ML11311A233
| ML11311A233 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 10/19/2011 |
| From: | Advisory Committee on Reactor Safeguards |
| To: | |
| References | |
| NRC-1216 | |
| Download: ML11311A233 (231) | |
Text
Offic ia l Tra ns c ript of Proc e e dings NUCLEAR REGULATORY COMMISSION Title: Advisory Committee on Reactor Safeguards Subcommittee on Plant License Renewal Docket Number: (n/a)
Location: Rockville, Maryland Date: Wednesday, October 19, 2011 Work Order No.: NRC-1216 Pages 1-159 NEAL R. GROSS AND CO., INC.
Court Reporters and Transcribers 1323 Rhode Island Avenue, N.W.
Washington, D.C. 20005 (202) 234-4433
1 1 UNITED STATES OF AMERICA 2 NUCLEAR REGULATORY COMMISSION 3 + + + + +
4 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 5 (ACRS) 6 + + + + +
7 SUBCOMMITTEE ON PLANT LICENSE RENEWAL 8 + + + + +
9 WEDNESDAY 10 OCTOBER 19, 2011 11 + + + + +
12 ROCKVILLE, MARYLAND 13 + + + + +
14 The Subcommittee met at the Nuclear 15 Regulatory Commission, Two White Flint North, Room 16 T2B3, 11545 Rockville Pike, at 8:30 a.m., John Sieber, 17 Chairman, presiding.
18 SUBCOMMITTEE MEMBERS PRESENT:
19 JOHN D. SIEBER, Chairman 20 WILLIAM J. SHACK 21 GORDON R. SKILLMAN 22 JOHN W. STETKAR 23 24 CONSULTANTS TO THE SUBCOMMITTEE PRESENT:
25 JOHN J. BARTON NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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2 1
2 NRC STAFF PRESENT:
3 KENT L. HOWARD, SR., Designated Federal 4 Official 5 GREGORY PICK
- 6 MELANIE GALLOWAY 7 ARTHUR CUNANAN 8 BILL HOLSTON 9 JIM GAVULA
- 10 MICHELLE KICHLINE 11 MATT HOMIACK 12 ALLEN HISER 13 CHING NG 14 CHRIS SYDNOR 15 JEFF POEHLER 16 17 18 19 20 21 22 23 24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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3 1
2 ALSO PRESENT:
3 DALE ATKINSON 4 DAVID SWANK 5 JOHN TWOMEY 6 MOT HEDGES 7 DONALD GREGOIRE 8 SCOTT WOOD 9 ABBAS MOSTALA 10 STEVE RICHTER 11 DAVID LEE 12 BRIAN ADAMI 13 JOHN SISK 14 JOHN LaSALLE 15 CAROLYN BEAUDRY 16 JIM HAMLEN 17 JACK COLE 18
- Present via telephone 19 20 21 22 23 24 25 26 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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4 1 C-O-N-T-E-N-T-S 2 PAGE 3 Opening Remarks - Jack Sieber, ACRS 5 4 Staff Introductions and Review Context 9 5 Energy Northwest - Columbia Generating Station 6 A. Introduction 15 7 B. General Plant Overview 17 8 C. Plant Status/Major Improvements 42 9 D. License Renewal Application 52 10 E. SER Open Items 64 11 F. Concluding Remarks 99 12 NRC Staff Presentation SER Overview 13 A. Introduction 103 14 B. Scoping and Screening Results 106 15 C. Onsite Inspection Results 106 16 D. Aging Management Review 116 17 E. Open Items/Time-Limited 18 Aging Analyses 122 19 F. Conclusion 144 20 Subcommittee Discussion 152 21 22 23 24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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5 1 P-R-O-C-E-E-D-I-N-G-S 2 8:26 a.m.
3 CHAIR SIEBER: The meeting will now come 4 to order. This is a meeting of the Plant License 5 Renewal Subcommittee. My name is John Sieber, 6 Chairman of this subcommittee meeting.
7 ACRS members in attendance are, John 8 Stetkar, Bill Shack, Gordon Skillman, and also with us 9 is John Barton, a former ACRS member and currently an 10 ACRS consultant.
11 Kent Howard of the ACRS staff is the 12 Designated Federal Official for this meeting. The 13 subcommittee will review the license renewal 14 application for the Columbia Generating Station and 15 the associated Safety Evaluation Report with Open 16 Items.
17 I note that there are six open items 18 currently on the report that I have, which is about 19 the maximum for a subcommittee meeting, so prior to 20 the full committee meeting we expect all those open 21 items to be resolved.
22 We will hear presentations from NRC staff, 23 Energy Northwest representatives and other interested 24 persons regarding this matter. I would like to add 25 that the Region IV inspector, Mr. Gregory Pick, is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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6 1 also participating in this meeting via bridge line.
2 Mr. Pick, if you are on the bridge line 3 could you please acknowledge?
4 MR. PICK: I'm on the bridge.
5 CHAIR SIEBER: Okay, thank you. And I'll 6 leave the bridge line open during this meeting for 7 your participation, and I note that you are scheduled 8 at 10:15 or thereabouts to make a presentation.
9 We have not received written comments or 10 requests for time to make oral statements from members 11 of the public regarding today's meeting. The entire 12 meeting will be open to public attendance.
13 The subcommittee will gather information, 14 analyze relevant issues and facts and formulate 15 proposed positions and actions as appropriate for 16 deliberation by the full committee.
17 The rules for participation in today's 18 meeting have been announced and part of the notice of 19 this meeting, previously published in the Federal 20 Register.
21 A transcript of this meeting is being kept 22 and will be made available as stated in the Federal 23 Register notice. Therefore, we request that 24 participants in this meeting use microphones located 25 throughout the meeting room when addressing the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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7 1 subcommittee.
2 The participants should first identify 3 themselves and speak with sufficient clarity and 4 volume so that they may be readily heard.
5 Now I would point out that the Plant 6 Operations and Fire Protection Subcommittee did visit 7 the Columbia Generating Station in, I think it was 8 July of 2010, and we had eight members of the ACRS 9 with us at that time.
10 So we have some familiarity not only with 11 the Generating Station but also its operating 12 organization in the surrounding site and environment 13 including the DOE activities at the Hanford 14 Reservation.
15 That was an important and worthwhile visit 16 for us to make to your plant. It gives us a better 17 background and understanding of the condition of the 18 plant, the competence and the willingness of the site 19 personnel to properly manage the plant, and also the 20 environmental impacts that may be caused either by the 21 plant or by DOE activities which is in the surrounding 22 area.
23 And I note that DOE has done a lot of 24 remediation work in that area and that continues on, 25 and there's no evidence that I can recall of any NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 1 environmental impact other than as is stated in the 2 environmental report into the Generating Station on 3 that site.
4 We will now proceed with the meeting and I 5 call upon Melanie Galloway to begin. Melanie?
6 MS. GALLOWAY: Thank you, Mr. Sieber. My 7 name is Melanie Galloway. I'm the Acting Director of 8 the Division of License Renewal. Brian Holian, who is 9 the director who would normally be here, is currently 10 taking an assignment as the Acting Office Director of 11 our Office of Research.
12 So while I'm assuming the role of 13 director, Mark Delligatti, to my right, has stepped in 14 to fill my position as the Acting Deputy Director of 15 the Division of License Renewal.
16 Mark comes to us from the Office of 17 Federal and State Materials and Environmental 18 Management Program and we're glad to have him.
19 To my left is Dennis Morey, who is the 20 responsible Branch Chief for the project management of 21 the Columbia License Renewal Application. In 22 addition, we have a number of staff here to support 23 this discussion today.
24 We have our three technical branch chiefs 25 from the Division, Dave Pelton, Bo Pham and Raj NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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9 1 Auluck. In addition, they each have staff as well to 2 support any line of question that may come up.
3 In addition, besides Greg Pick, who Mr.
4 Sieber indicated is on the phone, he will be 5 discussing the regional inspection. He's a very 6 experienced inspector having led five 71002 7 inspections already, the most recent being the 8 Columbia.
9 In addition, on the phone we have Jim 10 Gavula, a member of Dave Pelton's staff located in our 11 Region III office. And also have Dan Knotts, a very 12 experienced consultant of ours in Oak Ridge in the 13 concrete and concrete degradation area.
14 As we normally do, I'd like to give a 15 little bit of context to the Columbia review. As the 16 ACRS is aware, we've experienced a seven-month delay 17 in the schedule associated with our review.
18 And the challenges that resulted in that 19 delay have to do with the applicants needing 20 additional time than what we normally allow in our 21 schedule to respond to RAIs.
22 In addition, we have ten rounds of follow-23 up RAIs, so these two items contributed to our need to 24 extend that schedule.
25 Now to the applicant's credit, in December NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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10 1 of 2010, they did re-look at the way they were 2 responding to our RAIs and improved it. So that 3 resulted in us not having to take at this point in 4 time further delays in the schedule, so we appreciate 5 that.
6 But it is important to note that we have a 7 February 2012 due date right now for the issuance of 8 our final safety evaluation, but given the RAIs that 9 are outstanding, the open items that we have and the 10 fact that there is significant work yet to be done on 11 the part of the applicant as well as reviewed by the 12 staff, there is a likelihood that we will have to 13 consider a further schedule delay, because it will be 14 extremely ambitious at this point for us to be able to 15 meet that February 2012 date with the outstanding work 16 yet to be done.
17 As I've mentioned, there are six open 18 items. The committee will be familiar with one of 19 them. The metal fatigue issue has already been talked 20 about on Salem-Hope Creek.
21 But the other five issues are unique to 22 Columbia, and so that will be an opportunity for us 23 all to engage in some new items that are coming up for 24 us in the license renewal arena.
25 There is one particular open item that I NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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11 1 do want to discuss and it's the operating experience 2 open item. This is an area that has been of 3 increasing importance and emphasis to the agency, and 4 it's important to put it in context.
5 We have reviewed and renewed a large 6 number of licenses as part of our license renewal 7 program. However, there's only nine plants right now 8 that are in a period of extended operation.
9 So there is not that much experience in 10 transitioning and implementing all the Aging 11 Management Programs that go into an approved license 12 renewal.
13 And as a result of that the staff has done 14 a lot of work in capturing operating experience in a 15 number of documents. The most recent one being GALL, 16 Rev 2. Most of the updates to that document had to do 17 with changes and improvements and understandings in 18 operating experience.
19 In addition, we put out Information 20 Notices and we put out ISGs, all of which has 21 connection on operating experience.
22 While the staff is doing a lot of work in 23 this regard, we do have an expectation that 24 applicants, as they go into their period of extended 25 operation will do likewise, independent work to ensure NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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12 1 that they are understanding operating experience at 2 their site and in the industry to ensure that their 3 Aging Management Programs will remain effective over 4 that period of extended operation.
5 Based on some recent observations that 6 we've had, we've found that there might be some 7 challenges for applicants as they go into this period 8 of extended operation to ensure that their Aging 9 Management Programs are maintained up-to-date in light 10 of operating experience.
11 In particular, we see changes and turnover 12 of staff, we see training opportunities that need to 13 be met, but perhaps most important we see program 14 updates.
15 The idea that applicants as they go into 16 the PEO need to understand what changes and what 17 thresholds need to be met in order for those changes 18 to occur both in terms of thresholds of what 19 information along the lines of operating experience 20 that need to be shared with the industry, and what 21 thresholds need to be met so that they can update 22 their Aging Management Programs effectively all the 23 time.
24 10 CFR 54 requires that applicants as part 25 of their application are able to demonstrate the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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13 1 effectiveness of their Aging Management Programs over 2 time, and for the staff that includes operating 3 experience.
4 So as a result of our emphasis in this 5 area and the understandings that we have gained, we're 6 putting increasing expectations on what applicants 7 need to include in their application to demonstrate 8 that they are going to be in a position to manage 9 their programs over time, and that includes a key 10 component of operating experience.
11 So we'll get into a little bit more detail 12 with the applicant and the staff in discussing this 13 open item, but that gives you a little bit of 14 background as to how we have come up to this point.
15 I should note as well that we've also 16 recently put out an Interim Staff Guidance document 17 for comment.
18 We had a public meeting last week with the 19 industry and stakeholders, which was a very good 20 discussion, that is going to allow all of us to get 21 better alignment. The NRC has put out better guidance 22 in this regard that clearly indicates what we've 23 expected all along, but more appropriately states and 24 makes sure that everyone else understands what our 25 expectations are regarding operating experience in the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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14 1 period of extended operation.
2 At this point that concludes my opening 3 remarks and I'll turn it over to Dale Atkinson, the 4 applicant.
5 MR. ATKINSON: Thank you very much. I'm 6 Dale Atkinson, vice president of Employee Development 7 and Corporate Services for Energy Northwest.
8 Mr. Chairman and distinguished members of 9 the ACRS, we thank you for the opportunity to come 10 here and talk to and to bring our team from Energy 11 Northwest to present the License Renewal Application 12 for Columbia Generating Station.
13 I would like to say just a little bit 14 about the team I've got up here at the front. Again, 15 my name's Dale Atkinson. I've been at Energy 16 Northwest for over 22 years.
17 Represented here amongst the five of us is 18 in excess of 100 years of operating experience at 19 Columbia Generating Station alone, and thus the gray 20 hair and other challenges here.
21 But beyond that I've held a number of 22 positions at Energy Northwest including Chief Nuclear 23 Officer. When I return tonight, starting tomorrow 24 I'll be Acting Chief Nuclear Officer again and then 25 over the weekend Chief Executive Officer for a little NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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15 1 awhile.
2 And that's how it works in an organization 3 of 1,200 and some odd people. For myself personally, 4 besides the period at Oregon State, I do have 5 experience starting up other nuclear reactors for 6 General Electric Company.
7 I presently chair the Operations 8 Subcommittee at the Cooper Nuclear Station. I also 9 chair the Advisory Committee on Nuclear Engineering 10 and Radiation Health Physics at Oregon State 11 University.
12 I would like to take a moment to introduce 13 my team here. To my immediate left is Dave Swank.
14 Dave is our Engineering General Manager. To his left 15 is Don Gregoire, Manager of Regulatory Affairs.
16 To Don's left is John Twomey. John is the 17 incoming License Renewal Project Manager and he is 18 taking the reins in that regard from the gentleman to 19 his left, Abbas Mostala, who has followed this project 20 and provided the leadership on it to date, so thank 21 you, Abbas.
22 We also have quite a number of staff 23 throughout the room to provide the backup support 24 should we need some detailed discussion on a topic 25 that we at the front table might not have the level of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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16 1 detail that becomes necessary.
2 Mr. Chairman, we do have an agenda that 3 includes discussion about Energy Northwest and an 4 overview of Columbia Generating Station, and I do 5 understand that several of you have been to the site 6 and seen it.
7 So we'll move through that part 8 expeditiously except as individuals need some specific 9 questions answered, provide you a plant status and an 10 indication of some of the major improvements.
11 I think you'll see a pattern of 12 significant investment in Columbia Generating Station.
13 We will of course talk about the License Renewal 14 Application, the open items on the Safety Evaluation 15 Report, and then I'll provide some concluding remarks.
16 So just quickly, Energy Northwest itself, 17 we are a public agency. We have been providing public 18 power in the Northwest since 1957. Our largest 19 generating facility is Columbia Generating Station, 20 but in addition to that we do have hydroelectric, 21 solar and wind projects.
22 For those of you that visited the site, 23 you may have seen the solar project adjacent to 24 Columbia Generating Station. The entire output of 25 Columbia Generating Station is provided to the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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17 1 Bonneville Power Administration for distribution in 2 the Northwest.
3 On the grid it is provided at cost, and 4 between Bonneville and rate payers of the Northwest 5 there is quite a dependence on the safe, efficient and 6 reliable operation of Columbia Generating Station.
7 A little bit more about Energy Northwest, 8 we are a joint operating agency and that means that we 9 were authorized by the State of Washington to provide 10 energy and energy services at cost to rate payers of 11 the Northwest.
12 We have a membership that's comprised of 13 28 municipalities or/and public utility districts from 14 across the state of Washington. For those of you that 15 visited the site you'll recognize the next picture.
16 It is an overhead view.
17 It is not as flat as that picture looks.
18 We are located in Eastern Washington and in an area of 19 the state that is surrounded by a lot of hydroelectric 20 facilities or a lot of dams on the river.
21 You see Columbia Generating Station in the 22 foreground with the six forced draft cooling towers to 23 the immediate right there, the two ultimate heat sink 24 cooling ponds right above that with the spray rings in 25 operation.
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18 1 If you go to the top of the picture that 2 is the Columbia River, an enviable source of cooling 3 water, very clean and cold with the high volumes.
4 We're lucky to have that.
5 CONSULTANT BARTON: What are the two ponds 6 to the right?
7 MR. ATKINSON: On the far right there, 8 those are sewage treatment ponds.
9 CONSULTANT BARTON: Okay.
10 CHAIR SIEBER: Maybe since we have this 11 picture this is a good time to ask questions about the 12 general layout. But what's the ultimate heat sink for 13 Columbia Generating Station?
14 MR. ATKINSON: Well, we -- do you want to 15 answer that?
16 MR. SWANK: Sure. It's the two spray 17 ponds. So we have 30-day volume in the ponds and then 18 we have capability to make up. We could bring in 19 trucks. We have capability to make up from the river 20 as well.
21 CHAIR SIEBER: Okay, but now the river's 22 three and a half miles from the site?
23 MR. SWANK: That's correct.
24 CHAIR SIEBER: And you have a screenhouse 25 on the river?
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19 1 MR. ATKINSON: That's correct.
2 CHAIR SIEBER: But do you consider the 3 lines, the water line between the Columbia River 4 screenhouse and the plant site as safety related, 5 important to safety or just another water line in the 6 ground?
7 MR. SWANK: It is not safety related.
8 It's certainly beneficial to us to have it, although 9 like I say, we have the capability to bring the water 10 in by trucks if we need to.
11 CONSULTANT BARTON: Is it in-scope to 12 license renewal? Is it in-scope? Is that an Aging 13 Management Program or inspection program that piping 14 that Jack just asked about?
15 MR. TWOMEY: Yes, it is.
16 CHAIR SIEBER: And okay, then you will 17 later on explain a little bit what your Aging 18 Management Program is for that line?
19 MR. TWOMEY: Okay.
20 CHAIR SIEBER: Okay, I would appreciate 21 that.
22 MR. TWOMEY: We will make sure we do that.
23 CHAIR SIEBER: Now the EPZ, through this 24 50-mile EPZ includes a water plan for the reservation 25 but it also includes the Tri-Cities area?
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20 1 MR. TWOMEY: That's correct.
2 CHAIR SIEBER: And seemed to me the 3 population is over a million people in that 50-mile 4 zone, something like that including Indian reservation 5 to the southwest, which grows a lot of fruits and 6 vegetables.
7 When you have discharges from your plant 8 do you discharge to the Columbia River?
9 MR. ATKINSON: Through our permit it'd be 10 discharged into the Columbia River. In practice, what 11 we have done for over ten years is only the blowdown 12 flow that's required to maintain the salt 13 concentration in the forced draft cooling towers at 14 acceptable levels.
15 So we actually have not had a need to do a 16 discharge, but we are permitted to discharge to the 17 Columbia River within our operating license.
18 CHAIR SIEBER: And you have no real 19 commercial vegetation, you know, farms or so forth 20 basically -- well, there's a few, but not very much 21 within the ten-mile EPZ? It's mostly desert as we 22 can, there is semi-desert?
23 MR. ATKINSON: That's generally true, but 24 we do have some. If you'd like a description we have 25 an individual here that can cover the specifics.
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21 1 CHAIR SIEBER: Yes, and I have read the 2 environmental report and it's all in there.
3 MR. SWANK: You can actually see some of 4 the orchards in the top part of the picture, you know, 5 right across the river, on the other side of the 6 river.
7 CHAIR SIEBER: Right, it's on the other 8 side of the river. In fact, that's rising ground on 9 the other side of the river.
10 MR. SWANK: Very much so.
11 CHAIR SIEBER: Okay. Okay, thank you.
12 MR. ATKINSON: All right, and just to 13 point out as I said, this does look flat from that 14 aspect, but the plant itself is 88 feet above the 15 level of the river.
16 The next slide is intended to show the 17 layout of the land we actually lease from the 18 Department of Energy.
19 And essentially what we lease are 1,100 20 acres from the Department of Energy, includes an area 21 roughly 2,000 meters in diameter that surrounds the 22 plant and a corridor down to the Columbia River that 23 includes the piping that was just discussed and the 24 river water pumphouse.
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22 1 management of an exclusion area, and we have a 2 Memorandum of Understanding and lease agreements that 3 I've reviewed that provide pretty good controls on 4 what happens within that.
5 I think one thing to note, in fact, if we 6 go back to that previous slide, Abbas, one thing to 7 note on there that you brought up, Mr. Chairman, is 8 that on the bottom you'll see that square of land.
9 That is the closest area to be remediated 10 by the Department of Energy and those surveying 11 activities have commenced there.
12 CHAIR SIEBER: Yes, we spent quite a bit 13 of time during our visit going to the DOE sites. Not 14 only this one but there's others --
15 MR. ATKINSON: Right, they're very similar 16 to that.
17 CHAIR SIEBER: -- others in the area that 18 have more activity than this one appears to have.
19 MR. ATKINSON: Okay, Abbas, on Slide 9.
20 So this is an indication of the plant history, just a 21 very, very high level. Construction permit was 22 granted in 1973, operating license in 1983.
23 We have done a five percent uprate of the 24 plant in 1995. The original plant was licensed to 25 3,323 megawatts-thermal, power uprate took us to 3,486 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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23 1 megawatts-thermal. We are not planning any further 2 uprate at this time.
