the Commission. So if -- MEMBER KRESS: That's why I was thinking if it was in July we -- MR. ELTAWILA: -- every month you want a meeting, we will be supporting that. MEMBER KRESS: Well, thanks. I guess we're going to talk about -- yes, go ahead. One more thing. MEMBER ROSEN: I want to say one thing. I associate myself with all of the comments of the eminent Dr. Kress, but I am still concerned about the scope. So take that away. MR. FLACK: We gotcha. CHAIRMAN APOSTOLAKIS: And next time, John, just come with two viewgraphs. It doesn't matter. (Laughter.) It just doesn't matter. Okay. Thank you, gentlemen. MEMBER KRESS: Thank you very much. CHAIRMAN APOSTOLAKIS: This was a useful discussion, and we will recess now. How much time do you guys want? Do you want a full hour? Okay. Shall we be back at 1:50? 45 minutes? 1:50, okay. (Whereupon, at 1:08 p.m., the proceedings in the foregoing matter went off the record for a lunch break.) A-F-T-E-R-N-O-O-N S-E-S-S-I-O-N 1:53 p.m. CHAIRMAN APOSTOLAKIS: Next item, "CRDM Penetration Cracking and Reactor Pressure Vessel Head Degradation." Dr. Ford, please lead us through this discussion. MEMBER FORD: On April 9, presentations were made to the Materials and Metallurgy and the Plant Operations Subcommittees on the 2001-1 and 2002- 1 bulletins relating to cracking of CRDM housings and the degradation of CRDM housings. Obviously there's a tremendous amount of work going on on those two issues by both the industry and the staff. And on April 9, we heard preliminary information especially on that from Davis-Besse related to the root cause and generic implications of the degradation. Today, we're going to hear an update on these issues, and it's primarily for information. The staff have not requested a letter from us. Future meetings with the subcommittees and the full ACRS are scheduled somewhere in the near future for which there will be a letter, presumably, requested. Jack, you didn't have any comments? MEMBER SIEBER: No. MEMBER FORD: I'd like to move on then. We're going to take it in order, from the industry perspective, given by Larry Mathews, and then we'll move on to the Davis-Besse, and then finishing off with the presentation by the staff. So Larry is the Chairman of the MRP Program and from Southern Nuclear. MEMBER SIEBER: What's MRP? MEMBER SHACK: The first test. CHAIRMAN APOSTOLAKIS: What's MRP? MEMBER FORD: Materials Reliability Program, sponsored by EPRI. MR. MATHEWS: Like Dr. Ford said, I'm Chairman -- is this on? I'm Chairman of the Alloy 600 Issues Task Group of the Materials and Reliability Program. I work for Southern Nuclear, in case you care, or at least they pay me. I don't do much for them. (Laughter.) MEMBER POWERS: An extraordinarily honest man here. MR. MATHEWS: Not to imply I don't work. I just don't -- (Laughter.) These are kind of four topics I'd like to run through fairly quickly here today and provide a summary on: The Alloy 600 82/182 strategic plan that we have developed, an update on where we stand on crack growth rate issues, some brief words on the risk assessment and the probablistic fracture mechanics that we're doing for the reactor vessel head penetrations and then, basically, how we are responding to the Davis-Besse issue at this point. This is basically an outline of the strategic plan that the MRP has put together to address the Alloy 600 and the 81/182 issues. The plan has a problem staying on the goal and mission of trying to manage the issue, how we're going to go about it, what the roles of our various stakeholders are. And then we have a strategy right now, which are the five areas you see here. Basically, on the -- are you looking for this presentation? PARTICIPANT: Huh? MR. MATHEWS: Are you looking for the presentation? PARTICIPANT: No, no, no. MR. MATHEWS: Oh, okay, okay. On the butt welds, the basically strategy we've laid out is we're going to rely primarily on the ASME Section 11, the guidance for inspections and the frequency, but we're driving and we're trying to drive improvements into technology for doing those inspections. And, primarily, Appendix 8 has to be implemented by next fall, and at that point, all the inspections will be done by qualified inspectors. One of the things we will have to be looking at potentially in more detail is the frequency, is it appropriate, et cetera? But that's where we are right now is we believe Section 11, coupled with Appendix 8, will be the appropriate way to do it. There is a potential issue with the pass rates and the qualifications of the inspectors, and we're trying to address that right now. There's other areas up here, excuse me. The head penetrations in the near term, we put finalizing a safety assessment, but the real thing we're doing here is putting together mockups to drive the technology for doing volumetric inspections and to demonstrate those inspections. We're having mockups built that will be used in blind tests this summer for vendors that will be qualifying to do volumetric or under-the-head inspections next fall. There's also a mockup that was built that was available for people to use early and then another one for the spring outages. In the area of the longer term, what we're doing to do is get out inspection guidelines on what people ought to be doing, as far as inspecting their head penetrations. And then we want to work with the NRC and ASME to make sure this is, you know, all in conjunction with what's the right thing to do as far as inspecting the heads. All the other locations, we're working with the owners' groups to see what's already been done. We don't want to duplicate anything for all the other Alloy 600 locations. And where there are holes in what they've accomplished, we know they've done a lot of work, where there's holes in what they've accomplished, we'll work with those owners' groups and vendors to figure out where's the right place to develop those guidelines and get those programs underway. And, ultimately, the goal is to get out a management guideline for all the locations that would either provide information on how to manage it for your plant or direct you to where it would be available. One of the first things we want to work on is the inspection plant. We have draft inspection plant out now. This is something we need to get with the staff and make sure we're all in agreement on what's the right thing to do in the inspection. But it basically marches toward -- as the plant gets older and it has more time at temperature on the vessel head, the inspection should become more rigorous, if you will, going from a visual to ultimately, potentially all the way down to you must do a volumetric on some frequency. We haven't finalized that. That's in the final stages at this point. In the area of crack growth rate for Alloy 600, what we're trying to do is figure out what's the right crack growth rate people ought to be using when they're trying to do evaluations of cracks in the Alloy 600, initially looking at the base metal. We've created an expert panel. That expert panel has met several times, and they've screened databases available in the world. They're trying to refine their approach. It's been consolidated, but apparently, recently, we were very close to publishing the report, but then one of the labs said, "Well, we want to take another look at our own data." And then while that's going on, Davis- Besse occurs, and so especially with respect to what the annulus environment might be and the impact of the annulus environment, the experts said, "Well, we know what we said," and I'll tell you what that was in a second, "but before we publish we want to take another look at that and make sure we still believe it." And so they're meeting next week. It's a sid bar meeting to a meeting going on in France to look at that issue. CHAIRMAN APOSTOLAKIS: So when you say "curve," what are the axes? I mean one must be the growth rate. MR. MATHEWS: Growth rate and stress intensity factor. CHAIRMAN APOSTOLAKIS: Stress intensity. Now, isn't there any uncertainty in those curves? I mean are you displaying -- MR. MATHEWS: Oh, yes, quite a bit. CHAIRMAN APOSTOLAKIS: And you are displaying it? MR. MATHEWS: Pardon? CHAIRMAN APOSTOLAKIS: You are displaying it or are you just showing one curve? MR. MATHEWS: What we're proposing is a couple of different approaches. MEMBER FORD: Well, before you -- are you going to continue answering that specific question? MR. MATHEWS: Yes. Go ahead. What were you going to say? MEMBER FORD: Well, answer that question, because I want to come back to that. MR. MATHEWS: Okay. What we've done is we've taken the whole database and we've come up with a curve that we feel can be used for the deterministic evaluation of the crack growth rate for real flaws. And, basically, any flaws that you're trying to evaluate to leave in surface, the main ones that have been evaluated are flaws that are either ID axial flaws or if they are on the OD, they're below the weld. Anything above the weld it has to be a leakage path, and we can't leave that in service, so we wouldn't be evaluating real flaws above the weld. We do want to evaluate hypothetical flaws, for instance, all in the circ direction to determine if it flows into the safety, how long have we got and that sort of thing. And so above-the-weld flaws they've recommended a factor of two to account for the chemistry in the environment, but that's one of the things that the guys are going to take a look at next week in France, will make sure that Davis-Besse doesn't really throw a monkey wrench in. CHAIRMAN APOSTOLAKIS: But are on the issue of uncertainty now? You said it can be used for deterministic evaluation. MR. MATHEWS: Right. And the curve that we're proposing is for deterministic evaluation is like the one that would fit the 75th percentile of all the heats and material in the database. CHAIRMAN APOSTOLAKIS: Oh. So you're -- oh. MEMBER FORD: I think this is an ongoing argument within the industry for quite some time, and you've got a big scattered database, experimental. How much of that scatter is due to experimental control? Is much of it due to heat variations, for instance, in the materials in that database? And we have requested that at the next meeting that that database will be shown to the committees and how that has been analyzed. So that will directly answer your question. CHAIRMAN APOSTOLAKIS: Because it would seem to me to be an ideal place for a family of curves, would it not? MEMBER FORD: For a -- CHAIRMAN APOSTOLAKIS: A family of curves rather than one curve. MEMBER SHACK: People recognize there is a distribution. Just for deterministic evaluation you'd like to have -- MR. MATHEWS: No, but if you knew exactly -- if you knew exactly. CHAIRMAN APOSTOLAKIS: No. CGR data for base material feeds directly into the PRA. MR. MATHEWS: Well, that's not how we feed it into the probablistic approach, though. Instead of feeding it into the probablistic approach as a single curve, we put the whole database and all the scatter of the database to be sampled in the probablistic approach. The whole scatter for the whole database is put into the probablistic analysis. CHAIRMAN APOSTOLAKIS: I'd like to see that. MEMBER FORD: That is one of the things we've been asking that we do all see the database so we can understand the reasoning behind these words. MR. MATHEWS: Yes. And some of the staff is saying but we haven't shown them the ACRS. And part of the reason is it's in a state of flux right now. CHAIRMAN APOSTOLAKIS: So you're going to do this in a subcommittee meeting? MEMBER FORD: We'll do it in the subcommittee and present it at the full committee, yes. MR. MATHEWS: And hopefully we can do that at the next meeting. MEMBER FORD: Correct. MR. MATHEWS: I think we'll be much closer and we can do that. MEMBER FORD: Could you go back to your previous page? MR. MATHEWS: Sure. MEMBER FORD: The implications of the Davis-Besse, your last bullet, is that in terms of the question as to what the environment is in the circumferential annulus? MR. MATHEWS: Yes. That's what -- I believe that's what the experts would want to take a look at. They had made some assumptions, some MULTEQ calculations and some other discussions amongst the experts about what are the possible environments that could be in there in the annulus region, and then what effect would that have on the crack growth rate? And they came up with what they felt was a conservative multiplier, a factor of two. Given the situation at Davis-Besse, thought, they said, "Well, I don't know that it's going to change, but let's take a look at it and see if there's anything coming out of the Davis-Besse situation that would say that environment that we predicted is inappropriate to use for a circumferential crack growth. MEMBER FORD: And, again, that information will be discussed, presumably, at the next meeting, this specific information. MR. MATHEWS: We hope to have our report published well in advance of that meeting, and we can come talk about it. CHAIRMAN APOSTOLAKIS: Next meeting. MEMBER FORD: Well, in the near future, maybe one, two months time. CHAIRMAN APOSTOLAKIS: Subcommittee meeting. MEMBER FORD: Correct. MR. MATHEWS: Also, the expert panel they met very recently to look at the weld metal Alloy 82/182 and what we know about the crack growth rates in the weld metal. And they will be coming back to the MRP with recommendations on where there's holes in that database, and there are likely to be some because it's a limited database and where testing may be needed. There's also a research effort that's being undertaken right now by EPRI, and it's a DOE part of the NEPO Program to look at some crack growth rates in weld metal. And there may be some additional base metal crack growth rate in there, I'm not sure. And we will certainly be willing to continue to update you as we get more data, maybe provide you some. In the area of the risk assessment work, the approach is to predict the probability of leakage based on the industry experience and where we've seen links and modeling that in a Weibull model, Weibull statistics model. Then compute, after a leak develops, the probability of a nozzle ejection, looking at or considering the initiation and growth of a circumferential flaw above the J-groove weld. We can factor into that inspection and the probability that a leak might be detected prior to growing to an ejection situation. CHAIRMAN APOSTOLAKIS: How would you do that? MR. MATHEWS: I left that slide out. What you do is as the model progresses through the time, it's a statistical model but it progresses through time, and at given points in there, depending on the inspection frequency that you put in, you can put in a probability of detection. And if you -- and you do a sample on that. And if you find the probability that it is detected on that particular sample, you take it out of the database for an ejection. And if you don't, it goes on down to maybe the next level of inspection or the next whatever. You just the run the statistics, and if you put a probability of detection of 80 or 90 percent in there and you're doing inspection at a certain point in time, then 80 or 90 percent of any flaws that might be in existence there would be taken out of the database or if they're not -- CHAIRMAN APOSTOLAKIS: Would that be consistent with the Davis-Besse experience? An 80, 90 percent probability of detecting? MR. MATHEWS: Today, I would say, yes, probably. I'm not sure what the POD, probability of detection, that we're going to put in there. That's just the way it's modeled, and we'll have to decide. We haven't settled down on exactly what kinds of inspections or when they would be into the model to figure out the risk. But, you know, before Oconee the world was different than it was after Oconee, so people look at things a whole lot different. CHAIRMAN APOSTOLAKIS: See, what worries me is that I don't know how many times the world is going to change. MR. MATHEWS: Oh, yes. I know what you mean. CHAIRMAN APOSTOLAKIS: I mean it shouldn't. It should change any more for the current generation reactors. That's my problem. MR. MATHEWS: Knowledge isn't perfect, I must admit. CHAIRMAN APOSTOLAKIS: Boy, you can say that again. MR. MATHEWS: Yes. Anything else? Finally, what we do is we grow the flaw to the critical flaw size on a statistical basis from Monte Carlo sampling, and some of them grow to critical flaw and some of them don't. And then they take the fractions that do and that's the probability there. Couple that with the probability of a conditional -- I'm sorry -- yes, with the conditional core damage probability from a small break or medium break LOCA, and you have the core damage frequency. What we're going to do is assess the potential impact on the conditional core damage probability of the collateral damage. We think it's going to be minimal that might occur from an ejection. CHAIRMAN APOSTOLAKIS: Is it clear to everyone why nozzle ejection is the issue here? MEMBER SHACK: That's what causes your medium-break LOCA. MR. MATHEWS: Yes. CHAIRMAN APOSTOLAKIS: Oh, that's -- MR. MATHEWS: In almost all -- you know, if you look at all the times that plants run most of the time, almost all the time these plants are up at power and all the control rods are essentially all the way out. CHAIRMAN APOSTOLAKIS: So what's the equivalent diameter? MR. MATHEWS: The inside of a nozzle is about two and five-eighths inches, I believe. MEMBER SHACK: But when the whole thing comes out, it's like four inches. MR. MATHEWS: Yes. CHAIRMAN APOSTOLAKIS: Oh, okay. So then it's -- MR. MATHEWS: Well, you've still got to get through the part that's left. If you have a circ flaw above the well, then you've got a segment that's left from the well down that's not ejected and the inside diameter of that is two and something inches, and if it's a control rod location, it will still have a shaft in it unless that gets pulled on out too. CHAIRMAN APOSTOLAKIS: How will you go to the condition core damage probability? I mean you would just consider the new probability of a medium LOCA? The probability of nozzle ejection would be -- MR. MATHEWS: Well, the CCDP is the conditional core damage probability. CHAIRMAN APOSTOLAKIS: Right. MR. MATHEWS: Given that you have a medium-break LOCA, the plant risk assessments already have looked at what is the probability that you have core damage, given that you have a medium-break LOCA. And that goes through all the possible failures of your ECCS systems and all of that. CHAIRMAN APOSTOLAKIS: Would you consider dependencies between the initiating event and some of the other events? MR. MATHEWS: Yes. CHAIRMAN APOSTOLAKIS: In particular SCRAM? Would SCRAM be affected? MR. MATHEWS: Yes. And that's what we would look at as would there be collateral damage from the ejection of a control rod nozzle that could make that conditional core damage probability of a medium- break LOCA higher than if it was on a pipe somewhere. We'll look at that, and if it would make that conditional core damage probability, given the LOCA here as opposed to on a pipe higher, then that effect would be factored into the risk assessment. We think that effect's going to be minimal and we've gotten some preliminary work from the vendor, but we need to finalize that. CHAIRMAN APOSTOLAKIS: So you are also looking at small-break LOCA, I see. All right. MR. MATHEWS: From a risk standpoint, yes. We're not doing a deterministic blowdown of a small- break LOCA type thing, it's more of a risk analysis. CHAIRMAN APOSTOLAKIS: Okay. You're going to have to have experts again telling you what's going to happen if you have a nozzle ejection. MR. MATHEWS: Yes. And the vendors know -- CHAIRMAN APOSTOLAKIS: And how it will affect the SCRAM system. MR. MATHEWS: -- what's up there, and we're asking them to provide us input on that, and they've given us some preliminary stuff, and we need to follow-up on that and figure out how to factor that input back into the risk assessment. CHAIRMAN APOSTOLAKIS: So when will this be done? MR. MATHEWS: We were hoping to be through this month, but everything's kind of taken a -- everybody's busy on Davis-Besse issues right now. CHAIRMAN APOSTOLAKIS: Okay. MR. MATHEWS: Some of the key elements of the probablistic fracture mechanics analysis, which is the major part of the risk assessment, is the simulation of the leakage as a function of time and a Monte Carlo model. That's based on our time and temperature model using the fracture for the stress intensity factors, for the various types of flaws that would be in there as the flaws grow. The entire database for the structure crack growth rate database and the statistics, all of those statistics would be fed into for the sampling and then the effects of the inspection and the inspection reliability. We have some very preliminary results for a tight temperature plant, and I do stress preliminary. First cut thereafter after you've an inspection, the probability of nozzle ejection within the first or so is less than times ten to the minus three after you've done inspection. And then the conditional core damage probability, the worst one we could find on the high temperature plants was five times ten to the minute three. Multiplying those two together you get a core damage frequency in the range of five times ten to the minus six. CHAIRMAN APOSTOLAKIS: What is the main reason why the probabilities are so low? MR. MATHEWS: The main reason the probability of an ejection is so low after you've done an inspection is that you've found your leaks and repaired them. But in a few cases, when you do the statistical Monte Carlo approach, you can have some very high crack growth rates on some of this sampling. And those that grow very, very rapidly a few of them may grow all the way to the ejection in the sampling process, but it's a very, very few of them within one cycle or before you come back to do another inspection. CHAIRMAN APOSTOLAKIS: So you're assuming that when the size reaches a certain level, then there's a very high probability that they will be caught by inspection and somebody will act on it. MR. MATHEWS: Yes. Given today's environment and what everybody knows about what they need to be looking for, yes. CHAIRMAN APOSTOLAKIS: Today's environment meaning? MR. MATHEWS: After Oconee. I mean Oconee showed that you could have a leaking penetration that didn't have a lot of boric acid coming out down the side of your vessel. And so now people are keyed into you have to look for popcorn instead of big piles. CHAIRMAN APOSTOLAKIS: And CCDP, why is it so low? MR. MATHEWS: Because a small-break LOCA or -- CHAIRMAN APOSTOLAKIS: No, a medium LOCA. MR. MATHEWS: Okay. I'm not sure of the exact square inches on the small and medium LOCA, but we have lots of safety systems that are designed to handle the LOCA and to keep the core from being damaged. And the way you get damaged typically on a risk assessment analysis on the LOCAs is something fails, and there's probability and statistics put in on a failure probabilities of your various safety systems, and as you do that sampling on all the systems and their probabilities, it comes out with a fairly low probability for that size break that you're going to have core damage. CHAIRMAN APOSTOLAKIS: But how much credit are you taking for scrap? MR. MATHEWS: I'd have to go look at the PRAs. I'm not sure if we -- I know in the design basis axis on LOCAs I'm not sure we take any credit for SCRAM. CHAIRMAN APOSTOLAKIS: You're not sure of what? MR. MATHEWS: I'm not sure they take any credit on the design basis analysis, but on the risk assessment I think we do take credit for SCRAM. CHAIRMAN APOSTOLAKIS: The question is how much because I don't know that we really know what's going to happen if you have a medium-break LOCA at that location. MR. MATHEWS: Well, that's what we're counting on the collateral damage assessment to tell us: Does it have an impact on the conditional core damage probability? CHAIRMAN APOSTOLAKIS: Oh, so the collateral damage is not part of these numbers? MR. MATHEWS: Right. But like I say, the conditional assessment we have from the vendors is that it will have very minimal impact, if any, on the conditional core damage probability. A break at the top of the vessel is better than one that's at the bottom, and the CCDP is for all breaks. But -- MEMBER ROSEN: A break at the top of the vessel is better than one at the bottom but not for an event when you want the control rods drives to operate. CHAIRMAN APOSTOLAKIS: That's right. MEMBER ROSEN: Because the control rod drives on a PWR are at the top. CHAIRMAN APOSTOLAKIS: They're at the top. MR. MATHEWS: That's right. And that's what we have to see and have to assess in this collateral damage is is there something that could happen that would prevent a SCRAM or a significant portion of the rods from not going in? Severing the cables is great. MEMBER SIEBER: It's designed to have one rod stuck up. MR. MATHEWS: At least one. MEMBER SIEBER: And still get enough reactivity. MEMBER ROSEN: From a reactivity standpoint. MEMBER SIEBER: But if you damage the adjacent rods somehow so that they don't, then the probability of core damage goes up. CHAIRMAN APOSTOLAKIS: That's exactly what we're exploring here. MEMBER SIEBER: Wiping out 60 of them, I think, is pretty improbable. MEMBER ROSEN: What we're worried about is the steam environment, the jet environment and all of that that will be up there in very aggressive to the operation of the drives and the rest of the equipment up there. MR. MATHEWS: Well, most anything that's going to -- the real concern, if there is one, from a collateral damage, is if you could something that would prevent the rods from moving physically. MEMBER ROSEN: That's right. MR. MATHEWS: Severing the cables, no problem, they're going in. It's the -- CHAIRMAN APOSTOLAKIS: Physical, yes. MR. MATHEWS: If you bend the tube or something like that, that's the condition -- MEMBER ROSEN: If you have a plate right above this, you know, above the point where you have the break, and you create a high pressure environment between the plate and the top of the head and what if that plate cocks or something like that? I mean you can imagine -- MR. MATHEWS: The insulation plate. MEMBER ROSEN: Yes. MR. MATHEWS: Yes. Those are pretty low. MEMBER SIEBER: But what's the point if it does? MR. MATHEWS: And that's what -- we have to look at the -- MEMBER SHACK: We're not done. MR. MATHEWS: We're not done yet, but, you know, I think I heard yesterday and it's, at least to my way of thinking about it, the first thing that's going to happen is the voids are going to shut the reactor down. CHAIRMAN APOSTOLAKIS: The point is that the five ten to the minus six number does not include considerations of this type. MR. MATHEWS: Right. CHAIRMAN APOSTOLAKIS: Okay. MR. MATHEWS: It includes