ML23325A021
| ML23325A021 | |
| Person / Time | |
|---|---|
| Issue date: | 10/18/2023 |
| From: | Advisory Committee on Reactor Safeguards |
| To: | |
| References | |
| NRC-2579 | |
| Download: ML23325A021 (1) | |
Text
Official Transcript of Proceedings NUCLEAR REGULATORY COMMISSION
Title:
Advisory Committee on Reactor Safeguards Fuels, Materials, and Structures Subcommittee Docket Number: (n/a)
Location: teleconference Date: Wednesday, October 18, 2023 Work Order No.: NRC-2579 Pages 1-153 NEAL R. GROSS AND CO., INC.
Court Reporters and Transcribers 1716 14th Street, N.W.
Washington, D.C. 20009 (202) 234-4433
1 1
2 3
4 DISCLAIMER 5
6 7 UNITED STATES NUCLEAR REGULATORY COMMISSIONS 8 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 9
10 11 The contents of this transcript of the 12 proceeding of the United States Nuclear Regulatory 13 Commission Advisory Committee on Reactor Safeguards, 14 as reported herein, is a record of the discussions 15 recorded at the meeting.
16 17 This transcript has not been reviewed, 18 corrected, and edited, and it may contain 19 inaccuracies.
20 21 22 23 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com
1 1 UNITED STATES OF AMERICA 2 NUCLEAR REGULATORY COMMISSION 3 + + + + +
4 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 5 (ACRS) 6 + + + + +
7 FUELS, MATERIALS AND STRUCTURES SUBCOMMITTEE 8 + + + + +
9 WEDNESDAY 10 OCTOBER 18, 2023 11 + + + + +
12 The Subcommittee met via Video 13 Teleconference, at 8:30 a.m. EDT, Ronald Ballinger, 14 Chairman, presiding.
15 16 COMMITTEE MEMBERS:
17 RONALD G. BALLINGER, Chair 18 VESNA DIMITRIJEVIC, Member 19 GREGORY HALNON, Member 20 JOSE MARCH-LEUBA, Member 21 ROBERT MARTIN, Member 22 DAVID PETTI, Member 23 JOY L. REMPE, Member 24 THOMAS ROBERTS, Member 25 MATTHEW SUNSERI, Member NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
2 1 ACRS CONSULTANT:
2 DENNIS BLEY 3 STEVE SCHULTZ 4
5 DESIGNATED FEDERAL OFFICIAL:
8 ALSO PRESENT:
9 JONATHAN BLACK, EPRI 10 ROB CHOROMOKOS, EPRI 11 DYLAN CIMOCK, EPRI 12 KURT CRYTZER, EPRI 13 ILYA GOLDBERG, EPRI 14 SAMUEL JOHNSON, EPRI 15 DAVE OLACK, EPRI 16 JEREMIE VARNAM, EPRI 17 RYAN WOLFE, EPRI 18 19 20 21 22 23 24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
3 1 C-O-N-T-E-N-T-S 2 Opening Remarks and Objectives . . . . . . . . . 4 3 EPRI Opening Remarks . . . . . . . . . . . . . . 7 4 Nuclear Aging Management and Corrosion 5 Monitoring Research . . . . . . . . . . . . . . . 10 6 Low and Medium Voltage Cables . . . . . . . . . 51 7 Resilience, by Rob Choromokos, EPRI . . . . . . . 93 8 Intakes and Heat Sink by Jonathan Black, EPRI . 129 9 Open Discussions, All . . . . . . . . . . . . . 150 10 Adjourn 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
4 1 P-R-O-C-E-E-D-I-N-G-S 2 8:30 a.m.
3 CHAIR BALLINGER: Good morning, everyone.
4 The meeting will now come to order. This is a meeting 5 of the Fuels, Materials, and Structures Subcommittee 6 of the Advisory Committee on Reactor Safeguards. I'm 7 Ron Ballinger, chairman of today's Subcommittee 8 meeting.
9 ACRS members present are Bob Martin, Dave 10 Petti, Dennis -- our consultant Dennis Bley, Greg 11 Halnon, Jose March-Leuba, Joy Rempe, and I expect 12 we'll be joined by others shortly.
13 MEMBER SUNSERI: Hey, Ron, this is Matt 14 Sunseri. I'm on.
15 CHAIR BALLINGER: Ah, okay. Well, I 16 probably missed -- sorry about missing Matt Sunseri.
17 I'll probably miss somebody else as well, but 18 hopefully we'll get that take care of.
19 MEMBER ROBERTS: Hey, this is Ron Roberts.
20 I'm on, too.
21 CHAIR BALLINGER: Gee whiz. I have my 22 list of participants that don't show you folks. Oh, 23 well. Some days you win, some days you lose.
24 Okay. Christopher Brown of the ACRS staff 25 is the designated federal official for this meeting.
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5 1 This is our fourth Subcommittee meeting 2 with EPRI this year. So far we have had a 3 Subcommittee meeting on the materials, reliability 4 issues, instrumentation control, and fuels. I might 5 add this is the last of the meetings. I might also 6 add that the Sharepoint site or the site on which the 7 slides for all of these meetings will be plus I guess 8 the transcripts constitute a wealth of information 9 related to the materials area and we expect that -- we 10 know that this will be very useful going forward in 11 committee reviews for -- committee reviews in general.
12 During today's meeting the Subcommittee 13 will receive a balance-of-plant information briefing 14 from EPRI. The Subcommittee will hear presentations 15 and hold discussions with EPRI and other interested 16 persons regarding this matter. I might also add that 17 when we have been doing subsequent license renewal 18 reviews very, very often the AMPs and things that are 19 in place related to subsequent license renewal often 20 are related to balance-of-plant issues. So while 21 they're not -- this presentation will not deal with 22 primary stress corrosion, cracking, and other primary 23 systems and things, it's very relevant for subsequent 24 license renewal.
25 This meeting is open to the public. The NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
6 1 rule for participation in all ACRS meetings were 2 announced in the Federal Register on June the 13th, 3 2019. The U.S. NRC public website provides the ACRS 4 charter, bylaws, agendas, letter reports, and full 5 transcripts of all full and Subcommittee meetings, 6 including slides. The agenda for this meeting was 7 posted there along with the MS Teams link. We have 8 received no written statements or requests to make an 9 oral statement from the public.
10 The Subcommittee will gather information, 11 analyze relevant issues and facts, and formulate 12 proposed positions and actions as appropriate. I also 13 might add that this is an information briefing. It's 14 not -- we're not expected to produce a letter related 15 to this. A transcript of the meeting is being kept 16 and will be made available.
17 Today's meeting is being held over 18 Microsoft Teams. There is also a telephone bridge 19 line as well as the MS Teams link allowing 20 participation of the public. When addressing the 21 Subcommittee the participants should first identify 22 themselves and speak with sufficient clarity and 23 volume so that they may be readily heard. When not 24 speaking we request that participants mute your 25 computer microphone or phone by pressing *6, otherwise NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
7 1 we get sometimes feedback and things like that.
2 We will now proceed with the meeting. And 3 I'd like to call on Kurt Crytzer to provide opening 4 remarks from EPRI.
5 Are you there, Kurt?
6 MR. CRYTZER: I am. Can you hear me?
7 CHAIR BALLINGER: Yes.
8 MR. CRYTZER: Okay. Wonderful. Thank 9 you.
10 Okay. Thank you for your time. My name, 11 as was mentioned, is Kurt Crytzer. I'm a senior --
12 (Audio interference.)
13 CHAIR BALLINGER: Yes, as I said, somebody 14 better mute something.
15 MR. CRYTZER: All right. Give me one 16 second. I want to make sure that -- okay. My name is 17 Kurt Crytzer. I'm a Senior Principal Team Lead within 18 the Plant Engineering Group within EPRI Plant 19 Engineering. Next we'll be part of the EPRI's Plant 20 Reliability and Resilience Program, which we'll talk 21 about on the next few slides.
22 My personal background, I've been in 23 nuclear since 2001. I've worked for Westinghouse, 24 I've worked for Duke, and currently work for EPRI. I 25 do manage the balance-of-plant group within EPRI and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
8 1 my technical areas of expertise right now are heat 2 exchangers and thermal performance.
3 We've put together a pretty thorough agenda, so 4 I won't spend too much time on my background, but 5 thank you so much for this opportunity.
6 So as I mentioned, we'll becoming Plant 7 Reliability and Resilience, and we're going to talk a 8 little bit about our research, which you can see is in 9 the area of components systems, which includes 10 maintenance and engineering. This also includes 11 process guides and best practices.
12 As we roll into one group; you've 13 mentioned Instrumentation Control has presented to you 14 in the past, we will all be under one program. We'll 15 cover active mechanical, which is rotating and moving 16 equipment; balance-of-plant and all passive mechanical 17 systems, which also includes thermal performance; 18 electrical, which includes medium and low-voltage 19 cables, switchyard relays, instrumentation and 20 control, which You're familiar with; and engineering 21 maintenance and processes. These would be something 22 like single point vulnerabilities or various 23 maintenance processes.
24 So really the whole idea of bringing 25 everybody together is to be able to cross-collaborate NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
9 1 on engineering and the subsequent maintenance that 2 goes along with components with systems.
3 We're aligning our research focus areas 4 with industry issues that we're seeing and hearing 5 about. So as you mentioned before, plant life 6 extensions, power outbreaks. Our research touches on 7 those.
8 Resiliency, both in climate, environment, 9 and social resiliency. So most recently supply chain 10 issues, but obviously the impacts of climate change on 11 ultimate heat sink. You'll be hearing some things 12 moving forward on that.
13 Efficient and intuitive access to EPRI 14 information. So to get the information out as cleanly 15 and as quickly to the end-user as possible in a manner 16 that is convenient, not only for those who have 17 English as their first language, but using 18 illustrations to have those who perhaps English is not 19 their first language access the information 20 conveniently. So we're making a real mindful approach 21 to doing that.
22 Risk-informed and graded approaches. And 23 then modernization, the use of data, both gathering 24 and data analytics, and online monitoring. So all 25 these will bubble up through Plant Reliability and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
10 1 Resilience.
2 So I have a team put together today that 3 will hopefully touch on topics of interest including 4 balance-of-plant corrosion, low and medium-voltage 5 cables, plant resilience, intakes and heat sinks. And 6 then we'll hopefully have a really good open 7 discussion on some of the research.
8 As just a point, please feel free to ask 9 questions or interject at any time during these 10 presentations.
11 So with that I'm going to introduce the 12 first set of speakers. I'll let them introduce their 13 backgrounds themselves, but the first presentation 14 that we have is on buried piping, cathodic protection 15 research activities. We also have a new flow-16 accelerated corrosion initiative along with this 17 presentation that we're going to be talking with. And 18 this will be Dylan Cimock; Dylan is a senior technical 19 leader within my group, Jeremie Varnam, and Sam 20 Johnson, who will be joining from NDE.