3 The general description of the facility is 4 a General Electric BWR-5 with a Mark II containment.
5 As I pointed out on the picture, we do have a plant 6 circulated water system that utilizes six forced draft 7 cooling towers and the ultimate heat sink does have 8 makeup water available from the Columbia River.
9 CHAIR SIEBER: Okay, your fire protection 10 water also comes from the site ponds?
11 MR. SWANK: Actually a combination.
12 CHAIR SIEBER: You can go from the river 13 but --
14 MR. SWANK: Well, we actually have a 15 bladder tank in addition to the circulating water 16 basin so we're able to draw, different pumps draw off 17 of those two sources.
18 CHAIR SIEBER: Okay, are you going into 19 any detail on the containment structure? As I see it 20 this containment is unique in the industry. It is a 21 steel containment as opposed to other Mark IIs, and 22 there aren't very many Mark II containments.
23 I presume you were going to the 24 containment.
25 MR. ATKINSON: Okay, we will have a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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24 1 discussion on the containment in just a minute here 2 then. I don't think you'll find it particularly 3 unique for a Mark II, but we'll go into the specifics 4 of it here in just a moment. We'll do that.
5 Why don't we go ahead and jump into that 6 discussion here for just a minute? John, if you'll go 7 ahead and commence that with Slide 87, please.
8 MR. TWOMEY: I'm John Twomey. I've also 9 been the civil lead on the project since its 10 inception. Columbia, as this pulls up the slide, is a 11 Mark II free-standing metal containment.
12 This is the picture of it. It is a over-13 under, which means we have a drywell-wetwell separated 14 by reinforced concrete floor. We have a five-foot 15 thick approximately, bioshield wall, reinforced 16 concrete wall around it and then we have the reactor 17 building proper.
18 And I do note, highlighted, we do have a 19 sand pocket region that is at that elevation. It's a 20 fully 360-degree circumferential which creates about 21 300 linear feet of sand pocket area. Next slide.
22 CHAIR SIEBER: Do you have any access --
23 well, the containment is basically all steel in this.
24 It's free standing except it sits on the sandpile, is 25 that correct?
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25 1 MR. TWOMEY: No, it's free standing. As 2 you can see on the bottom there's an inner and outer 3 skirt on the drawing, so it physically sits on the 4 skirts and the skirts sit on the foundation mat, and 5 then we poured the concrete, both the concrete up 6 underneath it and up the sides.
7 CHAIR SIEBER: Okay, so it does not sit on 8 sand?
9 MR. TWOMEY: No, there -- next detail. So 10 as we were constructing it we added this, first we had 11 to pour the concrete underneath and come up the sides.
12 We added this sand pocket region.
13 CHAIR SIEBER: Okay.
14 MR. TWOMEY: As you can see, the metal 15 containment vessel, it starts to transition from 16 vertical underneath into the ellipsoidal head. So 17 that helped us pour the concrete around it, and as I 18 said that is full 360 degrees.
19 CHAIR SIEBER: And my question is, inside 20 the containment you also had concrete?
21 MR. TWOMEY: That's correct.
22 CHAIR SIEBER: So you have the bottom of 23 the containment vessel sandwiched in between a 24 concrete mass above it and concrete on the sides and 25 sand at the bottom?
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26 1 MR. TWOMEY: That's correct.
2 CHAIR SIEBER: How do you know the 3 integrity of the steel portion of the containment in 4 that area other than a leak test?
5 MR. TWOMEY: What we've done is, since in 6 1983 -- as you can see there's a drain pipe. There 7 are eight of those coming off the sand pocket region.
8 We verified we had a free drain flow path 9 through the pipe, and at that time we instituted a 10 weekly check of the drain lines and that is, which 11 slide is that that shows a picture of it, 91.
12 What we've got here is the drain lines 13 from the sand pocket region are accessible at one of 14 our elevations here. We have our equipment operators, 15 at that time they're going out weekly to do a water 16 check.
17 So basically what we're validating is that 18 we've got no water in that sand pocket region which 19 would then minimize any corrosion.
20 CHAIR SIEBER: How do you determine the 21 drain line is not flushed?
22 MR. TWOMEY: We verified that back in '83 23 and again in '87, 1987. We've made a commitment to go 24 back out by 2015 and verify that they are still free, 25 that the drain lines are still a free flow path.
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27 1 CHAIR SIEBER: Okay.
2 CONSULTANT BARTON: You may not be seeing 3 what has come out of your drain pipe. However, if 4 you've got a slight leakage up above that saturates 5 the sand, how do you know you don't have wet sand 6 sitting against the steel containment?
7 MR. TWOMEY: We have them pull a sand 8 sample out of it.
9 CONSULTANT BARTON: You have not --
10 MR. TWOMEY: Not recently. We did it in 11 1987 and it was about two percent moisture.
12 MR. ATKINSON: John, why don't you show 13 Slide 90 and the likely source of any water in 14 leakage?
15 MR. TWOMEY: This is the very top of the 16 containment. And what this is showing is we have a 17 refueling bellows seal so when we flood up --
18 CONSULTANT BARTON: Which is a lot of 19 plants do have leaks there.
20 MR. TWOMEY: Right. What isn't shown on 21 this is we have six drain lines all through the plant 22 and it's to do just -- right across here. So if the 23 bellows seal would leak the water would splash, come 24 down to here.
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28 1 into a common header and we have leak detection at 2 that common header. We have a flow indicating switch 3 that alarms in our control room over, at a flow of one 4 gallon per minute or more.
5 CONSULTANT BARTON: How much?
6 MR. TWOMEY: One gallon per minute or 7 more.
8 CONSULTANT BARTON: So it'll pick up one 9 gallon a minute or more of leakage?
10 MR. TWOMEY: That's correct, and we 11 calibrate that every six years. And I've checked, 12 I've gone back to 1991 because that's what we have in 13 our computer database, so it's readily available, and 14 that alarm has not come in.
15 MEMBER SHACK: There is a filler in that 16 gap?
17 MR. TWOMEY: Yes, there is, polyurethane.
18 MEMBER SHACK: What is it, polyurethane?
19 MR. TWOMEY: It's polyurethane foam. It's 20 sheet foam. It was placed in there as a spacer 21 between the concrete and the metal containment. We 22 didn't want the concrete poured up against the metal 23 containment.
24 And it's primary function is for thermal, 25 thermal growth of the primary container.
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29 1 CONSULTANT BARTON: Now you never had an 2 opportunity to go look in that gap area, have you?
3 MR. TWOMEY: Not yet. We have made a 4 commitment prior to the period of extended operation, 5 yes. Just below here, about ten feet below that we 6 have these eight inspection ports.
7 CONSULTANT BARTON: That's one of them 8 right there?
9 MR. TWOMEY: That's one of the eight. We 10 will physically remove that. We can get in behind 11 there, as well as when we pull out the inspection 12 quarter port off the backside that is also carbon 13 steel and has been exposed to the same environment as 14 the primary containment vessel and we will do 15 inspections on that.
16 We've made the commitments to do that both 17 in the fourth interval, ISI interval, which is the ten 18 years prior to the period of extended operation, and 19 then again at no more than -- including the ten-year 20 period of extended operation adjustable based on what 21 we find.
22 MEMBER SHACK: And the coating on the 23 outside of that vessel is?
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30 1 program. But we inspect all the coatings.
2 MEMBER SHACK: But you haven't looked at 3 the coating on the outside?
4 MR. TWOMEY: There is no coating on the, 5 it's only on the backside.
6 MEMBER SHACK: So it's bare steel.
7 MR. TWOMEY: It's bare carbon steel, 8 that's correct.
9 MEMBER SHACK: Just another curious thing.
10 In the suppression pool then you have the layer of 11 reinforced concrete at the bottom.
12 MR. TWOMEY: That's correct.
13 MEMBER SHACK: So this thing is exposed to 14 the water now. What kind of chemistries do you get in 15 that pool, or how do you control that chemistry in the 16 pool?
17 CHAIR SIEBER: You're talking about the 18 suppression pool?
19 MEMBER SHACK: Yes.
20 MR. TWOMEY: Yes, I'll ask Mot Hedges to 21 come up and talk about that.
22 MR. HEDGES: Mot Hedges, plant chemistry.
23 The suppression pool is demineralized water and it is 24 periodically run through a filter and demineralizer to 25 maintain purity, and it's essentially to demineralize NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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31 1 water. We have --
2 MEMBER SHACK: Does it become alkaline 3 from the concrete?
4 MR. HEDGES: No.
5 MEMBER SHACK: Just too much of it. Well, 6 the concrete is coated.
7 MR. TWOMEY: That's correct. The concrete 8 in the suppression pool is coated, that's correct.
9 And that is underneath our --
10 MEMBER SHACK: And it's coated with what?
11 MR. TWOMEY: I'll have to get you the --
12 MEMBER SHACK: Assuming it's an epoxy-like 13 coating?
14 MR. TWOMEY: It's an epoxy coating, right.
15 And that falls underneath our Class 1 coatings 16 program. And we go in every outage and check the 17 coatings with the diagram.
18 MEMBER SKILLMAN: This is Dick Skillman.
19 MR. TWOMEY: Yes.
20 MEMBER SKILLMAN: Are the water chemistry 21 conditions for the suppression pool water governed by 22 your tech specs?
23 MR. TWOMEY: Again, Mot?
24 MEMBER SKILLMAN: The question is, are the 25 water chemistry requirements for the suppression pool NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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32 1 water governed by your tech specs?
2 MR. HEDGES: Mot Hedges, plant chemistry.
3 No, they're not. We have limits in our plant 4 procedure site water chemistry too that cover those 5 but they are not in tech specs.
6 MEMBER SKILLMAN: Thank you.
7 CHAIR SIEBER: Okay, now it looks to me as 8 though the geometry of the suppression pool area 9 including the containment wall on the inside is I 10 think highly congested.
11 Have you ever during any outage been able 12 to drain down this suppression pool, and do you, any 13 kind of examination on the containment metal itself 14 from the inside to determine whether it has flaws or 15 corrosion or anything of that nature?
16 MR. TWOMEY: We have not drained down the 17 suppression pool at any time. We do go in and use 18 divers to do inspections of the suppression pool side 19 of the containment.
20 CHAIR SIEBER: Okay, and what kind of 21 inspection do they do?
22 MR. TWOMEY: It's under our ISI program.
23 CHAIR SIEBER: Yes, but --
24 MR. SWANK: It's a visual inspection.
25 CHAIR SIEBER: Is it ultrasonic?
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33 1 MR. TWOMEY: No, it's a visual inspection.
2 CHAIR SIEBER: A visual inspection.
3 MR. SWANK: In fact, this outage we did a 4 cleaning of the suppression pool to remove any, I'll 5 call it, typically what we find is rust products. So 6 we clean to keep our suction strainers in good health 7 and then did the inspection.
8 CONSULTANT BARTON: Do they also inspect 9 the downcomer pipes that go into the suppression pool?
10 Are they looked at?
11 MR. SWANK: Interior or exterior?
12 CONSULTANT BARTON: The exterior of those, 13 aren't they exposed to the water in the suppression 14 pool?
15 MR. SWANK: Yes, they are.
16 CHAIR SIEBER: Yes, on both sides.
17 MR. TWOMEY: Mot?
18 MR. HEDGES: Mot Hedges, plant chemistry.
19 I'm also one of the drywell coordinators, and the 20 divers do go up into each one of the downcomers and do 21 inspections inside and outside.
22 CONSULTANT BARTON: And what do you find?
23 MR. HEDGES: They have found, you mean 24 like debris floating in there? Yes, they have found 25 some debris in there and removed that.
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34 1 CHAIR SIEBER: Could you tell us what the 2 debris is?
3 MR. HEDGES: It's usually debris that 4 falls in there from maintenances during the outage.
5 So they go in and do a final cleanup, closeout, what 6 we call a foreign material inspection.
7 CONSULTANT BARTON: So you don't cover 8 those during an outage to prevent stuff from going 9 down into the suppression pool?
10 MR. HEDGES: Some of them are covered. We 11 can't really get to all of them. Some of them are in 12 pretty dose rate areas.
13 MR. SWANK: I think for clarity, they're 14 all covered but there's obviously a path for steam to 15 get through as well.
16 MR. TWOMEY: Right. As you can see the 17 top of the downcomers are in our drywell and they will 18 have a cover plate on them.
19 MR. SWANK: They have a metal cover 20 plates.
21 MR. TWOMEY: With a vertical, what we call 22 jet deflectors. So for steam, you know, if you get a 23 loss of coolant accident you flow down. But that 24 would, as Mot said, provide a foreign material.
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35 1 might drop something down, so the divers do a 2 cleanout.
3 CHAIR SIEBER: What's the inside diameter 4 approximately of the downcomers?
5 MR. TWOMEY: We have a 24-inch and 28-inch 6 opening for the downcomers.
7 CHAIR SIEBER: So it takes a skinny guy to 8 do the inspection, and it is a visual?
9 MR. TWOMEY: That's correct.
10 CHAIR SIEBER: And it's underwater.
11 MR. TWOMEY: That's correct.
12 CHAIR SIEBER: In a 24-inch space.
13 MR. TWOMEY: That's correct.
14 CONSULTANT BARTON: You've got several of 15 those capped. What's the reason for some of those 16 being capped, downcomers?
17 MR. SWANK: Completely capped?
18 CONSULTANT BARTON: I read in your 19 application I believe that three of your downcomer 20 pipes have been capped.
21 MR. SWANK: We'll have to get you an 22 answer.
23 CONSULTANT BARTON: I read it somewhere.
24 CHAIR SIEBER: Okay. Now a 24-inch, I 25 don't think a person could actually enter a pipe like NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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36 1 that really? I couldn't, and I'm skinny.
2 MR. TWOMEY: Twenty-four inch pipe --
3 CHAIR SIEBER: And so any inspection you 4 do either has to be with instruments that are on 5 extended tubes, or it's just at the areas of 6 accessibility by the inspector even if it's an 7 underwater inspection?
8 MR. TWOMEY: The divers have been able to 9 get up in there though. Again, they're not using 10 tanks, I mean they're hooked up on air. I don't know 11 if that helps somebody but I understand --
12 CHAIR SIEBER: I know how big a 24-inch 13 hole is and it's ten inches smaller than my waist.
14 CONSULTANT BARTON: Can I get you to kind 15 of answer that, because I did read I believe in your 16 applications that three of the 102 downcomer pipes 17 between the drywell and suppression pool have been 18 capped.
19 MR. GREGOIRE: That is correct. I just --
20 MR. TWOMEY: I can tell you -- right.
21 MR. SWANK: We'll get you an answer on why 22 they were capped. I think it's from initial 23 construction but I'm not sure.
24 CONSULTANT BARTON: Well, you can get back 25 to me, okay.
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37 1 MEMBER SHACK: And the coating you 2 inspected with divers, each outage the coating on the 3 suppression pool?
4 MR. TWOMEY: That's correct.
5 MEMBER STETKAR: Have you had any 6 indications of surface corrosion, coating failures?
7 I'm assuming that the answer to that is yes, because 8 any is an incomprehensible word.
9 MR. TWOMEY: Well, we did have one 10 coating, I guess we'll call it a failure indication.
11 The way our coatings program is set up, the coatings 12 engineer is notified and he makes the determination 13 whether we need to do the fix immediately or we can 14 wait until the next outage.
15 They repaired that which now put that into 16 them going back to the next outage. It was about a 17 half-inch like crack in the coating. They went back, 18 repaired that. Repaired it, went back the following 19 outage and could not find it, so the fix had worked.
20 I mean yes, we have.
21 MEMBER STETKAR: And about what fraction 22 of the whole surface do you typically inspect in an 23 outage?
24 MR. TWOMEY: Don't know the answer.
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38 1 whether you actually have indications and whether you 2 have any trending. For example, if you found them do 3 you keep any trending data of increasing corrosion 4 rates or increasing failure rates or anything like 5 that?
6 Because I'm trying to get a handle on, you 7 know, what fraction do you inspect and what frequency 8 do you go back and do inspections in same areas that 9 you've found the indications?
10 MR. TWOMEY: Okay, we'll have to get you 11 the percentage of what they do each outage, and I do 12 know that if they find anything then they have to go 13 back.
14 MEMBER STETKAR: Well, you said that the 15 one that you did find was repaired and then the one 16 that you recall --
17 MR. TWOMEY: Right, and when they had to 18 go back the next year to do the follow-up they could 19 not find it.
20 Mot, was there anything else you could add 21 to that?
22 CHAIR SIEBER: Now the containment volume 23 is about the same as a Mark I containment is, roughly.
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39 1 during an accident condition that you have between the 2 suppression pool and the remainder of containments 3 since it's all in one vessel.
4 You have an inert atmosphere during the 5 operation?
6 MR. TWOMEY: Yes, we do.
7 MR. SWANK: Yes, we do.
8 CHAIR SIEBER: And because of that you 9 monitor containment leak rate? I take it your 10 containments have a slightly positive pressure during 11 normal plant operation?
12 MR. SWANK: That's correct.
13 CHAIR SIEBER: Okay, so you monitor the 14 leak rate and the amount that you might have to add.
15 Have you had any significant positive in-flows to 16 maintain a containment atmosphere within 17 specifications during normal operation?
18 MR. SWANK: No, we haven't seen any real 19 change in the makeup rate that's required.
20 CHAIR SIEBER: Okay, thank you.
21 MR. ATKINSON: I understand we'll follow 22 up on some coatings discussion at the -- hey, Scott, 23 let's follow up at the end on that. Take a look at 24 it.
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40 1 containment?
2 MEMBER SHACK: Except for the coatings on 3 the suppression pool.
4 MR. ATKINSON: And in my understanding you 5 want to understand the inspection frequency --
6 MEMBER SHACK: Well, yes, just what the 7 coating system is. Is it epoxy coat? You have epoxy 8 on the concrete, what do have on the steel?
9 MR. TWOMEY: Okay.
10 (Off microphone comments.)
11 MR. ATKINSON: Okay, we have a response 12 for the explanation of the three capped downcomers for 13 you, sir.
14 MR. WOOD: Scott Wood, Columbia Generating 15 Station. Originally there were 102 downcomer pipes, 16 and during the assessment of the wetwell piping 17 hydrodynamic loads it was found that the local water 18 jet loads on the three containment vessel penetrations 19 and their supports were excessive.
20 So to eliminate these loads, three of the 21 downcomers were capped in the drywell region and that 22 leaves 99 for venting steam.
23 CONSULTANT BARTON: Thank you.
24 MR. ATKINSON: Thank you, Scott.
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41 1 the containment structure at this point? If not, 2 maybe we can get back on the plan.
3 MR. ATKINSON: Thank you, Mr. Chairman.
4 I'd like to turn the presentation over then to Dave 5 Swank. Dave?
6 MR. SWANK: Thanks, Dale. We recently 7 completed our 20th refueling outage for Columbia and 8 we've done a number of major modifications during this 9 outage. We replaced our main condenser.
10 So previously we had an admiralty brass 11 condenser, we replaced that with a titanium condenser 12 for reliability reasons. That also eliminated the 13 copper source for potential fuel crudding buildup.
14 We also replaced our main generator rotor.
15 So we have had two shorted turns on our main 16 generator rotor. We've procured a new rotor and 17 installed that this outage.
18 Finally we replaced the bolted connections 19 within our non-segregated buses, so we went to a 20 welded in flexible link connection similar to what we 21 have on our isophase bus.
22 All three of these, we started up last 23 month and to date all three have been performing very 24 well for us.
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42 1 microbiologically induced corrosion in your condenser?
2 MR. SWANK: In our condenser?
3 CONSULTANT BARTON: Did you have MIC in 4 your condenser before you changed it?
5 MR. HEDGES: Mot Hedges, plant chemistry.
6 There was no MIC of any significance.
7 CHAIR SIEBER: Do you have evidence of MIC 8 attack anyplace in your chamber or piping that you 9 know of and when, how do you control that stuff? It's 10 got to be enormous.
11 MR. HEDGES: I believe there is some.
12 I'll have to get back to you on the extent. What we 13 do is in the circulating water and the plant service 14 water, our raw water systems, we routinely halogenate 15 with a combination of chlorine and bromine.
16 CHAIR SIEBER: Do you use gaseous 17 chlorine?
18 MR. HEDGES: No, we use sodium 19 hypochlorite and sodium bromite.
20 CHAIR SIEBER: Okay, thank you.
21 MEMBER STETKAR: I don't know, I'm trying 22 to keep you on track here but you'll learn when you 23 deal with us that's impossible.
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43 1 in-scope what's out of scope?
2 And let me finish sort of the general, or 3 should I ask you -- you mentioned non-segregated bus 4 ducts and I had a question about the scoping of those 5 things. Should I wait?
6 MR. SWANK: No, I think now is a good 7 time.
8 MEMBER STETKAR: I know some of the bus 9 ducts are in-scope and some of them are not in-scope.
10 I didn't have an electrical drawing so I can't point 11 to specific buses, but I also know in your operating 12 experience you cited a, I guess an arc over-fault that 13 you had. I don't know what the year is.
14 MR. SWANK: 2009.
15 MEMBER STETKAR: Thanks.
16 MR. SWANK: In August to be exact.
17 MEMBER STETKAR: Probably know the date 18 and the minute.
19 MR. SWANK: I do actually know it.
20 MEMBER STETKAR: They're pretty exciting.
21 And that was in an out of scope bus duct, is that 22 correct?
23 MR. TWOMEY: That's correct.
24 MR. SWANK: That's correct. Yes, that was 25 a 6.9 kV bus for a reactor recirculation auger.
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44 1 MEMBER STETKAR: Did that fault cause any 2 external effects? Did you have a fire or did you have 3 any damage external to the bus duct when that fault 4 occurred?