an initial estimate that it's going to be a very minimal impact on that number, but we still have to go back and tie all that together. We're not through yet. MEMBER FORD: The first time that such an analysis was given, to the staff that is, was during the Duke presentations relating to Oconee, and my question now is have there been any subsequent discussions between you and the staff on this whole approach? MR. MATHEWS: We've had some fairly detailed meetings with the staff on how we are modeling primarily the probablistic fractured mechanics part. We haven't really gone in in much detail on the rest of the risk assessment. I think we've laid this level of detail out and discussed it with the staff. But on the probablistic fracture mechanics and how we're modeling the crack and the crack growth rate, we've met with Ed Hackett and the research folks and their contractors and had a couple of rounds of questions about how we're doing it versus how they're doing it and trying to reach resolution on some of those issues. MEMBER POWERS: Suppose that after all that they said, "Gee, you're just doing great. The crack growth rates are great, everything's great." How do you know the results are right? MR. MATHEWS: Well, from the probability of leakage is -- well, it's based on the experience in the field, and we continue to get experience in the field, and that is adjustable to match the experience in the field. We're trying to be somewhat conservative in this, and although it is a statistical approach -- MEMBER POWERS: How do you know you're being conservative? MR. MATHEWS: There are a number of details of how we're modeling the probability fracture mechanics work that are -- like immediately upon a crack going to a leak, we assume that it's instantly like -- I think it's 20 or 30 degrees around branch of the flaw, and it's going to take some time to initiate a circumferential flaw, but we assume it happens instantly. That's one thing. CHAIRMAN APOSTOLAKIS: Would assuming the presence of the degradation around this nozzle, similar to that of Davis-Besse, be a conservative thing to do and what numbers would you get? MR. MATHEWS: It might be a conservative thing to do, and we could model it. And I guess the next slide is -- CHAIRMAN APOSTOLAKIS: You don't know what number you're going to get, though, do you? Because it's not just the normal rejection. MR. MATHEWS: No, I don't know. CHAIRMAN APOSTOLAKIS: You may have additional failures. MR. MATHEWS: There is the potential there that if you got a nozzle that was in a situation like Davis-Besse where there is a wastage cavity next to it, if the cavity comes all the way around so that you lose a back wall on the opposite side from where the cert flaw is growing, it might have an impact on how fast the crack grows. And we can model that and do some studies on that, and we probably will do that, where we remove the nozzle, the constraint from the nozzle on the opposite side from the cert flaw. CHAIRMAN APOSTOLAKIS: Well, that would be an interesting case to see, a sensitivity case. MR. MATHEWS: Yes. And it's not that hard to do. There's gap elements on that side of the nozzle that we just set them to a gap instead of an interference and then see what happens to the nozzle leaning over as a function of the crack growing. Really, the way we've modeled it, it would only have impact after the flaw hits 180 degrees in through wall. If it's part through wall, we don't even model that restraint; that's ignored. So, basically, we're modeling it without that restraint already. CHAIRMAN APOSTOLAKIS: So if you were doing this analysis before Oconee, what number would you get? You said earlier, "in today's environment." So in yesterday's environment, what number would you get, five ten to the minus nine or five ten to the minus -- MR. MATHEWS: Well, we probably would have, yes. CHAIRMAN APOSTOLAKIS: Huh? MR. MATHEWS: Yes. It probably would have been in that -- CHAIRMAN APOSTOLAKIS: So all Oconee did was raise the number from ten to the minus nine to ten to the minus six? No? What? That's what they said. MR. MATHEWS: I didn't do it before Oconee, so I don't know what the number would have been if we hadn't -- where it comes in is the probability of the ejection. CHAIRMAN APOSTOLAKIS: Yes. MR. MATHEWS: Which starts from the probability of a leak. We would have thought that prior to Oconee in those flaws that have been recently discovered, we would have felt that the probability of developing a leaking penetration on a USPW head was lower than it really was. MEMBER FORD: I think the answer to both your questions, to a certain extent, is, again, I don't think you can -- the proof of the pudding, of course, is observation versus theory, and we haven't had any raw dejections, thank goodness. But you can do it what's the probability of a number of through wall -- through circumferential wall cracks that have been observed. And that's essentially the approach that Oconee did, or Duke did for Oconee, to compare these predictions against the number of circumferential cracks that they saw. Now, admittedly, it's not going the whole way, you're absolutely correct, but it is going -- they're doing a check of observation versus theory. MEMBER POWERS: What I guess -- I mean you've certainly interpreted my question correctly, and what I'm really struggling to find we apply this probablistic fracture mechanics in a lot of regimes now. This seems to be the first one where we don't get answers like ten to the minus 45, which I thought was a constant -- (Laughter.) -- in probablistic fracture mechanics. But I never -- I mean I'm sufficiently unfamiliar with the technology that no one ever shows me that it actually gives you good answers for any circumstance that isn't fairly well-contrived laboratory circumstance. And so I'm wondering as the geometry has become more complicated, and here they're about as complicated as comes quickly to mind, do we really have data for any circumstances, I mean it doesn't have to be a reactor vessel, but how about an internally pressurized vessel of some sort where we can show that indeed the probablistic fracture mechanics has got all the physics in it so that if we do what the speaker has said, we parameterize the model conservatively, we should get a conservative answer? MEMBER FORD: Do you want to answer that? MR. MATHEWS: I'm not a probablistic fracture mechanics guy. MEMBER POWERS: Well, that speaks well of you. (Laughter.) MEMBER FORD: I don't know -- quickly, off the top of my head, I don't know -- CHAIRMAN APOSTOLAKIS: Are there any cases where probablistic fracture mechanics gave probabilities on the order of 0.2, 0.3 value? Or is it an inherent thing of the methodology? MEMBER POWERS: Ten to the minus 45 is a really common number, I know that. MEMBER SHACK: Just to come back, George, you know, one of the things one observes is the way things depend on diameters, your famous Thomas correlation that you PRA guys love, you know, that comes out of the fracture mechanics. The low probabilities, of course, are for a large diameter pipe where, again, for the crack to grow all the way around the pipe, you have to grow a crack that's many, many inches long. So, obviously, that's going to take a lot longer than it does to, say, grow a crack around a four-inch pipe. I mean the physical -- you still have to grow 330 degrees, it's just the 330 degrees on a four-inch pipe is a whole lot less metal than 330 degrees on a 24-inch pipe. Now, it's very difficult, of course, to get one-to-one comparisons, because we just don't have a whole lot of data, but when you go back to the database, you get probabilities of failure that aren't all that -- you know, they're in the ballpark of what you're computing for your probablistic fracture mechanics; it's not a one to one. We have experimental confirmation of the ingredients; that is, you know, crack growth rate is measured independently. It's not in a probablistic fracture mechanics test. The biggest thing that you have are the loads on the pipe where we know the pressure loads very well. PR over T really work. The residual stresses you can measure independently. So you can measure those independent ingredients, and then -- MEMBER POWERS: But I never see anybody put the whole thing together and say, "Okay. Here are a bunch of data on this thing, and this thing works." MEMBER SHACK: When you come out with the probability of large diameter pipe failure of ten to the minus nine, you're not going to find data. MEMBER POWERS: Well, give me a small diameter pipe. MR. HACKETT: If I could add, this is Ed Hackett from the staff, we briefed the Committee, I guess, numerous times now on the pressurized thermal shock reevaluation program. I think that's where the staff and the industry have done the best job of applying this type of methodology. And in fact that has been benchmarked to international reference experiments, and in several cases has done quite well. In think in the case of Professor Apostolakis' comment, I'm not aware of any that have come up that high. We see these failures for vessels, and, again, thankfully, as Dr. Ford was mentioning, are in the range of E minus six or less when we're looking at reactor pressure vessels, different application than what Larry's talking about here specifically. MEMBER SHACK: But even there, Ed, when you benchmark that, you benchmark the fracture mechanics, "Yes, I failed a vessel with a crack so big." MR. HACKETT: That's correct. MEMBER SHACK: Just to say that the probability of the vessel failure is ten to the minus eight, you're not going to get a whole lot of statistics to -- MR. STROSNIDER: This is Jack Strosnider. I'd like to make a few comments on this too and maybe to defend the credibility of probablistic fracture mechanics somewhat. First of all, I think, you know, when you talk about benchmarking this, as Ed pointed out, thankfully we don't have an empirical database on pressure vessel failures or CD control rod drive mechanism failures, for that matter. So it is rather difficult to get that sort of benchmarking. However, I think when you look at the probablistic fracture mechanics, you can get results that are reasonable depending upon the conditions that are being considered. And I think the ten to the minus 42nd number that was brought up a couple times, I think you're referring back to some of the PWR work on vessel inspection. And in fact that number, it turned out, was the number that was generated when you assumed design basis conditions were satisfied. In fact, when you go through the full risk assessment that was done and what we ultimately ended up with, we came up with more like ten to the minus six to the ten to the minus seven numbers when we took into account beyond design basis events. The conditional -- or the vessel failure probability, given those events, was somewhat higher. It certainly wasn't those low numbers. But the other comment I'd make is that the analysis, methodology exists. We know how to put models together, we know how to identify random variables, we know how to model those, how to do Monte Carlo simulations. There's some challenges looking at dependence between the variables. But the biggest challenge, and frankly I would say this is true in all our PRA modeling, is coming up with the distributions that represent those random variables. For example, in this case, where one of the first things you had to look at was the initiating frequency, when does a crack initiate one of these? There's very little data available until we started getting results from the inspections that were done and could try to construct a distribution. So the biggest challenge that we have when we go into this sort of analysis is being able to define those random variables, the distributions for them, with some level of confidence. And usually you have to go out and do some work, inspections or whatever to get the information to do that. CHAIRMAN APOSTOLAKIS: But speaking of that, though -- MEMBER POWERS: Jack, you make huge amounts of -- when you do these probablistic fracture mechanics analysis, you're making huge simplifications in the way you describe the metal and the way you describe the crack, things like that. And I guess what I'm struggling with is how do you know you got them all. All the physics and all these approximations really are good ones to make. I mean some of your approximations are made because you know how to solve the mathematics. MR. STROSNIDER: Well, again, I would come back to if you look at all these models have an underlying deterministic model associated with them. If you look at the ability to predict crack growth rates as a function of stress intensity values, if you look at the ability to predict failure using either limit load or linear elastic correction mechanics, they work pretty well if you have a really well- controlled situation. And it comes back again to defining the distributions that are associated with those in real life. And I agree, that's a challenge. MEMBER POWERS: Well, every time I look for things that you predict well, you predict well those things that have been used to derive the physics, you know, nice, simple specimens, simple geometries. Now, you're applying them in really complicated geometries. There doesn't seem to be any database that I'm aware of, and I can't say that I've looked exhaustively, that says, okay, I've done my laboratory specimens, now I'm going to do this complicated thing that I don't understand very well and see if I can get it about right. Is there such a database? MR. HACKETT: I guess the one -- this is Ed Hackett again -- I guess the one I could point out, Dr. Powers, is the one -- it's a complicated acronym. They called it fracture assessment of large-scale international reference experiments; it's the FALSIRE project. And then there have been follow-on series, and this is an international collaborative effort, where they have gone from the small specimen geometries where things are nice and fairly simple to predict, to trying to predict what actually happens in a vessel. The Germans have blown up scale model vessels, we have at Oak Ridge. MEMBER POWERS: Yes. Now you're hitting exactly what I want to see. MR. HACKETT: And we have in fact -- MEMBER SHACK: Plus an enormous number of pipes at Battelle. MR. HACKETT: Absolutely. The most recent one, thinking of the follow-on activity, the NESC 1 spinning cylinder experiment in the United Kingdom. In fact, the folks at Oak Ridge, using their probablistic model, the FAVOR code, which is what we're using in the PTS Program right now, predicted the propagation of an embedded flaw in that vessel almost dead on in terms of initiation and arrest. CHAIRMAN APOSTOLAKIS: Don't take the viewgraph down. MEMBER POWERS: But if somebody can point that out -- point it out to me or come present it or something like that, it adds a lot more credibility to some of these categories. MR. HACKETT: Probably in the context of the PTS project we'll do that. MEMBER POWERS: That would be great. You know, if we could take a half an hour and just go through that, that would be great. MEMBER FORD: Could I suggest, Larry, that -- this will be -- CHAIRMAN APOSTOLAKIS: What does it mean the probability is less than ten to the minus three? Have you done an uncertainty analysis? How uncertain is that? How high can the ten to the minus three be? MR. MATHEWS: I don't have that right now. CHAIRMAN APOSTOLAKIS: But you will? MR. MATHEWS: I'm not sure we were going to do a full-blown uncertainty analysis. CHAIRMAN APOSTOLAKIS: Well, then what are you doing? I mean there are so many questions about all this. To give one number, what does it mean? If the ten to the minus three can be ten to the minus one, I don't know what conclusion I can draw from this. I mean all kinds of doubts have been raised, and it seems to me doing an uncertainty analysis means exactly, precisely to address these doubts and comments. There's something about the five ten to the minus six that bothers me, okay? That it was five ten to the minus nine and now it's ten to the minus six, that's all we learned. I just don't believe that. And the other thing I want to finish is that there is a certain pleasure in listening to Mr. Strosnider defend the probablistic method. Usually he's a skeptic. Today, he was on the other side. MEMBER SHACK: It's probablistic fracture mechanics he's defending. CHAIRMAN APOSTOLAKIS: I don't care what you put after probablistic. (Laughter.) It was nice to hear him talk that way. MEMBER POWERS: But, George, there is a difference. MEMBER SHACK: One's a science. (Laughter.) MEMBER FORD: If I could just -- CHAIRMAN APOSTOLAKIS: Go ahead, Dr. Ford. MEMBER FORD: -- move along here. In defense of the MRP, a lot of this is dependent on having a reasonable database for crack growth rates upon which that is dependent. Now I'm told that we're close to it. The next meeting we will see that database, and then we will see the follow-on to your specific question. CHAIRMAN APOSTOLAKIS: Great. MEMBER FORD: -- on that particular kinetics-driven analysis. Could I ask you to finish in five minutes, Larry? I realize that I've now cut you down to your knees. MR. MATHEWS: I will. In response to the Davis-Besse issue, we've had lots of interaction with the staff, but even before the bulletin came out we conducted, as an MRP, a survey, and it was based on some -- basically assumptions about what the possible causes at Davis-Besse were before the root cause or even the preliminary root cause was out. And there were three possibilities that we tried to consider in our survey, and that was leakage from above, leakage from a crack in a nozzle or a combination of the two. And then we'll be -- the ongoing Davis-Besse work will be used. We did that survey, we came up with four questions basically aimed at how confident are you that you don't have wastage on your head? And we received responses from all the PWRs in the country. We wound up categorizing the responses into four categories plus another group that didn't quite fit, and they range from -- you know, category one was they got the best knowledge, they're darn certain, they've gone and looked, they don't have any wastage. Category four, it was more like they were able to do from a historical view of leakage, et cetera, to feel confident. And then there was a category, other, that they had leakage and perhaps had not fully cleaned it up or there was some other reason they didn't fit into one of the other categories. And we categorized all these plants, gave the names of the plants to the staff, and I believe they've actually used our tables to help guide a little bit how they're contacting plants as far as what their intentions are. This is our ranking of the units that we put together a while back. If you look at it, the red triangles are the leaks, and most of those leaks are to the left of the graph, which is kind of where -- if the model's worth anything, that's where they'll be. A couple outliers, we do have one plant that had some cracks that was a little bit further out. Those cracks were nowhere near as severe as the cracks at these plants that have had leaks, so maybe we're picking up the precursor here. That's something we have to look at. All the blue diamonds have done inspections and haven't had leaks or the open blue diamonds are doing inspections this spring, yet to do a few plants in the fall and a few more next year. We'll have done inspections per bulletin 2001-01. Here's the table we sent to the staff. Turns out most of the plants, as far as the wastage on the head, feel a good degree of confidence that they don't have any significance wastage on the head. Some of these plants have even done inspections since then. Cook 1 I know plans an inspection very soon. Wolf Creek, I believe, has done an inspection, and I think Palo Verde just finished their inspection. So most of these plants are moving into greater degrees of confidence that they really don't have an issue with wastage at this point in time. MEMBER FORD: You should point out that, Larry, that that's on the basis of your survey, not on the basis to the replies of 2002-1. MR. MATHEWS: Absolutely. This was all put together -- it was probably right at about the time the bulletin was coming out or maybe shortly thereafter, but it was based on the response to our questions, not the responses to the bulletin. A couple of points about that. All the plants that are less than ten effective full-power years on our histogram will have been inspected by the end of this spring outage season. That includes the highest ranked 20 units in the country. And they should have a reasonable assurance that they don't have any significant corrosion on top of their head because of those inspections. And of the plants that were less than 30 EFPY, 34 out of 45 will have inspected by this spring. We're showing five in the fall and six in the spring of 2003. There's a little bit of confusion right now. We're not off more than one or two plants, I don't believe, but we've got to settle that out, straighten that out. This is something that we wanted to say, that of the 34 leaking nozzles and penetrations that have been discovered to date, all of them displayed visible evidence of leakage or corrosion on top of the head, leakage primarily. A total of 203 nozzles have been inspected at those -- let's see, is it nine plants where leaks have been discovered? And NDE has confirmed through-wall leaks or cracks -- I mean through-wall defects in all 34 of the nozzles that showed leakage. NDE did not detect through-wall defects in any of the others, and there have been, this says, four plants without evidence of leakage, and I'm sure by now it's much more than four plants have inspected the nozzles without any defects found. MEMBER SHACK: It would interesting on your chart, you know, where you've got the one with cracks that you found by NDE, to also see where the guys that inspected by NDE and found no cracks were on that chart. MR. MATHEWS: Yes. Up until when I put that together there weren't a lot. There was Cook 2 and maybe a couple of others that had done volumetric, that didn't have a prior indication of a leak that they were going and confirming. But we're getting more and more of the plants now that are doing volumetric inspections. I think Palo Verde just completed a volumetric inspections, and I don't even have them marked as having done that. But we will update the chart and try and figure out how many colors we could put on it. But we'll do that. Recent experience of the -- except for the Davis-Besse issue, in the other 31 leaking penetrations, there's no evidence of any significant corrosion or wastage. There has been a hint at a couple of other nozzles that there was a little bit here and there on top of the head or whatever but no significant evidence. And also on the plants that have repaired their nozzles that were leaking, most of those repairs have been performed using the Framatome repair technology where the nozzle is bored out and then rewelded up inside the head to the low alloy steel. And if there were significant wastage there, it would have been evident. They have to go PT that surface before they weld to it, and if there's a big gap, they can't even get it to weld. So out of all those other nozzles, there hasn't been any significant wastage like the one big cavity at Davis-Besse. CHAIRMAN APOSTOLAKIS: So what do I learn from that? What's the conclusion from that? MR. MATHEWS: Well, the conclusion is that something's different about Davis-Besse, the waste, the big cavity like they had compared to the rest of the industry. And they're going to talk about it -- CHAIRMAN APOSTOLAKIS: And the rest of the industry also had wastage there for the number of years that Davis-Besse had it? MR. MATHEWS: Well, that may be the key, and in fact it may be the difference between this one nozzle and the rest of them is the amount of time that the nozzle leaked. And Davis-Besse will discuss that when they get up here. That may in fact be the key is how long was the leakage allowed to go on without being detected? But do I know that that's absolutely the reason? I don't know that, not right now. Okay. I've only got two more. Ongoing activities, we're reviewing or have reviewed the Davis-Besse initial root cause, and we will review the final root cause for generic implications of that and use that information to get back into MRPs recommendations as far as inspection to the plants. And we're also taking a look back at the Owners' Group work that was done back in the early '90s. They did some work on head wastage, and we want to take a look at that and see does this really change any of that? CHAIRMAN APOSTOLAKIS: Are you done? MR. MATHEWS: Yes. I'll quit. MEMBER FORD: Questions? CHAIRMAN APOSTOLAKIS: Yes. I mean I'm amazed that you say you are not planning to do an uncertainty analysis. Uncertainty analysis is not an academic exercise. You keep telling me that there are all these experts that are looking at the huge scatter of data and so on, and then at the end we're not going to do an uncertainty analysis. MR. MATHEWS: Well, we're definitely going to do all kinds of -- CHAIRMAN APOSTOLAKIS: I'm amazed. MR. MATHEWS: We're going to do all kinds of sensitivity studies and look at the various parameters that go into the model and determine -- CHAIRMAN APOSTOLAKIS: Sensitivity studies, are you going to do them two at a time, three at a time, variables, playing all sorts of games to really gain insights? I mean to vary one variable at a time doesn't really do much for me. MR. MATHEWS: Well, the nature of the Monte Carlo is you do them all at once. CHAIRMAN APOSTOLAKIS: And that's a sensitivity study? MR. MATHEWS: No. You do -- well, yes. You put all of the uncertainty of all of the databases and all of that, it goes in there at one time and you do a Monte Carlo sample -- CHAIRMAN APOSTOLAKIS: Well, that's not sensitivity, that's uncertainty analysis. MR. MATHEWS: Right. But doing the sensitivity we'll go in and we'll change some of those parameters and distributions. CHAIRMAN APOSTOLAKIS: But you said you were not planning to do that. That's why I'm amazed. If you were planning to do it, I wouldn't be amazed. MR. MATHEWS: The term, "uncertainty analysis," caught me off -- we are going to do sensitivity studies to look at what the sensitivity of the analysis is to the various -- CHAIRMAN APOSTOLAKIS: Well, that's a way of doing it. That's a mechanics review. MR. MATHEWS: Yes. MEMBER FORD: Could I, just in terms of time management, call this one to a close but recognizing that there are questions along these lines, and when you come back within the next two months be prepared to answer them. MR. MATHEWS: Yes. MEMBER FORD: Mr. Chairman, am I allowed to go five, ten minutes