21 So with that I'll turn it over to Dylan 22 and let Dylan start it off. Dylan?
23 MR. CIMOCK: Good morning. Is my 24 microphone coming through okay?
25 All right. Good morning. So as Kurt NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
11 1 said, my name is Dylan Cimock, Senior Technical Leader 2 in the Plant Reliability and Resilience Group. And 3 for the last probably six, seven years I've been with 4 EPRI I've been leading a lot of our research 5 activities in the area of buried piping, cathodic 6 protection, and more recently on selective leaching.
7 Prior to joining EPRI I was with one of the nuclear 8 utility companies and primarily doing license renewal 9 work starting around 2009 until 2016.
10 Kurt, did you want to introduce the rest 11 or progress through?
12 Kurt, can you go to the next slide?
13 Okay. So in addition to the research 14 activities that we do in buried piping and cathodic 15 protection one of the other areas of responsibility 16 that we often have for many of these topical areas is 17 managing a number of industry-wide user groups.
18 Specifically I've been involved with our Buried Piping 19 Integrity Group, BPIG. So it's a group of utility 20 engineers mostly associated with buried piping program 21 owners, cathodic protection system engineers. We have 22 an annual meeting once a year where we have probably 23 about 100 attendees, anywhere from maybe 40 to 50 24 utility people and 50 to 60 members from either NRC 25 staff, INPO, as well as technology suppliers and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
12 1 vendors.
2 I thought I would maybe highlight a few of 3 the topics that we've been hearing about recently at 4 our annual BPIG meetings. So the three topics here:
5 one is on selective leaching degradation, specifically 6 as it applies to cast iron components. The other 7 topic we've seen presented a lot and discussed in the 8 industry has to do with different internal pipe repair 9 methods using non-metallics, things like carbon fiber 10 composites, cured-in-place piping, spray-in-play 11 piping. And then the third topic is cathodic 12 protection. A lot of discussion around performance 13 and reliability issues, system overhauls and 14 replacements, and some of the EPRI resources and 15 activities that we have available for the industry on 16 that.
17 Next slide? The first one we'll talk 18 about is selective leaching and some of the research 19 that we've been doing on this. So we've mentioned to 20 start this that there are a lot of aging management 21 programs in the BOP space that are coming through for 22 license renewal and second license renewal, and one of 23 those is the selective leaching AMP.
24 I'm not sure how familiar everyone is with 25 it, but selective leaching is a specific form of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
13 1 corrosion where one element of an alloy is 2 preferentially removed. It's also referred to as de-3 alloying. And the unique aspect of this is even 4 though the material is losing material, it may not 5 necessarily undergo any changes in dimension or shape.
6 So visually the component will look to be in near 7 nominal or completely satisfactory condition even 8 though it has actually lost some amount of material 9 and have some inflamed graded material properties in 10 the affected region.
11 So some of the materials that are 12 susceptible that we commonly find in nuclear power 13 plants and documented in both the GALL, GALL SLR, and 14 even IAEA IGALL report is grade ductile cast irons, 15 aluminum bronze with more than eight percent aluminum, 16 and then other copper alloys with at least 15 percent 17 zinc.
18 And some of the systems that we commonly 19 find these materials in, a lot of them are in the fire 20 protection systems with some as well in the Service 21 water condensate systems, and then even in some of the 22 cooling water aspects of the emergency diesel 23 generator, and sometimes even safety-related systems 24 like auxiliary feedwater.
25 So the picture on the right is an --
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14 1 DR. BLEY: Dylan, this is Dennis Bley.
2 MR. CIMOCK: Yes?
3 DR. BLEY: I've heard of this, but I'm not 4 completely familiar with it. Since this structure 5 hangs together and probably on the inside looks pretty 6 good for a long while through this process, what kind 7 of failure modes do we get? Is it sudden holes in the 8 pipe, or what's it look like when this leads to 9 failure?
10 MR. CIMOCK: Good question. It varies 11 based on the material. So with cast iron what we have 12 seen is oftentimes it will result in a crack of the 13 pipe, either circumferentially or even spiral and 14 longitudinally down the pipe typically emanating from 15 an area that's affected by the leaching. We have seen 16 other cases where the leaching actually penetrates 17 full through-wall. And then during some sort of a 18 system surge it actually kind of blows out a graphite 19 plug and it will leak. So those are the two 20 mechanisms that we see often with cast iron.
21 With the copper alloys they tend to kind 22 of weep, so it's kind of a porous microstructure that 23 eventually goes through a wall and water slowly kind 24 of migrates and diffuses through and begins to weep 25 out.
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15 1 But the picture on the right, that's an 2 example of a 12-inch diameter cast iron pipe that 3 experienced selective leaching. So the photo on the 4 left is actually after we wire-brush cleaned it and it 5 appeared to be in pretty much near nominal condition, 6 completely smooth, no indications of any form of 7 material loss. And after we had completed doing some 8 of NDE exams we subjected it to an abrasive sandblast.
9 And the extent of wall thinning there in the photo on 10 the right probably ranges anywhere from about 30 to 50 11 percent through-wall and there were some localized 12 areas, as much as 70 percent, through-wall, none of 13 which was seen during the initial exams.
14 Kurt, next slide? So why is it important?
15 It is a slow-acting mechanism so as plants continue to 16 operate beyond their original 40-year lives out to 60 17 and 80 years of operation, this form of degradation 18 composed a greater threat to the plants and to the 19 components. Many of the utilities have gone through 20 the license renewal and now second license renewal 21 processes or beginning to implement aging management 22 programs specifically for this.
23 And the recommendations for the quantities 24 of inspections have kind of gone up through the 25 progression of the original GALL, GALL Rev. 0, Rev. 1, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
16 1 Rev. 2. And so some of the utilities have been faced 2 with an increase in quantity of inspection sometimes 3 in the hundreds of inspections. So it's becoming a 4 kind of costly endeavor to manage this as well. Some 5 of them upon discovery of adverse findings have had to 6 implement periodic programs. And I'll talk about the 7 inspection difficulties a little bit on the next 8 slide.
9 DR. BLEY: Dylan, Dennis again. Have 10 there been any observed failures in the first 40 years 11 of operations from this mechanism?
12 MR. CIMOCK: I believe so. I don't have 13 a specific reference for it, but yes, I believe so.
14 CHAIR BALLINGER: This is Ron. One of my 15 other hats was as a corrosion consultant and I can 16 tell you that there have been many failures related to 17 this in the past.
18 MR. CIMOCK: Yes, it's also not unique to 19 the nuclear industry. We have a lot of cast iron 20 infrastructure in our water municipal infrastructure 21 and gas transmission pipelines, so this is not 22 something specific to the nuclear industry. A lot of 23 our buried infrastructure has been dealing with this 24 for many years.
25 CHAIR BALLINGER: Yes, this is Ron again.
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17 1 I have a house that's built in the early 1800s and it 2 had cast iron pipe for its heating system, hot water, 3 and I removed it to replace the heating system. And 4 one way to remove it is to take a ball-peen hammer and 5 just whack the elbows. And because of the selective 6 leaching graphitization the pipes would just fall 7 apart.
8 MR. CIMOCK: Yes. So this picture here is 9 kind of an example. You can see in the cross-section 10 of a valve body as -- the leaching is kind of 11 progressing its way through the thickness of that 12 component even though the dimension kind of remains 13 intact. So you can kind of see a darker gray area 14 where it's mostly graphite, and then even the red.
15 It's kind of oxidizing as it progresses through the 16 component wall thickness.
17 All right. Kurt, next slide? So some of 18 the challenges that we've been observing in the 19 industry from the standpoint of implementing these 20 aging management programs: One is just general 21 knowledge and training. It's not a really well-22 understood or even known about mechanism, so the aging 23 management program owners that inherit it don't 24 necessarily start off knowing a whole lot about it.
25 There's also been some questions about NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
18 1 when implementing a sampling-based inspection program 2 how to maybe go about choosing your components or 3 locations for inspecting based on things like severity 4 of the operating environment, relative susceptibility.
5 And then from a technique perspective I 6 mention that visual exams have definitely been 7 challenged by being able to adequately detect the 8 mechanism. GALL Rev. 2 introduced hardness testing as 9 an alternative and that has had somewhat mixed 10 results. Some components, their size and shape are 11 just not conducive to using portable hardness testers.
12 On the other hand, some have had success using that as 13 a detection-based technique. You'll find that the 14 leached areas exhibit a reduction in hardness, but it 15 doesn't necessarily tell you anything about the depth 16 of penetration.
17 And particularly until recently there 18 hadn't really been some objectively demonstrated NDE 19 techniques for leaching, and this has led to a lot of 20 utilities implementing a process of relying on 21 destructive examinations, sometimes just proactively 22 going in, selecting a component, removing it from 23 Service, and cross-sectioning it and looking within 24 the cross-sectional area for any evidence, which while 25 effective isn't necessarily the most efficient.
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19 1 Next slide, Kurt? So from an NDE 2 perspective we've been looking into this matter for 3 some time. We started off back in 2009 issuing a 4 couple of reports that initially showed some promise 5 for ultrasonics and electromagnetic techniques. The 6 problem was we were somewhat limited in the 7 availability of samples that we had to test on and 8 some of the field testing that we did do wasn't 9 necessarily fully conclusive.
10 So we followed that up with looking at 11 some additional techniques in 2016, but really 12 beginning in about 2019 or 2020 we put a more 13 concerted effort into trying to procure some field-14 removed samples exhibiting more significant amounts of 15 selective leaching. And we were lucky that we had a 16 number of utilities volunteer some removed components 17 in the form of both valve bodies as well as piping.
18 And that's really what's led to some of the progress 19 that we've seen over the last couple years in the 20 three most recent reports in 2021 and this year.
21 Next slide, Kurt? So in 2021 we published 22 two what we call technical briefs. These aren't full 23 EPRI technical reports. They were actually designed 24 in Microsoft PowerPoint, full of lots of images, 25 graphics, and a lot shorter text descriptions so that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
20 1 the reports were NDE-based, but maybe a little bit 2 easier to digest by the typical system program 3 engineer.
4 But the first one we documented the 5 results and the successes that we had using three 6 different ultrasonic techniques to detect selective 7 leaching inside of gray cast iron valve bodies. So 8 those exams were performed from the outside surface of 9 a valve body that was relatively clean looking for 10 degradation initiating from the inside surface.
11 The second project we look at four 12 different electromagnetic techniques to examine gray 13 cast iron piping. It included three techniques from 14 the outside surface and one technique actually applied 15 from the inside surface of the pipe.
16 And I'll pause. I think I just saw a hand 17 up.
18 CHAIR BALLINGER: No, that was a mistake.
19 MR. CIMOCK: Okay. So based on the 20 results of the electromagnetic techniques we did 21 publish an update and a more thorough EPRI technical 22 report earlier this year. It includes a lot more 23 detailed analysis of the original four techniques that 24 we used on each of three different piping samples.
25 And then we looked at two additional techniques in NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
21 1 2022.