5 MR. SWANK: Do we have pictures?
6 PARTICIPANT: Yes, we do, unfortunately.
7 MR. ATKINSON: I guess the short answer to 8 that is yes. You know, typical failure of one of 9 these buses is fairly catastrophic. It creates a 10 plasma and so anything in the immediate vicinity tends 11 to have some burn damage to it.
12 CHAIR SIEBER: I think you showed us that 13 area when we were on the plant -
14 MR. ATKINSON: Right. On the tour we took 15 you up there and showed you where that --
16 MR. ATKINSON: And the center of the 17 picture there's a better shot. That's where the bus 18 used to be inside the bus duct.
19 CHAIR SIEBER: That wasn't insignificant 20 as I recall.
21 MEMBER STETKAR: That's usually what they 22 look like. The question I had is, is that bus routed 23 through a room that contains any in-scope cables or 24 electrical switch gear?
25 MR. SWANK: Yes.
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45 1 MEMBER STETKAR: Okay, then why isn't that 2 bus in-scope for license renewal, because obviously 3 damage to that bus could affect safety related in-4 scope cables or switch gear?
5 MR. ATKINSON: It looks like we're going 6 to have to do a little homework on that one and get 7 back to you. While we do the homework though, would 8 you please advance to Slide 48?
9 MR. MOSTALA: Which one?
10 MR. ATKINSON: Forty-eight, the next one.
11 So that's what it looks like now, so those are the, 12 well, the flexible connections that differentiate from 13 the bolted connections that were subject to the 14 problem that we experienced previously.
15 So what you can see from that it's a very 16 durable connection that's actually got increased 17 material, the increased thickness for improved margin 18 as well.
19 CHAIR SIEBER: Perhaps my memory is 20 faulty, but I recall that area in the plant as being 21 sort of a labyrinth with crossing corridor-like 22 structures?
23 MR. SWANK: Actually it's fairly wide open 24 there. There's --
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46 1 is, yes.
2 MR. SWANK: Yes, this actually happened 3 right almost directly above switch gear. It's a 4 fairly wide open area at that particular location.
5 CHAIR SIEBER: Okay.
6 MR. ATKINSON: So we'll get back to you on 7 that scoping question.
8 MEMBER STETKAR: Sorry to interrupt, now 9 you can go back there.
10 MR. SWANK: Sure. Okay, we're back to 11 Slide 13.
12 CHAIR SIEBER: Yes, I think you're on 13.
13 MR. SWANK: We'll talk about some of the 14 other major improvements that we made to the facility.
15 I won't go through all of them, but I'd certainly be 16 happy to answer the questions you have on any of them.
17 CONSULTANT BARTON: The only question I 18 have is why the fourth diesel?
19 MR. SWANK: We went from a 72-hour LCO for 20 our diesel generators, limiting condition for 21 operation, to a 14-day limiting condition for 22 operation, so as part of that we installed or 23 purchased a fourth, this is a 480-volt diesel.
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47 1 2, and so it's basically a risk mitigation device.
2 MEMBER SHACK: Just on your hydrogen water 3 chemistry, as I was reading your operating experience 4 it appears that you have never found an SCC crack in 5 your piping? Is that correct?
6 MR. SWANK: I'm going to turn to Steve 7 Richter for --
8 MR. RICHTER: Steve Richter, Code 9 Programs. Not in our piping, no. We've seen some on 10 our vessel internals.
11 MEMBER SHACK: Right, but not on your 12 piping. So you went from '84 to 2004 without hydrogen 13 water chemistry and no crack?
14 MR. RICHTER: Correct.
15 CONSULTANT BARTON: Why did it take you 20 16 years to get there, 20 years before you implemented 17 it? Why did it take you 20 years to implement 18 hydrogen water chemistry when it's been around for a 19 long time?
20 MR. RICHTER: Well, it hasn't been around 21 -- we were keeping with the industry, but we did have 22 the issue of copper in our system. The copper acts to 23 poison our normal chemistry so, you know, we didn't --
24 noble metal comes through in 2001, which created the 25 hydrogen water chemistry.
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48 1 CHAIR SIEBER: Do you have any copper 2 anyplace in the heat exchangers?
3 MR. RICHTER: We do have other heat 4 exchangers that have copper, or 9:16:25, yes.
5 CHAIR SIEBER: Do you have any long term 6 plans to replace those?
7 MR. RICHTER: No, not that I know of. I 8 can get back to you on the system expert on that. Do 9 we have anything else in our communicating with the 10 reactor vessel, is that your question? Or just how 11 the plant --
12 CHAIR SIEBER: Right.
13 MR. RICHTER: No, I don't believe we have 14 any in our reactor cooling systems.
15 CHAIR SIEBER: Okay.
16 MR. RICHTER: That we communicate there.
17 MR. ATKINSON: Yes, we mentioned earlier 18 the discussion about replacing the main condenser, so 19 Dave has some information on that.
20 But basically that removed that admiralty 21 brass and Muntz metal condenser and installed titanium 22 that if you recall the previous solution for getting 23 hydrogen effectively implemented with --
24 CONSULTANT BARTON: Got you.
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49 1 electrochemical potential where you need it was to, 2 the solution for our a plant like ours was to use a 3 noble metals coating that took awhile to get 4 developed.
5 And once that got developed and we got a 6 hydrogen injection methodology available we installed 7 it.
8 CONSULTANT BARTON: Got you, thank you.
9 CHAIR SIEBER: Thanks for mentioning that 10 again. The first time around I was going to ask a 11 question but now I will since I didn't before.
12 Generally speaking, when you replace 13 admiralty metal with titanium there is a difference in 14 strength of the tubes.
15 And the spacing between various plates 16 within the condenser is if it's built for admiralty 17 metal, generally speaking, to avoid tube vibration you 18 have to change the distance between these plates. Did 19 you do that?
20 MR. ATKINSON: We did a lot more.
21 MR. SWANK: Yes, we actually didn't 22 replace the tubes, we replaced the modules. So we had 23 12 modules double stacked, three I'll call them 24 trains. We pulled everything out and put all new in.
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50 1 support plates were designed for titanium tubes as 2 opposed to a re-tubing job?
3 MR. SWANK: That's correct.
4 CHAIR SIEBER: Well, it's good that you 5 did that because I know personally that doing it the 6 other way is not a good way to do it.
7 MR. ATKINSON: Our condenser replacement 8 project was a very large scope project that replaced 9 all material from one water box at one end, the inlet, 10 to and including the water box at the other end. So 11 everything in between was removed.
12 All that remained from the prior 13 installation was essentially the shell which we 14 stiffened.
15 So once we installed all the modules and 16 basically all the metal that forms the ends of the 17 condenser including the intermediate water boxes, we 18 actually had constructed new water boxes and welded 19 those on the end as well. So that entire scope of 20 work is brand new.
21 CHAIR SIEBER: One more quick question.
22 There is a number of lines that go into the condenser 23 hot well, for example, heat pump recirculation lines 24 and so forth.
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51 1 titanium tubes the failure rate is higher than it 2 would be with admiralty, and they put baffles in 3 there. When you replaced all the modules did you 4 replace the baffles?
5 MR. SWANK: Actually we moved the pipes 6 down below so that they wouldn't impinge on the tubes.
7 CHAIR SIEBER: So you go directly to the 8 hot well and not into the tube bundles?
9 MR. SWANK: Right. So we actually moved 10 16 large lines down below the water level.
11 CHAIR SIEBER: Okay, that was a good idea.
12 Okay, thank you.
13 MR. SWANK: Okay, in 2007 we replaced the 14 final stage of feedwater heating. We had seen stress 15 corrosion cracking on the tubes and as a preemptive 16 measure replaced the heaters themselves.
17 In 2007, we also replaced the turbine 18 control systems or our digital electrohydraulic 19 control systems main turbine and replaced it with a 20 triple-redundant computer system to give us better 21 reliability. Next slide, please.
22 In 2001, we went from a 12-month operating 23 cycle to a 24-month operating cycle. So we're, I'd 24 say we're somewhat unique being in the Pacific 25 Northwest in the spring when the water flows off the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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52 1 mountains we would in many cases be asked to either 2 down-power or to shut down.
3 We're still occasionally asked to down-4 power but the grid system has changed, been a massive 5 change to the point where we're rarely asked now to 6 shut down.
7 But what this did was it gave us the 8 opportunity to only do the thermal cycle of the plant 9 once every 24 months versus once every 12 months. And 10 then finally in 1992, we replaced our low pressure 11 rotors.
12 So we have the original Westinghouse 13 rotors. Industry experience had found some 14 significant problems with that. We went to the 15 monobloc design and replaced all those rotors.
16 CHAIR SIEBER: And the original were not 17 monobloc?
18 MR. SWANK: That's correct.
19 CHAIR SIEBER: Okay.
20 MR. SWANK: Okay, and with that I'll turn 21 it over to Don Gregoire.
22 MR. GREGOIRE: Good morning. I'd like to 23 just briefly talk about our process, the license 24 renewal process. We initially formed our project 25 plans in 2006, pulled our team together in 2007.
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53 1 We had a specific in-house staff 2 overseeing this project. In 2009, we made sure that 3 our application had some external independent peer 4 reviews and then we submitted in January 2010.
5 Our license renewal team has been actively 6 engaged with the NEI License Renewal Task Force and 7 their working groups. We've participated in audits 8 and inspections at other facilities as well as 9 performed peer reviews for other facilities.
10 With regard to the -- next slide, please -
11 - our scoping and screening, we utilized the guidance 12 in NEI 95-10 and identified the in-scope structure, 13 systems and components.
14 We identified our (a)(1), (2) and (3) in-15 scope components, mechanical components with 16 mechanical boundary drawings. Next slide.
17 MEMBER STETKAR: Don, before you get a 18 change there, I dug into a few of the scoping and 19 screening decisions just to see if I could understand 20 what was done. A couple questions.
21 I know that there was an RAI about the 22 fire protection system in the turbine building which 23 there was a question. And I know that the resolution 24 of that RAI was to include the fire protection in the 25 turbine building as in-scope.
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54 1 I had a question about fire protection for 2 the outdoor transformers. Is that also in-scope?
3 MR. GREGOIRE: Scott Wood, could you speak 4 to that, Scott?
5 MR. WOOD: Scott Wood, Columbia Generating 6 Station. Yes, the --
7 MEMBER STETKAR: It is, okay, thanks. Yes 8 is good. We're short on time. I'll skip the other 9 one because it's kind of detailed. Another question I 10 had was your, I think it's called plant service water, 11 TSW.
12 MR. ATKINSON: Turbine service water.
13 MEMBER STETKAR: Turbine service water.
14 Okay, turbine service water, right. Parts of it are 15 in-scope, the stuff that's in the reactor building are 16 in-scope.
17 But the piping as I understand it from the 18 pumps into the plant is not in-scope. Why is that?
19 It's a normal cooling supply for reactor closed 20 cooling water, is that correct?
21 MR. SWANK: That is correct.
22 MEMBER STETKAR: Okay. Why isn't the 23 supply pipe from the pumps, you know, up to the RCC 24 heat -- I know the piping right around the RCC heat 25 exchangers is, but --
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55 1 MR. LEE: My name is David Lee, Energy 2 Northwest License Renewal Team. The plant service 3 water is in-scope for (a)(2) functional. It provides 4 the feed and bleed path during a loss or tornado 5 event.
6 MEMBER STETKAR: And it is in-scope all 7 the way from the pumps?
8 MR. LEE: From the pumps --
9 MEMBER STETKAR: It is? Okay, because the 10 drawing, you know, we see things betwixt and between.
11 The drawings I had didn't show it in-scope from the 12 pumps until you got to the reactor building.
13 MR. LEE: It includes the pumps.
14 MEMBER STETKAR: Thank you.
15 CONSULTANT BARTON: Do you have anything 16 else, John? Do you have anything else right now?
17 MEMBER STETKAR: No, not on scoping.
18 CONSULTANT BARTON: I'd like to ask you on 19 like the fire protection. I noticed your components 20 in the fire protection that are in-scope does not 21 include either jockey pump, but for aging management -
22 - I'm sorry.
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56 1 got two jockey pumps that I could not find were in the 2 Aging Management Program.
3 MR. WOOD: Scott Wood, Energy Northwest.
4 The jockey pumps are not required to perform a 5 function of putting out the fire, they only are a 6 convenience to keep from cycling water --
7 CHAIR SIEBER: Keep the pressure on.
8 MR. WOOD: So they just maintain pressure.
9 CONSULTANT BARTON: Also the system 10 contains several tanks, and I couldn't find those 11 listed as having Aging Management Programs.
12 MR. GREGOIRE: You're talking about the 13 fire protection bladder tank?
14 CONSULTANT BARTON: Well, I didn't write 15 down which one that is, but you've got Tank 3.7 or 16 1.10, FP-TK-110 and FP-TK-110 is not in-scope. Is 17 that the bladder tank?
18 MR. GREGOIRE: FP-TK-110 is the bladder 19 tank.
20 CONSULTANT BARTON: Okay.
21 MR. GREGOIRE: And it's within the scope 22 of license renewal. MR. WOOD: Excuse me, 23 sir, I have a correction to make. Scott Wood, Energy 24 Northwest. We did later put the jockey pumps in-scope 25 of license renewal. I spoke in error.
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57 1 CONSULTANT BARTON: Thank you.
2 MR. TWOMEY: No, the bladder tank for FP-3 TK-110, it is in-scope but it screens out because we 4 replace it.
5 CONSULTANT BARTON: Oh, okay, I got you.
6 I understand.
7 MR. GREGOIRE: Okay, moving on, we did 8 implement the Aging Management Review process as 9 outlined in 10CFR Part 54 and NEI 95-10. Our 10 application process considered GALL, Revision 1.
11 GALL Revision 2 came out in draft form 12 sometime after we submitted our application and became 13 finalized much later after our application was 14 submitted.
15 CHAIR SIEBER: Have you upgraded your LRA 16 to embrace the concepts in GALL 2?
17 MR. GREGOIRE: With regard to GALL 2, we 18 have a number of RAIs from the staff that challenged 19 us on getting in alignment with the GALL Rev 2 and so 20 we have made a number of commitments and changes to 21 our programs to recognize GALL 2.
22 CHAIR SIEBER: I sort of gathered that 23 you're not fully consistent with GALL 2. Is that 24 correct?
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58 1 full assessment of that document to ensure we are in 2 complete alignment with it.
3 MR. TWOMEY: We did not do a line-by-line 4 check.
5 CHAIR SIEBER: I'm sure during the staff's 6 presentation you will give us an assessment of your 7 opinion as to the degree to which the licensee's 8 application of the combination of GALL 1 and GALL 2 is 9 satisfaction to you.
10 MS. GALLOWAY: I can add something right 11 now. What we did with Columbia as well as other 12 applications we had in-house was take the operating 13 experience that was captured in GALL Rev 2, which had 14 been developing over time, and used that operating 15 experience as opportunities to ask RAI.
16 So we asked RAIs, all the in-house 17 applicants, that we felt were the most important 18 changes that were going to be captured in GALL Rev 2.
19 So yes, we do feel that on the important items that 20 we have captured that with Columbia as suggested.
21 CHAIR SIEBER: Yes, now that's been the 22 practice with a number of licensees within the last 23 two years, I would say that it's sort of bits and 24 pieces as you go along.
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59 1 systematic check against all the in-house applicants 2 against a 20 or so key changes that were being 3 addressed and captured in GALL Rev 2.
4 CHAIR SIEBER: And this is what, about the 5 70th LRA?
6 MS. GALLOWAY: Well, we've already 7 licensed for the 71, so yes.
8 CHAIR SIEBER: I lose count after awhile, 9 but I presume the ones in the future will become 2 10 exclusively?
11 MS. GALLOWAY: Yes, we have the Limerick 12 application which is a fairly recent one.
13 CHAIR SIEBER: Okay, thank you.
14 CONSULTANT BARTON: In your aging 15 management, the demin water system, your description 16 says it provides containment isolation and integrity 17 in the system since intended function is safety 18 related.
19 Yet the system also contains a storage 20 tank, which I couldn't find it had any Aging 21 Management Reviews of that storage tank. Is there a 22 reason for that?
23 MR. GREGOIRE: We'll get back to you on 24 that. Oh, wait a minute.
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60 1 License Renewal Team. The storage tank is not 2 credited for performing at (a)(1), (a)(2) or (a)(3) 3 intended function. That is why it's not in-scope.
4 The only function for the demineralized 5 water system is containment isolation boundary 6 portions of piping that go into the containment and 7 for portions, non-safety related portions of the 8 system that are in-scope due to the spatial 9 interaction in areas containing safety related 10 equipment.
11 CONSULTANT BARTON: The reason I asked is 12 your description in the application says system 13 intended function is safety related.
14 MR. LEE: For the containment isolation 15 portion. There's a portion of the piping that 16 penetrates the containment vessel.
17 CONSULTANT BARTON: Okay, just that 18 piping?
19 MR. LEE: Right.
20 MR. GREGOIRE: Next slide. So we are 21 accrediting 55 Aging Management Programs, 35 already 22 exist, 20 are new.
23 We have plans right now targeted to 24 complete the majority of those new programs within the 25 next couple years, incorporating or consider, take NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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61 1 into consideration operating experience and the 2 development of it to make sure that we are creating 3 programs that are effective at addressing aging 4 management.
5 CHAIR SIEBER: What's the date that your 6 current license expires?
7 MR. GREGOIRE: 2023.
8 CHAIR SIEBER: So we've got some time.
9 MR. GREGOIRE: Our commitments are no 10 later than 2023, but our plans are much more 11 aggressive in 2013.
12 CHAIR SIEBER: Yes, you will not succeed 13 if you wait until the last minute.
14 MR. GREGOIRE: That's right. No 15 disagreement --
16 CHAIR SIEBER: Advance, you adopt a new 17 program, which still gives you a lot of time.
18 MR. GREGOIRE: With regard to Time-Limited 19 Aging analyses, we've identified a number of 20 disposition in, in accordance with the NUREG and NEI 21 95-10, and characterized them in accordance with 22 54.21.
23 There are a couple exceptions that we 24 failed to do that we'll talk about in the open items.
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62 1 slide.
2 We have a number of commitments, 71 3 commitments we've made. However, the majority of 4 these are related to our existing and new programs.
5 We have individual ones for each program.
6 We have a commitment tracking process that 7 we use to ensure that we carry out our commitments as 8 we communicated them to the staff, and we'll be 9 relying on that to drive home all these commitments.
10 MR. ATKINSON: I guess additionally I'd 11 offer, senior management is quite interested in the 12 implementation both the earlier items and then the 13 follow-on to stick to the plan.
14 So there will be multiple opportunities 15 for us to track and weigh in on that programming and 16 ensure the resources and commitments are met.
17 MR. GREGOIRE: With regard to 18 implementation, we fully understand that there's been 19 challenges in the industry with implementation. We 20 plan to be engaged.
21 We know there's a lot of lessons learned.
22 We will be involved with the benchmarking other 23 sites. We'll continue to participate with the NEI 24 License Renewal Implementation working group.
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63 1 and audits during this preparation period prior to the 2 PEO, Period of Extended Operation. And we are in the 3 development process for having that project map laid 4 out with the expectation to have that somewhat 5 completed early next year.
6 Next slide. With that I'd like to 7 transition to --
8 MEMBER SHACK: Before you get, let me just 9 ask a quick question on that. I looked through your 10 first amendment to the License Renewal Application, 11 your commitment 39.
12 And you removed the commitment to enhance 13 the material and handling system inspection program to 14 look for corrosion. Why did you do that?
15 MR. TWOMEY: Because we implemented it.
16 The program owner saw the benefit into implementing 17 that enhancement right away, so he took the initiative 18 and upgraded all the program documents and they're 19 doing that now.
20 MEMBER SHACK: Okay.
21 MR. GREGOIRE: I'd like to move to the 22 open items. Now with respect to concerns expressed by 23 the NRC, I do want to say that of these six we've 24 already provided two responses, albeit they were here 25 in just the last month or two so they didn't have NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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64 1 opportunity to get into the Safety Evaluation Report 2 consideration.
3 The other four, we fully intend to have 4 those responses provided by next month if not sooner.
5 We have some sitting on my desk that'll be out the 6 door here very shortly.
7 But let's go ahead and go into the six 8 open items. The first one is related to the high 9 voltage porcelain insulators, and Abbas, if you would 10 just go to Slide 35.
11 Now the concern is with the insulators 12 that are out at the Ashe Substation. You can see on 13 the picture there that the Ashe Substation, it's 14 approximately three-quarters of a mile north of our 15 cooling towers.
16 We've had concerns with drift from the 17 cooling towers affecting insulators in our transformer 18 yard. We initially did some studies due to an event 19 we had back in the '80s, '90s time frame, early '90s 20 time frame.
21 And that those studies demonstrated that 22 the drift was somewhat limited to just right around 23 the transformer yard and it really dropped off if you 24 got a little bit north of the yard.
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65 1 insulators in the Ashe Substation in our program.
2 When asked to provide the data that supported the 3 evaluations we had some difficulty with that and it 4 really wasn't a major issue for us to go ahead and 5 include the Ashe insulators in our program.
6 As a matter of fact, this last outage we 7 went and tested the insulators for the accumulation 8 buildup on it and determined that it was very minimal 9 accumulation.
10 We have also instituted a PM to evaluate 11 these once every eight years for buildup to determine 12 if they need cleaning. And that's consistent with the 13 Bonneville Power Administration, who runs the 14 switchyard there, as far as their cleaning process.
15 CONSULTANT BARTON: Let me ask you a 16 question about your switchyard. Since you really 17 don't do the work and it's done by some T&D people, 18 how do you control the work as plan operators?
19 MR. ATKINSON: We essentially treat, the 20 work is primarily done by Bonneville Power 21 Administration under contract to us. We treat them as 22 a contractor and provide technical oversight for the 23 work conducted in the transformer yard.