over? CHAIRMAN APOSTOLAKIS: Well, if the Vice Chairman went over 45 minutes, I don't see why the members can't go over five minutes. (Laughter.) MEMBER FORD: Okay. CHAIRMAN APOSTOLAKIS: There's no schedule today anyway, so keep going. MEMBER ROSEN: Let's establish some sort of quantitative mechanism or a curve here, we can begin to -- MEMBER POWERS: Could I ask a question? CHAIRMAN APOSTOLAKIS: Yes, sir. MEMBER POWERS: Something perplexes me a little bit here. The speakers indicated the time that the nozzle was allowed to leak, I guess is the word, and Davis-Besse may have been key. And he said leak without being detected. Okay? And then we have inspections of the other things, which presumably have some probability of detection so that some of those declared not to have any cracks may in fact have cracks and may in fact be leaking but we just don't detect it. What are we doing about that? MEMBER FORD: A related question to that is we are assuming that when you see a nozzle, the popcorn on the top of the nozzle, that is the sufficient evidence that you've got a crack underneath. That's something that we've questioned. Could you have a crack down below the J-weld and not see the popcorn at the top? MEMBER POWERS: Well, I think the answer to that is yes. MEMBER FORD: Well -- MEMBER SIEBER: It's not through-wall or plugged. Either way you won't get -- MEMBER FORD: Well, plugged over the surface. We've asked that question, and that's under consideration. The other question is to whether from human error you don't see it. MEMBER SIEBER: Right. MEMBER FORD: That one has not been addressed apart from in the Duke presentation on Oconee the human error was addressed of not seeing it. But recognize this is still a fairly recent phenomenon, if you like. MEMBER POWERS: Well, I mean isn't it the conclusion that you come out of this as, "Gee, our methods of inspection are inadequate." MEMBER FORD: This is something you may have from the staff, because this might be a policy decision. CHAIRMAN APOSTOLAKIS: I'm not sure it's the methods. Ultimately goes to the safety culture. MEMBER FORD: But that question about -- CHAIRMAN APOSTOLAKIS: It didn't say -- it doesn't say here that they didn't know because, it's just they didn't pay attention. MEMBER FORD: This question of management of this whole situation by inspectors -- CHAIRMAN APOSTOLAKIS: This gentleman wants to say something; he's been trying for a while. MR. MATHEWS: I was just going to say that the human error -- this is Larry Mathews, I was just up there. The human error part could be easily factored into the inspection on a probablistic fracture mechanics as a probability of detection. CHAIRMAN APOSTOLAKIS: It could be easily placed there. Now what value you use is not going to be easy. MR. MATHEWS: Oh, yes. We have to figure that out. (Laughter.) CHAIRMAN APOSTOLAKIS: That's the whole issue. MEMBER SHACK: Sensitivity studies. CHAIRMAN APOSTOLAKIS: Oh, you do sensitivity, excuse me. MEMBER FORD: The answer to your question may well come up in the staff's presentation. Could I ask the representatives from Davis-Besse to come up. Normally half an hour but make sure you have enough time to present the stuff on the risk assessment aspect. John Wood and Ken Byrd from Davis-Besse. MR. WOOD: Good afternoon. My name is John Wood. I'm the Vice President of Engineering Services for First Energy Nuclear Operating Company. In our agenda today, I'll be discussing the information that we presented to the subcommittees on Tuesday. And then at the end of that, we'll have, at the subcommittees' suggestion, a discussion of the safety significance assessment that was given to the staff early this week. I'd like to just cover a couple points on background for Davis-Besse in that if you'll note in the middle there we have 15.8 effective full-power years at that Unit. Toward the bottom, hot leg temperature is a little bit hotter than other Babcock & Wilcox plants at 605 degrees up. That's about three or four degrees higher based on our core delta T. And we have 69 nozzles at our Unit. Sixty-one of those have control rod drive assemblies, seven are spare and one is used for a head vent that goes to our steam generator. This is a depiction on the next page of our reactor pressure vessel head configuration. The insulation is shown across horizontally here. You'll note that the dose above the insulation in the area of the flanges is about one-half a rem per hour. And beneath the head the dose is approximately three rem per hour. And those are the fields that we have to engage as a head sits on the head stand. In our next picture, or actually two pictures, what we have shown on this slide is the reactor vessel head sitting on the head stand in the left-hand picture with a couple gentlemen working up above. The picture on the right has been cut open this outage in order to access at the flange level. That area is 20-some feet below where those gentlemen on the left are standing, so typically people would be working in and around the flanges using 20-foot-long handled tools. The next diagram depicts a typical B&W control rod drive nozzle. It is shown in its position. There's a shrink fit of about one-half to one and a half mils that enters into the low alloy carbon steel. You can see there the shell cladding and the J-groove weld. Now, when I talk in a little bit about cracks, the cracks that we have depicted actually are on the OD of the tube on the wetted side, or ID, of the main reactor vessel head. And then through-cracks would go up past the weld into this annular space here. We went through details Tuesday with the subcommittees in regard to the UT examinations that we performed at Davis-Besse. This picture depicts the below or underhead UT examination tool. It has been demonstrated, using EPRI capability, to detect actual and circumferential flaws. It is delivered with a robotics system and an automated data acquisition system. This was used on all 69 nozzles at Davis- Besse, and then those nozzles produced indications of flaws were also inspected the top-down UT examination tool, and that has ten transducers in order to characterize the flaws. MEMBER POWERS: Would you give me an idea how long it took to inspect 69 -- MR. WOOD: That inspection period for Davis-Besse was approximately 96 hours. And that is around-the-clock time. Our UT examination results, and these, again, were detected with the underhead and then confirmed top-down, are shown on the next page. You'll see that there's six nozzles listed here. The first five had cracks indicated, the first three were the through-wall cracks. You can see Nozzle 1 had nine actual tracks, two went through-wall, and nozzle Number 2 had eight actual cracks, one circumferential flaw. And that circumferential flaw was approximately 30 degrees, a little bit more than an inch in length, 1.2 inches in length, and was about 50 percent through-wall for the nozzle. I should mention also the nozzle is approximately 0.63 inches thick. Number 3, of course, the one that has the cavity associated with it, had two through-wall leaks and there were cracks on Nozzle 5 and 47. Number 46 did not have a crack indicated; however, there's an investigation with a backwall signal on 46. CHAIRMAN APOSTOLAKIS: These examinations were done when? MR. WOOD: These were done approximately in early March, the first week in March. Actually, the last part of February, early March. CHAIRMAN APOSTOLAKIS: After the problem was found. MR. WOOD: That's -- no. This led to the finding of the problem. CHAIRMAN APOSTOLAKIS: Oh, this led to the problem. MR. WOOD: That's correct. This was the 100 percent UT examination of the nozzles at Davis- Besse was done in conjunction with our answering of 2001-01 in our extension from the end of the year to February 16. CHAIRMAN APOSTOLAKIS: But were examinations like this done routinely and on a periodic basis? MR. WOOD: No. At the time, we had the most extensive examination of the head using ultrasonic examinations. CHAIRMAN APOSTOLAKIS: So that was the first time you did this? MR. WOOD: That's correct. MEMBER POWERS: These were surprises to you? MR. WOOD: It was not entirely surprising that we had axial cracking. Based upon the information of 2001 and the information that we were getting from the industry, we expected to find some cracking. We did not expect to find through-wall necessarily and certainly didn't expect to find the cavity that we found on Nozzle 3. MEMBER POWERS: I'm sure that was a -- but I'm just asking about the -- MR. WOOD: Right. In fact, our plans included fixing up to four nozzles in our base plan for this refueling outage. This diagram lays out the nozzles that were found with cracks. Those are indicated in both the red and the green. I will note that the five nozzles in the center of the head are all from the same heat, and I'll talk about that later. Those are the only five nozzles from that heat at our Plant. You can see Nozzle 2, which had the circumferential crack, was located in this quadrant, and there was a very small amount of wastage in this area of Nozzle 2 that I'll talk about in a little bit as well. I guess that's the next slide. As we were going through the repair process for the nozzles, we did note, as it's shown here, as we machined up, as Larry discussed the repair process used by Framatome, you machine up and then the intent is then to weld onto the carbon steel. We did find a small cavity in that area. Its dimensions are approximated on this sketch. We have since removed that nozzle for further clarification. It is essentially as depicted here. It goes about a quarter to three-eighths maximum depth, as indicated in the reactor vessel head. MEMBER POWERS: You mentioned that the afflicted nozzles came from a particular heat, and the reason you know that is because of your Appendix B requirements? MR. WOOD: That is part of the MRP process that we have been working on and also the response of 2001 and the Babcock & Wilcox Owner Group efforts, knowing what the heat numbers are for the various nozzles in all the plants. The primary reason we're here today is the Nozzle 3 cavity. This is depicted in this drawing, or this picture. I will remind you that this circular hole where the nozzle was located is approximately four inches across. You can see there is some wastage on the right-hand side at the surface level, and this is the stainless steel cladding evident at this location. This is our number one nozzle, so this would be the dead center of the head, and flow downhill in that direction. The next page is more of a display of some of the numbers that we have determined using various tooling. It does not show the surface wastage that is off to the right. You can see there's a difference in color here. This is to represent a nose or an overhang, and there is additional erosion at -- or corrosion that goes on underneath that zone. You'll also notice that there is a proposed 13-inch circular cut line indicated here. In order to better capture this area, we're going to cut that out in one piece using an abrasive water jet, and that will then be retained for further evaluation as we go forward. That abrasive water jet will also leave us a very smooth finish that we can then prepare a final fit up of the forged disc that we discussed in concept yesterday with the NRC staff. The exact location of that cutout will be determined to optimize all things involved. After we found the cavity area around Nozzle 3, we chartered a root cause initial investigation team using First Energy personnel to lead the effort. Those individuals were not from the Davis-Besse staff. We did include members from the Davis-Besse staff on the team, as well as augmented it with industry experts from Framatome, Dominion Engineering and EPRI, as listed here. The team came up with a probable timeline using best engineering judgment in looking at the evidence that we had from the period of time in question. What you see here is a summary of that probable timeline. It shows that the crack potentially propagated through-wall in the '94 to '96 time frame, and thus went basically unaddressed for a period of two to three operating cycles. CHAIRMAN APOSTOLAKIS: Now, that's where I have a question. What does that mean? Were you aware that there were cracks? MR. WOOD: No, we were not aware that Davis-Besse had cracks at that time. CHAIRMAN APOSTOLAKIS: So when you say unaddressed, what do you mean by unaddressed? MR. WOOD: Unaddressed means that the leak was allowed to be active without awareness for that period of time. CHAIRMAN APOSTOLAKIS: Did you have any indications there was a leak? MR. WOOD: In a retrogressive look, certainly there were missed opportunities, and I believe the staff will relate those as well. And as I go through some of the contributing causes, there were reasons that the staff used to perhaps not center on those clues that a leak was occurring on the nozzle region. Now, I'll talk -- CHAIRMAN APOSTOLAKIS: All the rules and regulations were followed. You were not in violation of anything. MR. WOOD: I don't think I'm in a position at this point to say that there was nothing that was violated. Certainly, there were people with very good intentions that were doing the things they thought were right. As we look back, things did not go according to the desires and the expectations that should have been in place. CHAIRMAN APOSTOLAKIS: And that was, in your opinion, more a matter of judgment, which perhaps was poor in this case? MR. WOOD: Certainly, poor judgment. CHAIRMAN APOSTOLAKIS: Okay. MEMBER LEITCH: What gives rise to the probability that the crack initiated about three years before it went through-wall? Is that based on some crack growth rate? MR. WOOD: That's based on the same crack growth rate that you would have heard from the MRP individual -- Larry. MEMBER LEITCH: Then I guess one could assume that since we see no crack in Nozzle, what is it, four? MR. WOOD: Number four. MEMBER LEITCH: That we have a certain degree of confidence that it would not go through-wall within one cycle of operation. MR. WOOD: That's correct. But that's based on probabilities and not certainty. MEMBER LEITCH: Yes. Because Nozzle 4 seems like it's crying out to crack, right? I mean it's MR. WOOD: Well, and there have been numerous people, including myself, who have asked over and over and been told again and again that Number 4 does not have cracks. MEMBER SIEBER: Yet. MR. WOOD: Yet. And that's an important yet, and that's true with all the nozzles that are in that head. MEMBER LEITCH: Okay. Thank you. MR. WOOD: Now, the probable cause here is really of the failure mechanism, that being the cracking. And since we were in the repair process prior to finding the cavity -- as I have mentioned earlier, the repair effort requires us to grind up the nozzle from below to above the J-groove weld, and so the cracks themselves were taken out as a result of doing that. So that's why it's listed as probable cause because we don't have material to identify it as a factual root cause. But every indication -- MEMBER SHACK: Nobody tried to map the cracks as they were grinding them either. MR. WOOD: That's correct. We did have UT data that we showed the subcommittees Tuesday that mapped them out in the general sense but not to progress and grind in PT, as an example. With what we know that is happening in the industry on Alloy 600 and the control rod drive nozzle issue, we feel confident that it is primary water stress corrosion cracking that resulted in the crack initiating propagation and then allowed leakage to the reactor vessel low-alloy steel head. MEMBER FORD: If I could ask a question. It's fairly obvious that the initiating event was primary water stress corrosion cracking rising to a liquid of some sort in the annulus. But the key question is why did that environment give erosion or corrosion of the low-alloy steel in your condition but did not in many of the others, like Oconee? And that's the root cause question that needs to be answered. MR. WOOD: Correct. And the root cause of the cavity being there is this next page. MEMBER FORD: Okay. MR. WOOD: And that is our Boric Acid Corrosion Control and In-Service Inspection programs did not allow us to see that leakage at an earlier time. Now, this is, again, looking backwards at the data that we had at hand, but we feel that the leak had existed through-wall for two to perhaps three operating cycles and thus did not allow us to identify that -- CHAIRMAN APOSTOLAKIS: I'm confused by the words on this slide. MR. WOOD: Okay. CHAIRMAN APOSTOLAKIS: "The Boric Acid Corrosion Control and In-Service Inspection programs and the program implementation resulted in the Plant not identifying the through-wall crack." What does that mean? That the program resulted in you not identifying it? MEMBER SHACK: The failure to implement the Boric Acid Control Program. MR. WOOD: Right. CHAIRMAN APOSTOLAKIS: Oh. MR. WOOD: The Program neither robust enough nor was it implemented sufficiently in its form to detect the crack. So had it been, let's say, more robust and more rigorous applications, that would have been one approach. Even apart from that, had it just been implemented appropriately or properly, it would have been the other case. CHAIRMAN APOSTOLAKIS: So you are blaming both the Program and the implementation, at this point anyway. MR. WOOD: That's correct. MEMBER SIEBER: Now, I have a question. You, actually, when you asked for your extension from the bulletin schedule for inspections, you relied on videotapes, as I understood it, to say that leakage was not there? MR. WOOD: Yes. And what I think is being asked, as we went through the effort on 2001-01 to extend our outage from the end of the year, as was requested from the staff, until the time of February 16, we did an evaluation of the information we had in hand and knowing that there was some boric acid in the vicinity, the thought of the staff was that that boric acid had come down from the flanges from above and the mindset, for whatever reason, was focused on circ cracking and not on the potential wastage issue that we eventually found. MEMBER SIEBER: Did anybody from the NRC staff see those videotapes before the extension was granted? MR. WOOD: I cannot answer that question directly. MR. BATEMAN: Yes, I can answer that question. We spent about three hours looking at videotapes from the 1996 inspection, the 1998 inspection and the 2000 inspection. And there were substantial amounts of boric acid on the head at that time. MEMBER SIEBER: Did you, like the Licensee, assume that it came from the joint in the housing up above? MR. BATEMAN: We did not have that discussion at that point in time. MEMBER SIEBER: Okay. Thank you. MR. BATEMAN: By the way, Bill Bateman from the staff. CHAIRMAN APOSTOLAKIS: So let me understand the second bullet here, "Plant returning to power with boron on the RPD head after outages." So Plant personnel knew that there was boron on the RPD head after outage? MR. WOOD: There were individuals at the Plant that knew there was boron on that head, that's correct. MEMBER SIEBER: And, apparently, the staff did too prior to granting the extension. CHAIRMAN APOSTOLAKIS: They thought it was coming from the flanges. MR. BATEMAN: This is Bill Bateman from the staff again. I want to make it clear that the videos that we looked at were videos inside the shroud area around the mechanisms, not outside where the weep holes -- I think you saw the picture yesterday -- where the weep holes actually -- it dripped down from the holes onto the -- near the bolt circle on the head. We did not look at -- we did not see those particular pictures. We were inside that shrouded area of the videos that we looked at. MEMBER SIEBER: This was through those mouse holes. MR. BATEMAN: Right. MEMBER SIEBER: Camera on a stick? MR. BATEMAN: Right. Yes. Those are the videos we looked at. MEMBER SIEBER: Okay. CHAIRMAN APOSTOLAKIS: Okay. You said, Jack, that they knew there was boron there and they assumed it came from the flanges. So what, didn't they still need to clean it up? I mean whether you clean it up depends on where it's coming from? MEMBER SIEBER: I would have thought so at the time, but I'm not sure that everybody makes their -- up until today, makes their reactor vessel head squeaky clean each time they do an inspection. CHAIRMAN APOSTOLAKIS: But there's a difference between each time and not doing three or four times. MEMBER SIEBER: That's true. MEMBER POWERS: By the way, George, I just remind you of a point that was made at the beginning of the presentation. This is -- doing things on the vessel head that aren't absolutely required is a highly costly thing, not only in time but because of the radiation dose that you incur to your workers. So if you don't think you have to do it, you're probably not going to do it. CHAIRMAN APOSTOLAKIS: So the question is when do you decide that you have to do it? MEMBER POWERS: That's right. CHAIRMAN APOSTOLAKIS: Now, maybe you have already explained it, what is 12RFO? MR. WOOD: Twelfth refueling outage. We're currently in our 13th refueling outage. CHAIRMAN APOSTOLAKIS: Okay. Thank you. MR. WOOD: Okay. And as we have just been discussing, the environmental conditions which contribute to this is the cramped conditions of the design. And by that I mean there's about two inches of clearance between the top of the head and the insulation. As was mentioned, we have 18 weep holes near the bottom that provide us some access. And we, therefore, did not take appropriate compensatory measures as a result of these cramped conditions to allow ourselves to find that leakage. Another contributing cause was the fact that in the late '80s, early '90s, there was much leakage of the CRDM and flanges above the insulation, which allowed some boron to pass through to the head and participated in the mindset of the staff at the time. Now, I did mention the fact that we had a material heat that was unique for five nozzles, four of which had cracking, three of which had through-wall cracking. And all three of those nozzles that had through-wall were from this heat listed. We're aware that that heat is used at two other B&W plants. One plant has all but one of their nozzles from that heat; another B&W plant has one nozzle from that heat. The one that has the majority has been well-inspected and has thus contributed to a database that suggests that 20 percent of this particular heat of nozzles has cracked or has had evidence of cracking thus far. We spent some time Tuesday talking about crack length versus leakage. I don't intend to go into a long conversation on that, but I did want to mention that our unidentified leak rate at the Plant during the period of time in question was approximately 0.1 to 0.2 gallons per minute. So that is well below the tech spec limit of one gallon per minute. And you can see the fact that the longer crack lengths have more damaging corrosion resulting from them. Whether that's just evidence that it is interesting at this point or it is matter of fact, we don't know for certain. MEMBER POWERS: Could you give me some idea of what the width of the cracks is? MR. WOOD: The width of the crack, I don't have that information. I don't know if anyone from the staff does in the back there. MEMBER POWERS: Real tiny, as big as my finger? MR. WOOD: Very tiny, and we're talking in the orders of a thousandths of a gallon per minute up to the 0.2, 0.8 region. And so -- MEMBER POWERS: That's what I was looking for. MR. WOOD: Okay. As a result of our meeting Tuesday and getting together with -- CHAIRMAN APOSTOLAKIS: Before we go on, if I were to take with me the top two causes why this situation developed, what are they? Something must have gone wrong someplace, so what are the top two causes, so I remember? I read a lot of stuff and they say a lot of things, the timelines and this and that, but if you ask me what was the number one and number two contributing causes, I have difficulty figuring those out. So can you summarize them for us? MR. WOOD: Well, I think number one was the Boric Acid Control Program and the application of that. CHAIRMAN APOSTOLAKIS: Okay. MR. WOOD: I guess almost everything else pales by comparison. CHAIRMAN APOSTOLAKIS: Okay. MEMBER KRESS: I would have listed the potential for having a bad heat. There are cracks already there. MR. WOOD: Granted however in this business we're accustomed to dealing with things that may be first of a kind or second of a kind or whatever. So we wouldn't want to use the fact that we had a bad heat as the indicator of the cavities, the indicator of the crack. MEMBER KRESS: You still have to deal with those. MR. WOOD: Correct. MEMBER SIEBER: There may be an issue of standards involved too on the part of the inspection personnel and decision makers. MR. WOOD: Yes. Those standards of course will go to the very top. That's where standards come from. CHAIRMAN APOSTOLAKIS: I'm sorry. What standards are these? I missed it. MEMBER SIEBER: The kind of standards one would expect from a professional organization that operates a nuclear power plant. CHAIRMAN APOSTOLAKIS: Isn't that what some other people call safety culture? MEMBER SIEBER: That's a piece of safety culture. CHAIRMAN APOSTOLAKIS: Yes. It can be all of it. MEMBER SIEBER: Questioning added to high standards. CHAIRMAN APOSTOLAKIS: Yes. Okay. MEMBER SIEBER: Vigilance. MEMBER ROSEN: The application of the corrective action systems. CHAIRMAN APOSTOLAKIS: Okay. Thank you. MR. WOOD: Okay. Then as a result of our meeting on Tuesday, Peter Ford asked that we would include safety significant assessment. So we have Ken Byrd who will present that. MR. BYRD: Okay. My presentation will be a very brief summary of the results of a safety significance assessment that was provided to the staff earlier this week. For this assessment, we considered a range of breaks from very small to the size described on the top of this page 23. So that for the maximum size, we assumed the failure of the exposed cladding area which is approximately 25 square inches. In addition, we assumed that the whole was 50 percent larger than the exposed cladding area for about 38 square inches. We also assumed that CRDM Number 3 would eject. So our total area was approximately 50 square inches or 0.35 square feet. We're looking at a range from very small up to 0.35 square feet. For our analysis, we evaluated three critical functions. MEMBER ROSEN: Now before you get off that in terms of assumptions. You've obviously made the assumption although it's not shown here that nothing else was damaged. There was no additional damage. MR. BYRD: No, sir. I'm going to talk about that next when I look at these next three functions. MEMBER ROSEN: Okay. MR. BYRD: I'll get to that. We looked at three critical functions when we did this analysis. We looked