2 And just to give you guys kind of an idea, 3 Kurt, if you'd go to the next slide, a lot of people 4 are familiar with ultrasonics, but electromagnetic 5 techniques not necessarily as much. So this is just 6 some examples of what these slides -- or I'm sorry, 7 these tools look like. So the first four techniques 8 that we evaluated were pulse steady current, low-9 frequency electromagnetic technique, LFET, a through-10 transmission bracelet probe, and then the internal 11 remote field testing. So this is a tool that can be 12 pulled through the inside of the pipe and detect 13 degradation on either the inside or outside surface.
14 And then the second two techniques are magnetic flux 15 leakage and saturation eddy current.
16 Next slide?
17 DR. BLEY: Can I ask two quick questions?
18 Dennis Bley again.
19 MR. CIMOCK: Sure.
20 DR. BLEY: The one you showed on the last 21 slide where you can pass that through the inside of 22 the pipe certainly makes testing easier. Is it 23 reasonably effective? How does it stack up with the 24 others? And related sort of, you've mentioned valve 25 bodies several times. Are the valves more susceptible NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
22 1 or it's just a place that's obvious to check because 2 of the bends or connections associated with it?
3 MR. CIMOCK: So I wouldn't say the valve 4 bodies are necessarily more susceptible. They're just 5 part of a component population. Often what we see is 6 they represent a component that can maybe be more 7 easily removed from Service and replaced or perhaps 8 they have other issues such as properly seating and 9 sealing just do to raw water debris build-up. And so 10 they're proactively replaced due to isolation concerns 11 and then they're opportunistically evaluated for 12 selective leaching at the same time.
13 But from a detection point of view this is 14 some examples of what the qualitative view of the 15 results look like. So again on the left is the pipe 16 sample that we did the abrasive sandblast on. The 17 image next to it is actually what's called laser 18 profilometry. It's a technique to basically scan the 19 surface of a component and measure kind of the 20 contour, the surface of it. So it's not actual wall 21 thickness measurement, but rather a surface contouring 22 temperature.
23 The next are our qualitative images of the 24 corrosion maps generated for each of the first four 25 techniques.
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23 1 DR. BLEY: Are these all of the same pipe 2 section?
3 MR. CIMOCK: That is correct. So when we 4 initially collected the data the pipe was not 5 sandblasted. We had no indication of any degradation 6 present on the pipe. But each of the four techniques 7 showed us that there was something going on in the 8 pipe, some indication of wall thinning and it was 9 being displayed in kind of a consistent pattern, 10 shape, and location on the pipe. And that's what led 11 us to doing a destructive evaluation on one of those 12 pipes to confirm those findings.
13 So next slide, Kurt? So where we're kind 14 of at from an NDE point of view, with cast iron 15 components we demonstrated three different ultrasonic 16 techniques for when the degradation is occurring on 17 the opposite surface from the exam and six different 18 electromagnetic techniques, all commercially available 19 that can be used on piping.
20 One of the outstanding gaps that we still 21 have is that ultrasonics are still challenged when the 22 exam is performed on the same surface that the 23 leaching is progressing from. The material just seems 24 to be kind of porous in nature and difficult to get 25 the ultrasonic energy to couple into the piping NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
24 1 material and get a back wall response. So we're still 2 having challenges with coming with an ultrasonic 3 technique for that application.
4 With copper zinc alloys we see this mostly 5 in small valves as well as some heat exchanger tubing.
6 And unfortunately we haven't really had any field-7 removed tubing known to have selective leaching that 8 has allowed us to do some objective demonstrations on 9 eddy current testing, but what we have seen is some 10 industry operating experience which indicates that the 11 utilities have had success in detecting it either 12 directly or in any pitting that results from the 13 leaching.
14 Aluminum bronze is the third material type 15 and the industry has had some successes in developing 16 and advancing techniques like time-of-flight 17 diffraction and even phased array testing for that 18 material type for certain component geometries.
19 But based on the results that we've seen 20 as well as the industry operating experience we did 21 provide a recent comment during the open comment 22 period for NUREG-2191, Rev. 1, the GALL SLR update.
23 So we did provide a comment I believe it was last week 24 recommending that the NRC staff consider the results 25 of this research, the industry operating experience, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
25 1 and possibly include NDE as a viable option in the 2 XI.M33 selective leaching AMP. What we're seeing is 3 that these are more or less field-ready techniques and 4 offering a lot of advantages from a detection 5 capability as well as the surface area component that 6 can be examined.
7 Yes, Dennis?
8 DR. BLEY: Sorry. I couldn't get my mic 9 open. I was just wondering, quite a few -- well, 10 almost everybody now has aging management programs and 11 this sounds really arduous in time spent, not just 12 testing, but digging up the pipes so you can see it.
13 Has any of the licensees decided over the time they 14 expect to operate it's not worthwhile and begun 15 switching over to non-suspectable materials?
16 MR. CIMOCK: Yeah, they have. Sometimes 17 it's kind of informed based on results that you have.
18 If You're not finding a lot, you may elect to stick 19 with what you have. But if based on the inspections 20 you begin to see issues, utilities have absolutely 21 begin to implement a process of either replacing the 22 material with perhaps like-for-like material but extra 23 coatings on the inside of valves or improvement 24 materials like high density polyethylene or just a 25 material not susceptible to selective leaching. So NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
26 1 it's a little bit more on a case-by-case basis.
2 MR. BLEY: Okay. Thank you.
3 CHAIR BALLINGER: Yeah, this is Ron 4 Ballinger again. This kind of sheds a little bit of 5 light on what we see in SLR. A lot of times when it 6 comes to buried piping and the like, applicants have 7 simply resorted to basically digging things up at 8 locations which they, in their judgment, feel that 9 they would be susceptible as opposed to using some of 10 these inspection techniques.
11 MR. BLEY: Yeah, Ron, that's why I asked 12 that question. I seem to remember 10 or 15 years ago 13 as we were looking at license extension. Quite a few 14 people were opting to go susceptible materials. And 15 I didn't have any idea how far that's progressed.
16 MR. CIMOCK: Was there a question?
17 MR. BLEY: No.
18 MR. CIMOCK: Okay. Could you go to the 19 next slide? So I just want to highlight the materials 20 uses one are that we've been looking at from the 21 perspective selective leaching research. We have put 22 out a state of the art report to try to improve the 23 level of knowledge and understanding on the mechanism.
24 We did do a project that we published in 25 2021 where we've looked at a literature review on NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
27 1 factors affecting susceptibility, including some 2 limited lab studies. And we're currently 3 collaborating with one of the national labs on 4 furthering that research. We also have a report 5 coming out just in probably another week or two from 6 general programmatic guidance on implementing these 7 programs.
8 We put out training. And then we've also 9 done pilot studies on the selective leaching as part 10 of the larger EPRI and industry effort on leveraging 11 risk insights for aging management. So next slide, 12 Kurt. So we'll touch a little bit more briefly on 13 some of the non-metallic repairs that we've been 14 seeing used in the industry. Kurt?
15 This would include materials like high 16 density polyethylene, carbon fiber reinforced polymer 17 or CFRP, and spray in place pipe lining. So I don't 18 know how much you've guys have seen this. But we have 19 observed a lot of utilizes moving towards 20 rehabilitating buried pipes, particularly large 21 diameter using CFRP.
22 So it's essentially woven carbon fiber 23 fabrics saturated a polymeric resin and then hand 24 applied inside of the pipe. Because it's hand 25 applied, the diameters usually required manned entry, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
28 1 so greater than 30 inch. When they're designed, they 2 can be either designed to simply reinforce the 3 existing pipe or they can actually be designed such 4 that the pipe really just serves as a form to install 5 the system.
6 And once fully installed and cured, the 7 carbon fiber composite actually is the new pipe that's 8 credited with taking all structural and pressure 9 loads. And the host pipe doesn't rely upon any more 10 with the exception of what's called the terminal lens.
11 This is the end of the composite repair.
12 And those terminal ends are what's 13 credited with transferring the loads between the 14 repaired and unrepaired regions. So the lower right-15 hand corner, you can kind of see what a cross section 16 of these composites look like. You have a steel 17 substrate there at the very bottom of that. The black 18 layers are five layers of carbon fiber fabric 19 sandwiched between the blue epoxy resin after it's 20 been fully cured. So we can see this used a lot in 21 pipes that are larger diameter, buried deeper into the 22 ground, and where it might not be very economical to 23 actually excavate and replace all this large diameter 24 pipe due to the depths that it's at and underneath 25 other buried assets.
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29 1 MR. HALNON: What's the thickness in that 2 lower right corner?
3 MR. CIMOCK: That one there is probably 4 around 0.6 inches.
5 MR. HALNON: Okay, thanks.
6 CHAIR BALLINGER: Does this complicate 7 inspection down the road? Or does it basically 8 eliminate the requirement for inspection?
9 MR. CIMOCK: Largely, it eliminates the 10 requirement for inspection as basically a new pipe.
11 The one exception has been the ASME code case that's 12 in development for carbon fiber composites. The N-13 871-2 that's in progress right now, it has introduced 14 some volumetric requirements at these terminal ends to 15 ensure that degradation doesn't continue to progress 16 on the back side of the original pipe. If it's 17 strictly reinforcement, then yeah, there is still a 18 concern about monitoring the degradation beneath that 19 composite. So Kurt, next slide.
20 (Simultaneous speaking.)
21 MR. CIMOCK: -- right now is spray in 22 place polymeric linings. So using robotics to spray 23 in basically a polymeric lining solution. It's not 24 necessarily new, but what is new is the fact that 25 these are now being installed at a much higher dry NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
30 1 film thickness, somewhere on the order of about a 2 tenth of an inch up to a quarter of an inch.
3 And they're using new polyuria resins 4 which offer significantly faster curing times. Kurt, 5 next slide. So some of the research that we've been 6 doing on carbon fiber, we published a report last year 7 actually on NVE of the metallic substrates beneath the 8 CFRP to your point. So previously, these were too 9 thick and too attenuative for conventional 10 ultrasonics.
11 But we did identify two different 12 techniques that can still penetrate through that 13 carbon fiber and measure the remaining substrate 14 thickness. We have an ongoing project ran out of our 15 NDE group by Sam Johnson who's on this call related to 16 NDE of the carbon fiber composite system itself. And 17 we continue to score ASME code case every quarter and 18 include and identify any potential research gaps for 19 follow up.
20 With the SIPP solution, we have a report 21 coming out in a couple weeks looking at kind of 22 technology landscape assessment and the gap assessment 23 against using SIPP in the nuclear industry. And we're 24 working with the utilities on developing guidance on 25 testing and qualification of these systems for slake NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
31 1 related piping, including solicitation of interest in 2 using SIPP as a fully structural repair methodology 3 and what material properties need to be developed in 4 order to continue progressing that. Next slide. So 5 particularly with the CFRP, I wanted to note that we 6 have been working collaboratively with members of the 7 NRC staff on some common areas of interest with 8 respect to research gaps on carbon fiber.
9 And we actually held a workshop this past 10 July including members of the staff, national labs, 11 universities, and some NDE technology suppliers and 12 CFRP designers and installers. And currently right 13 now, both NRC staff and EPRI have two independent 14 projects where we're looking at the NDE of the 15 composite systems. So we've been collaborating on 16 understanding kind of the flaw types and sizes that 17 are of interest, the NDE technologies that are out 18 there that might work, and then setting up the 19 fabrication of actually mock-ups. So that's some work 20 in progress going on right now and into next year.