24 So I mean we're out there providing that 25 oversight.
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66 1 CONSULTANT BARTON: And there's a 2 requirement that they communicate with you before they 3 go in the yard to do any work or any, you've got that 4 all written down and --
5 MR. ATKINSON: We have a Memorandum of 6 Understanding and we do control that work out in the 7 yard. And frankly, it's come from some lessons 8 learned in dealing with that.
9 CONSULTANT BARTON: That's why I asked.
10 MR. ATKINSON: Yes, sir.
11 CONSULTANT BARTON: Okay.
12 MEMBER STETKAR: Dale, you hopefully 13 weren't being very careful when you said transformer 14 yard. What about the Ashe Substation?
15 MR. ATKINSON: The Ashe Substation is 16 actually operated by the Bonneville Power 17 Administration. So again we have a very good working 18 relationship on that.
19 From a practical point of view, you know, 20 this issue around the insulator fouling if you will, 21 you know, the mechanism, you look at that picture 22 you've got the cooling towers right in the middle.
23 And for those of you that were out there it was a 24 windy day.
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67 1 insulators in-scope so I'm a little less concerned 2 about insulators, that I'm a little more concerned 3 about the fact that that is the connection for one of 4 your accredited offsite power supplies out there to 5 the, within the breakout.
6 I didn't have an electrical drawing. For 7 some reason I couldn't find an electrical drawing in 8 your FSAR so I'm kind of at a loss.
9 But I'm assuming that the circuit breakers 10 are out there at that substation, otherwise we 11 wouldn't be talking about that substation and 12 therefore maintenance of those circuit breakers, 13 testing of those circuit breakers.
14 And since -- is it an overhead line that 15 comes into the site?
16 MR. SWANK: It is, yes.
17 MEMBER STETKAR: And the line itself are 18 under the auspices now of Bonneville Power authority.
19 So the question is, you know, extending 20 from your transformer yard out, how do you control, 21 you know, maintenance and testing of those circuit 22 breakers, maintenance of the line, you know, above and 23 beyond just the insulators that we're talking about?
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68 1 yourself.
2 MR. ADAMI: Technical Services Manager in 3 Sub. The scope of the work that is done at Ashe 4 Substation is coordinated with Columbia. Every time 5 we go into a manage group we're in discussions with 6 them what the scope is.
7 We strategize with them. In fact, 8 maintenance and upgrades, we used to have French air 9 blast Cogenel breakers in the Ashe Substation.
10 We have upgraded to SF6, and so the 11 installation, the testing of these devices, you know, 12 are things that we talk about and we have an agreement 13 that requires our involvement with them.
14 CONSULTANT BARTON: And there is an 15 agreement?
16 MR. ADAMI: There is an agreement.
17 MEMBER STETKAR: Just talking about things 18 isn't quite the same.
19 MR. SWANK: Right, but we -
20 (Simultaneous speaking.)
21 MR. SWANK: -- and make sure there's a 22 clear understanding of who owns what and how it's 23 controlled.
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69 1 the record, can you say your name again?
2 MR. ADAMI: Brian Adami, Tech Services 3 Manager.
4 MEMBER STETKAR: Thank you.
5 CHAIR SIEBER: And this is the standard 6 NERC agreement that you're referring to?
7 MR. GREGOIRE: No, I believe this is 8 separate situation. NERC is interface requirements 9 that we have for NUC-001, but there is a working 10 agreement for that, that were in place before NERC.
11 CHAIR SIEBER: Correct, okay.
12 MEMBER SKILLMAN: I'm Dick Skillman. I 13 would like to build on John Barton's question, please.
14 When asked about controlling work in the transformer 15 yard the answer was there's a Memorandum of 16 Understanding and it's controlled, I'm assuming 17 through your work control at the station?
18 MR. SWANK: That's correct.
19 MEMBER SKILLMAN: Please describe how that 20 same control is conducted at the substation, Ashe 21 Substation.
22 MR. SWANK: We'll let Brian talk about it 23 in detail, but understand that there is a difference 24 because we control physical access in our transformer 25 yard.
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70 1 So when you get to the Ashe Substation it 2 is different, and that's done through the --
3 MEMBER SKILLMAN: MOA.
4 MR. SWANK: Exactly. And so --
5 MEMBER SKILLMAN: But though, please let 6 me explain why that's the question. From an operator 7 in the control room, if my offsite power is coming 8 through Ashe I'm very interested in assuring that Ashe 9 is fit for duty and I don't want people in there doing 10 stuff that I don't know about.
11 MR. SWANK: Right.
12 MEMBER SKILLMAN: Hence my question, how's 13 the control of work conducted for Ashe?
14 MR. ADAMI: Brian Adami, Tech Services 15 Manager. BPA has their own requirements as far as 16 fitness for duty, security, access into the 17 substation.
18 Operation of the equipment over at Ashe 19 Substation is anything that's going to affect the 20 operation at Columbia Generating Station is 21 coordinated with us.
22 In fact, if we are going to go into a 24-23 hour run with a diesel generator and going to be 24 connected to the grid for that amount of time, we have 25 requirements in our procedure to coordinate with them.
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71 1 And if there's weather situations that 2 draw concerns for both of us in terms of grid 3 reliability, the test may be rescheduled. I'll say 4 that we go into discussions and have agreements on how 5 to protect offsite power.
6 We will ask them and they will agree to 7 not work on certain equipment if we're in a situation 8 that has any kind of vulnerability from a risk 9 standpoint. And so it's a combined mutual situation 10 as governed by our agreement with them.
11 MEMBER SKILLMAN: Thank you.
12 MR. GREGOIRE: If there are no further 13 questions in the insulators we'll move on to the next 14 open item. So Abbas, if you could go to Slide 26.
15 I should note one last thing with the 16 insulators. We did provide a response already to the 17 staff on August the 18th with that regard to inclusion 18 of those insulators.
19 The next open item has to deal with 20 operating experience. There was concern raised and 21 expressed with regard to how we as the licensee would 22 be treating future operating experience and using that 23 to shape or develop new Aging Management Programs.
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72 1 with the staff to make sure that we provide the 2 appropriate clarity.
3 But let me just be clear, I guess I'm 4 repeating myself. Let me be clear on this issue. We 5 are going to be laying out exactly how we're going to 6 be using operating experience.
7 We currently have an operating experience 8 program owner with the company who manages that. He 9 does that full time for the company. We have a 10 procedures processes.
11 We rely on an individual, or our License 12 Renewal Team participates in the daily or the weekly 13 review of operating experience to assess the impact 14 of, you know, whether we need to evaluate it further.
15 We fully intend to continue to use this 16 program. Currently we receive operating experience 17 from both INPO as well as the NRC that we use and we 18 evaluate some of them.
19 Recently, Information Notice 2011-04 we've 20 evaluated for effects on our Aging Management 21 Programs. There's a number of them out there. So we 22 are actively doing that right now.
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73 1 there so that we ensure that we're taking those 2 considerations into play when we're developed a 3 program.
4 But we are evaluating, and even when the 5 next version of GALL comes out, should it come out a 6 Rev 3, that it will be an operating experience program 7 and we'll be considering that as well.
8 Our response to the staff we expect will 9 be provided, it will be provided next month to close 10 this item.
11 MEMBER SKILLMAN: If I could, please. I'm 12 Dick Skillman. My question is two-fold. To whom does 13 your OE program owner report? And at your station on 14 a scale of one to ten, one being not important and ten 15 being very important, how is the OE program regarded, 16 please?
17 MR. GREGOIRE: Well, I would say it ranks 18 up there as a ten as being very important and we do 19 take it into consideration. The OE program reports to 20 our organizational effectiveness.
21 You know, it evaluates not only external 22 operating experience but as well as internal 23 experience, and we utilize that information to shape 24 the organization.
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74 1 that have evaluated us. We've, being of very few 2 issues that have been identified.
3 MEMBER SKILLMAN: Thank you.
4 MR. GREGOIRE: So in closing with this 5 one, we fully plan to have that submittal to the staff 6 no later than next month to hopefully close this item 7 with the staff.
8 The next open item is regarding upper-9 shelf energy requests for technical data associated 10 with the determination of our initial transverse 11 upper-shelf energy associated with certain nozzle 12 forgings.
13 And Abbas, if you could, let's go to Slide 14 61. So the nozzles we're speaking about are the N12 15 instrument nozzles. They're located in the beltline 16 of the reactor vessel.
17 We have provided the initial information 18 to the staff with regard to the initial upper-shelf 19 energy, 62 foot-pounds, as well as the copper content 20 of 0.27 percent.
21 Since then the staff has asked us for the 22 data to support it. We have obtained the data. This 23 is a letter that I just reviewed this week and it 24 should be submitted to the NRC no later than next 25 month.
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75 1 CHAIR SIEBER: What's the range of 2 diameters of those nozzles?
3 MR. GREGOIRE: I'll ask John Sisk.
4 CHAIR SIEBER: They look like six to 5 twelve, six to twelve inches.
6 MR. SISK: John Sisk, Principal Engineer 7 and program owner. And your question was, what is the 8 diameter of the -- the outside diameter of the water 9 level instrument nozzles are 3.32 inches.
10 CHAIR SIEBER: And that's the only ones 11 that you're concerned with?
12 MR. SISK: There are four nozzles and they 13 are all the same size, yes.
14 CHAIR SIEBER: So they're not large LOCA 15 points.
16 MR. SISK: That's correct.
17 CHAIR SIEBER: Okay, thank you.
18 MR. GREGOIRE: So again, the Request For 19 Information on technical data, we've just reviewed it 20 and we plan to be submitting that here very shortly.
21 MEMBER SHACK: Is the database that you 22 have comparable to the one that you supplied for the 23 Class 2 forgings or smaller?
24 MR. GREGOIRE: I'll have to refer to John 25 Sisk again. John?
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76 1 MR. SISK: John Sisk, Principal Engineer 2 and program owner. And your question was with regard 3 to the --
4 MEMBER SHACK: I assume you're supplying 5 the data, but I mean you gave them a number before and 6 they asked for the basis of that. And you've done 7 that before for the Class 2 forgings and they found 8 that the amount of data was acceptable.
9 I just wondered if you had a comparable 10 amount of data for the Class 1 forgings.
11 MR. SISK: It is a comparable number of 12 data points.
13 MEMBER SHACK: Thank you.
14 MR. GREGOIRE: Any more questions before 15 John Sisk? Thank you. So again like I said, we will 16 be providing that here shortly.
17 The next open item, if you go to Slide 28, 18 Abbas. This open item is related to metal fatigue and 19 the concerns for assessing other limiting locations.
20 We have received, this has taken us some time to get 21 through this.
22 We have looked at other locations.
23 They're listed in our Table 4.3.3 and 4.3.5 of our 24 application. Through the evaluations that we've done, 25 we've just completed them, all of the other locations NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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77 1 are less than 1.0, the ASME criteria.
2 So we will be submitting that and it 3 should be going to the staff no later than November.
4 The next open item is associated with 5 lower core plate rim hold-down bolts. Now we notified 6 the staff in June 29, that we did not have wedges in 7 our vessel.
8 And we had communicated that we would be 9 treating the core plate rim hold-down bolts with a 10 TLAA or we would be installing wedges at least no 11 later than two years prior to the period of extended 12 operation.
13 We have done assessments for the current 14 license, but with regard to the period of extended 15 operation we will do one of those two things. We will 16 either complete that TLAA or install the wedges.
17 However, the staff had asked us to be more 18 specific on what characterization of TLAA, 54.218 19 characterization, so we will be more specific and 20 we'll also submit AMR line item associated with this.
21 Again we expect to submit that information 22 no later than November.
23 MEMBER STETKAR: Don, you mentioned you 24 did assessments for the current licensing. Has that 25 all been resolved with the staff or is that an ongoing NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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78 1 --
2 MR. GREGOIRE: There is an ongoing 3 question. We need to provide them the information and 4 we are very comfortable with our analysis that 5 supports our current license basis.
6 MEMBER STETKAR: Thank you.
7 MR. GREGOIRE: And with regards to the 8 last open item, I want to point out this was a 9 response we provided just a few weeks ago to the 10 staff.
11 There was a concern about the application 12 of, or a TLAA application for our cranes, polar cranes 13 specifically.
14 CONSULTANT BARTON: You don't call this a 15 polar crane, do you?
16 MR. GREGOIRE: We do not have a polar 17 crane. We don't have a dome or, we have an overhead 18 crane. We have actually 15 in-scope cranes and hoists 19 and we will, you know, consider a TLAA for those 15 20 in-scope.
21 They do remain valid through the end of 22 the period of extended operation. And again like I 23 said, we had closed on, or we provided the response to 24 the staff just a few weeks ago.
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79 1 of them we've already provided the responses. The 2 other four are very close to being submitted out to 3 the staff.
4 We hope that there won't be any challenges 5 for meeting the future dates for license renewal. We 6 think we've pretty much closed the loop on these but 7 we'll try to address any concerns the staff may have 8 in a timely manner.
9 CHAIR SIEBER: Is your overhead crane that 10 you use during refueling, is that a single-failure 11 proof crane?
12 MR. TWOMEY: It is It meets all the 13 requirements of NUREG-0612.
14 CHAIR SIEBER: Okay, heavy loads.
15 MR. TWOMEY: It's heavy loads, that's 16 correct.
17 CHAIR SIEBER: Thank you.
18 MR. GREGOIRE: With that I will turn it 19 back over to Dale Atkinson.
20 MR. MOSTALA: There is some of the 21 functions that David Lee would like to correct.
22 David?
23 MR. LEE: David Lee, Energy Northwest 24 License Renewal Team. Mr. Chairman, I'd like to issue 25 a correction to an earlier statement that I had NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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80 1 stated.
2 CHAIR SIEBER: Okay.
3 MR. LEE: In regards to his question, he 4 was asking about the plant service water system not 5 the plant makeup water system.
6 MEMBER STETKAR: That is correct.
7 MR. LEE: The plant service water system 8 is not credited for (a)(1) function. Therefore, the 9 portions that are only in-scope are due to portions 10 accredited for (a)(2) spatial.
11 MEMBER STETKAR: Okay, plant service 12 water, acronym TSW so we're real clear, provides 13 cooling for the RCC heat exchangers. Is that correct?
14 MR. SWANK: Just for clarity, it does 15 provide the normal quote "cooling source." We can 16 cool the heat exchangers with our safety related 17 service water system.
18 MEMBER STETKAR: Okay, I didn't know that.
19 Thank you. That resolves that concern, thank you.
20 MR. GREGOIRE: I think we have a couple of 21 closures on some items.
22 MR. LASALLE: Just real quickly, John 23 LaSalle, coat programs. There was a question about 24 the coatings that we use in the suppression pool. And 25 the coating's an epoxy.
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81 1 The inspection is a 360-degree diver 2 visual each outage, and a minimum of 25 percent of 3 that each outage is a close-up visual, meaning within 4 three feet.
5 And then any identified areas of 6 degradation, they're followed up on subsequent outages 7 and are identified.
8 CHAIR SIEBER: Have you seen any areas of 9 degradation in the past?
10 MR. LASALLE: Yes, we have.
11 CHAIR SIEBER: And how do you repair that 12 of do you just monitor it?
13 MR. LASALLE: They've been monitoring it 14 and we have yet to do repairs on any coatings.
15 MEMBER SHACK: These indications, do they 16 number in the tens, the hundreds?
17 MR. RICHTER: Typically we measure them by 18 square foot. Steve Richter, Code Programs. We 19 measure them by square footage and typically they're 20 on square inches type, and then we track, we have a 21 limit of how much we would allow in terms of square 22 footage.
23 MEMBER SHACK: How many square inches are 24 there?
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82 1 can get back to you on that. I can tell you total we 2 have under 50 square foot of damage or degraded 3 coatings. Would you like a more exact number?
4 MEMBER SHACK: No, that's close enough.
5 CHAIR SIEBER: Any further questions?
6 CONSULTANT BARTON: I've got a bunch of 7 them. How tight do you want to be on your 10 o'clock 8 break?
9 CHAIR SIEBER: Yes, watch it.
10 CONSULTANT BARTON: Watch it, okay. Your 11 tank inspection program, diesel fuel tank. I couldn't 12 find evidence that you ever looked at it. Have you 13 ever inspected diesel tanks for corrosion?
14 MR. MOSTALA: Carolyn Beaudry can answer 15 that question.
16 MS. BEAUDRY: I'm Carolyn Beaudry, the 17 buried piping and tanks program owner. And our diesel 18 fuel oil tanks, we have three of them, and they are 19 buried underneath our diesel generator building. And 20 we do a, every ten years we do UT on the internals of 21 the tanks.
22 CONSULTANT BARTON: I didn't get you, you 23 do what?
24 MS. BEAUDRY: We do ultrasonic testing on 25 the inside of the tanks every ten years.
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83 1 CONSULTANT BARTON: Have you found any 2 degradation in the tanks?
3 MS. BEAUDRY: No. Based on our 2005 4 inspection of all three tanks, the greatest amount of, 5 through the period of extended operation the greatest 6 amount of degradation we would have seen would have 7 been 0.02 and our corrosion allowance is 0.18.
8 CONSULTANT BARTON: Okay, thank you.
9 MS. BEAUDRY: Thanks.
10 CONSULTANT BARTON: Do you also have --
11 oh, you still had a question on it?
12 MEMBER SHACK: Just a question. I mean 13 how much of the tank surface do you actually cover 14 with that UT inspection?
15 MS. BEAUDRY: I'm not sure. I can get 16 back to you on that.
17 CONSULTANT BARTON: You also have above 18 ground tanks?
19 MS. BEAUDRY: Yes, we do.
20 CONSULTANT BARTON: I mean just stay with 21 your audit, okay.
22 MS. BEAUDRY: Oh, I'm sorry, I don't have 23 it.
24 CONSULTANT BARTON: Oh, okay. Condensate 25 storage tank, fabricated steel located outdoors, are NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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84 1 these tanks insulated or not?
2 MR. TWOMEY: They are not.
3 CONSULTANT BARTON: Not insulated.
4 MR. TWOMEY: They are coated.
5 CONSULTANT BARTON: They are coated, 6 honestly.
7 MR. TWOMEY: Yes.
8 CONSULTANT BARTON: Have you ever found any 9 corrosion on the outside of the tank surface in your 10 inspections? Forget about the seal thing because I'll 11 get to that next, but the tank surface itself?
12 MR. TWOMEY: Not on the tank surface.
13 CONSULTANT BARTON: All right. The 14 interface of the tank to the foundation, was that 15 supposed to have a seal originally?
16 MR. TWOMEY: No. The design drawings 17 never called out for a seal.
18 CONSULTANT BARTON: All right, so you did 19 find some corrosion there and that's been corrected?
20 MR. TWOMEY: That's corrected and it's 21 been sealed.
22 CONSULTANT BARTON: Okay, and it's been 23 sealed.
24 MEMBER STETKAR: John?
25 CONSULTANT BARTON: Yes.
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85 1 MEMBER STETKAR: Did you have more on CST 2 as long as you brought it up?
3 CONSULTANT BARTON: On the --
4 MEMBER STETKAR: The condensate storage 5 tank.
6 CONSULTANT BARTON: Yes.
7 MEMBER STETKAR: You do have more?
8 CONSULTANT BARTON: Yes, the issue I still 9 have on this is, you do inspections of that area and 10 apparently that corrosion has been going on, and it 11 wasn't really identified and put in your corrective 12 action system.
13 And the system engineer has looked at that 14 tank and didn't enter it as an item in corrective 15 action.
16 So my question here is, you know, do you 17 have confidence in how effective is your corrective 18 action system when the system engineer, who I take 19 should be a responsible guy for a system and know 20 what's going on in a system, finds an item, a 21 discrepancy, does not enter it in the corrective 22 action system?
23 So I question, you know, how serious is 24 your corrective action system? How well does it work 25 and, you know, are you satisfied with it or you've got NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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86 1 to fix it?
2 MR. TWOMEY: Well, I can answer that 3 specific more than Adami, I guess in total. But you 4 ask if this engineer was aware of it, made the 5 decision up front that the cost, it was a limited 6 corrosion and it was, again this corrosion was on the 7 tank if you will, the lip where the hold-down bolts 8 are and it was outside the bolt circle.
9 So he had made the decision that well, 10 that loss of material doesn't affect the, you know, 11 the integrity of the hold-down bolts. Therefore, you 12 know, I'll watch it.
13 CONSULTANT BARTON: Until it got into the 14 bolt area and couldn't --
15 MR. TWOMEY: Right, and --
16 CONSULTANT BARTON: I don't get that, but 17 okay.
18 MR. TWOMEY: No, no, and then we coat, you 19 know, the corrosion. And we've just done the 20 training, a recent training, where the expectation is 21 you don't make that decision up front.
22 You document it in the corrective action 23 process and then you document that decision. You're 24 right. That was a shortcoming.
25 CONSULTANT BARTON: Thank you.
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87 1 MR. GREGOIRE: Well, and we provided 2 training to our engineering staff with regard to 3 identification and documentation of aging issues.
4 And we demonstrate, through our outage 5 we've had quite a number of CRs that have been 6 generated on corrosion, on wear, on cracks. So the 7 message has been sent and they do understand it.
8 CONSULTANT BARTON: Yes, because I noted 9 again, NRC had an issue on their inspection that it 10 appeared that training wasn't very effective in Aging 11 Management Program issues, et cetera.
12 MR. GREGOIRE: So we have currently 13 trained all our engineering staff. We have plans for 14 training our maintenance and operations staff. We are 15 working on establishing recurring training for all our 16 engineering staff on the aging concerns, 17 identification and addressing aging concerns.
18 MR. ATKINSON: This will be managed 19 consistent with the systematic approach to training.
20 So that's that the Training Advisory Group reviews it, 21 makes sure that the periodicity and depth of training 22 is adequate to maintain their required performance.