at the ability to have core cooling, to maintain shut down margin, and finally containment integrity. We do not have a Davis-Besse ACE, an analysis for a LOCA at this specific location. However our LOCA analysis covers a spectrum of LOCAs from 0.01 square feet up to 14.2 square feet. Setting aside at the moment collateral damage, this particular LOCA is equivalent to a hot leg LOCA with respect to core cooling. In that respect we would get injection flow going through the core for both core cooling and for boron precipitation control. Therefore with respect to core cooling, we were bounded by our existing LOCA analysis. Let's go on to my second bullet here which relates to shut down margin. I think this is where we get into the concern about the issue of collateral damage that might occur to adjacent control rod drive mechanisms. Consequently we had Framatome ANP do an evaluation of the potential for damage to adjacent control rod drive mechanisms. The Framatome Analysis looked at several different mechanisms. They looked at jet loadings. They looked at pressure loadings. They looked at loose debris which might mechanically jam an adjacent control rod drive mechanism. The results of their analysis was that it was unlikely that an adjacent control rod drive mechanism would be affected. Not withstanding that result, we went ahead and had them do a further analysis to look at the impact of all of the control rod drive mechanisms. We actually looked at five control rod drive mechanisms surrounding the affected area. Failing to insert is a result of collateral damage. In addition to that, we added one additional control rod which would be a random control rod failing to insert with the highest shut down margin for that control rod. With those six control rods failing to insert as a result of this accident, we were able to have both immediate and long term shut down margin. MEMBER ROSEN: Is that for the conditions that the Davis-Besse found themselves in at the end of the day on February 16 or whenever it was that you shut down? Was that a more general conclusion for any time during the cycle? MEMBER FORD: Before you answer, Ken, could you just let the Committee know if the staff have not reviewed this analysis yet? MR. BYRD: No. MEMBER ROSEN: So let me repeat my question. Is that result that you had plenty of shut down margin even with those six rods not reinserting? Was that a general result for if this had happened at any time during the cycle or a specific result that applies only to that day, the day you shut down? MR. BYRD: It was really intended to apply only to that day. But the analysis was done using the beginning of life for cycle 14 which was actually a more conservative time period. MEMBER ROSEN: Okay. MEMBER SIEBER: But is the break size you had, the larger the break the better able you would be to get reactivity reduction because of the insertion of highly borated water? MR. BYRD: Yes, sir. That would be true. CHAIRMAN APOSTOLAKIS: The rod ejection effect is instantaneous, but you're at full power. So you have some full power conditions. MEMBER SIEBER: Right. MR. BYRD: Right. CHAIRMAN APOSTOLAKIS: So that reduces the concern with the rod ejection. MR. BYRD: Okay. If I could go on to the third condition that we considered. We also considered containment integrity. The issues we were concerned with here were two issues. One was the control rod ejection, actually impacting on our containment. The other issue would be the mass and energy release from the particular LOCA. With respect to the first of these issues at Davis-Besse, we have missile shields above the control rod drive mechanisms which would prevent an ejected control rod from impacting a containment. With respect to the second issue, mass and energy release, this particular LOCA is bounded by much larger LOCAs which have been analyzed. So we did not see any significant issues with respect to containment integrity. MEMBER POWERS: Let me ask a question that you may not have the answer to. If you have blow out in that particular location, do you put an unusually large amount of mass into your sumps that could clog some pumps and things like that? MR. WOOD: No. That area would not be directly driven towards the sumps. That would be within the refueling canal. Then you saw the service structure arrangement around it. So there's not a lot of direct accessibility out of that into the sump area which is quite a ways away from that. MEMBER SIEBER: The refueling canal is empty during operation. MR. WOOD: That's correct. MEMBER SIEBER: You use a diaphragm between the vessel flange and the edge of the canal. MR. WOOD: No. There would be an opening in that area. MEMBER SIEBER: During operation. MR. WOOD: During operation. MEMBER SIEBER: That's the flow path to the sump. MR. WOOD: Right. MEMBER SIEBER: Okay. So there is a connection. MR. WOOD: The sump itself is up on a different level beneath the head. But would initially accumulate. MEMBER SIEBER: Okay. MEMBER POWERS: So it's a fairly contorted path that something would have to follow to get to your sump. MR. WOOD: That's correct. MEMBER SIEBER: It would have to go uphill. MEMBER POWERS: It wouldn't be so uphill. MEMBER ROSEN: The insulation that's above the head in that region is reflective insulation. There's no silicacious insulation. MR. WOOD: That's correct. MEMBER ROSEN: That's all metal in pipe insulation. MR. WOOD: Right. MEMBER POWERS: That didn't help you much. MEMBER KRESS: It's gets really pushed around a lot. MEMBER ROSEN: Well it does actually. MR. WOOD: However all that insulation would have been inside of the service structure. MEMBER ROSEN: The three GSI-199 is the most damaging kind of material. It is the kind of material that can plug the screens. Typically it's the silicacious sand-like material that -- MEMBER POWERS: No. MEMBER ROSEN: Plans toxin fibrous material and end up building the building up across the sumps. MEMBER POWERS: Fibrous material is of course very bad. But we've seen experiments showing that you can shred this stuff up. That shredded material is not too good either. MEMBER ROSEN: It may be. But I think if you read GSI-199, the most recent staff stuff that came out of, which lab? I'm trying to remember which lab. I think that report indicates that the worst material comes out of Los Alamos and the University of New Mexico. So I'm reasonably familiar with it. MEMBER FORD: If I could interrupt, could we just get this one through? Again I'm looking at the time. MR. BYRD: Okay. Going on to the next page. As a further effort to address the safety significance of this condition, we had a stress analysis of the as-found head condition performed. This stress analysis is a three-dimensional finite element, stress analysis of the wasted -- and the reactor pressure vessel head. We had a failure criterion set at the maximum strain of 11 percent through the thickness of the clad. We had the results verified by an independent analysis. We had this both performed by Framatome ANP and Structural Integrity Associates. The results were that the degraded cavity would maintain its integrity in excess of twice the transient loads. The results for the two analyses were fairly consistent. MEMBER SHACK: What's the rational for the 11 percent? MR. BYRD: This particular analysis is an input to my safety assessment. I think I have an expert here from Framatome who could probably address that better than I can. CHAIRMAN APOSTOLAKIS: Please identify yourself. MR. FYFITCH: I'm Steve Fyfitch from Framatome. The rational here is that's actually a conservative value that they used for the analysis. The 11 percent comes from an Oak Ridge report that we have access to that looks at 308 in stainless steel weld metal. The 11 percent is where necking starts to occur in the tensile test. We assumed that 11 percent was the failure strain. So it's in fact a very conservative because once the uniform elongation starts to disappear, it actually goes out and total elongation about 30 percent. MR. HACKETT: Bill, this is Ed Hackett from the staff. A follow up to that would be we're doing confirmatory analyses too as you know for the criterion failure strain. That number probably needs to be adjusted, Vom Mises or Treca for the multi-axial state of stress that would exist in the head. So probably the real number should be less than 11 percent. I don't know what the number should be. As Steve pointed out, that number is from uni- axial tension test. So what you have is at least a bi-axial state of stress in the head. That will come down somewhat. We're looking into that right now. MR. HERMANN: Ed, I think in the models the tensile stresses that were taken were compared to Vom Mises output in the models. MR. HACKETT: The 11 percent already reflects a Vom Mises or Treca adjustment. MR. HERMANN: Yes. It's just a comparison of what came out of the tensile stress versus that's not what was in the model. It was just a comparison of that. A unilateral strains. MR. HACKETT: Okay. Thanks. MEMBER FORD: For the Recorder, that was Bob Hermann. MR. HERMANN: Bob Herman from Structural Integrity. MR. BYRD: Now going to my last page. The results of this analysis on the previous page indicated that the expected failure pressure was well in excess of the pressure for any postulated transients. It's also well in excess of the pressure for any transients that have actually been experienced at Davis-Besse. However to estimate a risk of the as-found condition, we looked at the probability of a failure occurring at less than this estimated pressure based on our stress analysis. The results of this indicated that there are core damage frequency we estimated to be in the range of 1 times 10 to the minus 5th per year. The larger the release frequency was approximately of 1 times 10 to the minus 8th per year. Our public health risk was approximately 0.56 person rem per year. CHAIRMAN APOSTOLAKIS: Are these Deltas given these conditions? MR. BYRD: Yes, sir. These are Deltas. CHAIRMAN APOSTOLAKIS: So what is your baseline CDF? MR. BYRD: My baseline currently for internal events is 1.2 times 10 to the minus 5th per year. MEMBER ROSEN: Ten to the minus what? MR. BYRD: Fifth per year. CHAIRMAN APOSTOLAKIS: So your doubling. MR. BYRD: Approximately doubling our internal event baseline. MEMBER SHACK: Now as I'm corroding away at two inches a year, how many weeks do I have to wait until this thing goes? MR. BYRD: We have that analysis currently in progress. We're expecting an answer to that relatively soon. We have an analysis that will give us the size at which point we would have a failure at a normal pressure. As far as how long it would take to get to it, I think that's a little bit more speculative. CHAIRMAN APOSTOLAKIS: So this is given that I have the amount of degradation that was observed, the core damage frequency would be 10 to the minus 5. MEMBER KRESS: The maximum it could be is conditional. What's the conditional core damage frequency? CHAIRMAN APOSTOLAKIS: Well it is conditional. MEMBER KRESS: Given that you have the hole there. CHAIRMAN APOSTOLAKIS: Oh, the hole. MR. BYRD: If we had a LOCA? MEMBER KRESS: Yes. MR. BYRD: That would be a conditional core damage probability. In the calculation of this core damage frequency, we evaluated the conditional core damage probability from a range all the way to very small up to the 0.36. The largest was at about 0.1 square feet. That was 2.9 times 10 to the minus 3rd. CHAIRMAN APOSTOLAKIS: You said 0.36? MR. BYRD: The hole size with the maximum core damage probability. CHAIRMAN APOSTOLAKIS: So you estimated the probability of this LOCA to be the order of 7 10 to the minus 3. MR. BYRD: I'm sorry. CHAIRMAN APOSTOLAKIS: What's the frequency of this LOCA? MR. BYRD: I guess it might be easiest if I could just take a minute here and walk through the process because I think I have a few questions. Essentially what we did was we understood that at the pressure we calculated we weren't supposed to get a failure. So we looked at ways that this would fail at less pressure. There's a couple of things that came to our mind. One was a sizemic event. The other being overpressure transients that didn't actually get to this pressure. With respect to the sizemic event, we have recently completed a sizemic PRA. We looked at that. Based on the results of that a sizemic event of sufficient magnitude to cause this damage in Northwest Ohio the frequency is very small. So that was a very small contributor. The other thing that we looked at though was overpressure transients. We recognized that this number that we had from the stress analyses is a calculated number. It's dependent on a number of things such as the analysis, the actual condition of the clad, and the material strength. So we employed a process that is outlined in NUREG 2300, the PRA Procedures Guide and NUREG 5603 and 5604. This is a process we've used for doing our interfacing system LOCA type of evaluations in our PRA. It's also similar to what we use in our sizemic analysis and in our external event tornado analysis. To do that you actually assume a median failure capacity which we took to be the number we got from the stress analysis. Then we had to develop a logarithmic standard deviation. To do that we went to the new rigs and looked at the various different tabulated standard deviations for materials, for temperatures and different kinds of configurations. We took one that basically bounded the results we've seen in there. This is a way of approximating the probability that the failure might occur earlier. Based on that we were able to calculate the probabilities of failures at pressures of about 5600. We were able to come up with probabilities of 3 times 10 to the minus 3rd to 7 times 10 to the minus 3rd depending on the pressure. So that gave us a probability of failure at a given pressure. Then we had to determine since we weren't trying to calculate a frequency, we had to calculate a frequency which over pressure transients would occur at the plant. To do that we went back through our plant history all the way back to 1979 and looked at all of our overpressure transients. We actually calculated frequencies for various different categories in terms of the extent to which they overpressurized the plant. Then we were able to calculate a frequency of that we would get a transient that would actually cause a LOCA. That number was in the order of 4 times 10 to the minus 3rd which is about to give you a feeling two orders of magnitude higher than our normal medium LOCA number. CHAIRMAN APOSTOLAKIS: Does the number of 10 to the minus 5 include as part of the conditions the possibility of the six rods not going in? MR. BYRD: Based on our deterministic analysis, we had evaluated that even if the six rods did not go in, we would have sufficient shut down margins. So we did not specifically include that. CHAIRMAN APOSTOLAKIS: All right. MEMBER FORD: Okay. If I could jump in here. I'm watching the time here, George, unless you want to extend into your other time. CHAIRMAN APOSTOLAKIS: No. That's unfair. I shouldn't extend it if I want to ask questions myself. MEMBER FORD: That's right. CHAIRMAN APOSTOLAKIS: Let's move on. MEMBER FORD: Thank you very much indeed. I appreciate your comments. Let's call on Jack Grobe. You're now going to hear two presentations by the staff. CHAIRMAN APOSTOLAKIS: Should we take a break? We've been going forever. Do the members want to take a short break? MEMBER KRESS: Yes. MEMBER SIEBER: That would be good. CHAIRMAN APOSTOLAKIS: Okay. We're recessing until 3:50 p.m. Off the record. (Whereupon, the foregoing matter went off the record at 3:40 p.m. and went back on the record at 3:50 p.m.) CHAIRMAN APOSTOLAKIS: On the record. Back in session. MR. GROBE: My name is Jack Grobe. As was mentioned, there's three presentations this afternoon from the staff. I'm going to present the results of a recent inspection that was completed about a week ago. We exited on that inspection last Friday. Allen Hiser will then present the status of Bulletin 2001- 01. Ken Karwoski will present the current status of the bulletin responses for Bulletin 2002-01. Being from Region III, I'm the Director of Reactive Safety. I don't get to see you folks very often. I appreciate the opportunity to be here. Quite frankly I'm quite embarrassed to be here. As I go through this you'll see why. This wastage occurred over a period of years. Our staff did not identify it. Certainly the Davis-Besse caused it and had many opportunities to identify it. We'll get into that a little bit. I was going to cover three topics. The first and third I think we've addressed pretty extensively with the staff's presentation from Davis- Besse. There are just a couple of issues that I'll touch on in that area. As was mentioned there were five cracked nozzles, three were through wall. I'm going to get into a little bit of the description of the cavity, just some of the information that I think was important but not presented yet. You've already understood what happened at nozzle 2. This is just a little bit different rendering. This is an artist's rendering of the cavity. They spoke of the nose. There was substantial undercut in the cavity. In addition to that, there were some UT measurements were taken from beneath the cladding. There was an unusual result. They were taken on one inch centers. There were indications that for an extended distance outside of the visible cavity on the order of maybe two and sometimes more inches, there appeared to be a gap on the other side of the cladding. It's not clear what that is. When the licensee cuts out the cavity, they'll be able to investigate that more clearly. It's not clear whether that's a reflection. Whether it's actually a separation, it's just not clear. If you look at the physical character of the cavity, there's an uneven area quite a bit bigger than the cavity that appears to be as a minimum de- bonded between the stainless steel and the -- VICE CHAIR BONACA: Could you show us the location there? Is it possible to see the location? MR. GROBE: I don't have a slide that shows the layout of that. A plan view as it were. I don't have that. I apologize. MR. HISER: Yes. I guess just to try to provide a little bit of an answer this is Allen Hiser from NRR. It's around nozzle 11. It's just not clear at this point how far -- VICE CHAIR BONACA: Okay. Down there on the picture. MR. GROBE: Well, it actually goes laterally across the cavity as well as downhill. It appears to go the whole way to nozzle 11 and maybe somewhat around nozzle 11. Like I said it's at least in some cases two or more inches beyond the visible aspect of the cavity. VICE CHAIR BONACA: The reason I'm asking the question is that in the repair, they've already defined the size of the plug. MR. GROBE: Right. VICE CHAIR BONACA: Does that mean the plug may have to be larger than what they are planning right now? MR. GROBE: Or there may be repairs necessary. One of the first things that they are going to do after they cut out the 13 inch diameter, their current plan, is they're going to do diapenetrate testing of the surface to try to identify whether or not there's additional damage to that surface. VICE CHAIR BONACA: Okay. I understand. MR. GROBE: This is a view of the cavity. I think you can see in the lower section of the cavity there's a shiny area. That's where it was machined prior to the penetration to pitching as it were. The tube has been removed. You can see the walls of the cavity are fairly smooth. They slope in. You saw this drawing in the last presentation. There's nothing more to report on this except a characterization of the wastage area is a little bit incorrect. It comes out a little bit more now that we have impressions in the lower area. Then it tails off to be a little bit thinner. So it appears that there may be more than one mechanism. It may not just be corrosion. There may be some other things as well. I want to get into missed opportunities. I'm going to cover three areas. They are the containment air coolers, the containment radiation monitor filters and also the Boric Acid Corrosion Program implementation. Dr. Apostolakis, you asked what are the two main causes. The easy cause is to blame the Boric Acid Corrosion Program implementation. The entire operation of these facilities depends on human beings whether it's people doing designs, operators of the control panels, human beings make mistakes. Implementation of this program was not well implemented. That's by engineers. But the results of the program implementation were known to a number of people as well as a number of other precursors. I believe that the most important cause here is a complete failure of the Corrective Action Program. You'll see that as I go through my presentation. Just a little bit of system knowledge that you may not have that's important to this. There's a ventilation that the system intakes as suction on this volume here. Discharge is near the top of containment above the D-rings. The area below the insulation is connected to the area above the insulation through small gaps around the nozzles and things of that nature. So there is a communication of the ventilation system between these two areas. There are a series of almost 20 five by seven inch what are called "mouse holes" or "weep holes" that are right down here at the edge of the vessel. (Indicating.) So they are for air coming in through that direction. It's critical to understand that the discharge from these areas at the top of containment just to see what happened in the containment air coolers and radiation monitors. MEMBER SIEBER: The way out of that bottom plate and the mirror insulation is such that since the air flow is up, they don't have conoseals, but in those joints the leakage is probably not going to go down. Some of it does. MR. GROBE: The leakage will likely be horizontal. MEMBER SIEBER: That's right. MR. GROBE: It will be steaming horizontally. It will spray against other surfaced and evaporate. Then the vapor will be taken up through the ventilation system. There's been sufficient leakage at times during the past ten years that has actually leaked down along the penetrations, through the floor of this service structure and through the insulation and gotten onto the top of the head. MEMBER SIEBER: My recollection is that it's pretty windy in that area. MR. GROBE: I haven't been there. MEMBER SHACK: That is a plate though there. MR. GROBE: Yes. MEMBER SHACK: There was some picture there yesterday that gave me the impression of a gridwork that you attached the insulation to rather than a plate. MR. GROBE: I think it's a framework. Is it gridwork? MR. MCLAUGHLIN: It's angle iron. CHAIRMAN APOSTOLAKIS: Identify yourself please. MR. MCLAUGHLIN: This is Mark McLaughin from Davis-Besse. There is actual angle iron that goes across the service structure. That's what the insulation is laid on top of. MEMBER ROSEN: So you would not expect there be a large Delta P that would arise across that structure if there was a substantial steam leak below at the top of the head. Is that correct? MR. MCLAUGHLIN: That would be correct. The other thing that's not shown on there is there's insulation. See on the outside of the flange, that's were the reactor vessel hold-down bolts are. There's another layer of insulation that's L-shaped that's outside of that which covers up the bolt holes. So that would even further restrict air flow in that area underneath insulation. MEMBER ROSEN: What I was getting as was I was postulating that if you had a big leak right at that point of steam at the top of the head that somehow that insulation in that structure would somehow cock and cause some stresses. I'm trying to get the sense of whether you think that's possible. I think you're saying is this the gridwork that came with the Delta P that could create some kind of cocking of that structure. MR. GROBE: No. I think there's a fairly tight clearance around each penetration hole. This is a sheet material. Clearly the floor of the service structure is sheet material. I would expect if you're discharging 2,200 pounds into this area that you're going to get a very substantial differential pressure between these two areas. You would see some deflection in these plates which may result in some movement of the penetration tubes. I don't remember who asked the question. But they were very interesting and complex questions. These are also restrained near the top for sizemic purposes. I think you'd really have to get into how much would those bowl and what are the clearances inside before you could say how many rods would be affected. MEMBER ROSEN: Now you made me worry again. I was almost to the point where I was done worrying. I was the one who postulated this originally. Now I'm back to work. That's exactly what I was worried about. Because of the yards Delta P across some of this, there would be enough distortion caused by flexing of something that you could have some sort of common cause failure. CHAIRMAN APOSTOLAKIS: More about six rods. MEMBER ROSEN: Yes. MEMBER SIEBER: Well, the mirror insulation is in blocks. Right? MR. MCLAUGHLIN: I'm sorry. I didn't hear the question. MEMBER SIEBER: The mirror insulation is in blocks. Right? It's a puzzle that you put together. MR. MCLAUGHLIN: The way the mirror insulation was manufactured is if you look at it there's a flange right up above the insulation. MEMBER SIEBER: Right. MR. MCLAUGHLIN: The mirror insulation is really in long strips, I'll say. Each strip has a cut-out area for half of a nozzle along an entire row though. So what they did is they slid it in on its side. Then they laid it on top of the angle. So the insulation is installed with long strips. MEMBER SHACK: It's like around recessed lighting in your basement. MR. MCLAUGHLIN: Exactly. If you cut it around if you have recessed lighting in your basement and you cut half of one of your ceiling tiles, that's how it would look. So that's how it's installed. I would think that if you had enough of a force you might move one strip. However there is sufficient room between the insulation and the nozzles that it should move up. I would think it would tend to flip out of the way. MEMBER SIEBER: Now is there or is there not a plate involved here someplace? MR. MCLAUGHLIN: There is no plate. MR. GROBE: What's the construction of this, Mark, the floor of the service structure? MR. MCLAUGHLIN: That's just showing the circle. There's no plate inside there. The only thing that you have is the angle iron that supports the insulation. MEMBER SIEBER: The insulation is sitting in there loose. MR. MCLAUGHLIN: That's correct. MEMBER SIEBER: Does that help you? MEMBER ROSEN: A little bit. I'd actually like a more detailed drawing so I could conclude. MR. GROBE: Okay. Thank you. The tubes and