21 Next slide. So with that, I'm going to turn things 22 over to Jeremie.
23 MR. VARNAM: Thanks, Dylan. Can I do a 24 mic check?
25 MR. CIMOCK: Yeah, You're good.
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32 1 MR. VARNAM: Thank you. So I'm Jeremie 2 Varnam. I'm a senior technical leader at EPRI, 3 approaching my one-year anniversary with joining the 4 team. My career in nuclear started in the mid-2000s 5 with Progress Energy at the time. And then I've also 6 spent a good portion of my career in the consulting 7 world, mainly in the realm of chemistry and chemical 8 engineering.
9 I currently have some leads with working 10 with heat exchangers and condensers. But also I've 11 held out with some backup poles and buried pipe in 12 which one of the projects we're talking about here 13 with slake detection using ERT and also serving as a 14 backup in the area of flow accelerated corrosion.
15 Next slide. This is a conceptual measurement of the 16 electrical resistivity tomography application.
17 This concept was originally used at the 18 Hanford site where there's an electrical current that 19 is injected into their subsurface. And they use a 20 near tank well work casing that has an electrode. And 21 then they measure the corresponding electrical 22 potential within the tank. So as you start developing 23 a leak near the tank casing or around the tank, the 24 electrical connectivity of the soil in that vicinity 25 is altered.
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33 1 And you essentially get a change in the 2 electrical potential within the tank. Essentially, 3 this concept has been adapted using an array of cost 4 effective electrodes. So the ERT measurement 5 essentially requires four electrodes that you put in 6 direct contact with the subsurface or the soil.
7 So you start out with applying a current 8 between the positive and negative current electrodes.
9 So essentially, now you've got a source that's 10 considered a battery. And the current source is a 11 potential gradient in the subsurface which causes the 12 flow from the positive to the negative electrode.
13 We could measure that current conceptually 14 using an ammeter. And then we have two other 15 electrodes that are used to measure the potential in 16 the ground induced by the current source. And we do 17 this by essentially connecting the positive and 18 negative leads to a voltmeter to those electrodes and 19 measuring the voltage.
20 And this you simply use here with the four 21 electrodes, this ERT measurement. It's simply the 22 voltage normalized by the current. And we call this 23 transfer resistence.
24 So essentially, we're taking this 25 application here and we're applying it to many NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
34 1 electrodes and many measurements in the ERT system.
2 But it makes a very simple system that makes ERT 3 robust, customizable, and applicable to pretty much 4 any scale where you can reasonably connect a series of 5 wires and electrodes and get them into the soil. Next 6 slide. So for this project, we wanted to develop an 7 autonomous technique for monitoring leaks in buried 8 pipe and tanks to allow for early identification.
9 Not only with early identification being 10 important particularly with lines that may contain 11 radioactive fluids, but also being able to narrow 12 down, like, the portion of piping that would be 13 required for excavation. As far as our current 14 research activities, the project commenced with a 15 Phase 1 feasibility study where we essentially with 16 that modeling technique to see if ERT could be a 17 viable approach to use in our nuclear fleets. And 18 then we've recently completed Phase 2 and published 19 those findings this year where a small pilot was 20 conducted using the PNNL.
21 It was conducted at a BWR site where they 22 had their Service water piping discharge in a facility 23 that contains both saltwater and freshwater type 24 sources. In this project here, we did simulated leaks 25 of both saltwater and freshwater components. And we NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
35 1 were able to distinguish these leaks from major 2 rainfall events that occurred during the demonstration 3 period.
4 So with appropriate electrode spacing, 5 essentially we can minimize the area that would 6 require excavation to be minimized from a risk 7 standpoint. Next slide. This is the demonstration 8 setup. This considered the Setup No. 1 where we put 9 the -- the electrodes were buried about six inches 10 beneath the surface and spaced in between four 11 discharge lines for circulating water discharge.
12 There was a leak simulation tube. Look at 13 the photo on the right highlighted in the yellow 14 circle. That was our leak simulation tube that we put 15 on top of the pump bravo discharge line.
16 What we found out and I'll discuss these 17 results later is that this particular space in here 18 that was utilized, the lines were not close enough to 19 the leak source. As you move away from your leak 20 source, the sensitivity to detection decreases. But 21 this was the initial set up here that was deployed at 22 the site.
23 The ERT instrument and the control 24 computer, these components were stored inside in one 25 of the pump houses. So we completed two leak NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
36 1 injection tests, one using potable water which was 2 around 388 microsiemens per centimeter and then also 3 using the nearby canal water which has a conductivity 4 of greater than 3,000 microsiemens per centimeter.
5 The injection rate was set to approximately one gallon 6 per minute, and the ERT survey time which was the time 7 to pulse between the four series of electrodes is 8 about 20 minutes.
9 This test was conducted over the course of 10 two days where day one was about 170 gallons or 11 approximately three barrels of canal water used and 12 then followed by 2,000 gallons of a potable water 13 flush. And then day two was more the agility type 14 testing where we started with 57 gallons of barrel 15 water near discharge pipe C and 278 gallons of canal 16 water on pipe B. Essentially what we found there in 17 this first leak test was that the electrodes were too 18 far away from the leak.
19 Looking into the failure of this, it was 20 a design mistake based on incorrect assumptions and 21 lessons learned. So what could be done here is prior 22 to deploy the ERT technology is looking at doing 23 baseline measurements. So you have an understanding 24 of the background soil conductivity and use a 25 sensitivity study so you can help develop a map of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
37 1 sensitivity away from the components of interest, 2 whether it be a tank or a pipe to help with selecting 3 appropriate electrode placement.
4 So that was done after this first leak 5 injection test here. And if you'll get to the next 6 slide, Kurt, the electrodes were moved closer toward 7 the -- to be over top of the discharge pipes, and in 8 this case here, closer towards the leak injection 9 pipe. So these temporary surface electrodes, when you 10 use two lines of the eight electrodes each at about 11 one meter spacing, again, we use the same water 12 sources and potable water with a lower content in 13 canal water essentially being saltwater.
14 Use similar injection rates. And this 15 time, the ERT survey time required, we reduced down to 16 ten minutes. And for this test sequence, we used 17 approximately 100 gallons each of the potable water 18 source and of the canal water.
19 And the results were extremely promising 20 as shown on the next slide. You can start these 21 animations here. On the left-hand side is the potable 22 water, and on the right-hand side is the canal water.
23 And essentially what we were able to do 24 with these simulations is even with the potable water 25 at a very low connectivity, the leak was identified NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
38 1 after approximately 15 gallons were injected into the 2 soil. For the canal water which has a much higher 3 connectivity, the leak was identified after 4 approximately ten gallons. You see with these visuals 5 here, this data could be fed in to the software that's 6 utilized and help develop tomography of the area.
7 So again, this are extremely promising 8 results for this demonstration here. Your next steps 9 are to put the technique through some of its paces, 10 looking at influences from a cathodic protection 11 system and also assist in other issues which could be, 12 how does it work around non-insulated reinforced 13 concrete? Or in the presence of grounding grids, are 14 there other seasonal variations that need to be 15 considered beyond like heavy rainfall events, 16 particularly in regions that may contain a lot of 17 (audio interference) surface if sod is used. So 18 there's still some gaps that we're looking to do with 19 Phase 3. But the Phase 2 results show that with 20 appropriate sensitivity studies in advance, the plain 21 electrode placement, this is an extremely viable 22 technology to identify leaks that occur extremely 23 early and at low rates.
24 MR. CIMOCK: All right, Jeremie. Thank 25 you. So real quick and just for the sake of time I'm NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
39 1 going to touch on a few of the reports and research 2 that we've been doing around the cathodic protection 3 tanks. So Kurt, if you can go to the next slide.
4 Kind of summarize CP and what we're seeing in the 5 industry as kind of issues that maybe falls under 6 three different categories.
7 One is just general training and 8 knowledge, understanding how cathodic protection 9 works. Second is applying CP inside nuclear 10 facilities is immensely more complicated than was 11 commonly done inside the gas transmission pipeline 12 industry. We have a lot of pipes in close proximity.
13 They are crossing one another at different 14 depths. They are different materials. And they are 15 all electrically bonded together and connected to the 16 station grounding grid which is uncoated and more 17 favorable for CP than the steel piping that's 18 typically there.
19 And so trying to apply CP in such a 20 complex facility is complicated from trying to balance 21 areas that are overprotected to under protected in 22 getting it to the assets that need it everywhere. And 23 then the third challenge really stems from simple 24 maintenance prioritization with CP. At the end of the 25 day, it is not a safe-related system.
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40 1 It doesn't affect generation, and it 2 doesn't result in any LCOs when it's not performing 3 correctly. So from simply a prioritization issue, it 4 is a lower priority system. But to address a lot of 5 these gaps, we hasn't done some research historically 6 developing thorough guidance on how to manage the 7 system.
8 We've developed training that we are 9 actively upgrading this year and into next to try to 10 get the training into the hands of the engineers 11 sooner. And then we've also looked at developing 12 software for the industry to use to help with managing 13 their data and trimming it to forecast the need for 14 systemwide upgrades. So right now, it's a little bit 15 less research oriented and more in training an 16 knowledge transfer and retention.
17 And from a tank perspective, Kurt, if you 18 go to the next slide, we have published a couple of 19 reports on tank inspections. One is guidance for 20 performing tank inspections and different types of 21 tanks including above grade and buried tanks. And 22 then we've also looked at different NDE techniques and 23 methodologies.
24 A lot of what we're seeing, the industry 25 interest in right now is underwater inspections of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
41 1 tank floor plates for above ground storage tanks whose 2 bottoms sit on the soil. There's often a lot of 3 challenges with trying to coordinate draining of these 4 tanks and performing inspections. So being able to 5 perform them using robotics underwater is highly 6 desirable.
7 And there have been some vendors offering 8 these services. And we have evaluated some of these 9 techniques in the past and the report referenced 10 there. But we'll also continue to do some research 11 here looking at techniques like guided way to look at 12 the bottom of the tank floor plates from the outside 13 surface and possibly some reference guides about 14 different technologies, different deployment options 15 for each of the different types of tanks, above ground 16 storage, buried tanks, indoor horizontal cylindrical 17 tanks.
18 So different techniques for different 19 applications and from different services that they're 20 applied from. And so that's another project that 21 we'll be trying to pull together as more of, like, a 22 reference and resource guide for both engineering and 23 NDE personnel. So with that, next slide. Jeremie, 24 this is back to you.
25 MR. VARNAM: Thanks again, Dylan. This NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
42 1 next project was following a finding from one of our 2 utility members from one of their inspections related 3 to a wall fitting on a feedwater bypass line which is 4 this is a line that comes off one of the main 5 feedwater lines that is in operation less than 2 6 percent time of the year as considered a stagnant 7 location. So Kurt, if you kind of clip through, it'll 8 bring up some of the text and the highlighting here.