23 CONSULTANT BARTON: John, did you still 24 have something?
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88 1 because we're getting short on time here. On the CST 2 I need some clarification, because as I read the SER 3 and the inspection reports, the SER says in a response 4 to RAI v.2.1-1 it was noted that ultrasonic thickness 5 measurements of the tank bottoms, this is the 6 condensate storage tank, are performed every ten 7 years.
8 The inspection report seems to indicate, 9 the staff's inspection report, that the tank bottom 10 thickness has never been measured. Those two pieces 11 of information seem in conflict.
12 Have you ever measured the thickness of 13 the bottoms of the condensate storage tanks?
14 MR. TWOMEY: We have not. We have 15 committed to do that and we've only done a visual from 16 the --
17 MEMBER STETKAR: Yes, I saw the 18 commitment. That's what brought up this difference 19 between the RAI response and the commitment and the 20 inspection observations. So okay, thank you.
21 CONSULTANT BARTON: Inaccessible medium-22 voltage cable is not subject to 50-49. You've 23 experienced water intrusion in a couple manholes 24 adjacent to the cooling towers but never identified 25 the source of the water. Have you finally figured NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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89 1 that one out?
2 MR. ADAMI: Brian Adami, Tech Services 3 Manager. I'll address that question and cover both 4 manhole and the cable issue. So the cables in these 5 manholes they are designed for the environment in 6 which they are installed.
7 And they're operating normally and we're 8 maintaining these manholes dry. We're testing these 9 cables in the next refueling outage. So and the best 10 thing for these cables to remain healthy is for them 11 to remain in a dry environment and so let me tell you 12 what we're doing about that.
13 Thanks for bringing that slide up. If you 14 can see on the diagram where he has the mouse, there's 15 our six cooling towers in the middle. There's the 16 circ water pumphouse.
17 And then to the north, there's our 18 transformer yard, and the color coding on this slide 19 is such that the red dots are manholes that we have 20 found standing water in.
21 The green ones were inspected and they 22 were found dry. Any manholes that we did find water 23 in we immediately pumped the water out and we've 24 reconditioned the French drains in these manholes so 25 that they drain.
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90 1 We did find silt in them that was 2 preventing their drainage. They are routinely 3 inspected now for water, also for the continuing good 4 condition of those French drains.
5 Now furthermore, yes, we have found the 6 source of water for each of these locations identified 7 in red there. So for E7 down by the cooling towers, 8 the source of water was the drain water and surface 9 water from the cooling tower.
10 On E8, that water was found, the water 11 that was found to fill that communicates from our circ 12 water pumphouse basement.
13 We found that when level is raised in that 14 basement to allow the circ water pump to start, when 15 that level is high that water communicates to that 16 manhole. And that was recently discovered on our 17 start up following our last refueling outage.
18 CONSULTANT BARTON: Is there a fix to 19 that?
20 MR. ADAMI: Since it was just entered in 21 our corrective action program, we were looking at that 22 evaluating whether it should be administratively 23 controlled where we are going too high, higher than 24 necessary to bring the head for the pump start, or if 25 there's something like plug in the conduit that would NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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91 1 be the preferred fix for that. So it's being 2 evaluated currently.
3 CONSULTANT BARTON: Thank you.
4 MR. ATKINSON: But essentially what Brian 5 is saying is that we will either close that 6 communication path or control the water level such 7 that it never reaches a point of communication, 8 because it is our intent to not continue to allow that 9 water source to enter that manhole.
10 MR. ADAMI: That is correct.
11 CHAIR SIEBER: Now you said that you 12 either have tested or will test the cables that were 13 exposed to water intrusion. What kind of tests will 14 you perform to ensure the cable integrity is 15 maintained?
16 MR. ADAMI: Pan-delta tests on the medium-17 voltage cable and also on our 480 volt, we're 18 committed to meggering those cables.
19 CHAIR SIEBER: Okay, but you're limiting 20 it to a megger test?
21 MR. ADAMI: That is correct.
22 CHAIR SIEBER: Okay.
23 MR. SWANK: And these are normally 24 energized cables.
25 CHAIR SIEBER: Okay.
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92 1 MR. MOSTALA: Also, Mr. Chairman, there is 2 a follow-up question that Jim Hamlen would like to 3 address on the non-seg bus.
4 MR. HAMLEN: Yes, my name is Jim Hamlen, 5 and I'd like to answer Mr. Stetkar's question about 6 the 6.9 kV bus which failed. That bus is not in-7 scope. It does not perform a safety related function.
8 It supports no (a)(3) regulated event, and 9 the only cables in the vicinity were fail-safe cables, 10 so there's no (a)(2) non-safety, affecting safety 11 consideration for that bus.
12 CHAIR SIEBER: What's a fail-safe cable?
13 You can ground, you can short, you can open, and each 14 of those has an effect on safety related equipment.
15 Have you analyzed all three potential 16 failure modes and its effect as far as spurious 17 operations, failure to operate when required for an 18 upstream effect on the power supply itself from the 19 failures?
20 In other words, circuit breakers tripping, 21 protective actions. Could you --
22 MR. HAMLEN: I don't know if that 23 evaluation's been done but we'll find out.
24 CHAIR SIEBER: I think that would be a 25 wise evaluation to support. Find out what's in the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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93 1 room, look at the failure effects in analysis for 2 cables that are reasonably affected by a failure of 3 that cable or other cables, not in-scope cables, and 4 that can give you some assurance as to whether the 5 plant safety functions can be performed upon --
6 MR. TWOMEY: Well, just understand that 7 the location of that bus is a non-safety related area 8 of the plant. That is our turbine building.
9 CHAIR SIEBER: Nothing in that room is --
10 MR. TWOMEY: There's nothing in that area 11 of the plant that performs an (a)(1) function.
12 MEMBER STETKAR: The concern is larger 13 than that particular bus section. I think we all 14 understand that.
15 (Simultaneous speaking.)
16 MEMBER STETKAR: Have you looked at metal-17 enclosed bus failures throughout the plant and looked 18 at potential interactions with, in-scope not safety 19 related but in-scope cables and switch gear?
20 CONSULTANT BARTON: I've got one more, 21 Jack.
22 CHAIR SIEBER: All right.
23 CONSULTANT BARTON: Emergency diesel 24 generator starting error system has a history of 25 routinely failing the past dew point surveillances.
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94 1 And you guys put together a design change which you 2 didn't implement, instead you decided to change out 3 desiccant more frequently and that didn't solve the 4 problem.
5 Is this still an issue at the site or have 6 you found a way to get them over that problem that's 7 been going on for awhile?
8 MR. MOSTALA: Scott would you address that 9 question, or John.
10 MR. LASALLE: I'll go ahead and answer 11 that. John LaSalle, Code Programs. The problem was 12 basically a maintenance issue of the air desiccant.
13 And we basically have corrected that by --
14 CONSULTANT BARTON: What did you do?
15 MR. LASALLE: Increasing maintenance 16 frequency in our desiccant dryers.
17 CHAIR SIEBER: Did you use a purger with a 18 heater?
19 MR. LASALLE: Well, actually they're 20 physically going in and changing out the desiccant 21 frequently so you don't have channeling and you don't 22 lose your surface area.
23 CONSULTANT BARTON: So you now change, you 24 fixed this to change the desiccant out more 25 frequently?
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95 1 MR. LASALLE: That's correct. And we've 2 been maintaining a dew point of, it's minus 19 in the 3 air.
4 CONSULTANT BARTON: Okay.
5 MR. LASALLE: Could I make a quick 6 correction on the record for the coatings of the 7 wetwell? We have ten locations that have been 8 repaired and there are ten that are being monitored.
9 CHAIR SIEBER: Any more, John?
10 CONSULTANT BARTON: I got one on 11 miscellaneous waste and radioactive drain system. The 12 floor drains are now going to 55-gallon drums. Is 13 that the way you intend to continue this or, it sounds 14 like a Mickey Mouse kind of operation you've got going 15 now.
16 MR. SWANK: I'm not aware that we're doing 17 that.
18 CONSULTANT BARTON: Well, it's in your 19 application I believe. Miscellaneous waste, 20 radioactive system equipment and floor drains collect 21 borated water from the Standby Liquid Control System, 22 direct this water to 55-gallon drums in the reactor 23 building.
24 MR. MOSTALA: Mot Hedges would answer 25 that.
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96 1 MR. HEDGES: Mot Hedges, plant chemistry.
2 That is specifically drains from around our Standby 3 Liquid Control tank.
4 When we test that there is some borated 5 water that ends up in the test tank and that actually 6 drains down to a plant drain, because we do not want 7 the boron to go down and be treated with the regular 8 waste because otherwise the boron would end up in the 9 reactor.
10 So that specific waste is collected in 55-11 gallon drums and processed separately.
12 CONSULTANT BARTON: So that's your 13 permanent planned installation, is to --
14 MR. HEDGES: That's correct. That's the 15 way the plant was designed to operate.
16 CONSULTANT BARTON: Okay.
17 MEMBER STETKAR: Jack, if you'll indulge 18 me I've got one last one since you mentioned drains.
19 CHAIR SIEBER: Sure. We actually have all 20 day.
21 MEMBER STETKAR: I know I certainly do but 22 other people have lives.
23 CHAIR SIEBER: We don't need lunch.
24 MEMBER STETKAR: There was an event that 25 was documented, it came up in the SER and RAIs in the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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97 1 context of fire barriers. It was a water leak, and 2 I'm searching for my notes here because I have too 3 many notes.
4 There's a water leak in the radwaste 5 building cable spreading room. Fifteen to twenty 6 gallons I think that was characterized that apparently 7 dripped down through cracks in the floor and got into 8 the Division 2 switchgear room down below and caused 9 some problems.
10 And fine, I mean, you know, you made a 11 commitment, you sealed the floor and all that kind of 12 stuff. My question was, does that cable spreading 13 room have a sprinkler system in it?
14 Is it protected? Because the leakage was 15 characterized as a drain line from a fire protection 16 system. And so the first question is, does it have a 17 sprinkler system in that room?
18 MR. TWOMEY: Yes, it does.
19 MEMBER STETKAR: It does, okay. The 20 second question, if it's got a sprinkler system in the 21 room does the room have floor drains in it?
22 MR. TWOMEY: Yes, it does.
23 MEMBER STETKAR: Okay. The 15 to 20 24 gallons didn't make it to a floor drain then?
25 MR. TWOMEY: That's correct. Because the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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98 1 location where it was, and specifically what that was 2 it was a construction joint in that floor, basically a 3 cold joint.
4 And we recognize that of course water will 5 find the path of least resistance and the 15 to 20 6 gallons --
7 (Simultaneous speaking.)
8 MR. TWOMEY: -- before it could get 9 through a floor drain it went down through there and 10 now we treat those as part of our fire barrier.
11 MEMBER STETKAR: Great, thanks. I was a 12 little more concerned about floor drains, because if 13 it didn't have floor drains in it the water, water 14 does flow downhill.
15 MR. TWOMEY: I understand your concern, 16 yes.
17 MEMBER STETKAR: Thanks.
18 CHAIR SIEBER: Any further questions from 19 members? John?
20 CONSULTANT BARTON: I'm all right.
21 CHAIR SIEBER: Okay, go ahead, closing 22 remarks.
23 MR. ATKINSON: All right. Mr. Chairman 24 and members of the ACRS subcommittee, I do appreciate 25 the opportunity to bring the team here and discuss NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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99 1 Columbia Generating Station and the License Renewal 2 Application.
3 We are confident that we have the 4 responses necessary to meet the NRC staff's needs or 5 requirements to close the open items and my hope is 6 that we can do that on a timely and still supports the 7 schedule.
8 I did want to also communicate that in 9 senior management we do have periodic reviews. So for 10 the implementation of the programs we'll provide 11 detailed oversight of that.
12 I mean I'd like to recognize a lot of the 13 hard work of folks both on the Energy Northwest team 14 and also particularly NRC staff. This is a lot of 15 work to get through all the scoping and evaluation of 16 that and I really do appreciate it.
17 We at Energy Northwest understand our 18 responsibility and are committed to the long term safe 19 operation of Columbia.
20 With that, Mr. Chairman, I will turn it 21 back to you. I guess one thing to be clear on, my 22 understanding is we still have a question to get back 23 to you on perhaps after the break, with regards to a 24 fail-safe discussion with cables, is that correct?
25 CHAIR SIEBER: Okay.
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100 1 MR. ATKINSON: Okay, we'll -- excuse me, 2 are you ready to discuss that item?
3 MS. BEAUDRY: No, a different item.
4 MR. ATKINSON: Oh, we've got one more 5 follow-up, okay.
6 MR. BEAUDRY: Carolyn Beaudry, buried 7 piping program owner. The diesel fuel oil tanks are 8 UTed with a grid system and there are 164 points on 9 the diesel fuel oil. Thank you.
10 CONSULTANT BARTON: Thank you.
11 CHAIR SIEBER: No further questions?
12 Thank you very much for your presentation and your 13 responsiveness to our questions.
14 And we'll now take a break and we'll 15 resume at 25 minutes to 11:00 according to my watch as 16 opposed to that.
17 (Whereupon, the foregoing matter went off the record 18 at 10:18 a.m. and resumed at 10:35 a.m.)
19 CHAIR SIEBER: I think we're ready to 20 resume, but before we begin with the staff the 21 applicant would like to respond to items.
22 MR. HAMLEN: Yes, my name is Jim Hamlen, 23 and I'd like to provide additional information on your 24 question with respect to the bus failure and 25 evaluation of cables.
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101 1 There was an evaluation done to address 2 the issue with open circuits, with hot shorts and 3 shorts to ground. In the turbine building at 4 Columbia, the only circuits with a safety function are 5 the RPS and MSIV logic circuits, and those were 6 determined to be fail-safe.
7 If the circuit was opened or damaged the 8 components would be in their safe position, and the 9 only non-segregated bus, safety or non-safety, is in 10 the turbine building and then outside in the 11 transformer yard.
12 CHAIR SIEBER: Okay, you said open or 13 grounded, what about shorts?
14 MR. HAMLEN: That is included as well.
15 CHAIR SIEBER: Okay.
16 MEMBER STETKAR: And all of those 17 conditions, for example, MSIVs, will close?
18 MR. HAMLEN: Yes.
19 MR. SWANK: And one last correction.
20 CHAIR SIEBER: Okay.
21 MR. SWANK: Dave Swank, Energy Northwest.
22 I needed to correct a statement that I made. The RCC 23 heat exchangers, Reactor Closed Cooling heat 24 exchangers are normally cooled by the plant service 25 water system and they are only cooled by the plant NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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102 1 service water system.
2 The primary load for Reactor Closed 3 Cooling is the spent fuel pool cooling system and its 4 heat exchangers. Those heat exchangers can be cooled 5 by safety-grade service water.
6 MEMBER STETKAR: The RCC also cools the 7 recirc pump seals, is that correct?
8 MR. SWANK: That is correct. It also 9 provides containment cooling. And so on the loss of 10 Reactor Closed Cooling we would be forced to shut down 11 the unit.
12 MEMBER STETKAR: Does that mean on a loss 13 of plant service water you'll lose containment cooling 14 and recirc pump seal cooling?
15 MR. SWANK: That's correct.
16 MEMBER STETKAR: Okay. I guess I'm still 17 a little bit curious why the TSW supply line isn't in-18 scope.
19 CHAIR SIEBER: Okay.
20 MS. GALLOWAY: The staff appreciates the 21 opportunity to be able to discuss review to date as 22 well as provide a status of the open items that 23 remain.
24 I'd like to introduce the staff making our 25 presentation this morning. Arthur Cunanan is the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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103 1 project manager responsible for coordinating all at 2 ACRS that will be associated with the review.
3 Tony Gardner is a member of our technical 4 staff and he will be assisting Arthur in moving 5 through the presentation.
6 Allen Hiser is our senior level advisor in 7 the Division of License Renewal. I know the committee 8 is well familiar with Dr. Hiser. Matt Homiack is a 9 mechanical engineer in our Division who will be 10 talking about operating experience.
11 And then we've had the opportunity to be 12 introduced to Greg Pick earlier, the senior inspector 13 who will talk about the inspection today at Columbia.
14 CHAIR SIEBER: Okay, thank you. Arthur?
15 MR. CUNANAN: Good morning, Chairman, and 16 members of the ACRS staff. My name is Arthur Cunanan 17 and I'm the Project Manager for Columbia Generating 18 Station License Renewal Application.
19 I'm here to discuss the staff's review of 20 the Columbia License Renewal Application as documented 21 in the Safety Evaluation Report. Melanie has made 22 introduction on who's at the table.
23 Also seated are members of the audience 24 from the technical staff who participated in the 25 review of the License Renewal Application or at the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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104 1 audits conducted at the plant.
2 As mentioned before, Greg Pick from Region 3 IV is on the phone. Greg, can you hear me?
4 MR. PICK: I am on the phone and yes, I 5 can hear you, Arthur, thank you. This is Greg Pick.
6 MR. CUNANAN: Thank you, Greg, I can hear 7 you. Greg Pick will be available throughout this 8 presentation and will be presenting the results of the 9 license renewal inspection.
10 CHAIR SIEBER: Okay, great.
11 MR. CUNANAN: Next slide. Here is an 12 outline of today's presentation. Next slide. This 13 slide shows an overview of Columbia Generating 14 Station. The applicant has covered most of the points 15 presented in the slide.
16 The staff conducted audits and inspections 17 for the License Renewal Application during the period 18 shown on this slide. In addition, Region IV conducted 19 its license renewal inspection on October 18 through 20 November 4 of 2010. Those inspection results will be 21 presented shortly.
22 CHAIR SIEBER: I have a question on the 23 environmental report. Columbia River flows from north 24 to south basically from Canada. Well, it starts in 25 Montana and makes a big loop.
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105 1 As far as plant safety is concerned, I 2 presume the Columbia River has dams both upstream and 3 downstream of the plant.
4 MR. CUNANAN: Yes.
5 CHAIR SIEBER: Have those been examined as 6 far as dam failure and the effect on the ultimate 7 water supply to the plant in case of an accident 8 condition?
9 MR. CUNANAN: The analysis has been 10 conducted and it's presented in the UFSAR on Columbia.
11 And from reading its analysis it stated that the 12 seismic Category 1 structures are located in the 13 maximum postulated flood elevation that is designed to 14 withstand the static and dynamic forces which can 15 result in a flood, flood due to the breach of the 16 Grand Coulee Dam which is the maximum postulated -
17 CHAIR SIEBER: That's the major dam 18 failure that would affect the site?
19 MR. CUNANAN: Yes.
20 CHAIR SIEBER: Grand Coulee, okay.
21 Because the ones that are close to the site did not 22 seem to have enough head to cause a lot of damage.
23 MR. CUNANAN: And the UFSAR, they also 24 looked at the low water consideration, and the 25 analysis showed that it wouldn't compromise the safe NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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106 1 shutdown of the plant.
2 CHAIR SIEBER: Okay, thank you.
3 MR. CUNANAN: In preparing the Safety 4 Evaluation Report and in addition to the audits and 5 inspections already mentioned, the staff conducted in-6 depth technical reviews and issued over 230 Requests 7 for Additional Information.
8 Section 2 of the Safety Evaluation Report 9 describes the structures and components subject to 10 Aging Management Review. The staff issued some RAIs 11 as a result of the scoping and screening audit, but 12 the issues were resolved before the issuance of the 13 SER with Open Items.
14 Also the applicant submitted as part of 15 its annual update, a 440-page supplement to the 16 License Renewal Application on July 16, 2010, that the 17 staff had to review.
18 The supplement includes three new systems 19 which are added to the scope of license renewal. The 20 systems are heating steam, heating steam condensate 21 and heating steam vents.
22 For the three new systems the applicant 23 added no new material, aging effect or Aging 24 Management Program, and the staff agrees with this 25 supplemental submittal.
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107 1 If there's not any questions on this slide 2 I'll turn the presentation over to Greg Pick, the 3 Region IV lead inspector, who will discuss the license 4 renewal inspection review.
5 Greg, you can start. We're going to be on 6 Slide 8.
7 MR. PICK: Thank you, Arthur. Good 8 morning, Mr. Chairman, and members of the ACRS staff.
9 I'm a senior inspector in Region IV. I've been 10 leading the license renewal inspections since 2007.
11 I'm calling in the Wolf Creek facility in 12 Kansas where I'm leading the fire protection 13 inspection. Next slide, please.
14 Our team for the Columbia Generating 15 Station inspection consisted of one electrical, two 16 civil and three mechanical engineers. We did evaluate 17 scoping of non-safety related components affecting 18 safety related components.
19 We reviewed 34 of the 55 Aging Management 20 Programs. Before I go on, can everyone hear me 21 clearly?
22 MR. CUNANAN: Yes, Greg.
23 MR. PICK: Thank you, Arthur. And out of 24 those 34 programs we reviewed 14 of the new Aging 25 Management Programs and 20 of the 35 existing Aging NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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108 1 Management Programs.
2 We believe that the applicant had 3 developed appropriate Aging Management Program 4 evaluation reports of their Aging Management Programs 5 that allowed us to make assessments of their plans for 6 managing aging. Next slide, please.
7 In the inspection results, we questioned 8 the applicant's suitability of using a one-time 9 approach for several of their 11 proposed one-time 10 programs.
11 We believed that the one-time programs 12 were inappropriate since they did not verify the 13 absence of aging effects in structures, systems and 14 components being monitored by existing one-time 15 programs. We contacted Division of License Renewal 16 who shared similar concerns.
17 After further discussions with the team 18 and the knowledge of forthcoming Requests for 19 Additional Information on these programs, the 20 applicant revisited their use of the 11 one-time 21 programs and identified six that should be 22 characterized as plant-specific programs, and 23 initiated actions to develop Aging Management Programs 24 for each.