fins of the containment air coolers obviously are cooler than atmosphere. Anything that's in the atmosphere they'll condense water out of the air as they're cooling the air. Contaminants in the air and moisture in the air will plate out on the fins and tubes. The containment air coolers need to be cleaned occasionally depending on leakage inside containment. They were cleaned in 1992. Prior to some substantial leakage, there was equipment that needed corrective maintenance in the 1998 time frame, late '98/early '99 which resulted in unidentified leakage in containment going from about one-tenth of a gallon per minute to about 0.8 gallons per minute. During that time frame it was necessary to clean the containment air coolers 17 times. A mid-cycle outage was taken in April 1999 to repair that equipment. Unidentified leakage only went down to about 0.3 gallons per minute after that outage. It remained higher than it had been prior to '99. Also during this time frame after the mid- cycle outage, the containment air coolers had to be cleaned twice in late '99 and seven times throughout 2000 and 2001. During that time frame, the engineers reported that the character of the material on the containment air coolers had changed. Previously it might appear as a spray painting, a very white dusty material on the fins and the tubes. During this time frame it took on a different color. It was dark brown. The Davis-Besse staff assumed that the change in color was due to corrosion of low alloy steel components in the air coolers themselves. MEMBER ROSEN: Did anybody do any measurement of the activity of that deposit? MR. GROBE: No. I don't believe so. When you say "activity" you mean specific activity, radio activity? MEMBER ROSEN: Yes. MR. GROBE: I'm not aware of that. I'm not sure if the Davis-Besse folks here are aware of that either. I did not ask that question. Okay. The radiation monitor filters. There were routine preventive maintenance to change the filters on the airborne radio activity monitors inside containment every 31 days. Prior to the '99 time frame, that was sufficient to maintain that equipment. Beginning in May '99, this is after the mid-cycle outage, the frequency of filter changes increased. Between May and August of '99, it went from about once a month as a preventive activity to every other day. In July '99, the engineer responsible for this equipment requested to have the material analyzed on the filter. The filter itself had previously never appeared reddish-brown in color. That was the character of the filter in this time frame. It was analyzed in July '99. The analysis came back that the filter was clogged with boric acid and iron oxide that was produced in a steam environment, not surface corrosion. The facility staff looked for a leak that might cause this. They were unable to find one. They assumed that the leak was from flange leakage. You can't observe the flanges during operation. In August '99, they installed banks of HEPA filters with high volume fans to try to reduce the frequency change for the radiation monitor filters. That was successful. It reduced it to about every other week. In July '01, the frequency gradually began to increase again. This is after refuel outage in 2000. It continued to increase to every other day. In October '01, the staff reported that the filters were abnormally dark brown. MEMBER KRESS: Are these little filters? MR. GROBE: I haven't seen them. What's the physical size of these filters? I don't think we have anybody here that's seen them. They're in-line filters in the air sampling system so I don't expect them to be very big. MEMBER KRESS: They're small I would guess. MR. GROBE: Yes. I've talked about the containment air coolers and the rad monitor filters. Nothing associated with the air coolers was reported in the Corrective Action System. The rad monitor filters was captured in the Corrective Action System. But the Corrective Action was inadequate to identify the source of the material. In fact some of the actions taken potentially insulation of the HEPA filters masked any ability to detect whether it was increasing on the short term. I want to talk next about the Boric Acid Corrosion Control Program. I think you're aware that this is an NRC required program. Through our Quality Assurance Regulations, it's clearly a procedure affecting the safety of the plant. So it's required to be implemented. In 1998, we issued a bulleting that required licensees to describe their program for monitoring boric acid. It's an extremely sensitive but not on-line of course way of detecting leakage. Just a little analogy here. One drop per second will leave about 15 pounds of boric acid in a year. So it's an extremely sensitive indicator of leakage. Ongoing nozzle flange leakage. The engineer responsible for maintaining the quality of the flanges was provided a period of time each outage to repair nozzle leakage, flange leakage. During some outages there was a little flange leakage. All of them were repaired. During some outages there was more extensive nozzle leakage. The engineer would prioritize those nozzles as far as how badly they were leaking and get as many of them repaired as he could before it was time to restart the unit. Nozzles were left in service leaking. In 1990, the Davis-Besse staff identified that it was necessary to have a modification to the skirt beneath the service structure. The mouse holes or the weep holes at the bottom of that skirt were not sufficient to do adequate inspections and cleaning of the vessel head. That modification would involve a number of large diameter openings around the parameter of the skirt, much higher in that skirt structure. That modification was approved for implementation in the early '90s. I think it was '94 or '95. It was scheduled in successive outages and deferred out of each of the successive outages. So the fact that the licensee was unable to do thorough inspections and cleanings of the head was of their own doing. Reactor vessel head boric acid deposits were not removed at the end of each outage. It was believed throughout that period of time that boric acid deposits on the head were not significantly hazardous. Moisture would be driven out of the boric acid and the remaining crystals would not be significantly corrosive. In the '96 outage, the boric acid that was left on the head was characterized as "patches of white loose consistency material." What could be gotten was cleaned up with mechanical means vacuuming. In '98, the boric acid was characterized as "fist-size clumps and a thin layer of generally brown boric acid around the center penetrations." Again, most of the boric acid was removed by just vacuuming. In the year 2000, the boric acid was characterized as "accumulating over the head." There was a thick layer of boric acid in the center of the head. I'm going to put a slide up now. This is from the 2000 Bulletin and as Bill Bateman mentioned a few minutes ago, the staff did not have the opportunity to see the condition of this part of the vessel head. The Boric Acid Control Program clearly indicates that if there are indications of red or brown coloring, that's an indication of corrosion. It should be pursued. In 2000, this material was approximately one to two inches deep. It had flowed out the weep holes. In fact, the material inside the weep holes was high enough to cover the weep holes. The material had to be removed with crowbars. Eventually a water wash was used to dissolve some of the material. But a substantial amount of material was left on the head. This was documented in the Corrective Action Program as was the boric acid on the head throughout this period of time. The close-out of the Corrective Action Program document, the Condition Report, actually they call them "peacocks" at Davis- Besse at this time, was listed as "head was cleaned and inspected." MEMBER ROSEN: I'm sure that you're going to take a close look at the corrosion effects of all this leakage on those bolt circles. MR. GROBE: Yes. We issued a confirmatory action letter that requires a review of the entire primary reactor coolant system. Not only the head and the bolts on top of the head, but throughout the entire system including the bottom head and other areas. Clearly there were indications of reactor head corrosion. They were not recognized as indications of corrosion and not evaluated. The licensee described the preliminary root cause, outside diameter, primary water stress corrosion, cracking cavity caused by boric acid corrosion. Significant corrosion began at least four years ago. It's pretty difficult to argue with any of that. There's a lot of issues that are clearly not addressed yet at least in documents that we've seen. They haven't submitted their corrective action document to us yet. There's very interesting chemistry I'm learning from this opportunity. Boric acid crystals begin to react with air at a temperature far below the temperature of the head and begin to form boric oxide. In addition to that the melting temperature is only slightly higher then the temperature at which that reaction starts. So you could have had a very interesting combination of boric acid, boric oxide, and liquid boric acid flowing down the head. It's not clear what role that chemistry played in that cap over the top of the head and corrosion that might have initiated from the head down. The role of head temperature throughout the operating cycle, outage times, start up times, it appears that there were times that boric acid was pooled in the bottom of this cavity. That's certainly an opportunity during shut down times when the head is at ambient temperatures. It's not clear what role that may have played in the corrosion process. The rate at which the cracks progressed and the corrosion progressed is not clear. I don't see a reason to believe that the corrosion progressed at a uniform rate through the years. So those issues are not answered. Clearly the correlation between Davis-Besse and the rest of the industry hasn't been explained. So there's a lot of outstanding questions that I'm hoping are answered to a large extent in the licensees root cause assessment. That completes the information. I apologize for being quick. MEMBER FORD: Jack, who has the action to provide that data. MR. GROBE: I'm sorry. MEMBER FORD: Who has the action to provide that data. MR. GROBE: The licensee is required to provide us the root cause. It's not clear to me that those questions can be answered without research. The grinding operation on the nozzle in penetration 3 started. The nozzle twisted a little bit and tilted a little bit. At that point the licensee did extensive cleaning operations on the top of the head to discover the cavity. All of that material is gone. Had we been able to take samples of that material, it would help. The licensee at that point had no reason preserve that material because they didn't understand what was going on. Maybe that's reason enough to preserve it. In addition, of course all the cracks were machined out. So we have no information on the cracks. It's not clear to me that we're going to have sufficient data from the licensee's analysis to answer all these questions. Likewise it's not clear to me that we need all those answers necessarily to approve an appropriate repair to the head. Those answers are important for going forward as far as Davis-Besse and the rest of the industry. So there's a lot of things that play here. I anticipate there may be some research, Hackett's ears are perking up, that will come out of this. MEMBER FORD: That comes down to the question of the timing of which this research goes to get to an identifiable goal. Bearing in mind that it's assumed that there are no other observations of such magnitude in the existing fleet. Until we have that data we don't know. Tomorrow it may start, unless we know the chemistry, physical dimension interactions. MR. GROBE: It may be that the right answer is to do volumetric examinations of these areas every outage. I don't know what the right answer to this is. MEMBER FORD: Okay. MR. GROBE: Then you never get into this situation. At least not from these cracks. MEMBER POWERS: This is the part that I don't quite understand, Peter. In the inspections of heads that we're doing elsewhere, are we looking for boric acid corrosion of the mild steel pressure vessel? MEMBER FORD: Inside the annulus? MEMBER POWERS: Yes. MEMBER FORD: Not as far as I know. Not unless they're doing 100 percent UT. They're not. MR. STROSNIDER: This is Jack Strosnider. I just wanted to make two comments on the discussion. First of all with regard to the research, NRR has requested the Office of Research to start doing some work in this area including looking at what information is already available. Also looking at the feasibility of mock-ups. We've also had some additional discussions with the industry I believe with regard to doing that kind of work. With regard to what the inspections are expected to look at, I think that's a subject of the next presentations. In particular Bulletin 2002-01. When you hear the presentation, you'll see that's exactly the issue that we're trying to get to in that bulletin. CHAIRMAN APOSTOLAKIS: If I look at this incident from the New Reactor Oversite Process. Is this white? MR. GROBE: The licensee's analysis puts it at the white, yellow order. We haven't even begun to review that. That's the next inspection that will begin in the next week or so, both to look at the regulatory implications of the findings of the AIT as well as the risk analysis. CHAIRMAN APOSTOLAKIS: But are you using the action matrix right now? No. MR. GROBE: The AIT, the Augmented Inspection is an event response. Now we'll go into the follow up inspections and apply the Significance Determination Process. CHAIRMAN APOSTOLAKIS: Okay. MR. GROBE: It's an interesting opportunity. CHAIRMAN APOSTOLAKIS: Yes. We've been hearing a lot about the utility personnel there and so on. How about the resident inspectors? MR. GROBE: That's an excellent question. As part of the follow up activities, I'm required to recommend to appropriate offices actions to take. CHAIRMAN APOSTOLAKIS: Were they aware of any of this? MR. GROBE: No. The residents were not aware. Our inspection program does not require inspections in these areas. The in-service inspection program primarily focuses on piping and welds in the BWRs, BWR internals, as well as steam generators. Reactor vessel heads was not included as part of our inspection program. CHAIRMAN APOSTOLAKIS: They were aware of the fact that the 1990 modifications to improve the reactor vessel heads had not been installed. MR. GROBE: No. CHAIRMAN APOSTOLAKIS: They were not aware of that. MR. GROBE: No. I don't know how many modifications every year that Davis-Besse has. But I would expect that it's certainly in the dozens and maybe many more than that. Corrective maintenance activities would be in the thousands. So the chance that a resident inspector may choose to pick one of these activities to look at is fairly small. CHAIRMAN APOSTOLAKIS: Now the Corrective Action Program is one of the cross-cutting issues. Is it not? MR. GROBE: That's absolutely true. CHAIRMAN APOSTOLAKIS: So what? We're not doing anything about it. It's an old issue between us and the staff. The staff claims that even if you have a defective Correction Action Program, then you will see the consequences of that. That's what happened here. MR. GROBE: I think that's what we have here. MEMBER ROSEN: I think that's what you said, Jack, is that you're doing a Significance Determination Process. MR. GROBE: Right. MEMBER ROSEN: What comes out of that is what's off the action matrix. MR. GROBE: Exactly. Also to answer your question, we're going to have to look at our inspection program and how we implement it to make sure that we're addressing appropriate inspection activities. CHAIRMAN APOSTOLAKIS: The question is whether you should stick to this point of view that if there are problems with the Corrective Action Program let them be until something happens or you should try to devise some ways of evaluating the quality of the Corrective Action Program before things happen. MEMBER ROSEN: I don't think your premise is correct. I don't think that they do. I'm not talking about Davis-Besse, any place without a serious event. If the inspection, resident inspectors and the NRC find that the Corrective Action System is somehow not working as it should, then that becomes an issue. CHAIRMAN APOSTOLAKIS: They're not looking, Steve. They're not looking. MEMBER ROSEN: I think they are. CHAIRMAN APOSTOLAKIS: No. It becomes a major contention. MEMBER SIEBER: There's a module for that. CHAIRMAN APOSTOLAKIS: There's a what? MEMBER LEITCH: It's 4500. Isn't it? MEMBER ROSEN: I think it's a major focus of the inspection program now. MR. GROBE: There's three areas where we look at the Corrective Action System. There's an inspection that's now conducted every other year which is a team inspection. It's a large inspection. It covers several weeks. CHAIRMAN APOSTOLAKIS: Of what? MR. GROBE: It's of the Corrective Action System itself. A wide variety of condition reports are chosen on a risk informed basis to examine the effectiveness of the Corrective Action System. There's also a series of interviews of staff across the facility to get a sense for their safety focus as it were. In addition to that a certain percentage, I believe it's 10 percent of the hours of every inspection whether it's a radiation safety inspection, security and safeguards, maintenance, surveillance testing, or whatever it may be, is intended to spend in the Corrective Action area looking at Corrective Actions for deficiencies identified in that specific area. In addition to that now we're implementing sampling of about ten more minor events. Events that wouldn't get to the level of a special inspection where you send a team out to the region. More minor daily events that by following our nose, catch our fancy. We spend a little bit drilling more on that specific event into how it happened. So there are three ways we look at the Corrective Action Program. It's very difficult to apply the Significance Determination Process to Corrective Action violations. The Corrective Action Program if it's a violation of not fixing things correctly, it will most likely found the issue before it became significant from a risk perspective. But didn't fix it properly. So by definition that would be a low- risk violation. There's still quite a bit of dialogue among myself and my peers about whether or not it's appropriate to apply a risk-based, risk-driven Significance Determination Process to a Corrective Action Programmatic deficiency. Or whether there should be some programmatic Significance Determination Process developed that's more deterministic. MEMBER ROSEN: So given all that, what was the staff's conclusion about the Corrective Action Program at Davis-Besse prior to this event? MR. GROBE: The staff's view is that the Corrective Action Program is well implemented at Davis-Besse. That's what's very troubling. It's something that I'm going to be getting to the bottom of over the next several weeks, maybe months. The extent of the behavior that created this problem is multiple people weren't following the Corrective Action Program. For example, engineers were not speaking laterally. The rad monitor engineer wasn't talking to the containment air cooler engineer, who wasn't talking to the head engineer. There were several decisions that were made which included supervision and management that don't appear to have been good decisions. Some examples are the delay of the modification, installation of HEPA filters in containment, the decision to not continue to pursue the source of iron oxide in the '99 time frame, quite frankly the decision to restart after the 2000 refueling outage. So there's just a plethora of issues that we need to continue to follow up on. Why those decision making processes, communication processes, supervision deficiencies didn't manifest themselves in other areas, that's another question we have to ask ourselves and try to find the answer to. But they didn't. I'm fairly comfortable with our inspection program. CHAIRMAN APOSTOLAKIS: Okay. They didn't. But we, the NRC, have no way of finding out that they did not because we were not looking for that. Is that correct? We were not looking for the existence of communication channels between this group of engineers and that group of engineers because that's a safety issue. We're not supposed to look at that. Is that correct? MR. GROBE: Whenever you identify, it's what I refer to hardware and software. Most problems have fixes in two sides. They have a hardware fix. For example in this case potentially drilling out a hole in the head, installing a plug, welding it in. They also have a software fix. It's a human performance problem or a communications problem or a procedural deficiency. CHAIRMAN APOSTOLAKIS: Right. MR. GROBE: We look at all of those issues when we look at fixing a deficiency in the facility. If it's our violation, we follow up on it. The 10 percent of each inspection procedure is spent doing that. We pick about a half a dozen less significant events per year. We drill down in each one of those to make sure that the root cause is identified and fixed. Every two years we spend a significant period of time. CHAIRMAN APOSTOLAKIS: I think I'm getting a different picture from you of what our inspections do. Then you guys would develop the ROP. MR. GROBE: Well, I can tell you that you get a picture of what we're doing in Region III. I believe it's the same as the other regions. CHAIRMAN APOSTOLAKIS: Yes. MR. GROBE: I apologize. MEMBER POWERS: In fairness, you explained this when we visited you. All of the regions have explained this. They do this baring down on the less significant issues and things like that. It's one of the values of our visit to the regions. CHAIRMAN APOSTOLAKIS: I know. Sure. Another thing that you said that I find very interesting is you said that you are not sure of the Significance Determination Process as it is structured now. That makes sense for things like the Corrective Action Program. Put another way, should we evaluate everything on the basis of CDF and LERF? That's really what you are saying. MR. GROBE: Exactly. CHAIRMAN APOSTOLAKIS: I don't think we should. MR. GROBE: I agree. CHAIRMAN APOSTOLAKIS: You agree with me. Okay. MR. GROBE: When you look at the Design Control Program for example if our inspectors go in and we spend a week and we find 20 calculational areas which are not minor oversights like a transposition of numbers or something like that -- MEMBER ROSEN: This is at Davis-Besse. MR. GROBE: No. This isn't Davis-Besse. This is philosophical. MEMBER ROSEN: I apologize. I won't digress. CHAIRMAN APOSTOLAKIS: That's fine. Philosophy is good. Keep going. MR. GROBE: If you find 20 calculational areas where the calculational area had a precursor of not understanding the engineering a mis-application or a mis-assumption or something of that nature but each one of them came out as to not render the equipment inoperable, currently the Significance Determination Process would classify those as either minor or green. They would be non-cited violations. When in fact that's a clear precursor that there's a problem with the competency of the engineers as well as the competency of the engineering supervisors. So there are areas and these are the things that we're still working out in implementation of the ROP. I think the Corrective Action Program is likewise. It needs something less than less rigorous analytically than a risk analysis to evaluate the significance. I certainly appreciate this podium to express these views. I don't get it very often. CHAIRMAN APOSTOLAKIS: It can be a risk- like analysis but not using core damage frequency is the end stake. Something before that. MEMBER ROSEN: It sounds to me like what you're suggesting is the Reactor Oversite Process ought to be risk-informed not risk-based. MR. GROBE: That's exactly right. In some areas it can be risk-based, but overall it should be risk-informed. CHAIRMAN APOSTOLAKIS: Nothing we do is risk-based. MEMBER ROSEN: Well, if you're writing something that's agreeing because it's number that you've calculated is way down there, that's risk-based not risk-informed. CHAIRMAN APOSTOLAKIS: No, but that's a rule. MEMBER ROSEN: What Jack is arguing for is a true risk-informed regiment which is in my view the right answer. It's always I think the wrong answer to use a risk-based regiment. CHAIRMAN APOSTOLAKIS: No, but the point is should you be using core damage frequency to make all these determinations. I think that's a fundamental problem. VICE CHAIR BONACA: For example one concern that you have raised and I brought out at least personally was the fact that the Significant Determination Process doesn't take into consideration repeat events. CHAIRMAN APOSTOLAKIS: That's true. VICE CHAIR BONACA: And yet it is something that traditionally we have looked very hard at the plans as indicators of problems with the Corrective Action Program. You fix something, you say you fixed it and it's not fixed again and again. That's a major indicator. Yet the Significance Determination Program doesn't deal with that. CHAIRMAN APOSTOLAKIS: Also the example with the calculations is a very good point. VICE CHAIR BONACA: Yes. CHAIRMAN APOSTOLAKIS: Because you have 10 wrong calculations spread over time. Each one would probably become a "green." But if you find a common cause behind them then I don't know what you are going to get. MR. GROBE: I think we still have growth in the area of how to apply our risk tools. A good example of that in the maintenance area was at Quad City several years ago. They were incorrectly maintaining their motor operated valves. They were repetitively failing. But at each failure they didn't have redundant equipment in a failed state or out of service. Consequently there was essentially no risk significance to each individual failure but there were 17 valves that failed over a period of two years. It was because the maintenance activity was inadequate and the Corrective Action Program wasn't identifying it. So that's a situation I think that goes to right to both these issues. CHAIRMAN APOSTOLAKIS: Exactly. MR. GROBE: We need to continue to mature in how we are using our risk tools. CHAIRMAN APOSTOLAKIS: Very good. It has been really very useful. MR. JOHNSON: George, this is my chance. Over here at the table. George. CHAIRMAN APOSTOLAKIS: Oh, you again. I thought you weren't in the room, Mike. MR. JOHNSON: I was hoping not to say anything here. But I couldn't not say anything. I do want to point out that we have had continuing dialogue with ACRS on