9 But essentially, what one started with was 10 an inspection of the Charlie feedwater bypass line.
11 This line was inspected following some questions by 12 one of the newer system engineer at this particular 13 site where they were questioning as the 14 inch line 14 that comes by for the charted line is a non-15 susceptible material. So it's P22 chrome alloy 16 material.
17 And then the Charlie bypass line is a 18 susceptible material, carbon steel. So there's some 19 questions on whether or not there could be an inverse 20 effect having to go from a non-susceptible to a 21 susceptible material. So there known specs in history 22 as these bypass lines were categorized as non-23 susceptible as they are in operation for less than 2 24 percent operating time.
25 The findings were unexpected where the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
43 1 actual thickness was 100 mils versus a coded mil of, 2 excuse me, 213 mils. So this led to some scope 3 extension for the alpha and bravo bypass lines. And 4 the metal and thicknesses identified there were even 5 lower where the alpha bypass line having a thickness 6 of 52 mils and bravo having a thickness of 92 mils.
7 These bypass lines were emergently 8 replaced with a P22 chrome alloy material which allow 9 for some examinations of these specimens. And all of 10 these bypass lines exhibit a rippled or an orange peel 11 surface which is pretty consistent with single phase 12 flow accelerated corrosion. There were --
13 CHAIR BALLINGER: This is Ron Ballinger 14 again. That minimum thickness, how close were they to 15 rupture?
16 MR. VARNAM: I'm not sure if we had that 17 information from the utility as far as what kind of 18 burst criteria would've been with that wall thickness.
19 Ryan Wolfe is also on the phone. He's our fact lead 20 here. Ryan, do you have any additional insights if 21 that information was shared?
22 CHAIR BALLINGER: I'm reminded of the 23 incident they had in Japan at Miyajima where they did 24 have a rupture. And 52 mils, boy, that seems pretty 25 close.
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44 1 MR. VARNAM: It does. But yeah, I'm not 2 sure how that was in relation if there was any formal 3 evaluation. At least I'm not aware of one that was 4 shared.
5 MR. WOLFE: Yes, this is Ryan Wolfe. I'm 6 a technical executive at EPRI in the area of balance 7 of plant and also flow accelerated corrosion. I'm not 8 aware either of an evaluation that was done regarding 9 a week before break of this particular defect.
10 CHAIR BALLINGER: Thanks. I just thought 11 maybe somebody would have it. Seems awful thin.
12 MR. VARNAM: The next slides show some of 13 the visuals from one of the specimens that was 14 removed. So the utilities actually did contact EPRI 15 and coordinated with our Checkworks users group 16 advisory committee to help define the extended 17 condition. So the factors that were looked at were 18 operating time, erosion and leak by.
19 Those were eliminated as likely not 20 factors. Interest effect and water chemistry were 21 assessed. And while they may have been factors, there 22 was not enough history for certainty.
23 The area of high interest that warranted 24 additional investigation that led to our project were 25 looking at flow conditions. So we did decide to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
45 1 tackle this using a computational fluid dynamics as a 2 project. Next slide, Kurt. So to help determine 3 whether in fact thinning was the likely cause of this 4 wall thinning here, we did deploy computational fluid 5 dynamics.
6 One of the things that we want to also 7 inform is whether or not similar effect thinning of 8 those lines could occur at other plants and wanted to 9 change to the EPRI guidance. So what we're looking to 10 do here beyond the model of the actual plant 11 conditions is also doing a variety of parametric 12 studies to help characterize different conditions of 13 these branch bypass line connections. Next slide. So 14 some of our preliminary results are shown here.
15 So on the right-hand side is an animation 16 showing all the velocities. One thing that we, early 17 on as we were setting up the model, noticed that we're 18 not getting a monotonic convergence at residuals. So 19 we're really dealing with a very unsteady state here.
20 So instead of being able to look at potentially, like, 21 1.0 time as determining the resonance time to the 22 system here and taking an average of results to the 23 system.
24 But essentially, this system was modeled 25 here. We started with the initial boundary at the 18 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
46 1 inch lines. The two 18 inch lines feeding into a 2 common 14 inch header.
3 The three 14 inch lines are the feedwater 4 lines. And then the branch connections there were all 5 4 inch lines. Beyond looking at the flow velocity for 6 these systems, we were able to use this share stress 7 model to also look at the turbulence kinetic energy 8 and wall shear. And Kurt, if you go to the next 9 slide. Looks like we're getting stuck with some of 10 the videos here.
11 MR. CRYTZER: Yeah, Jeremie, right now I'm 12 having -- have to restart the program.
13 (Pause.)
14 MR. VARNAM: So I was mentioning beyond 15 looking at the flow velocities through these different 16 sections, we also looked at the turbulence kinetic 17 energy and the wall shears. And the one thing that we 18 noticed although it's kind of hard to see using 19 Microsoft Teams here is that where we're seeing, like, 20 the highest velocities, the wall shears, and the 21 turbulence kinetic energy, they match extremely well 22 to where the actual wall thinning was observed on the 23 samples from the utility. So it gave us a good 24 competence that when developing an appropriate CFD 25 model that it could inform us of different parameters NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
47 1 that could influence fact finding and gave us 2 confidence that the flow turbulence, add that 3 rotation, was the likely contributor to the wall 4 thinning observed at these particular locations. Next 5 slide.
6 This next slide will show some of the 7 correlations that we're working on here where we're 8 looking to correlate the wall thinning with some of 9 the different parameters. In this case on the right-10 hand side, You're showing a correlation of the CFD 11 simulation in the blue line. In the gray line is some 12 of the inspection data from the plant.
13 And it looks like we can develop a fairly 14 decent correlation between wall thinning and the 15 turbulence parameters that are predicted. So our next 16 steps are looking at parametric analysis to help 17 prioritize additional locations and help define an 18 extended condition for the industry. And in doing 19 that, we're looking at the information such as bypass 20 line size.
21 And so instead of having, like, a 4 inch 22 into 14 inches is adjusting that bypass line. We did 23 lower sizes and all the way up to 14 inch, taking a 24 look at the bypass entrance. Where does that bypass 25 entrance occur?
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48 1 Is it two diameters away from the header 2 all the way up to about four diameters away? Also 3 looking at a variety of pipe connection geometries.
4 So in this example here, this particular connection 5 was a welder let. So it's kind of a fairly sharp 6 entrance into that branch connection.
7 We've also adjusted the model to mimic 8 like a forged tee with different blended radii on the 9 elbow piece of it. And then other considerations that 10 we're looking at are bypass operation, whether or not 11 it's been in use for more than 10 percent of the time 12 and potentially looking at the fluence, if there's 13 bypass valve leakage. How does that influence some of 14 the turbulence and wall shears that are expected at 15 that entrance location.
16 MR. VARNAM: All right. Thanks, Jeremie.
17 MR. CRYTZER: All right, Ilya, You're next 18 up on our agenda unless there are any questions.
19 MEMBER HALNON: Before we move on, this is 20 Greg Halnon. Jeremie, did -- I'm sorry. I had to 21 step away just for a second. Did any fundamental 22 changes get made to the industry-wide fact program 23 because of what you found here?
24 MR. VARNAM: As of this time, not yet.
25 With the parametric study, you know, we're looking to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
49 1 see if that would result in the need of changing some 2 of industry guidance, so we're -- you know, the 3 positive thing is that, you know, we were able to kind 4 of mimic, you know, some of the, you know, at least 5 with CFD modeling.
6 You know, where the plant actually saw the 7 wall thinning is where we're seeing the highest 8 turbulence of kinetic energy, so we're looking to play 9 with a variety of stuff that's more indicative of what 10 may be out in the industry, you know, for like a force 11 feed connection instead of being like a 14-inch to a 12 four-inch, doing 14 to 14, because that's, you know, 13 kind of a common type of how some of these branch 14 connections are made, to help inform to see if it does 15 warrant a change in the guidance. So, we're still --
16 the parametric study piece is still ongoing, but near 17 to wrap up.
18 CHAIR BALLINGER: Yeah, this is Ron 19 Ballinger. A related question, these inspections are 20 oftentimes time consuming and expensive, and has this 21 additional analytical capability been able to inform 22 operators as to reducing the number of locations that 23 they have to inspect, narrowing the susceptible 24 population?
25 MR. VARNAM: Right, yeah, and that was, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
50 1 yeah, as we worked through this and, you know, I 2 think, one, developing the higher confidence level and 3 the use of CFD and how it's, you know, actually shown 4 here to be pretty applicable to the plant findings 5 with wall thinning.
6 You know, some of the future work that we 7 have identified here, it is for something such as that 8 where, you know, maybe we apply it to, you know, to 9 the heat exchangers, and, you know, are there other 10 particular components around the shell where, you 11 know, the higher turbulence is where we need to focus 12 our inspection studies versus, you know, at another 13 link of the component itself.
14 CHAIR BALLINGER: Thank you.
15 MEMBER HALNON: So, Jeremie, back to my 16 question before Ron jumped in, in my previous 17 experiences, I do remember the CHUG membership coming 18 back and have been doing some interim actions based on 19 industry operating experience. Is the CHUG still 20 active enough that people brought this back?
21 Because it's clearly a safety issue from 22 the standpoint of potential, as we talked earlier, 23 rupture, or even a leak at that pressure and 24 temperatures. Is it -- the next available outages, 25 are people thinking about this and inserting this into NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
51 1 their inspection programs?
2 MR. WOLFE: Jeremie, if I could jump in 3 here, this is Ryan Wolfe again with EPRI. I'd just 4 like to say that evaluation of operating experience is 5 one of the key elements of an effective flow-6 accelerated corrosion program. It's one of the main 7 sources of inspections.
8 In this situation, this operating 9 experience was made known to the CHUG membership, and 10 each of those CHUG members will have separately 11 evaluated the operating experience to determine its 12 applicability not only to the feedwater piping bypass 13 lines, but also in other lines that may be excluded 14 from the flow-accelerated corrosion program due to 15 having low flow conditions. I would say in that case, 16 the information has been considered by other folks.
17 MR. CRYTZER: All right, thank you, Ryan, 18 and thank you, Jeremie. Ilya, do you want to take 19 over?
20 MR. GOLDBERG: Sure, thank you. Can you 21 hear me all right?
22 MR. CRYTZER: We can hear you well.
23 MR. GOLDBERG: Great, thank you, and 24 thanks for passing it on. So, my name is Ilya 25 Goldberg. I am a senior technical leader at EPRI with NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
52 1 a few areas of coverage, but one of the main ones 2 being cable aging and cable condition monitoring.
3 I have about 13 years prior experience in 4 the cable industry. I started off in fiberoptic 5 systems and then transitioned to downhole medium 6 voltage cables in oil and gas before joining EPRI 7 about three and a half years ago to work on cable 8 programs for nuclear power plants. Go ahead, next 9 slide.
10 We're going to talk about both medium 11 voltage and low voltage programs, but we are going to 12 start off with the medium voltage cable installation 13 condition monitoring program and some of the 14 developments that we've had in that over the years.