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109 1 program, the one I'll visit, their procedures did not 2 include clear and concise acceptance criteria and did 3 not identify the detail required when documenting 4 structural defects.
5 Our concern was that this would not allow 6 for effective trending of the defects during their 7 five-year inspections, and the different inspectors 8 conducting inspections would not have the ability to 9 identify any changes in the structural defects.
10 The applicant agreed with this and 11 initiated a corrective action document to make sure 12 they modify their program in the future.
13 For their chemistry program effectiveness 14 we questioned the basis for their sampling plan, which 15 specified a five percent sample of applicable 16 components up to ten samples for each population of 17 components grouped by material and environment.
18 We had revised our guidance in GALL Rev 2 19 for recommended sample size, and when we talked to the 20 applicant they agreed to adopt the sample selection 21 criteria identified in Revision 2 of the GALL for each 22 population of components.
23 Next slide, please. In regards to the 24 high-voltage insulator program, the applicant during 25 their discussion accurately characterized what our NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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110 1 inspection found and the inspection team is 2 comfortable with the actions being taken to test every 3 eight years and clean if needed, the Ashe Substation 4 insulators.
5 In its results related to buried piping, 6 the team determined the applicant had reliability 7 problems with their post-anode system. They had in-8 scope service water piping still protected with the 9 post-anode system but would eventually need to replace 10 the remaining existing post-anode strings.
11 The applicant had already installed 12 several deep anode beds and retired the unreliable 13 post-anode strings. The applicant has committed to 14 install the remaining deep-bed anodes to ensure 15 protection of the in-scope piping.
16 In regards to the lube oil analysis 17 program, in their Aging Management Program evaluation 18 report they discussed using the Karl Fischer test to 19 identify the presence of water.
20 When we went to the metallurgy lab and 21 discussed this with the people, they in reality did 22 not use the Karl Fischer test method because it 23 created false positives. They used a different test 24 method for water.
25 The applicant committed to change their NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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111 1 Aging Management Program evaluation report to 2 accurately reflect the water content test being used.
3 During our interviews with several of the 4 system engineers on site, the system engineers were 5 not comfortable with their training related to 6 identifying aging effects on structures, systems and 7 components that they were assigned to inspect.
8 We also learned from the applicant that 9 they already had plans to provide EPRI training for 10 monitoring aging effects, therefore the team was 11 comfortable with the applicant's plans for providing 12 training for their system engineers.
13 Next slide, please.
14 CONSULTANT BARTON: Before you go to the 15 next slide I have a question and it's probably for the 16 applicant. The bullet you brought in on buried piping 17 cathodic protection system issues, what has the 18 applicant done to improve that?
19 MS. BEAUDRY: Carolyn Beaudry, buried 20 piping program owner. In 2008 we did upgrade our 21 cathodic protection system although not all of it was 22 upgraded.
23 We installed four deepwell anodes and we 24 do have plans to install another one. Right now, Zone 25 10 of our old rectifier system is still in operation NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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112 1 and providing protection to our service water system, 2 and we will upgrade when it becomes necessary. Zone 3 10 is still functioning.
4 CONSULTANT BARTON: When will you upgrade, 5 when it becomes necessary? When will it become 6 necessary? What's your plan to upgrade, I guess?
7 MS. BEAUDRY: We will upgrade when it's no 8 longer functional and we have to upgrade. We will 9 hopefully before then.
10 MR. GREGOIRE: We will be evaluating the 11 system. It's not going to just sit there and fail on 12 us. We'll be evaluating along the way and Engineering 13 will evaluate the situation associated with it and 14 make that determination at the appropriate time to 15 replace that.
16 CONSULTANT BARTON: Thanks.
17 MR. GREGOIRE: My name is Don Gregoire.
18 MR. HOLSTON: My name's Bill Holston, on 19 the DLR staff. Just to augment the licensee's 20 response, they are committed to perform annual 21 cathodic protection surveying, checking all ground or 22 soil to piping potentials on an annual basis.
23 And from that they can easily determine 24 where they need to make the necessary improvements.
25 CONSULTANT BARTON: Thanks. All right, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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113 1 Greg, I'm done.
2 MR. PICK: Thank you, sir. Our additional 3 inspection issue related to a, this issue was an 4 example that had elements in both Part 50 and Part 50, 5 and this was resolved during the inspection.
6 The applicant did make some changes to the 7 Aging Management Program related to specific 8 documentation of structural indication.
9 The team independently evaluated the 10 condition of the reactor building as part of our 11 review of the site-specific operating experience. It 12 described a surface crack on the exterior of the 13 reactor building.
14 From our walk-downs in the field, the team 15 identified that the interior of the reactor building 16 had a crack that followed the outline of the crack on 17 the exterior and questioned whether this was a 18 through-wall crack.
19 We had concerns that a possible aging 20 mechanism related to moisture intrusion on the 21 reinforcing steel may have occurred and impacts on the 22 structural capability to withstand a design-basis 23 seismic event.
24 The applicant provided photographs and 25 they performed evaluation in accordance with the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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114 1 concrete codes.
2 Following review of the photographs and 3 independent review of their evaluation, the team 4 concluded that the applicant took appropriate actions 5 to evaluate the design capability to withstand the 6 design-basis earthquake and to assess the impact of 7 the aging effects.
8 CHAIR SIEBER: Were you ever able to 9 determine whether the crack was continuous from the 10 outside to the inside?
11 MR. PICK: Our conclusion based on the 12 evidence that the applicant provided, the photographs 13 and discussions and review of their construction 14 paperwork, we do not believe that it was ever a 15 through-wall crack.
16 We agree with their conclusion that it was 17 a cold joint crack. That it occurred because they had 18 stopped a pour.
19 CHAIR SIEBER: Oh, okay. Thank you.
20 MR. PICK: Next slide, please. Our 21 overall conclusion based on our inspection, the 22 applicant properly scoped non-safety related 23 structures, systems, components, and they properly 24 applied Aging Management Programs to those structures, 25 systems and components.
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115 1 And we believe that reasonable assurance 2 exists that aging effects will be managed and intended 3 functions maintained. That concludes my presentation.
4 Are there any questions?
5 CONSULTANT BARTON: Yes, I've got one.
6 Your inspection report states that the applicant had 7 not completed many elements in their Aging Management 8 Programs so the team could not assess the 9 effectiveness of the planned implementation.
10 But yet your slide says you got reasonable 11 assurance that aging effects will be managed and 12 intended functions maintained, so I guess I'm in a 13 quandary here.
14 MR. PICK: What specifically was missing 15 during our inspection is, for new programs applicants 16 generally do not have program procedures whatsoever.
17 Our experience in Region IV has been some applicants 18 have identified procedures, drafted procedures, 19 identified changes to existing procedures on their 20 plans for monitoring aging effects.
21 This applicant as I understand, has 22 another program that's going to be budgeted to develop 23 those procedures that I just talked about. That 24 statement was specifically there for future 25 inspections to recognize the limitations of our NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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116 1 inspection.
2 CONSULTANT BARTON: That's why I had asked 3 the question, because I thought you'd have to do a 4 follow-up inspection and you said you're going to 5 probably have to do that. Okay.
6 MR. PICK: The follow-up inspection will 7 be the 71-003.
8 CONSULTANT BARTON: Okay. I understand, 9 Greg.
10 MEMBER SKILLMAN: Greg, this is Dick 11 Skillman. The question that I have is, for each of 12 these items that your team found, were they entered 13 into the licensee's corrective action program?
14 MR. PICK: Yes, they were.
15 MEMBER SKILLMAN: All can be accounted 16 for?
17 MR. PICK: Yes, they were. I did that 18 independently by talking to the applicant.
19 MEMBER SKILLMAN: Thank you, Greg.
20 MR. PICK: Any additional questions?
21 CHAIR SIEBER: Apparently there are no 22 additional questions.
23 MR. PICK: Thank you, gentlemen. I will 24 turn the meeting back over to Arthur.
25 MEMBER STETKAR: Greg, don't hang up the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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117 1 phone though.
2 MR. PICK: I don't plan on hanging up.
3 MR. CUNANAN: Greg will be here throughout 4 the meeting. All right, thanks, Greg. We're going to 5 move on to Section 3.
6 Section 3 of the SER covers the staff's 7 review of the applicant's Aging Management Programs 8 and Aging Management Review line items in each of the 9 systems which was reviewed against the criteria in the 10 GALL report.
11 For a given Aging Management Review, the 12 staff reviewed the intended function, material, 13 environments, aging effect and the proposed Aging 14 Management Program combination.
15 If an Aging Management Review did not 16 align with the GALL report, the staff conducted a 17 technical review to ensure adequacy and issued a 18 Request of Additional Information if appropriate.
19 Next slide. As shown on the Table, the 20 staff reviewed 55 Aging Management Programs. The 21 staff also reviewed over 5,000 Aging Management Review 22 line items from the submitted license renewal 23 application.
24 As Greg had discussed, there were several 25 one-time inspection programs which were revised to a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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118 1 plant-specific periodic inspection programs. The 2 staff at headquarters coordinated with the Region 3 about these one-time inspection program and the Region 4 further incorporated its attention to these programs 5 during its inspection.
6 The staff believed that the one-time 7 inspection programs were inconsistent with the GALL 8 report which recommended periodic inspections for 9 systems that have environments that change over time 10 such as raw water.
11 Subsequent generic RAIs were issued 12 related to the sampling size. All programs shown in 13 this slide are unique to the plant except for a Small 14 Bore Class 1 Piping program which is a generic program 15 that plants must revise to a plant-specific program if 16 the plant had operating experience related to small 17 bore weld cracking, which brings us to our first open 18 item.
19 MEMBER STETKAR: Okay, before you do that, 20 Arthur, I've got a couple questions about specific 21 AMPs and sort of the rationale of why the staff 22 accepted certain things.
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119 1 associated with buried piping as a result of internal 2 corrosion.
3 In the applicant's response to RAI B.2.5-4 2, they say that alternative volumetric examination 5 methods will not be used to conduct interior wall 6 thickness measurements in lieu of excavating and 7 visually inspecting buried pipe.
8 And the staff accepted external visual 9 inspections of buried pipe as a way to infer the 10 thickness of the wall?
11 Based on the fact that they've had 12 experience with internal corrosion of buried pipe, I 13 don't quite understand that. So could you explain why 14 that's acceptable?
15 MR. CUNANAN: Yes, I have Bill Holston 16 that can comment on that.
17 MR. HOLSTON: Yes, my name is Bill 18 Holston, Division of License Renewal. The purpose of 19 the buried pipe inspection program is to examine only 20 the external surfaces of the piping system.
21 And that's why directed excavated 22 inspections of at least ten feet of pipe are typically 23 the norm. What we allow in GALL Revision 2 is 24 alternatively is to take 25 percent of the piping 25 length and do it from the inside with an ultrasonic NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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120 1 examination.
2 Of course that gives you the added benefit 3 of looking inside and looking from the outside. In 4 some cases piping systems are buried 20, 26 feet in 5 the ground and that's why we offered that opportunity.
6 There are other programs, for instance, 7 internal surfaces monitoring program, the open cycle 8 cooling water program that would address the operating 9 experience which you cited.
10 MEMBER STETKAR: Does the open cycle 11 cooling water program here include internal 12 examination of, for example, standby service water 13 piping and the fire protection piping that's buried?
14 MR. HOLSTON: I did not evaluate that 15 program. Jim Gavula, you still on the line?
16 MR. GAVULA: Yes, I am. Hello?
17 MR. CUNANAN: Yes, go ahead, Jim. Can you 18 answer that question?
19 MR. GAVULA: Yes, open cycle cooling does 20 internal inspections. I would need to go back and 21 look at the specific portions of the systems that it 22 looks at though.
23 MEMBER STETKAR: I'd appreciate that, 24 because at least for fire protection there seems to be 25 evidence that they're not going to do internal NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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121 1 inspections of any of the buried piping sections, at 2 least from what I could divine from a couple hundred 3 pages worth of stuff.
4 So I'm really curious about whether 5 they're going to be doing internal inspections of 6 buried in-scope piping systems, in particular those 7 associated with, you know, raw water fire protection, 8 standby service water and anything else, because it 9 wasn't at all obvious.
10 MR. GAVULA: If I can add, in many cases 11 they will infer the condition of the buried piping 12 based on the condition of the above ground piping in 13 that the internal surfaces would be comparable as a 14 similar environment.
15 MEMBER STETKAR: Okay, thanks.
16 MR. CUNANAN: Thanks, Jim. I also have 17 present, Michelle Kichline.
18 MS. KICHLINE: Hi, I'm Michelle Kichline, 19 License Renewal. I review the fire protection 20 programs.
21 And the fire protection program does allow 22 you to use inspections of the internal surfaces of the 23 above ground piping to determine what the condition 24 would be of the internal surface of the buried piping.
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122 1 inspections to determine the condition of the internal 2 surfaces of the piping.
3 MEMBER STETKAR: Okay. I guess, and this 4 may be for the applicant. And since the operating 5 experience mentions instances of leakage associated 6 with buried piping as a result of internal corrosion, 7 have you had instances of leakage of above ground 8 piping associated with internal corrosion?
9 I mean is there something unique about the 10 buried piping environment that I don't understand?
11 MR. ATKINSON: One moment, please.
12 MS. BEAUDRY: Carolyn Beaudry, buried 13 piping program owner. The only leaking pipe that I am 14 aware of is actually potable water which is a PVC 15 pipe. I'll have to get back to you on to where the 16 internal corrosion --
17 MEMBER STETKAR: Okay, and as I said this 18 is only, I extracted that from the operating 19 experience that's cited in, if you want to look it up, 20 it's SER Section 3.0.3.2.3.
21 CONSULTANT BARTON: That talked about 22 several problems in these systems.
23 MEMBER STETKAR: Yes, you know, that's 24 what I extracted from my quote here.
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123 1 system.
2 MEMBER STETKAR: Corrosion of, you know, 3 obviously the system you mentioned wouldn't be 4 subjected to corrosion.
5 CONSULTANT BARTON: Two thin wall PVCs, 6 something like that, yes.
7 MR. CUNANAN: We have it as marked to get 8 back to you on that.
9 MEMBER STETKAR: Yes, thanks.
10 MR. CUNANAN: Okay, this open item 11 describes the staff's concern related to operating 12 experience. So the program descriptions in the 13 License Renewal Application state that future 14 operating experience will be used to adjust the 15 program as appropriate.
16 The details on how it will use future 17 operating experience to ensure that the Aging 18 Management Programs will remain effective are not 19 fully described.
20 I would like to introduce Matt Homiack, 21 who will address this open item.
22 MR. HOMIACK: Good morning. Thanks, 23 Arthur. As Melanie Galloway highlighted the 24 importance of this issue during the meeting, on behalf 25 of the staff I will follow her lead and provide some NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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124 1 additional context.
2 As Arthur mentioned, this open item 3 concerns how the applicant will use future plant 4 specific adjustments through operating experience to 5 ensure that its AMPs are effective and to update them 6 or to create new AMPs when necessary.
7 This is a new emergent issue under NRC 8 staff review for all license renewal applications. It 9 has not previously been presented before the ACRS.
10 Melanie mentioned that the staff undertook 11 an effort to review applications against GALL Rev 2 12 changes, this is a similar item except it stems from 13 the SRPLR Rev 2.
14 To ensure that new issues and lessons 15 learned on aging management will be appropriately 16 captured and evaluated, the staff has asked the 17 applicant to describe its programmatic activities for 18 the ongoing review of operating experience.
19 In response to the staff's RAI, the 20 applicant has proposed to use its existing operating 21 experience program in conjunction with its corrective 22 action program as the means to gather and evaluate 23 operating experience.
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125 1 management will be considered under these two 2 programs. Some of these things are like 3 identification and categorization of operating 4 experiences related to aging management.
5 Clearly the corrective action program is a 6 critical element for the applicant's ability to use 7 operating experience. Do they have the ability to put 8 the right information into that program and also to 9 extract the right information out of that program?
10 Also of concern is what type of 11 information the applicant will consider in operating 12 experience evaluations when they concern aging. Are 13 they going to look at the materials and environments 14 and aging effects when necessary?
15 Also of concern is the type of information 16 that the applicant's going to consider as operating 17 experience. Initially they had indicated that they 18 would not consider subsequent revisions of the GALL 19 report as operating experience.
20 Note that they did say that they would 21 consider GALL Rev 3 as operating experience so we're 22 glad to hear that, but it also extends to other, you 23 know, lessons learned as operating experience that we 24 think that should be considering as well, also 25 training for use of these programs on age related NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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126 1 degradation.
2 We did note that the applicant has 3 initiated some action and to provide some training to 4 its personnel. However, we think there's probably 5 additional areas that need training such as for 6 screening operating experience and also for submitting 7 operating experience information.
8 Also note that the applicant indicated 9 earlier that it's using its License Renewal Team on a 10 daily basis to screen operating experience and that 11 kind of thing.
12 My question is that that, is a correct-out 13 because the applicant's applying for license renewal?
14 We'll need to see some plans on how they want to go 15 forward with that on an ongoing basis.
16 So in summary, the staff is challenging 17 the applicant to make sure that its existing processes 18 are appropriately sensitized with respect to the 19 consideration of operating experience on aging 20 management.
21 MEMBER SKILLMAN: Matt, this is Dick 22 Skillman. Let me ask you to explain a little more 23 regarding your last comment.
24 What I heard you say is it seems the 25 applicant has zeroed in on OE because they're making NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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127 1 an application. Please say more about what you meant 2 when you said that.
3 MR. HOMIACK: What we want to see is a 4 plan to go forward and consider operating experience 5 for license renewal on an ongoing basis. So the 6 question is, how is the applicant going to, you know, 7 essentially move from its License Renewal Team to its 8 normal plan operating staff, you know, for license 9 renewal?
10 MEMBER SKILLMAN: May I ask, as you have 11 made that comment is there reason to believe they 12 wouldn't invest the same amount of energy in the 13 future that they are now investing in OE?
14 MR. HOMIACK: No, I don't think so. But 15 we just want to see what their plan is for making that 16 transition.
17 MS. GALLOWAY: I think we see this more as 18 a broad industry issue. There's a difference in the 19 first 40 years of operation where there's a lot of 20 emphasis on failures and events and operability.
21 But when you get into an aging management 22 emphasis there's more of a prevention and how do you 23 change things in your program so that the failures 24 don't occur. And that's the kind of transition we 25 want to be sure and see.
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128 1 And that's the training and that's the 2 orientation and that's this idea of thresholds, of 3 understanding when you get enough operating experience 4 information you rationally need to process it as a 5 change to your Aging Management Programs. And that's 6 what we want to look at.
7 And when we talked about updates to 8 guidance documents, you know, we're glad when we hear 9 the industry looked at a GALL Revision as operating 10 experience, because clearly that's what we view it as 11 a compilation of.
12 But what we want the industry and 13 applicants to be sensitized to is that by the time it 14 gets in an update to a GALL it's already historical.
15 We want them to be evaluating it in real time.
16 We don't want them to wait for the 17 industry compilation to come out from the NRC, and we 18 want it to be both plant specific information as the 19 corrective action we have talked about during the 20 applicant's presentation, but we also want the 21 information shared so that the industry as a whole has 22 the benefit of aging management operating experience 23 that can be incorporated into maintaining the 24 effectiveness of those Aging Management Programs for 25 that 20-year license renewal period.
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129 1 MEMBER SKILLMAN: Thank you.
2 MR. CUNANAN: Are there any further 3 questions on operating experience? All right, thank 4 you, Matt and Melanie.
5 This open item describes the staff's 6 concern related to the high voltage porcelain 7 insulators. The high voltage porcelain insulator 8 program manages the buildup of hard water residue on 9 in-scope high voltage insulator deposited by vapors 10 from the cooling towers.
11 Management of this effect consist of 12 either periodic coating or cleaning of the high 13 voltage insulator. The staff noted that the applicant 14 did not include the high voltage porcelain insulator 15 at the 230-kilovolt Ashe Substation in the High 16 Voltage Porcelain Insulator program even though its 17 breaker provided an alternate path during a station 18 blackout.
19 The applicant stated that it did not 20 include these porcelain insulators because they 21 concluded that the spray drift phenomenon would not 22 occur due to the significant distance from the cooling 23 towers, but could not provide any further information 24 to support its conclusions.
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130 1 RAI response indicating that it would include the 230-2 kilovolt porcelain insulator as part of the High 3 Voltage Porcelain Insulator program with testing every 4 eight years and cleaning if needed.
5 The staff has reviewed the applicant's 6 response and expects to close this item. Is there any 7 questions on this program?
8 Section 4 of the SER contains the staff's 9 review of the Time Limited Aging Analysis, TLAA. The 10 following slides presents the open items related to 11 the TLAAs.
12 This open item describes the staff's 13 concern related to metal fatigue. This is a generic 14 item that the ACRS has seen before with previous 15 plants, such as Hope Creek and Salem.
16 The applicant stated that it addressed the 17 effects of component fatigue life by assessing the 18 impact of the reactor cooling environments on a sample 19 of critical components identified in NUREG-6260.
20 This NUREG identified sample locations 21 that are susceptible to the effects of a reactor 22 cooling environment. The staff noted that the 23 applicant's plant specific configuration may contain 24 additional locations that need to be analyzed for the 25 effects of the reactor cooling environment other than NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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131 1 those identified in NUREG-6260.
2 The applicant stated that it will submit 3 its analysis to the staff to resolve this open item.
4 The staff must still review this analysis when it is 5 fully submitted.
6 MEMBER STETKAR: Arthur?
7 MR. CUNANAN: Yes.
8 MEMBER STETKAR: Not related to this 9 specific open item but the general topic of metal 10 fatigue, I noticed that the projected number of 11 transient cycles for a number of transients out 12 through the 60-year period of extended operation will 13 well exceed the number of analyzed cycles.