cross-cutting issues. I couldn't sit there and remind us that the goal of the ROP was never to make sure that we didn't have issues. There is never a guarantee in the ROP that would say that we would not have issues and then you would find and look back and say hey you know what. There were some cross-cutting issues that if the licensee had taken care of we wouldn't have gotten here. In fact what the philosophy of the ROP is is that if in fact there are problems in cross-cutting areas that those will be reflected in performance issues like perhaps this performance issue that we're talking about in time for us to take action before the performance is unacceptable. So that's the premise of the ROA. I wanted to be very clear about that. The other thing is that I wanted to be sure that we remember that the commission has given us some specific direction with respect to treatment of cross-cutting issues. The direction from the commission was before the agency takes action on a cross-cutting issue we need to make sure that it is an issue that has reflected itself in terms of performance that it has crossed some threshold. So the commission has been very clear with us with respect to our previous process of looking at issues that have continued to aggregate if you will. Aggregation was a feature of the previous process and has steered us away from aggregation towards where we are in the ROP. I'm sorry, George. I just couldn't sit there and not say that. CHAIRMAN APOSTOLAKIS: Are you still the head of that? MR. JOHNSON: No, I am not. MEMBER FORD: George, I have one question from the public. Then I'd like to get back on to the agenda. CHAIRMAN APOSTOLAKIS: Sure. We can never go back. MEMBER FORD: That's true. MR. GUNTER: Paul Gunter, Nuclear Information Resource Service. Just a quick question. Jack, could you inform me if the 1990 modification that Davis-Besse didn't undertake was that part of compliance with generic letter 8805? I mean 8805 had a specific piece about increasing accessibility for inspection. I'm wondering in what context did the 1990 modification come about. Did Davis-Besse just volunteer it or was this part of 8805? MR. GROBE: That's Paul Gunter by the way for the records. Paul, 8805 didn't require any sort of modifications. It simply required the licensee to have a program in place that addressed certain attributes of boric acid corrosion management and to describe that program to us. The modification that was identified in 1990 was proactive in a sense that the Davis-Besse staff identified for themselves that this would be a benefit to them. There wasn't any requirement to implement a modification of any sort. As a matter of fact of the B&W pressurized water reactors most of them have implemented such a modification. Some have not. So it's simply a matter of what a licensee views is necessary for their own organization. The disturbing issue at Davis-Besse is that over the years their staff had identified that one of their inabilities to effectively inspect and clean the head what influenced that inability was the fact that they had limited access through these mouse holes or weep holes. That reemphasized the need for implementation of the modification. I think I've answered your question. MEMBER FORD: I'd like to move on if I may. Ken, do you want to swap your presentations? You deal with 2002-01 and finish off with 2001-01. It's a suggestion. MR. KARWOSKI: That's fine. For continuity purposes, I'll be discussing Bulletin 2002- 01 which was issued in response to the findings of Davis-Besse. Just to recap, the NRC is taking a number of generic actions as a result of the findings at Davis-Besse. I'll be discussing some of those. I'll also be discussing some of the results that we have to date as a result of reviewing responses to the bulletin and talking to licensees. Just to go through it quickly because I know we are behind schedule. The first slide just recaps what we knew about the findings at Davis-Besse at the time. We knew that they had boric acid on the top of their head and we knew that they had leaking nozzles. With that information and the knowledge that there was a cavity, we contacted the industry and asked them three questions. Those three questions are listed on this slide. Basically we asked them for plants that had just recently completed their inspections in response to Bulletin 01-01 which had to do with circumferential cracking of the nozzles. Were the techniques used during that inspection capable of detecting the type of wastage that was observed at Davis-Besse? The other thing we asked them is to provide a justification for continued operation for the plants that had not performed those inspections at that point. We also asked them for a risk assessment. The industry conducted a survey and Larry Matthews of MRP described that survey. They categorized their results. While the industry was performing that survey and about the time we received those results, the NRC issued Bulletin 2002-01 on March 18. We had several reporting requirements in that bulletin and I've listed those on this slide. Within 15 days of the date of the bulletin, we asked licensees to provide a summary of the reactor vessel head inspection and maintenance programs. We asked them to evaluate those programs for the ability to detect degradation such as what was observed at Davis-Besse. We asked them to identify conditions that may lead to degradation such that was observed at Davis-Besse. We also asked for their plans for their next inspection outage and then the justification for continued operation. We also asked that within 60 days that they provide a more comprehensive evaluation of their Boric Acid Corrosion Prevention Program. We also asked the results of their next inspection to be provided within 30 days of the completion of that outage. With respect with where we stand today, the staff as a result of the MRP survey, we took the plants that were listed in the other category that were on the slides of Larry Matthews that presented including Beaver Valley, Calaverdi, Wolf Creek, Watts Park. We've contacted all those licensees because of possible concerns because the other category is a category where the results of the inspection were questionable and we felt we needed to understand a little better why they were categorized that. Some of those plants have subsequently performed inspections. We are still pursuing additional information from one of those plants. We are also contacting licensees that are currently in outages to obtain the results of their results of their inspections and also to discuss their plans for the inspection recognizing that the bulletin went on the 18th and the responses weren't due back until the first week of April. We wanted to make sure that we understood the licensees inspection scopes and we wanted to make sure that the results of inspection whether or not we wanted to evaluate those results to determine whether or not we needed to take additional regulatory actions. Those phone calls are still on- going. As a result of those phone calls, we have not identified any other plant with similar conditions. In most cases, I have characterized the results as there is small debris on the top of the vessel head. That debris could be a result of maintenance activities and be metal shavings or pieces of metal or small pieces of boric acid crystals as a result of previous leaks but nothing to the extent as what was observed at Davis-Besse. We are reviewing the responses to the bulletin. We have completed initial categorization. We are proceeding on those reviews now. That's basically where we stand with respect to the activities of this bulletin. MEMBER FORD: Thank you, Ken. Questions? MR. HISER: I'd like to describe that the status of review of Bulletin 2001-01 looking back that was on circumferential cracking of vessel head penetration nozzles. VICE CHAIR BONACA: Could I ask a question? I'm puzzled. It will be a quick question. When they looked at the Davis-Besse, they looked from the bottom. Then they did the inspection and identified cracking I guess through UT inspection in the sense. So that means they never looked from the top because of the super structure (PH) I guess it was. Right? MR. HISER: As a part of the 2001-01 inspections for the prior bulletin, they looked using ultrasonics to determine whether or not they had any circumferential cracks. As a part of their overall activities, they intended to do a visual inspection of the head as well. The sequence of events was such that they completed their ultrasonic inspections and then begun repairs before they did their visual inspection. VICE CHAIR BONACA: I just wanted to make sure for the other plants in genera that there is always a plan to inspect visually from the top. MR. HISER: For many plants that's true. For some plants the insulation configuration is such that the insulation is directly on the head. Then there are cases that it really isn't feasible to do a visual exam of the head's surface. VICE CHAIR BONACA: So would you find the same problem if you -- Do you see where I'm going? MR. KARWOSKI: There are a number of plants whose insulation is either glued or cannot be removed for the head easily. One of the recent plants that shut like that is Genet. They had a well documented history of prior leaks. They also did a visible inspection of the surface of the insulation. In areas where it was stained they cut up pieces and looked down to the bare metal. They also did additional examinations in areas where there was a known prior history of leaks. In the case of Genet specifically they did UT thickness measurements from the bottom of the head near the center nozzle. They also did some UT in the periphery around the shroud ring as result of a prior leak in that area. So there are other actions that plants who have nonremovable insulation can take. Certainly if they have never had a leak there is a possibility that leakage would come down from the top. VICE CHAIR BONACA: But you would expect provisions however that they would take so if there is a faradic erosion over time taking place in the ferritic steel would be identified. MR. KARWOSKI: Yes. I was just addressing the corrosion from the top of the head. VICE CHAIR BONACA: I understand. I have just been wondering though since in some cases you cannot have a visual from the top, how do you assure that if you have an event of this type it's going to be identified in all cases? That still puzzles me. MR. BATEMAN: Just a point of clarification. Bill Bateman from the staff. When Ken says leaks, he's referring to flakes from above from the phalanges at the conoseals that would run down and land on the header and the insulation. MR. HISER: One of the things that the industry talked about on Tuesday was interpretation of the ultrasonic data above the weld and the inference fit zone and the ability of that to characterize whether they have metal behind the nozzle or not. That's one approach that the industry is taking. VICE CHAIR BONACA: But they're addressing this issue. MR. HISER: Right. Here's what I would like to do today is to just provide a brief summary of the inspection results and how that fits within the context of the susceptibility ranking approach and then provide some observations and forward looking on where we are headed with this. The table illustrated here provides the inspection results for all the high susceptibility plants along with two moderate susceptibility plants, Crystal River 3 and Millstone 2 that did identify cracked nozzles. In general, plants have tried to use a qualified visual exam if they are able to do that. Again the qualified visual means that you are able to inspect the inner section of the nozzle with the head so that you can split to that bare metal to see if there are any boric acid deposits. Also you have done a plant specific analysis to demonstrate that any leaks in the annulus between the nozzle and the base metal would provide a deposit on the head that would be available for detection. In some cases in Millstone 2 and Davis-Besse, they also did a 100 percent ultrasonic inspection because they were not capable of doing a visual exam with the as-found condition. Now for the plants that have identified leaking or cracked nozzles, any positive findings from the qualified visual exam were followed up with ultrasonic techiques in order to characterize the type of degradation or is it actual flaws or a circumferential flaw whether it was through wall or not. A number of nozzles have been repaired. I guess two things to point out is from the susceptibility rankings, we do have two plants in the moderate susceptibility bin that have found cracked or leaking nozzles. One of those Crystal River 3 is actually the first plant in the moderate susceptibility range. They did identify a circumferential crack in the one nozzle. Millstone 2 identified three nozzles with crack from the ultrasonic test. None of those were thrown wall and none of them appeared to provide any leakage. Some discussion of Oconee 3. That was the first plant that identified circumferential cracking. That was identified in February of last year during a midcycle maintenance outage. A refueling outage in past November did identify additional degradation with the seven nozzles having cracks or leakage. One of those nozzles did have a circumferential crack. So I guess some of the points to be made here is at this point all of the high susceptibility plants with the inspection of Davis-Besse have been inspected. We have continued to find cracked nozzles and also some circumferential cracking. Looking at this within the context of the susceptibility ranking, plants are within zero to five EFPY of Oconee 3 were classified as high susceptibility. As you can see many of these have identified cracked nozzles. In two cases they have not from recent inspections this is the Crystal River -- MEMBER SHACK: Those are really leaking nozzles. Right? They did visuals. VICE CHAIR BONACA: That's right. MR. HISER: In some cases. In at least one plant all of the nozzles that were found to be cracked did not have definitive indications of leakage on the head, did not have definitive conclusions of through-wall. MEMBER SHACK: No, the two that we have down there in the high zone that say no cracking. Those had some visuals on them. MR. HISER: That's correct. Yes. MEMBER SHACK: So the no leaks is the true -- MR. HISER: No leaks. Yes. That is correct. The highest ranked plant that has leakage is Crystal River at this point. Again Millstone 2 identified cracking because they did an ultrasonic exam. Probably if they had done a visual exam they probably would have been a blue square. We would have said they have no cracking. As you can see there clearly are a lot of plants that still will be doing inspections either later this spring, next fall or even next spring because of the cycle of outages. MEMBER FORD: Allen, did I hear that correctly that particular plant a visual inspection is not sufficient to determine that you have no cracking? Is that what you said? MR. HISER: In this case the cracking that was identified as the maximum extent was about 40 percent through-wall. MEMBER FORD: Oh. So there it wasn't a through-wall crack. MR. HISER: Right. It was not a through- wall crack. VICE CHAIR BONACA: Some of the confusion is that you are using the expression "cracking." You should use the expression "leaking" because that really is what you are monitoring with the exception of that plant there, Millstone 2. I would suspect that all of them are somewhat cracked. MR. HISER: They may be. That's correct. We'll improve the indications on this chart. MEMBER SHACK: No. Matthews' chart says it has four plants with volumetric inspection that had no cracking. VICE CHAIR BONACA: I thought there were two. There were two on that table. Only two plants with UT. Millstone 2 and Davis-Besse. MEMBER SIEBER: But there were others who found cracks. MR. HISER: Yes. The plants that are shown in the table are predominantly those that are less than five EFPY. Some of these other plants probably also did ultrasonic inspections. They should be indicated a little bit differently. That's correct. I guess the one point we wanted to make is that although all of the leakage is down in the low EFPY area we have seen cracking here. Ultimately it is going to get to the point that cracking extends throughout the histogram. At this point in time the history does justify I think the susceptibility ranking model that we have. MEMBER POWERS: I guess that's not apparent to me. You have appointed 15 EFPY. It seems to say that this ranking is not correct. MR. HISER: From the standpoint of circumferential cracking in nozzles, the plant had no circumferential cracks. It had three nozzles with about 40 percent through-wall. VICE CHAIR BONACA: And no leakage. MEMBER POWERS: If I wait until 12 EFPY it has two wall cracks. MEMBER FORD: I think an explanation, Dana, is that this model is based purely on time and temperature. It misses out the fact there is differences in stress and especially differences in heat. Therefore you are going to expect a scatter around those values. So it doesn't surprise me at all that you have at least one plant who when you look at the distribution of those plants that have seen cracking -- VICE CHAIR BONACA: If that plant had performed a visual -- MEMBER POWERS: Well, I think what this is telling you is that this ranking is just not adequate. MEMBER FORD: You're always going to scatter around those points. You are absolutely correct. VICE CHAIR BONACA: If that plant had performed visuals like the other reds it would not have been red but it would have been green. MEMBER POWERS: That also says that visual inspection is not adequate. MR. STROSNIDER: This is Jack Strosnider. I'd just like to make a comment on this discussion. As was pointed out with these susceptibility models there are parameters that aren't taken into account here such as residual stresses, materials, et cetera. We wouldn't expect this to be exact. I think the one thing I want to caution is when we say it's not exact. When we ask the question is it adequate from a regulatory perspective, I want to point out that even the largest circumferential crack found in these plants had substantial margin to failure. Is it adequate in terms of protecting against the circumferential crack that's going to lead to failure? That's what we're concluding that yes the inspections are happening soon enough to give us that information. It's not going to predict this plant is going to be at exactly this time or this plant will be exactly before that plant. But when you look at the results of the inspections, we believe it's adequate to provide confidence that the cracks will be caught in time to preclude any failures. I guess the one other thing that I'd point out is then you ask the next question. What about the Davis-Besse experience and the fact that a leak lead to the sort of thing that we saw at Davis-Besse? That's the point of the bulletin that Ken talked about. For people who have already done these inspections, one of the things that they have to respond to is tell us why that inspection was good enough to tell you that you didn't have any degradation occurring in the head. So I think you need to look at both the bulletins and what they're accomplishing there. MEMBER KRESS: Yes. But there's going to be an unfinished part of that. They're going to come back and say we're sorry we couldn't have found the Davis-Besse thing without inspection. Then you'll have to come back with now what. MR. STROSNIDER: Yes. If we see a responsible Bulletin 02-01 which says that we can't tell you a licensee that can't provide the argument as to why they don't have degradation occurring in the head, we need to have more discussions with them. MEMBER KRESS: They'll have some arguments. But you'll have to use judgement as to whether they're good enough. I think what you'll find out is they really can't tell you. Then you have the decision to make. What are you going to do? I think you ought to be thinking about that. MR. STROSNIDER: We are. MEMBER KRESS: Okay. MR. STROSNIDER: If we get a response to Bulletin 02-01 which doesn't provide confidence that the type of degradation saw at Davis-Besse is not occurring, then we will have to follow up on that. That's the point of our argument. MEMBER POWERS: Jack, let's come back on this regulatory adequacy. You have this, I think it's Crystal River up there at 15. Is that right? MR. HISER: That's Millstone 2. MEMBER POWERS: That's Millstone 2. I'm sorry. You say it's okay because this things going through a wall. Isn't that an accident? If I look at the next plant down, couldn't it be that it has through-wall cracks? MR. STROSNIDER: Which one? MEMBER POWERS: One of them. MR. BATEMAN: Right now we're managing this issue through leakage. If we look at that plant, do a visual inspection and we see popcorn there then we know there's leakage. The licensee fixes it. They don't restart until they've fixed all their leaks. Right now the way we're managing this issue is through leakage. MEMBER POWERS: Right now this curve is used to tell you the urgency with which they're doing an inspection. MR. HISER: Actually I should have set the stage on this. The bulletin had two main purposes. First of all is to identify any plants that had a safety issue such as the cracks that were identified at Oconee. So far we've found no plants that have a safety issue with large circumferential cracks. The other is to provide us with data in a graded approach that would help us to determine what the long term management, i.e. inspection methods need to be to assure that we don't get any large circumferential cracks. Within that context, the susceptibility ranking is supported by the data that we have at hand. MEMBER KRESS: I don't think you should overlook the blue squares, Dana. They tell you a lot of information. MEMBER POWERS: You have blue squares down here at three. MEMBER KRESS: I know. You would expect -- MEMBER POWERS: They don't tell me anything except that the curve is not adequate. MEMBER KRESS: You expect some overlap at that level down there. MEMBER POWERS: It looks to me like the density is about the same. I would argue that the blue squares are about uniform across that grid. MEMBER FORD: You don't think that the ratio of cracking to no cracking changes as you go from the left hand side to the right hand side. MEMBER POWERS: It doesn't look to me like it does. MEMBER FORD: There's no red squares up in the right side. MEMBER POWERS: But you haven't looked. MEMBER KRESS: I'm presuming that you've looked at the blue squares. MEMBER POWERS: First of all I have two blue squares in the first block. I have four in the next block. I have three in the next block. I have three in the block. Two in the next block. MEMBER KRESS: That's just an indication of which ones you looked at. VICE CHAIR BONACA: But let's change the name to leaking because really the cracking is just misleading. Those two boxes on the left between zero and five may be -- MEMBER POWERS: That's what I disagree with, Mario. VICE CHAIR BONACA: May be 90 percent through right now. They show however no cracking. No that's not true. No leaking. They haven't seen any leakage. But they may be so close to all extent they're in the same bunch. MEMBER POWERS: I think I agree with you. VICE CHAIR BONACA: What will you shift the criteria? Do you call the other one up there no cracking? That means no leaking actually. You have seen no leaking in less than two. But you know that there is cracking. I can make the same statement about any of those. I probably could go at 20 years and find some at 20 years that have cracking but no leaking. MEMBER KRESS: But I would be awfully surprised to see that many blue squares if indeed you're supposition is right. Some of them are that close to being -- VICE CHAIR BONACA: I was talking about the one between zero and five, those two. MEMBER KRESS: Well, those two might very well be. VICE CHAIR BONACA: They may be very close. MEMBER KRESS: But that just validates the curve if that's the case. MEMBER POWERS: It may also be true that the two up around 15 are within 95 percent of through wall. MEMBER KRESS: But I would be very surprised. MEMBER POWERS: You see if I didn't have the red dot, I might be surprised. But now I have the red dot. Why am I going to be surprised? You know already. MEMBER KRESS: The red dot is the one thing that raises a flag. VICE CHAIR BONACA: That's apples and oranges. MEMBER KRESS: If I had two red dots, I'd be more concerned. VICE CHAIR BONACA: But you don't have that. CHAIRMAN APOSTOLAKIS: So this is the one minute presentation? MEMBER LEITCH: Another important variable and it becomes a limitation I imagine of how much you can plot, is the inspection method. CHAIRMAN APOSTOLAKIS: Good. MEMBER POWERS: The one uncontested conclusion I get out of this is visual inspection looking for evidence of leakage is -- MEMBER FORD: This is going to come up in further discussions because this is relating to the policy of how you manage these. MR. HISER: Okay. I believe initially this whole two hour meeting was going to be on Bulletin 2001-01. That overtook us. So we're trying to squeeze two hours into about five minutes. MEMBER FORD: If I could just interrupt because this is a serious point. Dana, this will come up for discussion in the near future to discuss that policy with regards to how we're going to manage this. MEMBER POWERS: Good. MR. HISER: This says conclusions. But really these should probably be observations and status. I guess what I really want to focus on is the implications of Davis-Besse to the future inspection needs for CRDM nozzles is yet to be determined. Once the Bulletin 2002-01 review activities are completed and the root causes end then we will have a better understanding of that. In addition the bulletin addressed the next refueling outage for plants after August 2001. In some cases plants a year from now will be up to their second inspection. In all honesty, the bulleting really doesn't apply in that case. What we hope to do is have some inspection guidance in hand by that time so that plants will be able to implement that next spring. I believe that the Committee was provided with a copy of our draft action plan that will be used to resolve the VHP nozzle cracking issue. Again that was drafted before the Davis-Besse findings. We have chosen at this point not to modify it because things are in such a state of flux. Clearly that will be revised as the implications of Davis-Besse become understood. MEMBER FORD: That's both underlining I think, Allen, that parts of the actual experiments and analyses in that action plan are already being done by the MRP. So you say it's a draft. It is in fact. The