15 Go ahead to the next slide.
16 So, let's start off with some background.
17 Cables were initially classified as long-lived passive 18 components, so things that, you know, that really did 19 not require maintenance and testing, and that was the 20 position endorsed by NUREG 1526, et cetera, and the 21 majority of cables will, in fact, last for plant life, 22 but there are some exceptions, and the biggest, you 23 know, the first big primary one is cables that are 24 exposed to adverse local environments.
25 So, good examples of adverse local NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
53 1 environments, you know, you have your thermal 2 exposure, water exposure, electrical, mechanical, 3 chemical, radiation. There are also considerations 4 for cables that are damaged during installation or 5 maintenance, or any latent damage that occurs and then 6 comes up over the years and becomes more problematic.
7 Now, specifically in medium voltage 8 cables, your primary adverse local environment, your 9 most important ones are the ones with dielectric 10 impact, and that is primarily water aging. There are 11 thermal aging situations, impacts that have occurred, 12 but they are relatively rare. So, a lot of the focus 13 goes into water aging and water exposure aging.
14 Successful programs are ones that identify 15 these adverse local environments and manage how the 16 cables age in those environments. Aging management 17 programs are typically designed to do that, to find 18 which cables are going to be exposed to these 19 environments and to test, monitor, and manage their 20 aging. Next slide, please.
21 So, let me continue on with some 22 background. Medium voltage cable, the failures really 23 started to occur during the mid-1970s, and GL200701, 24 the summary report, was provided with data that had 25 been collected on the failure rates and failure NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
54 1 occurrences, kind of a summarization of what had been 2 seen in the industry at that time.
3 There was a wide range of failures and a 4 wide range of cables that had been captured, including 5 in-Service and test barriers, about 188 of the 269 6 cable failures were medium voltage, so rated 5kb to 7 46kb. Now, it's important to keep in mind though what 8 the population sizes are when You're looking at that.
9 So, although you see quite a bit of low 10 voltage cable failures, you have to keep in mind that 11 a typical plant is going to have about 30,000 to 12 40,000 low voltage cables and maybe a few hundred 13 medium voltage cables. So, in terms of population 14 impacts, you can really see why there's been focus on 15 the medium voltage cables.
16 The leading causes were attributed to 17 water and moisture, and failures were pretty common 18 across the types of insulations that were in use, you 19 know, the butyl rubbers, EPRs, and XLPEs. And, you 20 know, there was some characterization, but of course, 21 you know, that characterization also has a large 22 presence of unknown categories. So, again, your data 23 quality is what you can get out of it. Next slide, 24 please.
25 There were some NRC staff conclusions and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
55 1 recommendations that came out of that summary. Two of 2 those, that many utilities did not at the time have 3 cable-specific testing and monitoring programs, and 4 that there was increasing trending of these failures, 5 you know, increase in trends as plants aged.
6 So, the recommendations were reasonable 7 preventatives should be made to keep cables dry, but 8 there were also some conclusions that came out of the 9 GL that really begged for more research, including 10 cables are designed or qualified for submergence, and 11 concerns that a common mode failure of cables could 12 occur. And these are some of the -- you know, some of 13 these ideas informed the research that went on after 14 this. Go to the next slide? So -- yes?
15 MR. BLEY: This is Dennis Bley. My memory 16 is over the last many years, people who were coming in 17 for a license, you know, reported to the community 18 these kind of problems, and I seem to recall that 19 there were more failures associated with cables that 20 got flooded, dried out, and then rewetted multiple 21 times than ones that were just submerged. Is my 22 memory right on that?
23 MR. GOLDBERG: We mention this a little 24 bit later on, that essentially if cables can be dried 25 out and then kept dry. I don't have the information NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
56 1 to say that repeated wetting versus consistent 2 wetting. I can't say that offhand.
3 MR. BLEY: Okay, thanks.
4 MR. GOLDBERG: So, continuing on, a need 5 for research of commonly used EPR and medium voltage 6 cables was identified. A lot of the research up to 7 that point had looked at XLPE insulation, and that 8 failure mechanism research really began in 2006, with 9 the first reports being issued in 2007.
10 EPRI harvested and collected thousands of 11 feet of previous in-Service medium voltage cable that 12 either had in-Service failures or had poor test 13 results, and evaluated them to look at what the cause 14 of that failure was. Between 2000 and 2015, eight 15 reports were issued on those findings and what was 16 identified in those cables. Next slide, please?
17 So, first off, to describe the approach of 18 this research, and then what essentially we did is 19 once those samples were pulled in, there was a 20 systematic methodology for finding the faults in those 21 medium voltage cables.
22 So, it starts off with VLF Tan Delta, and 23 then you section you cable into increasingly small 24 pieces and use combinations of VLF and AC breakdown to 25 try to find the weak points in them, all the way down NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
57 1 to, and this is an image shared on the right showing 2 the use of a pin-type, you know, a pin-type tool to 3 really identify where that leakage, where that weak 4 point is in the cable. Once those weak points were 5 identified, the cables are sections and analyzed to 6 see what kind of understanding, what kind of knowledge 7 can be gained about the nature of the failure.
8 So, at the bottom right here, we see a few 9 of those points are weak points that were sectioned 10 and then photographed to show exactly what had gone 11 inside the insulation at that point, and it shows the 12 presence of a water tree underneath it. We can go 13 ahead to the next slide, please.
14 So, from that large body of samples, we 15 were able to make some findings to address some of the 16 initial concerns. So, one of the primary ones was 17 that VLF Tan Delta testing, so very low frequency Tan 18 Delta, identifies the degraded insulation, and it can 19 sort out, using some criteria, cables that fit into a 20 good category, an action required or failed category, 21 and a further study category in between those two.
22 And what this does is it allows you to 23 sort your cable populations and identify where your 24 problems are through this testing to know where you 25 need to take action in order to get ahead of any NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
58 1 issues you may have.
2 Now, one of the other outcomes here is 3 that these water tree developments, they were not 4 homogeneous, and what it means, you know, what that 5 practically means is that when you look at parallel 6 sections of cable that were pulled and you look for 7 failures in the same portions of those parallel 8 section, you don't see them across all of the phases.
9 And what You're doing there is You're 10 essentially demonstrating that this is not a common 11 cause failure mechanism because you don't see it 12 across multiple sections that are all exposed to the 13 same adverse environment, adverse local environment, 14 in that adverse local environment. We can go ahead to 15 the next slide.
16 So, from that research, there were some 17 guidances that were issued. Two that I wanted to call 18 attention are Report 1020805 was the aging management 19 program guidance for medium voltage cable systems for 20 nuclear power plants.
21 There is a Revision 1 that was issued in 22 2013 under number 3002000557. This is the general 23 aging management criteria, and that also includes 24 these Tan Delta sorting tables and condition, you 25 know, evaluation criteria that we identified from the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
59 1 previous cable sample inspection program.
2 Another component to that is 1021070.
3 That is the medium voltage cable aging management 4 guide, also in Revision 1, and that is more -- pulls 5 in some initial insights into how Tan Delta is 6 applied. These are both -- the most commonly used 7 one, the most commonly, you know, referenced one is 8 the 3002000557 with those criteria.
9 These reports recommended some actions for 10 medium voltage cables in wetted conditions, whether 11 they are in those conditions presently or whether they 12 have been wetted in the past and that condition has 13 been corrected, or rectified, or addressed.
14 There are recommendations to perform 15 inspections for inaccessible cables and to keep the 16 dry where possible, and then also there were some 17 guidelines for how that VLF Tan Delta testing, which 18 had been shown to be able to identify these issues, 19 how to apply it, that essentially you start off after 20 certain initial periods of aging with a six-year test 21 frequency for cables that are testing good so you can 22 trend them, and then that frequency gets increased to 23 two to three years if those cables fall into a further 24 study test condition, and then as soon you start 25 falling into repair/replace, once you hit the actual NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
60 1 required range.
2 So, once You're in the actual required 3 range, that's where you really should be starting to 4 look at things you can do to take action about that 5 cable system. Go ahead to the next one, please.
6 So, there has been some follow-up work 7 since then. We have collected seven years of data 8 over two different reports. They're listed down here.
9 1025262 was the initial report and then 3002005321 was 10 the follow-up report where more tests were collected.
11 We initially had 700 different phases 12 tested from 198 circuits in the first report, and then 13 there were, in the second report, we stepped that up 14 to 541 circuits comprising approximately 1,800 15 individual cables, so this is a fairly large sample 16 size.
17 What I wanted to call to here in this 18 slide is that this was a pretty good cross-section of 19 the different types of cable that are installed. So, 20 we saw different kinds of EPRs and XLPEs represented, 21 as well as some, you know, rubbers represented in this 22 test sample size.
23 The other thing I wanted to call attention 24 to is that when cables from the first study phase were 25 retested in the second phase, we did not see further NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
61 1 progression. And what we did with that is that we are 2 -- what we were showing is that VLF Tan Delta is 3 effective at finding the problematic cables, and once 4 your problems are eliminated, you know, the cables 5 that have been exposed to those adverse local 6 environments, once you've addressed that, you don't 7 see a further progression.
8 The remaining population remains healthy, 9 and that was one of the reasons why there was this 10 initial large population sample and then this even 11 larger follow-up sample was to really look at how 12 these cables had progressed and done. Next slide, 13 please.
14 So, here I wanted to address something 15 specific. So, this is, this was the RL2021O11. This 16 was essentially a letter issued that looked at the Tan 17 Delta methodology, and the NRC had noted some findings 18 with regard to it.
19 The NRC generally found the methodology of 20 Tan Delta testing was sound and the criteria were 21 sufficiently conservative. However, it was not 22 endorsed due to insufficient data for some specific 23 types of cables, so brown EPR and XLPE as an example.
24 Now, one thing to note there though is 25 that these cables make up, brown EPR and XLPE made up NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
62 1 relatively small portions of the population, and with 2 that, of course, they're going to make up smaller 3 portions of the data collected. You can kind of see 4 what our test results broken out by cable type are 5 here on the right, and these are relatively small 6 portions of the population that was received.
7 But the biggest message, you know, the 8 bigger take-away that we saw is that the failure mode 9 and progression had been consistent across the 10 insulation types. So, for us looking at this, that 11 body of evidence really needs to be evaluated as a 12 whole.
13 And the capability of this test method, 14 Tan Delta, had been demonstrated on the whole and on 15 different types of populations, cable populations, and 16 since we're not seeing a different progression or 17 failure mode within specific insulation types, this 18 method still -- you know, this method is still a very 19 capable and powerful tool for identifying degradation 20 across all types of insulation based on what we've 21 seen through the data so far. Please go ahead to the 22 next slide.
23 So, just to get a little bit more into how 24 Tan Delta testing is applied today, you know, where we 25 are with this methodology today and how it's applied NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
63 1 today. Tan Delta tests give you three different 2 parameters about the cable system that you are 3 testing.
4 They give you a combination of your mean 5 Tan Delta, your delta Tan Delta, which is essentially 6 how that Tan Delta changes as you step up your 7 voltage, and then your standard deviation percentage, 8 which is how steady your reading is at any given 9 voltage.