14 If just look at their linear extrapolation 15 in Table L4.3-2 of the License Renewal Application 16 and, in fact, it looks like, you know, a number of 17 those will exceed the number of analyzed cycles even 18 before you enter the period of extended operation.
19 And I think the staff had a couple of RAIs 20 regarding that and I understand that the applicant has 21 a program to constantly reevaluate the number of 22 cycles.
23 The question I had was, did you ask the 24 applicant for any histograms of the actual annual 25 occurrence rates of each of those transients so that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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132 1 you could see if there were any trends?
2 In other words, in some plants you notice 3 a very large number of transients early in core life 4 with a decreasing number as a function of history, 5 which means those linear extrapolations might be very, 6 very conservative.
7 On the other hand, if the frequency has 8 remained fairly constant over the how ever long it is 9 operating the plant, 20 some-odd years now, yes, you 10 draw a little bit different conclusion about the 11 possible conservatism of those extrapolations.
12 Did you ask for any of that information?
13 Was it supplied?
14 MR. CUNANAN: Allen Hiser can speak to 15 that.
16 MR. HISER: We did not in this case and 17 generally we don't look for details like that.
18 MEMBER STETKAR: Okay.
19 MR. HISER: The applicant, within their 20 calculations once they establish a limit on the number 21 of cycles, if it turns out to be non-conservative they 22 have to deal with the consequences of that through 23 their Aging Management Program.
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133 1 they still have to deal with the --
2 MEMBER STETKAR: I was more curious 3 because they did what seems to be a linear 4 extrapolation. Other applicants have gotten fairly 5 creative about segments of the data, historical data 6 that they use for the extrapolations. Here it was 7 strictly a linear extrapolation.
8 MR. HISER: Well, it's linear but if it's 9 a two-point linear, if you do have a decreasing trend 10 then -
11 MEMBER STETKAR: And that's why I say, in 12 this particular case since they did just a linear 13 extrapolation I'm less concerned about it. I was just 14 curious whether you'd actually asked them for it.
15 CONSULTANT BARTON: Some applicants have 16 actually come in here and showed us the history.
17 MEMBER STETKAR: No, that's right. That's 18 right.
19 CONSULTANT BARTON: Yes, and then it kind 20 of peters out.
21 MEMBER STETKAR: The reason I bring it up 22 is just whether you'd asked for it, because other 23 applicants have used selective exclusion of certain 24 parts of their operating history to justify different 25 extrapolations.
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134 1 MR. HISER: If we see anything unusual in 2 the way that they have treated their data then we 3 would go into more detail on that. But in this case 4 with the linear extrapolation and our expectation of a 5 decrease in trend in transients, it really wasn't 6 necessary.
7 MEMBER STETKAR: Okay. Thank you.
8 CHAIR SIEBER: Well, part of the analysis 9 is to identify all of the transients that occurred so 10 you can tell what the operating experience really is.
11 In some cases that requires a lot of detail work in 12 reviewing logs and plant transients and so forth.
13 Some licensees will use the design 14 functions which are usually conservative, and say I 15 either do or don't have enough cycles remaining to 16 last through the 60-year lifetime.
17 My question would be, to what extent did 18 this licensee use actual operating history to 19 determine what the cycles were and how many 20 assumptions went into that process to sort of fill in 21 the blanks for avoid having to do detailed day-by-day, 22 week-by-week or month-by-month analysis of what the 23 transients were and how do we know the information?
24 MR. CUNANAN: I have Ching Ng who can 25 speak to that.
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135 1 MR. NG: This is Ching Ng from License 2 Renewal. In applicant's fatigue monitoring program 3 they say that I will track, they will look at the 4 trends of the occurrence of the different transient on 5 an annual basis.
6 And even though that they don't have a 7 specific action limit, for example, 80 percent or 70 8 percent, but by looking at a trend annually the staff 9 believe that applicant can enable to catch the 10 instances when the occurrence of transient exceed the 11 design limits.
12 CHAIR SIEBER: Okay, but does that include 13 examination of the past history of the transients at 14 the plant or do they make some assumptions and say, 15 this is our base point from this point forward where 16 we're going to count transient, which is of those is 17 true?
18 MR. NG: I think let's step back and, 19 typically during the Aging Management Program audit 20 the staff will look at the histogram of the 21 occurrences of the different transients.
22 And those histograms of occurrences, the 23 staff reviewed it on site and do not require them to 24 submit it as part of license renewal, but the staff 25 did look at it.
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136 1 MEMBER STETKAR: Was that histogram 2 available during the audit on this applicant?
3 MR. COLE: Jack Cole, Energy Northwest 4 engineering staff. What we at Energy Northwest did is 5 we looked at our operating transients, our cycle 6 counting, over the full period of 1983 until this 7 time.
8 And we found that some transients were 9 going to be lower and some were going to be higher.
10 We were short on startups and shutdowns. As result 11 of our review, we issued what we, tech metal, it has 12 the projected number of cycles for the full 60-year 13 life of the plant.
14 And for our fatigue analysis, then we went 15 back for our TLAA evaluation with environmental 16 fatigue, updated the cycles to the projected 60-year 17 cycles and re-ran those analyses.
18 The plant has a commitment now that when 19 they are approaching any of the limits they will have 20 to update to Class 1 design reports. But as we've 21 done that for all of the TLA locations we have good 22 expectation.
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137 1 cycles.
2 CHAIR SIEBER: Thank you. That answers my 3 question.
4 MR. CUNANAN: Is there any further 5 questions with metal fatigue? All right. This open 6 item describes the staff's concern related to the core 7 plate rim hold-down bolts.
8 In the original license renewal 9 application the applicant stated that Columbia had 10 core plate wedges installed around the periphery of 11 the core plate within the shroud.
12 Core plate wedges prevent lateral motion 13 of the core plate and are not subject to stress 14 relaxation. However, in a conference call the 15 applicant stated that it had discovered there were no 16 core plate wedges located around the periphery of the 17 core plate within the shroud.
18 Having no core plate wedges results in the 19 applicant having to perform bolt inspections as 20 described in BWRVIP-25 titled BWR Core Plate 21 Inspection and Flaw Evaluation Guidelines.
22 The applicant submitted a license renewal 23 application supplement to include a commitment to 24 install wedges at least two years prior to the 25 beginning of the period of extended operation or NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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138 1 submit a plant specific TLAA addressing the stress 2 relaxation of the core plate rim hold-down bolts to 3 the NRC for review and approval at least two years 4 prior to the period of extended operation.
5 However, the applicant had not selected 6 one of the three options of 10 CFR 54.21(c)(1) to 7 demonstrate the evaluation of the TLAA. Also the 8 applicant did not provide an AMR line item for the 9 core plate rim hold-down bolts for the aging effects 10 of loss of preload due to stress relaxation.
11 Furthermore, the applicant stated that it 12 would deviate from the BWRVIP-25 inspection guidance 13 until December 31, 2015, because as with other BWRs 14 with no wedges it does not plan to inspect the hold-15 down bolts for stress relaxation due to the 16 difficulties in performing the inspection.
17 The staff has concern that the effects of 18 aging will not be adequately managed without 19 performing the inspections. The applicant has not yet 20 provided its response for staff review.
21 MEMBER STETKAR: Arthur, and I asked this 22 earlier. This is I assume an issue for the current 23 licensing basis as well as the license renewal, is 24 that correct? Because it's sort of a bit disturbing 25 that they discovered in 2011 that they didn't have the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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139 1 wedges in a plant that's been operating for 27 years.
2 MR. CUNANAN: Yes, we agree that it's a 3 current licensing and a license renewal kind of issue.
4 MEMBER STETKAR: And NRR is following --
5 MR. CUNANAN: Yes, we're currently with --
6 MEMBER STETKAR: Just out of -- I'm not a 7 boiling water reactor guy so I'm, nor am I structural 8 guy so I'm speaking well out of my area of expertise.
9 You mentioned other boiling water reactors don't have 10 the wedges either.
11 Have any of them performed inspections of 12 the bolts during their current licensing period?
13 MR. CUNANAN: Chris Sydnor?
14 MR. SYDNOR: Hi, this is Chris Sydnor.
15 I'm a materials engineer in Division of Component 16 Integrity, since been consolidated into the Division 17 of Engineering.
18 We engage the BWRVIP, is the EPRI BWR 19 Vessels and Internals Project, on these kinds of 20 issues in current licensing space and during the 21 current for, on an ongoing basis.
22 That's correct. The deviation that was 23 discussed in the slide is in a sense kind of generic 24 for all boiling water reactors without wedges. So 25 we're going to be kind of engaging them in, you know, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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140 1 on an ongoing basis on the potential need for 2 inspections as discussed in BWRVIP-25, and if 3 inspections are not performed what kind of analyses 4 are being done to support that conclusion.
5 MEMBER SHACK: Yes, but how have you dealt 6 with this problem with the other BWRs in license 7 renewal? I mean I went back and looked and a lot of 8 them had deviations but then it wasn't clear to me how 9 they were resolved.
10 MR. CUNANAN: Yes, to that point there is 11 the deviation and then until the point where it pass 12 the date of 2015, then a decision has to be made 13 whether to do inspections or it's a revise from the 14 BWRVIP program that shows how the inspections will be 15 conducted.
16 MR. SYDNOR: Yes, the subject deviation is 17 set to expire at the end of 2015, December 31st, 2015.
18 MEMBER SHACK: And so the other BWR 19 license renewals probably have a similar sort of a 20 thing for their deviations? There's a --
21 CHAIR SIEBER: For a currently operating 22 plant ultimately.
23 MR. CUNANAN: Yes, for a current 24 operating. I have Jeff Poehler on the microphone too.
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141 1 Materials Engineer in the Vessel Internals branch of 2 Division of Engineering. Yes, to the other question, 3 have other BWRs inspected?
4 Some have performed inspections of those 5 bolts but they have not performed the inspections that 6 were originally prescribed in the BWRVIP-25 Inspection 7 Evaluation Guideline, because it originally prescribed 8 ultrasonic testing or a VT1 from below the bolts which 9 proved to be unfeasible.
10 So some of them have done limited VT3 11 visual inspections of some portion of the bolts.
12 MEMBER SHACK: There's a big difference.
13 MR. POEHLER: Right, but yes, it's 14 basically in my understanding is they've done those 15 from above and it's been a best effort to see if the 16 bolts have rotated, which would indicate fractured 17 bolts.
18 And they haven't seen any evidence of any 19 IGSCC cracking that would cause failure. But again 20 they're not doing ultrasound exams which would be more 21 effective.
22 So it needs to be addressed on a generic 23 level for the whole fleet, the whole BWR fleet. And a 24 number of them have submitted the TLAA, committed to 25 do the TLAA for stress relaxation and have submitted NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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142 1 those analyses.
2 CHAIR SIEBER: Any further questions on 3 this topic? Okay.
4 MR. CUNANAN: Okay, moving on to the next 5 slide. This open item describes the staff's concern 6 related to the upper-shelf energy. I would like to 7 introduce Allen Hiser to present this open item.
8 MR. HISER: Thanks, Arthur. As the 9 applicant described earlier they identified several 10 small-bores from the instrument nozzles that have 11 neutron fluence levels above 1 times 10 to the 17th 12 neutrons per centimeter squared, and this necessitates 13 consideration of neutron embrittlement effects in 14 these nozzles.
15 For the N12 nozzle forging, which we saw 16 several schematics from the applicant, the applicant 17 demonstrated that the, showed that the upper-shelf 18 energy would meet the Appendix G requirements of 50 19 foot-pounds using an initial energy of 62 foot-pounds 20 and copper content of 0.27 percent identifying that 21 these values are not heat specific but come from a 22 statistical analysis performed by General Electric.
23 In the absence of a technical basis for 24 these assumptions, the staff has requested that the 25 applicant provide documentation of the source of these NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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143 1 values so that the staff can determine acceptability 2 of the applicant's analysis.
3 The applicant as I stated earlier has 4 indicated they will provide this information in its 5 RAI response.
6 CHAIR SIEBER: Is that kind of information 7 typically retrievable by licensees, the non-specific 8 characteristics of various heats?
9 MR. HISER: It depends on what's 10 available. In the case of this nozzle, there was no 11 heat specific NPRs with Charpy data or with the copper 12 content. In this case they're relying on a database 13 analysis from other similar heats.
14 CHAIR SIEBER: Yes, that's where the issue 15 is. And so what happens if you don't come up with 16 item-specific heat data?
17 MR. HISER: Well, if you don't have heat 18 specific then the staff generally has accepted an 19 analysis of a database of similar materials. In this 20 case, this is an A508 grade Class 1 forging and so 21 they have data that, they have indicated that they 22 have data for other A508 Class 1 forgings.
23 CHAIR SIEBER: Similar, yes. Okay.
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144 1 relative to that database will determine whether we 2 find it acceptable or not.
3 CHAIR SIEBER: Okay, thank you.
4 MR. CUNANAN: Any further questions on the 5 upper-shelf energy open item? Okay, next slide.
6 Thanks, Allen.
7 This open item describes the staff's 8 concern related to the applicant's analysis for its 9 cranes. The applicant states that the analysis for 10 its cranes does not meet the definition of a TLAA.
11 However, the staff believes that the 12 analysis for its cranes meet the definition of a TLAA 13 because there is a design limit on the number of 14 cycles specified in Crane Manufacturers Association of 15 America, CMAA 70 specifications, which involved a time 16 limited assumption.
17 The applicant has submitted its RAI 18 response indicating that it would analyze the cranes 19 under 10 CFR 54.21(c)(1)(I). The staff is still 20 reviewing its response.
21 In conclusion and pending successful 22 resolution of the open items, the staff will be able 23 to determine that the requirements of 10 CFR 54.29 (a) 24 have been met for the license renewal of Columbia 25 Generating Station.
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145 1 The staff's conclusion will be provided in 2 the final Safety Evaluation Report which is scheduled 3 for a February 2012 issuance, which Melanie has stated 4 in her introduction may be challenging due to the 5 extent of RAIs and open items.
6 And with the possibility of follow-up RAIs 7 we are looking ahead towards the need for further 8 scheduled delays. This concludes my presentation. Do 9 you have any further questions?
10 CHAIR SIEBER: Any further questions?
11 MEMBER SKILLMAN: I do. This is Dick 12 Skillman. In the past say three operating cycles, six 13 years on the 24-month cycle, has this station been in 14 95-001, 002 or 003?
15 MS. GALLOWAY: Greg, can you answer that?
16 MR. GREGOIRE: Don Gregoire, Regulatory 17 Affairs Manager. We had a 95-001 due to a multiple 18 scrams performance indicator going white, and that was 19 in 2009 time frame, 2010 time frame.
20 MEMBER SKILLMAN: Thank you.
21 CHAIR SIEBER: That's the only one.
22 MR. GREGOIRE: That's the only one in the 23 last, what did you say?
24 MEMBER SKILLMAN: Three cycles, six years.
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146 1 one related to security.
2 MEMBER SKILLMAN: That's fine. Thank you.
3 CHAIR SIEBER: Any additional questions 4 from the members? John?
5 MEMBER STETKAR: I have one for the, not 6 for the staff if you want to dismiss the staff, I have 7 a follow-up for the applicant.
8 CHAIR SIEBER: Well, go ahead.
9 MEMBER STETKAR: Okay. I'm back on the 10 bus duct failure out in the turbine building. And my 11 problem is I don't understand the words fail-safe, so 12 I tend to just dismiss those words as kind of 13 meaningless.
14 The steam pressure sensors that are out in 15 the turbine building are there for a reason. They 16 actuate MSIV closure for some types of steam line 17 breaks I assume.
18 You know, what they're there for in 19 particular and where they are, I have no idea. My 20 question is, can you have failures of those cables or 21 the pressure sensors such that the low steam pressure 22 signal does not go into the protection logic and 23 therefore does not close the MSIVs?
24 That is not a fail-safe, it is not a cut 25 the cable and have an open circuit, it is not the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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147 1 design basis analysis of the transmitter. It's can 2 you have a failure of that cable that gives you a 3 false high pressure signal thereby disabling the MSIV 4 closure signal from those sensors? That's the 5 question.
6 If the answer to that question is yes, 7 then I'm really not sure why things that can affect 8 those cables are excluded from the scope of license 9 renewal.
10 MR. ATKINSON: We'll have to have just a 11 moment to think about this.
12 MEMBER STETKAR: Okay. It's very 13 complicated and it's the way people don't normally 14 think because people think fail-safe, fail-safe, fail-15 safe.
16 And it gets to -- Jack asked the question 17 and we got a very quick response, but it really didn't 18 address the fundamental issue. Sorry. We have time 19 so I thought I'd bring it up.
20 CHAIR SIEBER: We actually have an 21 additional 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
22 MR. ATKINSON: Yes, this is Dale Atkinson 23 with Energy Northwest. We'll take just a few minutes.
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148 1 that perform this function and verify that this is --
2 MEMBER STETKAR: Also the cables too.
3 MR. ATKINSON: Right.
4 MR. CUNANAN: Also if the applicant's 5 answer is not satisfactory to the staff we will 6 continue further discussion after this.
7 MEMBER STETKAR: You know, in some sense 8 it would be nice to have a definitive answer, you 9 know, within the context of this meeting, but 10 understand. Occasionally you do have takeaways from 11 these subcommittee meetings.
12 CHAIR SIEBER: I would like to have it on 13 the transcript if we can.
14 MEMBER STETKAR: If we can. But if we 15 can't, you know, we can follow up and if there's 16 another subcommittee meeting or a full committee 17 meeting we can follow up. We tend not to forget.
18 MR. CUNANAN: We do have a takeaway with 19 your question on the internal corrosion.
20 CHAIR SIEBER: I have schematics but I 21 don't have physical layouts. I have all the drawings 22 of the plant but they're off of schematics.
23 MEMBER STETKAR: You don't have electrical 24 drawings, do you?
25 CHAIR SIEBER: I have whatever is in the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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149 1 FSAR.
2 MEMBER STETKAR: I couldn't find much on 3 electrical in the --
4 CHAIR SIEBER: It's not complete. It's 5 single lines and typicals. And single line doesn't 6 answer it.
7 MEMBER STETKAR: No, no.
8 MR. ATKINSON: Is this an item we're going 9 to be able to give back to you in a few minutes or do 10 you want to just wait right now for a response?
11 CHAIR SIEBER: I think the choice is 12 pretty soon or at the full committee meeting.
13 MR. SWANK: I'll give you what we have.
14 So I think there's some confusion on what signals 15 we're talking about. This is Dave Swank, Energy 16 Northwest.
17 So they'd be, signals of concern would be 18 DEH oil pressure, low oil pressure which would feed 19 into RPS, Reactor Protection System. And then 20 secondarily, also feeding into RPS would be the 21 throttle valve position.
22 So those are the two signals there at the, 23 if you remember for those of you who came to the 24 plant, on the west end of the turbine building are all 25 the non-segregated buses that we're talking about.
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150 1 These signals are all down on the east end of the 2 turbine.
3 And so what we're looking at, believe we 4 evaluated it, we want to verify that we evaluated the 5 distance and the potential effects from any of the 6 buses on the west end to the signal cables on the east 7 end running to the control room.
8 MEMBER STETKAR: The reason I focused on 9 this was not so much the RPS, the reactor scram.
10 It's, and I'll give you a hook and this again is from 11 the SER. But it's the response to RAI 2.1-1(a).
12 And at least as it's characterized in the 13 SER, it talks about loss of RPS and MSIV isolation 14 logic sensors. And it says things like, the safety 15 related MSIV isolation logic sensor inputs the safety 16 related components of the miscellaneous drainings 17 system and safety related main steam valves located in 18 the turbine generator building are classified as 19 safety related because of an NRC commitment, yada, 20 yada, yada.
21 That's what led me to believe but, you 22 know, I know you have EHC oil pressure, I know you 23 have a turbine stop valve or a governor valve input 24 for reactor protection.
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151 1 also may be steam pressure or steam flow sensors out 2 there in the turbine building that give you an MSIV 3 closure signal. Perhaps I'm misinterpreting or 4 reading too much into the, you know, this excerpt from 5 the RAI response.
6 MR. SWANK: And I think that may be the 7 case.
8 MEMBER STETKAR: If that's the case that's 9 fine, but --
10 MR. SWANK: The only safety related --
11 MEMBER STETKAR: That's the only one.
12 MR. SWANK: Yes, the ones you described, 13 those two sets of instruments are the only safety 14 related components in the turbine building.
15 MEMBER STETKAR: And that's just the EHC 16 oil pressure and the turbine stop valve or control 17 valve position?
18 MR. SWANK: Exactly. Correct.
19 MEMBER STETKAR: I think I'm happy with 20 that. There are a number of reactor scram signals 21 that come in from various and sundry, but I was more 22 concerned that -- for some reason I've seen plants 23 that have secondary steam, you know, steam pressure 24 for secondary steam line breaks out in the turbine 25 building that feed back into the MSIV closure logic NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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152 1 which is a completely different function.
2 And, you know, there may not be a backup 3 protection for some of those breaks.
4 MR. SWANK: Right.
5 MEMBER STETKAR: But if you tell me 6 there's none of that type of sensors out in the 7 turbine building I'm satisfied.
8 MR. SWANK: Okay. We've asked that 9 question to our team back home. We're looking for the 10 answer back.
11 CHAIR SIEBER: Yes, when we have the full 12 committee meeting perhaps you can direct that as --
13 MR. SWANK: Thanks.
14 CHAIR SIEBER: Well, I think we're at the 15 point on the agenda where we will, it's labeled 16 Subcommittee Discussion. Generally during meetings, 17 types of subcommittee meetings for license renewal, we 18 ask each of the members if they have comments to make 19 or concerns that have either not been addressed or 20 have arisen during the conduct of the testimony here.