actions are already going on. MR. HISER: Yes. That's correct. That's what we had planned to talk about today. MR. STROSNIDER: This is Jack Strosnider. I'd like to just add one comment here if I could to emphasize something that Allen touched on. I don't know if this will go fully to addressing Dana's concern. Hopefully it might help. Again the bulletin was just a one time at their next outage, that's all it addressed. We recognize that we need a longer term program to manage this. I think that's where the work is ongoing. The Sub-Committee heard on Tuesday and the Committee today heard something very important from the MRP that I just wanted to go back and highlight. That was that the MRP has reached a conclusion that just visual inspections to look for leakage is not an appropriate long term method for managing this type of degradation which has very important implications with regard to the type of inspections that would be done. Basically it draws you to doing volumetric examinations and finding cracks before they ever develop into any kind of leak at all. Hearing that from the MRP and that's an issue that we were looking to have some resolution on I think we'll be working with them to look at a longer term program that follows that philosophy. We're waiting to see their proposal on that subject. Recognize that, yes, there is a longer term follow up that has to happen here with regard to managing this problem because it will show up at other plants. This distribution is marching forward in time. It will have to be managed. MEMBER FORD: I'll pass it back to you. CHAIRMAN APOSTOLAKIS: Well, thank you very much. I guess we'll take another break now. Then we'll go with the last item on the agenda. We'll take 15 minutes, until 5:20 p.m. Off the record. (Whereupon, the foregoing matter went off the record at 5:07 p.m. and went back on the record at 5:21 p.m.) CHAIRMAN APOSTOLAKIS: On the record. We're back in session. Risk-informed inservice inspection, break exclusion, region piping, that's what it says here. MEMBER SHACK: Just to remind everybody that we've been through this notion of risk-informed inspection for piping which seemed like a good idea at the time. Again it was a notion. Now we've learned about where pipes fail and about the consequences of failing. In fact we could do better inspections by looking mostly at regions where we expected to find degradation of piping and looked hardest at the piping who's failure had the most severe consequence. When we approved that it was basically for piping that was covered by the ordinary Section 11 plants. The augmented inspection regions were not covered under that one. Now the industry is proposing to extend that to regions who are augmented and inspections were required. One of those is the break exclusion region where in fact you're supposed to do 100 percent inspection of the welds. There's a proposal then to risk-inform that. The staff is going to tell us about their assessment of that proposal. MS. KEIM: Okay. I'm Andrea Keim. I'm going to be handing off this presentation later to Steve Dinsmore. We have a few other support staff here to help us answer any questions. Again we're here to talk about the risk-informed inservice inspection of an augmented inspection program covering break exclusion region piping. A little bit of the background of the PRA implementation plan included the following guidance that was developed for devising risk-informed decision making. There were some general guidance developed and four application specific guidance in four areas. They covered technical specifications, inservice testing, graded quality assurance and inservice inspection. So far mostly the inservice inspection has been the most useful for industry. MEMBER ROSEN: A point of order. I think our hand out is every other page. At least mine is. No, there's two on each page. I'm sorry. Human error. MS. KEIM: A little bit more on the regulatory project covering risk-informed inservice inspection. Again we've developed a regulatory guide that was issued in September 1998 and a standard review plan. We've also reviewed topical reports from Westinghouse Owners Group and an EPRI topical report covering inservice inspection. Again that covered ASME code piping from code class 1 and 2. These were issued back in '98 and '99. Now what we're looking to do is extend that to a different augmented inspection. First I wanted to go also and show the status of risk-informed ISI reviews. We're proposed to receive 99 plants wishing to implement a risk- informed ISI inspection program. We've received 46 through December 2001. We anticipate getting another 42 in 2002. We anticipate an additional 11 post-2002. The 37 of these submittals that we've already received used the EPRI methodology. The 13 have used the WOG methodology. CHAIRMAN APOSTOLAKIS: What's the difference between the second bullet and the third bullet? MS. KEIM: Not much. MEMBER KRESS: A few months. CHAIRMAN APOSTOLAKIS: Major bullet. MS. KEIM: Yes. CHAIRMAN APOSTOLAKIS: Number of plants expected to implement RI-ISI is 99. Number of plants that have submitted, what is that? MS. KEIM: That's what we have received so far to date. So we have 50 applications so far. CHAIRMAN APOSTOLAKIS: So it's the 46 through 2001 plus a few -- MS. KEIM: A few that we have gotten this year. CHAIRMAN APOSTOLAKIS: Okay. MS. KEIM: We've approved 46 of these plants. All the ones through 2001. CHAIRMAN APOSTOLAKIS: I don't understand. Why do you have to approve them since they are following methodologies that you have approved? MS. KEIM: Because these cover ASME code piping class 1 and 2 which require a submittal for a relief request. CHAIRMAN APOSTOLAKIS: Okay. Even though they follow an accepted methodology. MS. KEIM: Yes. MR. BATEMAN: It's never quite so simple that they follow an accepted methodology. Each licensee always has their own little differences they want to take from the accepted methodology. CHAIRMAN APOSTOLAKIS: So you have number of plants that have submitted is 50 or approved. Sorry. MS. KEIM: So we have 50 that are submitted. Our current activities are covering the Westinghouse Owners Group and EPRI submittals that are extending this risk-informed ISI methodology to the augmented inspection of break exclusion region piping. MEMBER KRESS: Could you give me a little idea of what break exclusion is about? MS. KEIM: We're going to get to that. MEMBER KRESS: Okay. MS. KEIM: That is coming. Where that's defined and where those requirements came about. Primarily our today's presentation will focus on the EPRI methodology and the EPRI submittal because that one is farther along in the review process. A little bit more background on the objective of ISI, inservice inspection. That's to identify degraded conditions that are precursors to pipe failures. I think we're all familiar with that. For normal ISI, it's referenced in 10 CFR 50.55(a)(g). That's the requirement that still requires them to still submit a relief request for the code class piping. That again references ASME code for the requirements. Now to what everybody's interested in. The break exclusion region came around from reviews of general design criteria, number 4 which requires that structures, systems and components important to safety be designed to accommodate the effects of a postulated accidents and include appropriate protection against the dynamic and environmental effects of postulated pipe ruptures. The staff has issued a number of documents that provide criteria for implementing the above requirements. That covers the Standard Review Plan chapter 3.6.2 which also includes a staff technical position MEB 3-1. The Standard Review Chapter states that breaks and cracks need not be postulated in break exclusion region piping provided they meet certain design and inspection criteria. So from this they designed these pipes with the different criteria. They also are required to inspect 100 percent of the piping welds in these regions. CHAIRMAN APOSTOLAKIS: I must say it's not clear to me what a break exclusion region is. What is it? MS. KEIM: Well actually it's piping that is in the vicinity of the containment which is from the inside isolation valve to the external isolation valve. CHAIRMAN APOSTOLAKIS: Okay. MEMBER KRESS: That's piping that you guys want them to design and inspect so that you can exclude the possibility that it won't break. MS. KEIM: Right. MEMBER ROSEN: That's what exclusion really means. It doesn't have anything to do with excluding from the welds or from the inspection. MEMBER KRESS: Yes. Okay. MEMBER ROSEN: It has to do with excluding breaks from the process. MEMBER KRESS: There are important regions of piping that you just don't want to break. You want to be sure. MS. KEIM: Right. MEMBER SIEBER: So you have to do 100 percent of every weld. CHAIRMAN APOSTOLAKIS: This is the only place where 100 percent inspection takes place. MEMBER SIEBER: I think that sampling in other places. CHAIRMAN APOSTOLAKIS: Everywhere else it's sampling. MS. KEIM: Yes. MEMBER ROSEN: The code typically requires I think 25 percent. MS. KEIM: Yes. For class 1. CHAIRMAN APOSTOLAKIS: What is MEB? MS. KEIM: MEB is another acronym that we use to identify different branches. MEB is the Mechanical Engineering Branch. CHAIRMAN APOSTOLAKIS: Oh, okay. MS. KEIM: That's included in the Standard Review Plan which is attached into the Chapter 3.6.2. MEMBER SIEBER: I think the nickname for the break exclusion region piping is superpipe because it gets inspected so much. MS. KEIM: Also because it has additional design criteria. MEMBER SIEBER: Right. CHAIRMAN APOSTOLAKIS: Okay. So now I understand what a BER is. What is the first sub- bullet? "Pipe breaks not postulated in BER if criteria is satisfied including augmented IDI of piping welds." What does that mean? MS. KEIM: I think some of that we're going to cover a little bit later. CHAIRMAN APOSTOLAKIS: What do you mean "not postulate"? MR. DINSMORE: This is Steve Dinsmore from the staff. MEMBER SIEBER: You don't have to consider it. CHAIRMAN APOSTOLAKIS: Oh, if the criteria is satisfied -- MEMBER SIEBER: You don't have to postulate a pipe break. CHAIRMAN APOSTOLAKIS: You do the safety analysis. MEMBER SIEBER: Right. MR. ALI: This is Syed Ali from the staff. Maybe I can clarify just a little bit. I think one of the big differences between the BER and the non-BER is in the regions breaks had to be postulated and hardware had to be installed for the effects of those breaks such as pipe replacing, check shields. This region which is generally between the inside and the outside containment isolation valve is so congested that the staff came up with the criteria that you don't have to postulate breaks. Therefore you don't have to install all that hardware provided a number of conditions can be met. One of those conditions was 100 percent inspection. Other conditions were stress below a certain level, you critique below a certain level. CHAIRMAN APOSTOLAKIS: Okay. So I guess if you had written "pipe breaks need not be postulated" then it would be clearer. MR. ALI: Right. CHAIRMAN APOSTOLAKIS: Okay. This is an interesting situation that you just described because it goes against the defense in depth philosophy. Does it not? It says you are shifting everything to prevention. They say no longer areas. You also do something to mitigate, to contain the possibility. But here you just convince yourself that the break will not happen. MR. ALI: There are a number of conditions that have to be satisfied. MEMBER POWERS: George, you're promptly committing the cardinal sin of defense in depth. That is applying it to every damn sub-system in the whole reactor. CHAIRMAN APOSTOLAKIS: That's a cardinal sin? MEMBER POWERS: Yes. CHAIRMAN APOSTOLAKIS: So big. MEMBER POWERS: Yes. CHAIRMAN APOSTOLAKIS: Jesus. I'm beginning to become a rationalist again. All right. That's clear now. MS. KEIM: So now what the proposal is -- CHAIRMAN APOSTOLAKIS: Well excuse me. But it doesn't tell me anywhere that the defense in depth stops at some point. If I read all the documents, that's a philosophy. MEMBER POWERS: If you read the exemplary paper by Sorenson, Powers and Apostolakis, it would outline this for you. CHAIRMAN APOSTOLAKIS: That was probably the part that Apostolakis did right. Okay. Sorry, Andrea, it's late. MS. KEIM: That's okay. So what the proposal is -- CHAIRMAN APOSTOLAKIS: You're doing fine actually. MS. KEIM: Risk-informed methodology to select piping elements and welds to be inspected in lieu of the 100 percent examination. With that I'm going to hand it over now to Steve Dinsmore. MR. DINSMORE: Hi. I'm Steve Dinsmore from the PRA branch. I've been involved in this risk- informed ISI since pretty much day one or since the beginning of time, whichever is longer. CHAIRMAN APOSTOLAKIS: That's where time started. MR. DINSMORE: Just to give you a brief overview that can avoid some confusion later. What we have is this temporary ISI TR, the original TR. It's about 200 pages. It has a whole description of a methodology. It's been approved to use. Except it was explicitly excluded for use in the break exclusion region. Now we have this second topic. This is what we call the EPRI BER TR. Not topical essentially identifies tweaks to the original methodology. If they used them, they can take the original methodology, tweak it and apply it to the break exclusion region. This slide is a quick overview of the different steps in the original methodology and how they're changed to let the BER program be included. The first one is scope definition. It's easy. It used to be excluded. Now we include it. The consequence evaluation. The BER TR includes a fairly well defined criteria which should be used to determine the consequences of ruptures in these regions. So that's probably the major difference. Degradation mechanism evaluation. There's no change. Piping segment definition. There's no change. Risk categorization. There's no change. Selection of welds. There's no change. Risk impact assessment. Essentially what we -- CHAIRMAN APOSTOLAKIS: Let me understand that. When you say "no change" to what? MR. DINSMORE: To the original methodology. CHAIRMAN APOSTOLAKIS: Okay. Not to what you used to do to the break exclusion area. MR. DINSMORE: Right. This is to the original methodology. CHAIRMAN APOSTOLAKIS: This is to the report. MR. DINSMORE: This is to the methodology. CHAIRMAN APOSTOLAKIS: The methodology. MEMBER ROSEN: The existing approved methodology to the 46 plants. CHAIRMAN APOSTOLAKIS: Now it makes sense. But did you explain to us what they propose to do to the exclusion region? MR. DINSMORE: The tweaks are described here. This is a quick overview. CHAIRMAN APOSTOLAKIS: Okay. MR. DINSMORE: The risk impact assessment. We had to figure out how to apply the risk criteria that we'd been using to this region and to the plant in total. There's also a slide on that. Monitoring feedback. There's no change to that. The implementation is another one of the bigger changes. A lot of these BER programs are only referenced in the FSAR. You could use 50.59 to make changes that are referenced in the FSAR. CHAIRMAN APOSTOLAKIS: What does that mean implementation if you use 50.59? MR. DINSMORE: If you do a 50.59 evaluation, you can determine whether you need to make a submittal for prior review or not. Sometimes they are in other places, but those plants have their own problems. If it's only referenced in the FSAR, you should be able to apply your 50.59 evaluation, use this methodology and then apply the evaluation. Then you won't have to come in with a submittal. You can just make a change. CHAIRMAN APOSTOLAKIS: How would you apply 50.59 to piping in the exclusion region? Have you thought of the questions that you're effecting initiating vents? MR. DINSMORE: Actually the seventh question is are you -- CHAIRMAN APOSTOLAKIS: I thought the first question of 50.59 was what you are about to do could effect initiating events. MR. DINSMORE: We have our 50.59 person here specifically for that. CHAIRMAN APOSTOLAKIS: Okay. MS. MCKENNA: This is Eileen McKenna from the NRC Staff. I think you're going to get to it a little later in the presentation. I think part of the point that was trying to be made here is that this part of the program, the BER, is not in 50.55(a). So you don't have to follow a 50.55(a) review and approval process. Then you look at what is the approval process if there is one that might apply to this. To the extent that it's in the FSAR, then it would be 50.59 that would apply to it. What we're talking about as you'll see a little bit later is we're really looking at the methodology by which you select your inspection locations as changing from the 100 percent inspection to the risk-informed approach. Then using a methodology that has been approved through the topical process. Then you would go through Criteria A which is the method of evaluation criteria in 50.59. CHAIRMAN APOSTOLAKIS: But I suspect that all of this will fail to pass the Criteria 50.59. Would it not? So you would actually have to come to the staff. MS. MCKENNA: We're approaching it from looking at it as being the method for determining the inspection locations. CHAIRMAN APOSTOLAKIS: Right. MS. MCKENNA: We're looking at it as being Criteria A method of evaluation. The criteria that's established is that if you're changing from the method that you had in your FSAR to another method that has been approved by the NRC for the intended application, that is a change that can be done under 50.59. MR. DINSMORE: You don't have to answer the other seven questions. MS. MCKENNA: Right. If it's methodology. CHAIRMAN APOSTOLAKIS: It's only methodology here? You say you are reducing the number of locations. MEMBER SHACK: You're changing the method that you're selecting the inspection. MR. DINSMORE: Right. MS. MCKENNA: It has that effect, yes. MEMBER SIEBER: But that's already been approved by the staff as a generic methodology. So it doesn't result in an unreviewed safety question. CHAIRMAN APOSTOLAKIS: No. But it has been approved for regional solid of the exclusion rate. MR. DINSMORE: We're in the process. If we issue this SE, it will approve it for use specifically in this region. The SE even says that. CHAIRMAN APOSTOLAKIS: Let me understand this. Before this, we were inspecting at how many locations? MR. DINSMORE: At 100 percent. CHAIRMAN APOSTOLAKIS: At 100 percent. Now it's going to be in a smaller number. MR. DINSMORE: Yes. CHAIRMAN APOSTOLAKIS: You consider that a change in method. Is that an unresolved question? MR. DINSMORE: No. We're reviewing it as a change in methodology. CHAIRMAN APOSTOLAKIS: That's what I'm saying. Why is that so? It doesn't sound to me like it's a change in method. It's a change in results. You are inspecting less. MEMBER ROSEN: I think it's a change in method that results in a change in results. It's a change in the methodology. CHAIRMAN APOSTOLAKIS: Which results though in a real change which may effect initiating events. MR. DINSMORE: But all methodology changes could result in a real change. CHAIRMAN APOSTOLAKIS: All? MR. DINSMORE: I think so. MEMBER SHACK: The assessment will find that it doesn't significantly increase your risk. MEMBER SIEBER: The generic assessment. The SER. MEMBER SHACK: If you follow the methodology. MR. DINSMORE: Yes. MEMBER ROSEN: George, you're having a bad day. MR. ALI: This is Syed Ali from the staff again. The original EPRI methodology is specifically excluded from its scope the application to this region. So what they are doing now is coming with an addendum to that methodology that says their methodology can be applied to this region also. We are reviewing that addendum. If we approve the addendum then we would have approved the original methodology but now being applied to this region also. There are some slight tweaks to the methodology changes. But it's basically the same methodology. MR. DINSMORE: I think the idea is first put out this NEI 97.06 that if you use this approved methodology or an approved methodology for the purpose it was approved for, you don't have to address those other questions. The NRC has accepted that as guidance for using 50.59. MEMBER KRESS: These pipes penetrate the containment generally. There's isolation valves on either side of the containment. If the pipe breaks on the other side of containment, you've automatically violated your containment. MEMBER SIEBER: Not if the valves work. MEMBER KRESS: Well, the valves are generally open. You have to close them. Right? MEMBER SIEBER: Well, they close generally automatically. MEMBER KRESS: What I'm trying to reconcile is that 1.174 and by extension to the inservice inspection part of 1.174 there's a stipulation that you don't violate the defense in depth principle. It seems to me like this is a defense in depth consideration. I don't know whether it violates it or not. It appears to violate it to me, but I'm not sure. CHAIRMAN APOSTOLAKIS: No. The 1.174 says the defense in depth philosophy. MEMBER KRESS: Well, that's a philosophy. CHAIRMAN APOSTOLAKIS: So that's a way out of that. MR. DINSMORE: Well, we include the spatial effects of the failure of this piping in the evaluation. Exactly what you gentlemen are talking about is why we have a much more well defined spatial effects evaluation process in the TR instead of leaving it somewhat up to the licensees to develop and document how they want to address spatial effects. In this case, we've taken the extra step. We've put in a good bit more description and criteria about how they're supposed to do that analysis. But if the results of the analysis are acceptable according to all the other criteria that we have, then it's okay. MEMBER LEITCH: It seems to me that if you get past this first issue of the questionable definition of methodology and you applied the other seven questions, it would fail. Would it not? Clearly it would fail. CHAIRMAN APOSTOLAKIS: Yes. Clearly fail. MEMBER LEITCH: So if the whole arguement is hinged on the definition of methodology then you're not going to get to the others. CHAIRMAN APOSTOLAKIS: Exactly. MR. DINSMORE: It might not fail so bad though because we did look at the questions a bit. MEMBER SIEBER: My way of looking at it, and you can correct me because it's a simple way of looking at it is that if it fails, that means it is an unreviewed safety question. Then you have to go to the staff to get approval. MR. DINSMORE: Right. MEMBER SIEBER: But they've already approved when they write this SER the methodology. So it's no longer an unreviewed safety question. I think that's what that means. So you don't end up having to go down that chain of questions to legitimately apply the methodology because the staff has already approved the methodology. Is that a way to look at it? CHAIRMAN APOSTOLAKIS: How does that compare with the earlier information that Andrea gave us about the number of plants submitting risk-informed ISIs and being reviewed by the staff? MR. DINSMORE: But that's a totally different process. CHAIRMAN APOSTOLAKIS: You are reviewing the process that you have. MR. DINSMORE: If you want to get a relief from applying, that's going to be Section 11 inspections, you have to come in to the staff and request relief. MEMBER SIEBER: An exemption. Right? MR. DINSMORE: It's a relief request. CHAIRMAN APOSTOLAKIS: So that doesn't apply here. MEMBER SIEBER: From 50.55(a). MR. DINSMORE: Yes. MEMBER SIEBER: Right. MR. ALI: Again, it's Syed Ali. I just want to add something on that also. In the original program, they were specifically going below the inspections that are required by ASME 11. So they had to come in for a relief. Here in this region there's ASME piping and there's non-ASME piping. For ASME piping that is in this region, they would have to maintain at least the ASME 11 inspections in order to apply 50.59 and not come for a relief. If they go below the ASME 11 then it will go into the same kind of a treatment as the rest of the plant. They will have to come in with a relief request. So the floor is still the ASME 11 in this region for the 50.59 process to be applicable. MEMBER LEITCH: The actual floor is about a 10 percent inspection. MR. ALI: Well, it's 25 percent for ASME class 1 and about 7 and a half for ASME class 2. That's the ASME level in the floor. CHAIRMAN APOSTOLAKIS: Well, I guess if it's clear to all the members, we can go ahead. MEMBER LEITCH: Just one more question. Is that 25 percent per 10 year interval? MR. ALI: The 25 percent per each 10 year interval, yes. MEMBER LEITCH: Thank you. MR. DINSMORE: Okay. Now we move to the consequences. We'll explain a little bit again the difference between BER piping and non-BER piping. The non-BER piping had pipe failure postulated during the design and evaluated using these SRP guidelines. The mitigative hardware was added as needed. I guess we already talked about this a lot. In the BER piping, the pipe failures were not postulated and the mitigative devices were not constructed. So essentially when we did the original risk-informed ISI we were looking at the non-BER piping because that's the only place they were changing inspections. We were more or less crediting this SRP analysis out there. They had done this SRP analysis one time already. So these guys can do their PRA realistic analysis on top of that. Now inside the BER piping, we don't have that fall back. It's just whatever is there. That's the reason in the EPRI BER TR, we essentially said you can use the SRP guidelines or criteria or somewhat more conservative. They can use somewhat more conservative because it's not as sensitive. What the result is, is that the segment goes into higher medium. The result of that is they do 10 percent or 25 percent of inspection. It's not that they have to build in all this equipment. So I think the two pilots were somewhat conservative because it didn't hurt them that much to be conservative. MEMBER LEITCH: Once again I just want to make sure I understand this. Under the BER piping, the reason that pipe failures were not postulated is because this particular piping was very conservatively designed and because we were going to do 100 percent inspection. MR. DINSMORE: Right. MEMBER LEITCH: Not because it's not important. In fact it's to the contrary. It's very important. CHAIRMAN APOSTOLAKIS: Yes. I think that was the reason. MEMBER LEITCH: These are high energy pipe lines. MEMBER SIEBER: Some are, some aren't. MR. DINSMORE: We're working on it. MEMBER LEITCH: It's main stage. It's feedwater. Isn't it? MEMBER SIEBER: Sure. MR. SULLIVAN: This is Ted Sullivan. I'd like to add a little perspective. I think Dr. Kress really hit upon it earlier. You couldn't postulate a break in these areas. If you postulated a break for example in a boiler and coupled with it the single failure of the isolation