10 These readings come in in the criteria and 11 each one tells you something a little different about 12 the cable system. So, our evaluation criteria looks 13 at all three and applies all three, and in situations 14 where you start seeing a failed or further study 15 required result, you can actually gain some insight 16 into what's happening based on which one of these 17 parameters is showing the problem or if it's all 18 three.
19 Now, some other take-aways with how this 20 testing is applied today that I wanted to highlight, 21 testing is typically done every six years and is 22 sufficient to prevent cables from transitioning from 23 a good test to a degraded test, which is another way 24 of saying that we're catching the problem cables 25 before they traverse all the way to, you know, to real NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
64 1 issues, that we get indications of those with the 2 testing cycle.
3 When combined with withstand testing, 4 which is another term for hipot testing, it gives you 5 a reasonable confidence to prevent immediate in-6 Service failures, which is another way of saying that 7 typically, when you start seeing progression, one of 8 the ways, one of the recommendations that comes out is 9 to apply withstand testing to make sure that you can 10 return your cable to Service immediately and give you 11 some confidence for the near term, while also stepping 12 up the monitoring campaign for that cable circuit and 13 prepare to replace it as, you know, as you can.
14 And one other thing that I wanted to 15 mention is that when you do identify degradation, if 16 you can use what I mentioned about how different 17 parameters reflect different aspects of the cable 18 system, you can sometimes use it and some other test 19 methods to figure out exactly what portion of the 20 cable system is giving you trouble and make repairs.
21 You know, oftentimes you can find that 22 there is an insulation issue, I'm sorry, there's an 23 installation issue with one of the splices or 24 termination, and those typically present in specific 25 ways in Tan Delta testing, and when you can make NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
65 1 repairs that fix that issue, or even in cases of 2 degraded insulation due to an adverse local 3 environment where you can correct that environment and 4 replace the cable system section with a new section, 5 you can restore the cable test results to good. Once 6 you've rectified that issue, then you can continue to 7 use that testing to monitor the condition of your 8 cable circuit. Next slide, please.
9 So, highlighting a few pieces of ongoing 10 work, you know, at this point in the presentation, 11 we've gotten to where we are today. Where are we 12 going tomorrow? So, a few things that are out now 13 and, you know, really kind of came out recently on the 14 cutting edge, we're looking at applying VLF testing 15 with motors attached and also VLF testing with your 16 transformers.
17 The intentions here is, in other words, is 18 to show how this testing can be applied on full 19 circuits with, you know, your equipment load, and 20 whether we can differentiate effects within the cables 21 within the motors or transformers, and whether that 22 testing still provides useful information.
23 This is often useful because in some cases 24 in some circuits, it's really difficult to disconnect 25 the load, and any insight you can get into your cable NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
66 1 system before going in to disconnect the load is going 2 to be very useful in terms of planning for, you know, 3 what kind of issue you need to address.
4 There have been two pilot sites and 5 several others that have applied for using this 6 research, you know, and it's starting to come out and 7 be applied, and we're starting to glean some useful 8 information out of it. There are two reports that 9 have been issued from laboratory testing and some 10 initial looks on how to use this technology.
11 There is some other research currently in 12 progress. One of the key ones that's going through 13 right now is evaluation of insulation shields' 14 attenuation effects on high-frequency test signals.
15 Now, this is important because VLF Tan Delta is a low-16 frequency test technique, but there are other high-17 frequency test techniques, you know, TDR/FDR for 18 example, that have some promise to be useful.
19 Well, there are some questions around how 20 shield attenuation plays into the usefulness of those 21 testing techniques, and there's been some research, 22 you know, kind of going in several different 23 directions, but there hasn't really been certainty 24 yet.
25 So, we're looking at how to really, you NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
67 1 know, to characterize that attenuation and understand 2 how it impacts these high-frequency test techniques 3 because we see the need to apply them in the future 4 and we want to lay the groundwork for application of 5 those high-frequency test techniques.
6 Now, in line with that, you know, we saw 7 a few slides ago that there was a large body of data 8 collected for medium voltage cable test results. We 9 are not formally, through a formal program collecting 10 further test results, but we continue to collect them, 11 you know, informally.
12 It's done now through member input.
13 Oftentimes, this is for me or some of my colleagues 14 with the cable program, get requests from a member 15 that say, hey, we got a test result. We're not 16 exactly sure what this means. Can you take a second 17 look at it?
18 And, you know, we do everything we can to 19 help with that, but we're also collecting those. You 20 know, we're also collecting that data so that we have 21 an understanding of what is happening, what kind of 22 test results are being gathered from the industry, and 23 what kinds of trends we're seeing as time goes on.
24 Another big part of that is, you know, the 25 meetings we have, the cable user group. You know, we NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
68 1 get feedback on how these testing and other emergent 2 issues have progressed and how these techniques are 3 being applied, and what kinds of results we're seeing 4 with them. This all feeds into, you know, a good 5 understanding of what the state of the industry is at 6 the moment. So, if we could proceed to the next 7 slide, please?
8 So, in review, just to kind of very 9 briefly cover some of the things we've talked about as 10 well, post-GL200701, we've applied VLF Tan Delta 11 testing, and that has really led to improved operating 12 experience. We've had very few in-Service failures 13 since 2015, in part attributable to these monitoring 14 programs and VLF Tan Delta as a tool.
15 Important to remember to that, medium 16 voltage cable insulation typically degrades from 17 dielectric stressors, and VLF Tan Delta as, you know, 18 as shown by the results above and previously has been 19 proven capable of identifying cable degradation for 20 both wet and thermal aging. Now, thermal aging, we 21 saw it as part of the, you know, test sample, but it's 22 very rare.
23 To kind of re-highlight what the 24 progression, the damage progression is, water trees 25 form at stress points, typically manufacturing NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
69 1 anomalies or latent damage from installation. The 2 insulation degradation sites are not -- I'm sorry.
3 And because these sites are typically, you know, 4 almost random in nature, they are not really a common 5 mode concern.
6 We talked about that when we looked at how 7 circuits that lay next to each other that are parallel 8 and are exposed to the same adverse local environments 9 don't necessarily develop the same failure mode across 10 those locations.
11 And then also keeping cables dry or even 12 wet then dry is better than being submerged 13 continuously, and that testing will identify issues, 14 and what that -- that in some ways gets back to the 15 question that was asked earlier, but your best bet is 16 to keep it dry. Your next best bet is to dry out the 17 wet cable rather than just repeatedly, rather than 18 just continuously submerging it.
19 And in the close to the medium voltage 20 section, I just wanted to say the medium voltage cable 21 insulation will be long-live because dielectric 22 stressors can be managed by the above strategies. So, 23 everything we've talked about is the tool for managing 24 the dielectric stress, and that the degradation can be 25 corrected through the methods we've talked about here.
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70 1 And the last thing to highlight is that 2 thermal oxidative, you know, thermal aging is not a 3 typical factor in medium voltage cable, and I 4 specifically put that at the end of this summary 5 because we are next going to move to low voltage cable 6 insulation testing, and there the things change a 7 little bit.
8 So, progressing onto the low voltage aging 9 management and some of the tools and work that we are 10 doing here, before I do that, are there any questions 11 before we move to low voltage?
12 MEMBER HALNON: Yeah, this is Greg. Just 13 one quick question. Is the lack of NRC endorsement 14 hindering in any way the use of this, and if so, what 15 benefit could we gain from getting full endorsement?
16 MR. GOLDBERG: There were some questions 17 initially about what the progression of this testing 18 will be and kind of what the future of it will be.
19 That being said, the testing has already proven so 20 useful and effective that it's still seeing very 21 regular implementation. You know, it's almost become 22 the go-to to do Tan Delta testing on these cable 23 circuits.
24 One thing I will say is that I think it's 25 going to be very important to reevaluate as we gather NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
71 1 more and more data and we see more and more how 2 effective Tan Delta testing is and that, you know, if 3 we periodically look back at that assessment and see 4 how the body of evidence has grown behind how useful 5 this testing is, we could really get some more 6 confidence if there is a reevaluation.
7 And that if, you know, once that 8 requirement for, you know, the more, I would say the 9 more, sorry, the less frequently existing cables is 10 really, you know, met, there would be so much extra 11 confidence, especially internationally for use of this 12 testing, that it would be important.
13 MEMBER HALNON: Okay, so are we going to 14 go back and try to get endorsement at some point in 15 the future or is that still kind of an open-ended 16 question?
17 MR. GOLDBERG: I think it's going to be 18 informed by, you know, the needs, and what amounts or 19 data we get back, and what we see as this testing 20 evolves. I think it's going to be, you know, evidence 21 that, hey, we should take another look at this and we 22 could really forward this, use of this testing to even 23 more places and more conditions if we had that 24 endorsement under reevaluation in the future.
25 MEMBER HALNON: Okay, thanks.
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72 1 MR. GOLDBERG: Okay, if there's anything 2 else, we can move onto low voltage. Okay, so going 3 into low voltage, once again, low voltage cables are 4 long-lived, passive components, but once again, you 5 have a situation where adverse local environments can 6 accelerate stress and cause issues.
7 The difference between medium voltage and 8 low voltage cables though is that the primary driver 9 of adverse local environmental aging in low voltage 10 cables is thermal in nature. So, specifically we're 11 talking about external heating. That typically is 12 where you see the most problems, the biggest cause of 13 problems, and identifying those areas where that 14 external heating can produce some issues and managing 15 them has been the focus of cable aging management for 16 low voltage cables.
17 In other words, what you really want to do 18 is you want to know which cables are seeing localized 19 thermal heating, external heating. You want to 20 correct that if you can. And, you know, you also want 21 to monitor that to see what the progression of aging 22 has been. So, I'm sorry, there's a question now?
23 MR. BLEY: Yeah, it's Dennis Bley. I'm 24 going to take a guess, but, I mean, will you explain 25 why there's a difference between low and medium cables NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
73 1 in this cause? And I'm kind of guessing that it's 2 because water is more of a problem for the higher 3 voltage cables or is there something else going on 4 that's making a difference?
5 MR. GOLDBERG: Yeah, absolutely, so the 6 reason for that is that in wet aging, that progression 7 of water exposure to water trees to then electric 8 trees, which is the manifestation of failure in the 9 insulation, it's a voltage-driven process. You need 10 a driving voltage behind it, and low voltage cables, 11 they just don't put enough of a voltage grading across 12 the insulation to drive that process forward.
13 The thermal aging process is not one that 14 needs a voltage driver behind it. The presence of 15 external heat does the work, so that's where you see, 16 you know, the degradation path occurring.
17 MR. BLEY: Okay, and that leads me to the 18 next question, which is are medium and high voltage 19 cables just as susceptible to thermal aging and it's 20 just that we have a more likely source driving failure 21 with the water or are they not exposed to the same 22 temperature regime? And I don't know why that would 23 be.
24 MR. GOLDBERG: Well, we actually do see 25 rarely, but we see some external heating issues driven NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
74 1 in medium voltage cables, and that was mentioned as a 2 cause that does happen. It's just fairly rare and I 3 suspect that's because of a combination of factors, 4 part of them being where and how they're installed and 5 just, you know, the size and type of cables that are 6 used, that it's just, it's a rarer cause of failure in 7 the medium voltage population.