21 Gordon, do you have any of those two 22 categories, additional questions or concerns?
23 MEMBER SKILLMAN: I don't have a concern 24 but I have an observation.
25 CHAIR SIEBER: All right.
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153 1 MEMBER SKILLMAN: I found in the work that 2 I've been doing for some time that when an inspection 3 team or the station's CNRB or other oversight members 4 find that there is weakness in a particular program, 5 it doesn't take long to find that that weakness is 6 promulgated into other related programs, and among 7 them the corrective action program.
8 And so to the extent that the aging 9 programs or the oversight of the aging programs may 10 not drive the rigor and discipline to identify the 11 problems or the issues in the corrective action 12 program, that gives me cause for alarm. And it just 13 reinforces how important the focus is on 10 CFR 50 14 Appendix B.
15 It's almost a lost art in our business 16 that unless senior leadership is driving hard to 17 implement all 18 points, then it's very easy to forget 18 about design control, good old Number 3, our 19 corrective action program, which I believe is XIV.
20 And so when I hear a weakness here and 21 weakness there, I go to that point in my mind where I 22 say, how much energy is senior leadership investing in 23 ensuring that Appendix B to 10 CFR 50 is really being 24 obeyed?
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154 1 other programs, I raise that flag.
2 CHAIR SIEBER: Okay.
3 MEMBER SKILLMAN: Thank you.
4 CHAIR SIEBER: Thank you. Bill?
5 MEMBER SHACK: Maybe a similar one. That, 6 you know, I looked at the regional inspection and the 7 AMP inspection. They seemed to find a lot of problems 8 and I think more so than I think is fairly typical, 9 and you sort of wonder whether you should, you know, 10 there have been an expanded inspection like we do for 11 steam generators?
12 You know, when we find out we've got this 13 many problems in these, you know, should you look at 14 all the Aging Management Programs?
15 But, you know, the staff seems to feel 16 that what they're doing is satisfactory but that's 17 just, I just wondered if there is a, you know, a 18 program where you would, in fact, go back for another 19 regional inspection just to see if, in fact, they 20 really followed up or to look at the rest of the 21 programs.
22 If the batting average is that poor on the 23 first sample, you know, should you be doing more?
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155 1 thing for the staff to think about whether they need 2 to do something additionally or whether they can under 3 the inspection programs that are out there.
4 John? Thanks, Bill.
5 MEMBER STETKAR: I have nothing more to 6 add. I kind of echoed Dick's and Bill's sentiments 7 regarding possible follow-up.
8 CHAIR SIEBER: Yes, I come up with the 9 same kinds of feelings that the other members have 10 concluded in this area. And I'm not sure what 11 mechanisms the staff has to address that but I think 12 it's something that we ought to think about.
13 MEMBER STETKAR: I know at least on one 14 plant license renewal, you know, that I chaired, the 15 staff indeed did a second follow-up inspection. It 16 wasn't on looking at an additional number of AMPs, it 17 was a different issue, but indeed they did another 18 inspection.
19 So apparently before the whatever it is, 20 the final 70-something or other, I can't open on 21 numbers, before the --
22 CONSULTANT BARTON: Yes, I don't remember 23 which plant that was but I remember the issues.
24 MEMBER STETKAR: And it doesn't make, I 25 actually do remember the plant but it's not relevant.
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156 1 CHAIR SIEBER: Yes, I remember a similar 2 instance, but this one is a more general which is, 3 what is the total adequacy of all the programs? I 4 mean are they effective or not to be able to draw 5 conclusions applicable to license renewal or not?
6 And I think that we have to ponder that 7 but I'd like to ask the staff to ponder that also.
8 MEMBER STETKAR: And in a sense we're sort 9 of quizzing the staff the same way they quiz the 10 applicant about, if you find the deficiency what's the 11 program for increasing the sample size?
12 CHAIR SIEBER: Okay, is there any other 13 comments from members? John?
14 CONSULTANT BARTON: Yes, I don't like 15 doing reviews of plants that are 12 years out, and I 16 think some of the comments you're hearing is because 17 of that.
18 The plants that are closer to the, you 19 know, the period of extended operation, the start of 20 that, seem to be more prepared in their Aging 21 Management Program, at their training.
22 They've actually run some of their 23 programs so that you get a good sense of how ready 24 they really are. I mean we're 12 years out, we're 25 hearing they're not ready, they're not trained.
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157 1 They've got a bunch of programs, they've 2 miscalculated programs, a bunch of issues that, you 3 know, is it really meaningful or not? But they've had 4 a lot of time to go and fix these things.
5 So when you look at a program this far out 6 I don't know what it really tells you, how ready they 7 really are for their extended license. And, you know, 8 as far as any major issues, are there any, you know, 9 big things out there I see in reviewing this, no, I 10 don't.
11 But I see a lot of smaller issues that --
12 and I wonder about the inspection. We've done the 13 inspection. The NRC has 12 years out and lots of open 14 items.
15 And when I asked are you going to do 16 another one, no, we're going to the final 70P3 or 17 whatever it is. Well, I'm looking for something 18 between now and then because of the number of issues 19 you've got out here.
20 CHAIR SIEBER: Well, you know, the 21 Columbia's not unique in this regard. I think that 22 the program either says you ought to have the programs 23 in place where you have to have sufficiently clear 24 commitments, the program that you will establish 25 before license renewal takes effect will properly NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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158 1 cover the issue.
2 And so the situation the Columbia presents 3 to us is not unique at least in my experience and I've 4 done audits.
5 On the other hand, what it does is it 6 transfers to the inspection process basically the 7 obligation to determine if the details that the 8 programs that licensees establish fully satisfies 9 number one, the regulations, and secondly, the 10 commitments that they made in the process of applying 11 for license extension.
12 So the situation we're faced with here is 13 not unique. On the other hand, the opportunity for 14 ACRS to become involved goes away once we approve the 15 staff's action to bring it an extended license.
16 And so I appreciate the concerns that we 17 have because it's sort of like grabbing at a cloud, 18 but I think the point that's to be made from this 19 discussion amongst all of us is the fact that if you 20 get your renewed license that does not stop the 21 additional work, the additional thought and the 22 additional definition of the requirements, and are 23 these requirements being satisfied to make a renewed 24 license or an extended license valid?
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159 1 of us to do, applicants and staff. And on the other 2 hand, I think that we can all put some additional 3 thought into these concepts and maybe the process 4 could be improved a little bit. But right now I'm not 5 prepared to describe how we could contribute to an 6 improved process.
7 Any other comments from the members? If 8 not, I'd like to thank the applicant for the work they 9 have performed and for coming here with a large 10 contingent of plant people.
11 I hope there's somebody left in the state 12 of Washington or out at the plant to keep it safe.
13 And I think the staff has done a very good job in the 14 review and I'd like to thank you also. It's not only 15 for the work that you did but for your presentations 16 today.
17 And I would ask at this point, if there 18 are any members of the public who would like to make a 19 statement before the committee? If not, I thank all 20 of you for the work that you've done to prepare for 21 this meeting and for the presentations that you have 22 made.
23 With that this meeting is adjourned.
24 (Whereupon, the foregoing matter was 25 concluded at 11:55 a.m.)
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160 1
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Columbia Generating Station ACRS License Renewal Subcommittee Meeting October 19, 2011
Columbia Generating Station Dale Atkinson - Vice President, Emp Dev/Corp Services Dave Swank - Engineering General Manager Don Gregoire - Manager, Regulatory Affairs John Twomey - Project Manager, License Renewal (incoming)
Abbas Mostala - Project Manager, License Renewal (offgoing) 2
Columbia Generating Station Team Plant Management License Renewal Team Program Owners/Subject
Dale Atkinson John Twomey Matter Experts
Dave Swank Scott Wood Carolyn Beaudry
Bruce MacKissock Abbas Mostala John Lasalle
John Bekhazi AREVA Team John Sisk
Don Gregoire Steve Richter
Brian Adami Steve Gosselin
Jack Cole
Doug Ramey
Mott Hedges
Jim Tansy
Robert Nielson 3
Agenda
- Energy Northwest and Plant Overview
- Plant Status, Major Improvements
- Safety Evaluation Report Open Items
- Concluding Remarks 4
Energy Northwest at a Glance
- Providing public power since 1957
- Hydro, solar, wind and regions only nuclear power plant
- Projects generate carbon-free power for 1 million homes 5
Who are We?
Energy Northwest is a Joint Operating Agency authorized by the State of Washington 6
7 Hanford Site - Tenant Only
- Approximately 1100 acres leased from the Department of Energy (DOE).
- Located on the Hanford Nuclear Site which is wholly owned and operated by the DOE.
- Energy Northwest maintains authority to determine all activities in the plants exclusion area as defined in 10 CFR 100.
8
Plant History
- Construction Permit - March 19, 1973
- Operating License - December 20, 1983
- 5% Power Up-Rate - May 1995 9
Plant Description
- General Electric Boiling Water Reactor
- BWR-5 / Mark II Containment
- Plant circulating water & ultimate heat sink makeup supplied from the Columbia River
- 3486 MWt/1230 MWe 10
Plant Status and Major Improvements David Swank Engineering General Manager 11
Plant Status
- Recently completed refueling outage R20
- Significant accomplishments during outage:
- Replaced main condenser
- Replaced main generator rotor
- Modified non-segregated bus 12
Major Improvements
- Main condenser replacement 2011
- Reactor recirculation pump motor 2007, 09 replacements
- Feedwater heater replacement 2007
- Improved turbine control system 2007
- Addition of 4th diesel generator 2005
- Emergency bus cross-tie 2005
- Hydrogen water chemistry 2004 13
Major Improvements (contd)
- Noble metal coating - reactor vessel 2001,07 internals
- 24 month operating cycle adopted 2001
- Reactor recirculation pump adjustable 1996 speed drive
- Digital feedwater level control system 1996
- Low pressure turbine rotors replaced 1992 14
License Renewal Application Don Gregoire Manager, Regulatory Affairs 15
License Renewal Application (LRA)
- License Renewal Project
- Initiated 2006
- Team Established June 2007
- LRA Peer Reviewed May 2009
- LRA Submitted January 2010
- LR Team Engaged with the Industry
- NEI License Renewal (LR) Task Force and Working Groups
- Observed Audits/Inspections at other Plants
- Participated in other Plants LR Peer Reviews 16
- Scoping and Screening
- Consistent with 10 CFR Part 54 and NEI 95-10
- In-scope structures, systems, and components screened to determine if Aging Management Review required
- Mechanical boundary drawings identify (a)(1),
(a)(2) and (a)(3) in-scope components 17
- Aging Management Review (AMR)
- Consistent with 10 CFR Part 54 and NEI 95-10
- Used NUREG-1801 Generic Aging Lessons Learned (GALL) Report Revision 1 18
- Aging Management Programs (AMP)
- 55 Programs Credited for LRA
- 35 Existing
- 14 Enhancements
- 20 New 19
- Time-Limited Aging Analyses (TLAA)
- TLAA Identification and Disposition Consistent with NUREG-1800 and NEI 95-10
- TLAAs Dispositioned in Accordance with 10 CFR 54.21(c)(1) 20
- 71 License Renewal Commitments
- Commitment Tracking System
- Ensures changes to implementing procedures and programs reviewed for License Renewal impact
- Commitments Include:
- Existing programs credited for the period of extended operation (PEO)
- New programs, inspections, and enhancements to be completed prior to and during the PEO 21
- Implementation
- Industry Benchmarking for Lessons Learned
- Participation in NEI License Renewal Implementation Working Group
- Self-Assessments/Audits
- Implementation Project Road Map Under Development 22
SER Open Items 23
SER Open Items
- High-Voltage Porcelain Insulators
- Operating Experience
- Upper-Shelf Energy
- Metal Fatigue
- Core Plate Rim Hold-Down Bolts
- Fatigue Analysis of Polar Crane 24
SER Open Items
- OI 3.0.3.3.7 High-Voltage Porcelain Insulators The 230 kV Station Blackout recovery source insulators at Ashe substation were not included in the LRA insulators Aging Management Program (AMP)
Resolution
- Insulators are now in program
- Tests conclude minimal accumulation and within limits
- Testing on 8 year frequency consistent with operating experience
- Response submitted August 18, 2011 25
SER Open Items
Future operating experience evaluations for aging effect were not specifically included in the LRA Resolution
- LRA to be updated to clearly call out intent to review OE on an on-going basis
- Internal/external OE considered on an ongoing basis
- Operating Experience program documentation to specifically address aging effects
- Initial/recurring training for plant staff
- Response to be provided in November 26
SER Open Items
- OI 4.2-1 Upper-Shelf Energy (USE)
Technical basis not provided for initial transverse USE and copper content for instrument nozzle forgings Resolution
- Technical basis to be provided in November
- Supports acceptability through end of period of extended operation 27
SER Open Items
- OI 4.3-1 Metal Fatigue Columbias metal fatigue Time Limited Aging Analysis (TLAA) performed for sample of critical locations listed in NUREG/CR-6260 may not be limiting Resolution
- The limiting locations have been identified
- Calculations conclude that all locations have an environmental cumulative usage factor below 1.0
- Response to be provided in November 28
SER Open Items
- OI 4.7.4-1 Lower Core Plate Rim Hold-Down Bolts Neither TLAA nor AMR line item for the reactor pressure vessel lower core plate hold-down bolts were provided Resolution
- LRA will be amended to include:
- TLAA disposition for 10 CFR 54.21(c)
- Response to be provided in November 29
SER Open Items
- OI 4.7.5-1 Fatigue Analysis of Polar Crane Columbias LRA did not include TLAA for polar crane Resolution
- Columbia has an overhead crane but not a polar crane
- TLAA for the 15 in-scope cranes and hoists
- Remains valid through the end of the period of extended operation
- Response provided October 5, 2011 30
Closing Remarks 31
Ashe Substation Transformer Yard Cooling Towers 35
39 46 47 48 61 N12 WLI Nozzle (3.32 in. dia.)
62
87 Sand Pocket Detail 88
Detail of Refueling Bellows Seals 90
Typical Sand Pocket Drain Line 91
Typical PCV Inspection Port 92
Advisory Committee on Reactor Safeguards (ACRS)
License Renewal Subcommittee Columbia Generating Station (Columbia)
Safety Evaluation Report (SER) with Open Items October 19, 2011 Arthur Cunanan, Project Manager Office of Nuclear Reactor Regulation 1
Presentation Outline
- Overview of Columbia license renewal review
- SER Section 2, Scoping and Screening review
- Region IV License Renewal Inspection review
- SER Section 3, Aging Management Programs and Aging Management Review Results
Overview
- License Renewal Application (LRA) submitted January 19, 2010 Applicant: Energy Northwest (EN)
Facility Operating License No. NPF-21 requested renewal for a period of 20 years beyond the current license date of December 20, 2023
- Approximately 12 miles north of Richland, WA
- BWR with a Mark II containment 3
Audits and Inspections
- Scoping and Screening Methodology Audit
- May 10-13, 2010
- Aging Management Program (AMP) Audits
- May 24-28, 2010
- Region IV Inspection (Scoping and Screening &
AMPs)
- October 18, 2010 - November 4, 2010 4
Overview (SER)
- Safety Evaluation Report (SER) with Open Items issued August 30, 2011
- Operating Experience
- Metal Fatigue
- Core Plate Rim Hold-Down Bolts
- High-Voltage Porcelain Insulators
- Upper-Shelf Energy
- Fatigue Analysis of Polar Crane 5
SER Section 2 Summary Structures and Components Subject to Aging Management Review
- Section 2.1, Scoping and Screening Methodology
- Methodology is consistent with the requirements of 10 CFR 54.4 and 54.21
- Section 2.2, Plant-Level Scoping Results
- Systems and structures within the scope of license renewal are appropriately identified in accordance with 10 CFR 54.4
- Sections 2.3, 2.4, 2.5 Scoping and Screening Results
- SSCs within the scope of license renewal are appropriately identified in accordance with 10 CFR 54.4(a), and those subject to an AMR in accordance with 10 CFR 54.21(a)(1) 6
License Renewal Inspections Greg Pick Region IV Inspection Team Leader
Regional Inspections Overview Six inspectors for 2 weeks Scoping & screening inspection Aging management programs inspection 8
Regional Inspections AMP Inspection Results One-Time Inspections - applicant misapplied use of one-time program in six cases Structures Monitoring - no administrative mechanism to trend structural indications Chemistry Program Effectiveness - committed to revise sample sizes to meet GALL, Revision 2 9
Regional Inspections AMP Inspection Results High Voltage Insulators - improperly excluded 230kV insulators from aging management activities Buried Piping - reliability issues exist with portions of the cathodic protection system Lube Oil Analysis - identified implementation weaknesses Various Programs - identified a need for training on how to assess aging effects 10
Regional Inspections Additional Inspection Issue Assessed a reactor building crack after review of plant operating experience in Structural Monitoring AMP:
Impact of moisture on the crack Ability to withstand seismic forces 11
Regional Inspections Inspection Conclusions Scoping of non-safety SSCs and application of the AMPs to those SSCs were acceptable Reasonable assurance exists that aging effects will be managed and intended functions maintained 12
Section 3: Aging Management Review
- Section 3.0 - Aging Management Programs
- Section 3.1 - Reactor Vessel & Internals
- Section 3.2 - Engineered Safety Features
- Section 3.3 - Auxiliary Systems
- Section 3.4 - Steam and Power Conversion System
- Section 3.5 - Containments, Structures and Component Supports
- Section 3.6 - Electrical and Instrumentation and Controls System 13
SER Section 3 3.0.3 - Aging Management Programs 55 Aging Management Programs (AMPs) presented by applicant and evaluated in the SER Consistent Consistent Consistent With Plant with GALL with exception with exception & Specific enhancement enhancement Existing 15 3 10 1 6 (35)
New 10 3 7 (20) 14
SER Section 3 Several one time inspection programs were revised to plant specific periodic inspection programs:
- Cooling Units Inspection
- Diesel-Driven Fire Pumps Inspection
- Diesel Systems Inspection
- Flexible Connection Inspection
- Monitoring and Collection Systems Inspection
- Service Air System Inspection
- Small Bore Class 1 Piping Program 15
SER Section 3 Open Items SER Section 3.0.2.1 - Operating Experience OI B.1.4-1
- Details of future operating experience to ensure AMPs will remain effective for managing the aging effects are not fully described 16
SER Section 3 Open Items SER Section 3.0.3.3.7 High-Voltage Porcelain Insulators OI 3.0.3.3.7
- High-voltage post insulators at the 230 kV Ashe Substation is not included in the AMP
- The applicant indicated that it would either:
- Establish appropriate coating or cleaning tasks
- Develop information that would demonstrate why the spray drift phenomenon would not affect the 230 kV switchyard station post insulators 17
- 4.1 Introduction
- 4.2 Reactor Vessel Neutron Embrittlement
- 4.3 Metal Fatigue Analysis
- 4.4 Environmental Qualification of Electrical Equipment
- 4.5 Concrete Containment Tendon Prestress Analysis (not applicable to Columbia)
- 4.6 Containment Liner Plate, Metal Containments, and Penetrations Fatigue Analysis
- 4.7 Other Plant-Specific TLAAs 18
SER Section 4 Open Items SER Section 4.3 - Metal Fatigue OI 4.3-1
- Addressed the effects of the coolant environment on component fatigue life on a sample of critical components identified in NUREG/CR-6260
- The applicant's plant-specific configuration may contain additional locations that need to be analyzed other than those identified in NUREG/CR-6260 19
SER Section 4 Open Items SER Section 4.7.4 - Core Plate Rim Hold-Down Bolts OI 4.7.4-1
- Contrary to the original LRA the plant does not have core plate wedges
- The applicant had not selected one of the three options of 10 CFR 54.21(c)(1) to demonstrate its evaluation of the TLAA
- No AMR line item for the core plate rim hold-down bolts
- The applicant submitted a deviation from BWRVIP-25 inspection guidelines, which could result in inadequate management of the aging effect 20
SER Section 4 Open Items SER Section 4.2.2 - Upper-Shelf Energy OI 4.2-1 Applicant projected upper shelf energy (USE) for the N12 nozzle forgings to 54 EFPY, but did not justify:
- The initial USE of 62 ft-lbs
- The copper content of 0.27 percent Staff needs to verify acceptability of applicant assumptions to assess applicants analysis that the USE for the N12 nozzle will remain > 50 ft-lbs at the end of vessel life 21
SER Section 4 Open Items SER Section 4.1.2.9 - Fatigue Analysis of Polar Crane OI 4.7.5-1
- The applicant stated that the analysis for the crane does not meet the definition of a TLAA
- Crane is designed to CMAA No. 70, which has a design limit on the number of lifts. Therefore, the staff believes it meets the definition of a TLAA 22
Conclusion On the basis of its review and pending satisfactory resolution of the open items, the staff will be able to determine that the requirements of 10 CFR 54.29(a) have been met for the license renewal of Columbia Generating Station 23
Backup Slides 24
ASHE 230kV SUBSTATION COLUMBIA TRANSFORMER YARD 115kV 25
26 Drywell Head El. 598-8 Detail 1 Fuel Storage Pool El. 583-1/4 Detail 2 Bellow (8) - Inspection Ports
@ El. 570-0 Seal Plate El. 579-6 1/2 Detail 1 - Inspection Port Drywell Detail 2 - Refueling Bellows Seal Steel Plate (1 1/2 to 1 5/16 thick) 2 Thick Flexible Urethane Foam Detail 3 El. 446-0 Sand Filled El. 446-0 Pocket El. 435-3 El. 428-3 1/4 4 Sand Filled Drain Pipe Sand Filled Pockets *Vacuum every outage
- Inspection @ 28 day Containment Structure Valve frequency
- Boroscope examination in 2015 Detail 3 - Sand Drain and Closure 27