valve -- MEMBER KRESS: Or leaking at that. MR. SULLIVAN: You violate containment. So it's really an outgrowth of that. MEMBER LEITCH: All the more reason for inspection though as I say. I agreed you couldn't postulate a break. But I just don't understand the logic of this. If you couldn't postulate a break, it's not because it's not a problem. It's a big problem. So all the more reason to inspect. MR. SULLIVAN: I don't disagree with you. There are some representatives of industry here if they want to add to what I'm saying, industry's view was that these are fairly high radiation areas. They really have not been finding anything to speak of or much to speak of from doing these inspections. They've done thousands and thousands of weld inspections. The performance of this piping is very good. So what they proposed and we've been reviewing is a concept of focusing inspections basically for cause. Where is the degradation expected to have some potential to occur? Let's inspect in those regions and couple that with regions where the consequences would be high rather than forcing the licensees to continue to do 100 percent in a lot of area where they really can't even identify a potential degradation mechanism. CHAIRMAN APOSTOLAKIS: It's a performance based initiative. Because they haven't found anything in many inspections, they say why should we keep doing this. MR. DINSMORE: Why should we keep doing 100 percent? CHAIRMAN APOSTOLAKIS: Yes. MR. DINSMORE: I think that's right. MEMBER KRESS: That's a different arguement than we've been hearing. CHAIRMAN APOSTOLAKIS: It's a very different arguement. MEMBER KRESS: It's a more persuasive arguement. CHAIRMAN APOSTOLAKIS: In fact, it's much more persuasive, yes. This is not risk-informed stuff. This is performance based. MEMBER POWERS: In fact, it has to be a risk-uninformed thing. I mean, WASH 1400, NUREG 1150 all tell us if you want to get yourself in real trouble you have a bypass accident. MEMBER KRESS: That's exactly right. CHAIRMAN APOSTOLAKIS: Yes. MEMBER POWERS: So if you bust these pipes, you have a bypass accident. Anything that degrades your confidence in these, would have to be a risk-uninformed activity, inverse of risk-informed. CHAIRMAN APOSTOLAKIS: You would never pass 50.59. You just don't. MS. KEIM: We have someone from industry that would like to speak. MEMBER KRESS: You might if you postulate that the inspections aren't doing you any good because they never found anything. CHAIRMAN APOSTOLAKIS: No. The inspections are always doing something good. They never found anything. That's strong evidence that the uncertainty has been reviewed significantly. Right? MR. DINSMORE: Yes, sir. MR. BALKEY: This is Ken Balkey from Westinghouse. I'm working with our team on the Westinghouse Owners Group methodology. They fall as the same procedure in the EPRI method as well. To add to Ted Sullivan's comments, when we did the risk-informed ISI work from the original topicals a few years ago, we learned a lot. That ASME code had 25 percent and 10 percent. There was a history of how they came up with that. It just says there's a history is why there's 100 percent here. To do these exams, it's not simply just go out. They are in congested areas and high radiation areas. There are only so many examiners to go around as well too. When we did the risk-informed ISI process with either method to do the Section 11 exams, we feel that we've done a real service. Even though we're doing a smaller population, we are in the process of moving the exams to the areas of active degradation. Therefore making very good use of the utility's resources in doing those examinations. We knew about this area when we did the original program. We even had a lot of discussion with the NRC of could we include this, even in the original topical three or four years ago. The staff felt and industry agreed that we have to take one step at a time here. It was enough of an issue to get through the ASME Section 11 exams and working through a regulatory process with the relief as Andrea said in terms of utilities making submittals and getting approval for a relief request. The industry now said we should be able to take the same knowledge we just gained from that program, and apply it to the high energy line break exclusion region. We're not taking exams down to zero. I think we're trying to support what Dr. Kress said. Do you really 100 percent to give you assurance that the integrity is good within this piping? If it was easy to do, we wouldn't be here. They are difficult exams to do. So we're saying can we do a smaller population and still get the same level of assurance in this region like was done in the same piping for the Section 11 program. All the questions in terms of if it breaks, would it take out other areas or what it's effect is from a PRA, we still have to look at that. There are areas where we will not remove examinations because the PRA indicates them a consequence. You really still need to do a number of exams in that area. In summary, what we are trying to do is really take what we learned on the original application and now extending it to this for the 100 percent. It does free up the resources to really get at some other degradation issues we're dealing with in our plants. MEMBER KRESS: Let me ask you a question. MR. BALKEY: Sure. MEMBER KRESS: When you say 25 percent of piping instead of 100 percent, let's just pick a number. MR. BALKEY: Okay. MEMBER KRESS: Does that mean you eventually inspect all the piping? You would only spread it out in time a little more. MR. BALKEY: That's a good question. The original concept for the 25 percent came from 30 years ago. You do 25 percent in the first 10 years, 25 percent in the second and so forth. So over the life of the plant, you do 100 percent. But guess what? As plants operated, folks said we did the first 25 percent and we really should go back and take a look to see if anything changed. If you go another 25, going back to a location you just did 10 years ago and you get a different signal from your ultrasonic, you know degradation is under way. So you're better off getting to a smaller population and really monitoring the degradation closer than trying to do it all one at a time. MEMBER KRESS: You could do a combination of those two. MR. BALKEY: Right. In this application, the intent would be you'd have a smaller population. But they are the areas that you would expect degradation and of course areas of high consequence. You would go back to those areas each ten year interval. CHAIRMAN APOSTOLAKIS: So you are always inspecting the same 25 percent? MR. BALKEY: Yes. Or whatever the percent ends up being in this region. Yes. You would go back to the same. But the program also as part of its update if you find something whether it's in the Section 11 program or if it's in a break exclusion region, you may have to expand your sample. Not may, it is. There's a sampling scheme that if you find something in that outage, you have another population that sees it now somewhere else you weren't inspecting. If you find something there, then you're doing 100 percent of your area. So the process allows you to get to 100 percent if you start finding degradation in the sample that you're doing. MEMBER LEITCH: How big an issue is ease of inspection in determining which 25 percent? MR. BALKEY: I would actually ask one of my colleagues here who is an examiner at his plant. Dave, do you want to speak to the difficulty in getting to some of the locations. MEMBER LEITCH: I know some of the locations are very difficult. My question was really how do pick your 25 percent. CHAIRMAN APOSTOLAKIS: Do you pick them randomly? MR. BALKEY: Right now Dave has to do 100 percent of the exams at his plant. MEMBER LEITCH: I know some of them are really hard. What I'm saying is when you determine your 25 percent sample view, do you eliminate the real hard ones? MR. BALKEY: No. I can give you an example. Turkey Point is one of the plants that's been submitted not for break exclusion but in the original Section 11. We looked at their risk-informed ISI. We indicated in their surge line for their operational experience. They had to do 100 percent of the surge line. That was a very difficult finding because they had to go back and spec underneath the pressurizer. It's a very high radiation. But we said you have to examine it because of the information you had. We would use the same philosophy. The same philosophy would apply here. Just because it's hard to get to is not the reason you would drop it out. If you find it's an area of degradation and your PRAs telling you that it's really important if it fails, unfortunately you're going to have to go in and make the effort to do the examination. MEMBER KRESS: What is the risk criterion? How do you establish whether the one pipe section is more risky than another one? Is it because of equipment that may be around it? MR. BALKEY: Yes. MEMBER KRESS: Is it the size of the pipe or the flow rates or a combination? MR. BALKEY: It's a combination of the temperatures and pressures. That's part of what Stephen was talking about and the consequence evaluation on this slide here. One has to go in and look a lot more carefully. You look at your pipe whip for jet impingement effects and also flooding effects on the electrical equipment if there's anything that happens to be nearby. MEMBER KRESS: That's how you decide the risk. MR. BALKEY: Yes. That's part of the process. MEMBER ROSEN: The functions of the piping as well. MR. BALKEY: As well as the functions of the piping. We usually break it in to a direct consequence to address the functions. Then the indirect effects are the pipe whip and jet impingement of pipes whipping and taking out other equipment nearby. That has to be done as part of the process. MEMBER KRESS: Thank you. MR. DINSMORE: Okay. I'm not quite sure this is resounded. We do use some risk information in the process. So that they don't have to come in with a submittal, you have to keep that in the back of your mind, the quality of the PRA needs to be the same acceptable quality as for risk informed ISIs since it's pretty much the same process. MEMBER SHACK: Can he do this without having a risk-informed ISI program for his Section 11 piping? MR. DINSMORE: They can apply this to the BER region without doing a risk-informed ISI. MEMBER SIEBER: Right. MR. DINSMORE: Within the BER region then as Syed was saying earlier -- MEMBER SHACK: Could you do it with 50.59? MR. DINSMORE: Yes. But you couldn't change the ASME Section 11 inspections if there are any in this BER region. You could only change the BER specific ones. MEMBER ROSEN: Do you expect anybody to actually do that, someone who hasn't done the basic risk-informed ISI? MR. DINSMORE: I have Pat O'Regon back there nodding. He's from industry. So I have a feeling he knows. MR. O'REGON: I'm Pat O'Regon from EPRI. The answer is yes. There are several plants that would like to implement BER only. In particular a couple of BWRs will be implementing BWR VHP 75 on the stainless steel piping and risk-informed BER on the carbon steel piping. MEMBER POWERS: How would the quality of your PRA affect the conclusion that seems to be robust trough all PRAs that containment bypass accidents are very hazardous accidents? MR. DINSMORE: Well, they would assign a pretty high conditional core damage probability or a conditional large early release probability to those segments which would contribute to those sequences. Then it would be up to whatever degradation mechanisms are in those segments. If there's no degradation mechanism and a very low failure probability then those segments would be lower risk. If there's some degradation mechanism and a high probability, there would be a higher risk. MEMBER LEITCH: Do we have any idea how much man-rem per plant per year is attributed to the execution of this program as it now stands? In other words, what's the man-rem saving per plant per year estimated to be? MR. DINSMORE: Maybe industry would know. I don't. I guess not. No. MEMBER ROSEN: Another way to look at that same question is what's the percentage reduction in the program that would come out of this. How big an effect is it on the remaining overall program? Can you give us any feel for that? MR. DINSMORE: The EPRI TR says that if you get below 10 percent, you need to provide a good explanation of the design features in your plant which supports finding that you have to inspect less than 10 percent of the welds in this region. MEMBER ROSEN: That's not exactly the question. That's not the answer to the question that I thought I asked. The question is let's say before you have a start at this you were inspecting 1,000 welds in the 10 year period. Then you go to risk-informed ISI. Now you're only inspecting 350 welds. You knocked out two-thirds of them which I think is the number I remember. So you're down to 350 welds in the 10 year period. Now can go to break exclusion piping and knock that out. Now you're inspecting not 350 but only 175 or 300? I'm trying to get a feel for the additional reduction. MR. DINSMORE: This is one of the pilots that we didn't review by the way we just looked at it. If you had 135 welds, one of them went down to 20 for example. So that's about 11 percent. The other one went down to 3 percent. MEMBER ROSEN: Wait a minute. You said 135 and you went to 20. MR. DINSMORE: Yes. MEMBER ROSEN: That's a reduction of almost 90 percent. Right? MR. DINSMORE: That's because we're starting with 100 percent. You see if you start with ASME -- MEMBER ROSEN: Out of 135 welds you're total example was the BER scope. MS. KEIM: Yes. MR. DINSMORE: Right. You inspect them all to start with. In the ASME class 1, you were going from 25 percent down. Here you're going from 100 percent down. MEMBER ROSEN: So basically it's a very large reduction in the BER scope. MR. DINSMORE: It can be. MEMBER KRESS: When you do the risk assessment to calculate the change in LERF for example, can you check it along with the absolute LERF? If you have more than one unit on the side, are you going to add the LERFs together? MR. DINSMORE: We don't have process to deal with that. If you had more than one unit on the site I think what happens is if you add the two together, the relative increase would be the same. We don't really apply these criteria. MEMBER KRESS: No. You have an absolute LERF then you have a Delta LERF. The Delta LERF stays the same. If you do it to one unit only, the Delta LERF is for the unit. But the LERF is a LERF for the site. It ought to be the sum of all the plants that are on the site. That's a glitch or a short coming of 1.174 that I've been trying to get fixed. That's why I ask the question every time. MR. DINSMORE: We haven't fixed it in this SE. CHAIRMAN APOSTOLAKIS: A straightforward answer. You'll wait until 1.174 is fixed first I imagine. MR. DINSMORE: Right. CHAIRMAN APOSTOLAKIS: Okay. Let's move on. Go to 11. MR. DINSMORE: This is 11. CHAIRMAN APOSTOLAKIS: This is 11? MR. DINSMORE: I have a different numbering system. CHAIRMAN APOSTOLAKIS: So what number do you have for this one? MR. DINSMORE: I have 11 for the other one. We took one out. We put one together. CHAIRMAN APOSTOLAKIS: We discussed this. Didn't we? MR. DINSMORE: Yes. We discussed this in the beginning. We can just maybe even skip it. CHAIRMAN APOSTOLAKIS: Yes. MEMBER KRESS: This is the final conclusion you have. MR. DINSMORE: Right. CHAIRMAN APOSTOLAKIS: Now let me understand the first bullet. As I recall Regulatory Guide 1.174 as we said earlier today has a beautiful discussion of uncertainties incompleteness, models. Are you guys doing any of that? MR. DINSMORE: Those are included mostly in the system level guidelines. We don't allow them to for example take a bad weld in a dangerous system and start inspecting that. They get a big plus risk from that and use that to stop inspection many welds in other systems. We don't believe that the numbers support those type of large shuffling of risk. CHAIRMAN APOSTOLAKIS: When you say the basic acceptable quality of the PRA is the same as the risk-informed ISI, so you have already approved 46. Right? MR. DINSMORE: Right. CHAIRMAN APOSTOLAKIS: These are 46 submittals. You are now reviewing four. MR. DINSMORE: There are five. We got one yesterday. CHAIRMAN APOSTOLAKIS: Five. Okay. So you are really busy then. When you reviewed the 46, did you look at issues like model uncertainty and incompleteness? My impression is that nobody's doing uncertainty analysis anymore. MR. DINSMORE: What we required for the risk-informed ISI is that the licensee go back and look at all the negative comments made by the research review and the peer review process, the BWRG. They evaluate all these comments and make sure that either they don't affect the results of the ISI analysis or that they incorporate somehow the comment into the evaluation. CHAIRMAN APOSTOLAKIS: But what if the PRA has not done an uncertainty analysis at all? We were told last month that asking for uncertainty analysis means killing the program because nobody does it. So I don't know how you conform with Regulatory Guide 1.174 if you don't do that. MR. DINSMORE: Well, I think 1.174 says that if you do a reasonably conservative analysis or if you do something that you think is a bounding analysis, you can address uncertainty in that way. CHAIRMAN APOSTOLAKIS: I thought 1.174 really looked at all these uncertainties. How do you know something is conservative if you don't understand the uncertainties? Don't you have to understand what is uncertain first before you say now what I'm doing is conservative? MR. DINSMORE: It's also that the uncertainties in the pipe failure probabilities are probably much larger than in the PRA. CHAIRMAN APOSTOLAKIS: That's also true. So how are these uncertainties handled? MR. DINSMORE: We handle them by having different criteria. Again this risk level criteria, we don't allow them to move risk around between systems very much. The risk level criteria is you can't get more than a 10 to the minus 7th increase in LERF. So it's a factor of 10 below the plant level criteria. It's regardless if you only have three systems. Then the plant level is going to be 3 times 10 to the minus 7th and not 1 times 10 to the minus 6th. We've tried to deal with uncertainty by putting in this backstop of what you can move and what you can't move. We've actually done it in the BER program as well. We've taken the BER program by itself. They have to apply the same criteria to the BER program. In other words, every system within the BER program they cannot increase the CDF by more than 10 to the minus 7th per year. For the total BER program although it's not really useful, they couldn't increase the CDF by 10 to the minus 6th. Then if they put it together with the risk-informed ISI, they have to apply those criteria to the total change as well. So there's a couple of steps in the criteria. That's the main -- CHAIRMAN APOSTOLAKIS: What you're saying is that they don't need to do the uncertainty analysis because the criteria we have established have allowed for the uncertainties that you may have which is a new interpretation of 1.174. MR. DINSMORE: We used it in the basic programs. CHAIRMAN APOSTOLAKIS: I understand that you have used it. Okay. Let's go on. MEMBER ROSEN: I have a question about those few licensees that might come in and just want the BER program. Would they have to come and get approval or could they completely avoid any review, just do 50.59 and off they go? MR. DINSMORE: If they don't change the ASME Section 11 or any other licensing basis, they could. Yes. They would not have to come in. They could just do it. They have to put it in their yearly report that they've done it. MEMBER ROSEN: So the staff would never get a chance to talk to them about their PRA and how good it is or any of those things. MR. DINSMORE: No. But they're required to do the same analysis which we've been requiring them to do for risk-informed ISI which is to take all the comments and everything and document it. The documentation requirements to be maintained onsite are the same if they just do the BER as they are if they do a risk-informed ISI. It's just that they don't send us anything. MEMBER ROSEN: That part troubles me quite a bit. At least in the basic risk-informed ISI program licensees came in with the EPRI method. The staff reviewed what they wanted to do, looked at their PRA and their peer review and had some handle on it. With the small number of licensees I'm told who would never have to go through that process, could use 50.59 and change the break exclusion region piping sample size without any staff at all of anything except after the fact. MR. DINSMORE: We do very limited reviews of the PRA. Really all we ask for is who said what bad things about your PRA and what did you do about them. We look at what they do. They usually give a reason. If somebody said you had a bad human error, they say we applied these new methodologies and so on. We've occasionally gone back and said that's not enough, please give us more. But that's not often. These guys if they just do the BER, they're still going to have to do the same process. If we go out and eventually audit one of these guys and they didn't do it or they didn't document it, then I'm not sure what we'll do. But we'll do something. MEMBER LEITCH: I'm still a little bit confused with the approval of this proposal. What determines whether it's 25 percent or 10 percent? MR. DINSMORE: Well, 25 percent of the welds in high safety significant segments have to be inspected. The 10 percent of the welds in medium safety significant segments have to be inspected. That's a hold over from the old methodology. MEMBER LEITCH: So the determination is based on whether it's high or medium safety. MR. DINSMORE: Right. MEMBER LEITCH: There are no low safety significant systems in this set, I guess. MR. DINSMORE: There are. You do not have to inspect those. MEMBER LEITCH: Are they inspected now? MR. DINSMORE: On the BER everything is inspected, yes. MEMBER LEITCH: So there are some where there are low safety significant that you would go from 100 percent inspection to zero inspection. Is that what I understood you to say? MR. DINSMORE: That's correct. CHAIRMAN APOSTOLAKIS: I'm missing something here. Has anybody objected to that? Why are they reluctant to do that when we talk about option 2? The low risk significant SSC still impose some requirements. They are unwilling to lump them with non-risk significant. Yet for pipes it seems that they're willing to go to zero. MR. DINSMORE: Well we did a bounding calculation. MR. O'REGON: Pat O'Regon from EPRI again. We looked at three plants, two sites out of the BER application. We did find some low safety significant locations. But they were as a result of the utility conservatively applying the BER rules. They extended piping beyond where they would have had to if they held strictly to the SRP requirements. So that's why they fell as low safety significant. They weren't big pipes that created big holes in containments. As Steve mentioned, the high, medium or low are from the EPRI TR ISI, the base case methodology where we rank things as high, medium or low. We just kept that consistent when we extended it to the BER programs. CHAIRMAN APOSTOLAKIS: All right. MR. DINSMORE: The methodology is consistent with the EPRI Topical Report. The inconsistencies are the things we've explained to you. The changes to BER program as described in the FSAR may be made under 10 CFR 50.59. Inspections within the BER program to change that come from other regulatory requirements need to be changed according to how you change the other regulatory requirements. MEMBER SHACK: Anything else? CHAIRMAN APOSTOLAKIS: No letter. Right? No request for a letter. MEMBER SHACK: There's no request for a letter. CHAIRMAN APOSTOLAKIS: So there will never be a letter. MEMBER SHACK: Not unless we decide one. They're not requesting one. We can discuss whether we want to send one. CHAIRMAN APOSTOLAKIS: Okay. Anymore questions to the lady and the gentleman? MEMBER POWERS: Well, there's another point to be made. That is it is true enough that bypass accidents are risk dominant. But bypass accidents initiated by failure of this particular piping don't show up in the PRA at all. They never occur. MEMBER SHACK: There is one difference though. When we did the original in service risk- informed, you could make the argument that you were in fact approving safety. Obviously you might have been looking at fewer welds. But you were looking at the more important welds. So you could make an argument that your Delta CDF could have gone down. In this case, it might be a small change but it has to go. MR. DINSMORE: That's part of the reasons that we applied the criteria specifically to the BER as well. That was the best way we could think of to deal with that. MEMBER POWERS: But you still have this performance observation. MEMBER SHACK: Right. CHAIRMAN APOSTOLAKIS: That's really a powerful argument. MEMBER SHACK: That's incorporated in the argument that you're going to apply all that good performance to assign most of this stuff to a low probability of failure. You don't want to give them double credit for that. They're going to take that credit already. Again, it's a very small change in LERF for perhaps ALARA reasons. CHAIRMAN APOSTOLAKIS: Isn't there a table that the regional methodology has when they have the risk significant of a piece of piping? Then they have a susceptibility. That's where the performance comes. MEMBER SHACK: That table still applies. CHAIRMAN APOSTOLAKIS: The performance comes there. MEMBER SHACK: Yes. CHAIRMAN APOSTOLAKIS: Is this for everything or at Westinghouse? MEMBER SHACK: Yes. It's everything. MR. DINSMORE: I wouldn't bring Westinghouse to EPRI SE. CHAIRMAN APOSTOLAKIS: No. I mean, they have something similar I think. MR. DINSMORE: They have something similar, yes. But you can see here if it's a really high consequence in this methodology, it would end up in a medium box even with no degradation mechanisms. CHAIRMAN APOSTOLAKIS: Medium means? MR. DINSMORE: The 10 percent. CHAIRMAN APOSTOLAKIS: My concern is bigger than what you're doing. I think that the implementation of Regulatory Guide 1.174 has drifted away from what the guideline is saying. It has a lot to do with you. Are there anymore questions for Steve and Andrea? Well, thank you very much. MR. DINSMORE: Thank you. CHAIRMAN APOSTOLAKIS: I would ask the members to stay here for a few more minutes. Maybe we can discuss things among ourselves. Shall we take a five minute break? Eight minutes. We don't need transcription anymore. Thank you. Off the record. (Whereupon, the above-entitled matter concluded at 6:21 p.m.
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