8 MR. BLEY: Okay, I'm not sure I fully 9 understand that, but maybe they're not packed as 10 densely in the cable trays or some such thing?
11 MR. GOLDBERG: Yeah, that's part of it, 12 but just where they're typically installed, and also 13 the actual population sizes play into it. You know, 14 as we mentioned, there's thousands and thousands of 15 low voltage cables installed everywhere in plants.
16 There's typically only several hundred medium voltage 17 cables in some specific areas.
18 (Simultaneous speaking.)
19 MR. GOLDBERG: Well, it's an opportunity 20 for exposure as well.
21 MR. BLEY: Okay, that seems to be a 22 certain effective rate, but the numbers would be much 23 lower, okay.
24 MR. GOLDBERG: Okay, all right, so popping 25 to the next slide, in terms of how this thermal aging NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
75 1 has been addressed up to now, so the background of 2 what's been done so far, typically, these terms of 3 degradations are identified and, you know, quantified 4 visually.
5 So, through walkdowns, through periodic 6 inspections, visual inspections of these cables, you 7 can identify the adverse local environments and you 8 can look for effects of those adverse local 9 environments on the cables. Visual indicators are 10 usually, you know, they're present and they're 11 important.
12 A lot of this is because your jackets 13 start to degrade initially, and then you start to see 14 the effects later on the insulation material. Your 15 jacket is external. The heating source is, again, 16 typically external, so that's where you see your first 17 impacts.
18 And depending on your jacket material, 19 that can be cracking, you know, full circumferential 20 cracks, weeping of plasticizer. There's really a 21 whole host of different things that can occur that are 22 going to clue in that hey, there's an adverse local 23 environment here, and that something is happening to 24 these cables that needs further inspection and 25 monitoring.
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76 1 We also see discoloration, just a whole 2 host of visual indicators, and typically these precede 3 the insulation beginning to degrade underneath them.
4 However, once you start seeing that insulation 5 degradation in the jacket materials, you want to start 6 thinking about getting an understanding of what the 7 condition of the insulation underneath is because this 8 jacket is kind of sounding a warning bell that hey, 9 something is -- you know, there's an adverse local 10 environment here. Something is going wrong. You need 11 to start thinking about looking deeper and 12 understanding what the condition of the cable is 13 overall. Go ahead to the next. Next slide? Thank 14 you.
15 There have been some quantitative tests 16 that existed in the industry before and that currently 17 exist that have seen some use, and these tests tend to 18 be very common, but they're rarely applied, which is 19 a differentiation in terms of how often they're 20 actually used. A lot of these tests are either 21 destructive or they require laboratory processing of 22 the materials exposed to those adverse local 23 environments.
24 So, a good example of those on the 25 destructive side is elongation of break, and that is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
77 1 a very good typical indicator of thermal aging, but 2 it's also one that's hard to collect, and then some 3 laboratory testing that can be used alongside, you 4 know, oxidation induction is a good example of that, 5 but these, again, are tests that require a lot of, you 6 know, effort and work to implement, and also that are 7 not necessarily applicable, that they're hard to apply 8 because in part you need to know where your adverse 9 local environment is and you need to be able to get 10 samples out of it, and that's not always the case for 11 circuits as an option that's available.
12 That's really the big problem behind some 13 of these existing techniques is the ability to harvest 14 samples. It's not always present and it's not, you 15 know, something you can do constantly. You are 16 limited in how often you can do it and in places that 17 you can do it.
18 So, that really puts a limitation on some 19 existing techniques that are more material based. You 20 know, we call them mechanical and physicochemical 21 techniques. Next slide, please?
22 Now, looking at commonly used current 23 electrical techniques, one of the most commonly 24 applied ones today is insulation resistance, what's 25 commonly called Megger, Megger testing. The problem NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
78 1 with Megger testing, especially in dry cables, is that 2 you can often have pretty severe degradation, you 3 know, all the way almost up to exposed conductor, and 4 in a dry air environment, you may not see indications 5 of that in a Megger.
6 That's pretty common to see that a cable 7 is fairly, you know, significantly damaged, but it 8 doesn't show up in that Megger test as a problematic 9 test result. And the reason for that is that air is 10 a good insulator, and if you have a proper air gap 11 around your degraded region, your Megger test is not 12 necessarily going to show you a problem, and that's a 13 big gap. That's really something that, you know, 14 limits the ability of this test method to find issues.
15 Another common sets of tests that is used, 16 time and frequency domain reflectometry, so TDR/FDR 17 we'll hear as an industry term that gets used for FDR, 18 is one that can indicate anomalies in insulation. Not 19 all of those anomalies are degradation, and what that 20 essentially means is that there's a lot of false 21 positives.
22 There's a lot of instances where an FDR 23 will show you where your cable is going around the 24 bend, and You're not sure if that's a problem or if 25 it's just a cable going around a bend. That limits NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
79 1 the applicability of that test method. I think I saw 2 a hand go up?
3 MEMBER ROBERTS: This is Tom Roberts.
4 Just a quick question on the problem with the Megger.
5 Do we have the same problem with the Tan Delta type of 6 measurement which is relying on finding resistance in 7 kind of a static voltage?
8 MR. GOLDBERG: Well, Tan Delta is looking 9 at your difference in lag between your voltage and 10 current waves, so it's not really looking at 11 resistance, and You're also, when you use that 12 methodology, You're looking at how steady that 13 measurement is and how much of a voltage dependence 14 there is to that measurement. And then finally, of 15 course, you know, it's typically being -- you know, 16 You're looking for issues in cables that are in wet 17 environments on the medium voltage side. Did I see a 18 couple more hands go up?
19 MEMBER ROBERTS: Yeah, just a quick 20 follow-up. So, the reason why you get the angle 21 change in a Tan Delta is because of resistance, right, 22 so You're counting on the high voltage, seeing a 23 resistance that shouldn't be there between the 24 insulation and, you know, ground, or shield, or 25 whatever it is You're comparing to. So, just how is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
80 1 it different that the Megger doesn't find that 2 resistance, but the Tan Delta does?
3 MR. GOLDBERG: Well, part of it is that 4 you look not just at the Tan Delta value itself, but 5 how much of a voltage dependence there is to that 6 value, and also how steady that value is within the 7 same voltage. So, you know, it happens where you see 8 an acceptable Tan Delta value, but man, that reading 9 is not steady or that reading is getting higher and 10 higher between your voltage steps, and that tells you 11 that there are issues as well, and that's not 12 something You're necessarily doing with a Megger.
13 Now, we're going to get to it in a few 14 slides, but there are variations on the Megger test 15 that reflect something similar to that I-pole versus 16 ID-pole that look at essentially how your reading 17 steadies out over time that are providing useful 18 information, and that is part of a methodology that 19 we're working through to help evaluate this situation.
20 So, if you look at more than just the value You're 21 getting back, there is useful information that can be 22 extracted.
23 MR. BLEY: This is Dennis Bley. That last 24 thing is pretty interesting. I look forward to when 25 you have some results in that area to share. The NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
81 1 thing I'm wondering about is I always assumed that the 2 highest temperatures were deep inside the cable trays, 3 especially for power cables, and the visual inspection 4 is only going to see the cables on the outside.
5 The pictures you've shown have been in 6 cabinets and places like that where, you know, maybe 7 it's control cables in there that are getting damaged.
8 Can you say anything about that?
9 MR. GOLDBERG: Sure, what that points to 10 is the difference between what you would call ohmic 11 heating and external thermal heating. What we've seen 12 is that the biggest, most frequent driver is external 13 heating. So, there is, you know, a common example of 14 that is a cable that's coming, you know, a cable tray 15 that's coming close to a pipe carrying hot steam that 16 doesn't have insulation or that the insulation was 17 removed and not replaced, or cable trays that were 18 routed through areas of a plant that are very hot.
19 There, you see degradation on the 20 exteriors, specifically the places that are closest to 21 the heat source. Ohmic heating, from what we see, is 22 less common, and there you would have a concern that 23 you may -- you know, you can have ohmic heating 24 inside, but there is plays into, you know, that goes 25 into, back to the design of the cable system to make NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
82 1 sure it's sufficient to carry the current load that 2 it's asked to carry, as opposed to external heating 3 which is typically, you know, something that maybe 4 changed in a plant where a cable that wasn't initially 5 exposed to excessive heating is now exposed because a 6 piece of insulation, a piece of thermal insulation was 7 removed from a pipe. So, those tend to be on the 8 external side closest to what's emitting the heat.
9 MR. BLEY: Interesting. It makes sense.
10 Thank you.
11 MR. GOLDBERG: Thank you. Okay, go ahead.
12 So, jumping into this next point where we're going to 13 talk about the testing, low voltage cable testing 14 methodology that EPRI is working through and piloting 15 right now, the first thing I wanted to do is just 16 briefly highlight the difference between a global 17 assessment test and a local evaluation test.
18 So, your global assessments are giving you 19 a look at the overall condition of your whole 20 insulation system. So, good examples of this, you 21 know, going back to what we talked about the 22 insulation resistance test method, dissipation factor, 23 which is Tan Delta, dielectric spectroscopy, which 24 looks at similar results, but over a wider band of 25 frequencies, and polarization/depolarization current, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
83 1 which is what I had briefly alluded to in terms of 2 gathering more data from a Tan Delta, or from an 3 insulation resistance test based on how it performs 4 over time, but those are all assessments of the 5 insulation system as a whole for that cable.
6 Now, as opposed to that, the second 7 pillar, the second part of the cable test methodology 8 are localization methods. What these do -- and good 9 examples of them are TDR and FDR, LIRA. These methods 10 are meant to help you figure out exactly where in the 11 cable you are seeing your problem, so to localize the 12 area of concern. Go ahead to the next slide.
13 So, let's get into the actual research.
14 This research product, 3002020818, test protocol for 15 condition monitoring of low voltage cables using 16 dielectrically-based methods, it's what we -- I mean, 17 that's a mouthful. It's what we commonly call the low 18 voltage test methodology, and the thinking behind it 19 is to take an array of tests rather than just one test 20 to try to do everything with, and use that array of 21 tests to achieve a specific set of goals for a cable 22 system.
23 So, you start off with identification.
24 You know, is there a problem with my cable system or 25 is this a green test result that I don't need to be NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
84 1 concerned with it for the next period of time?
2 Proceeding through that is discrimination.
3 Is this an internal and real problem? What is the 4 nature of the problem? You know, this is something I 5 alluded to a little bit where you see issues with 6 FDR/TDR where You're not sure whether the, you know, 7 whether the echo that You're seeing on the chart is 8 actually a problem or just a bend in the cable or a 9 change in the environment there. Part of this test 10 methodology aims at that discrimination function.
11 The next one is localization. We talked 12 a little bit about that in the last slide between 13 global methods and local diagnostic methods, in order 14 to help you understand where in your cable system you 15 do have a problem once you've identified that there is 16 a problem.
17 And finally, assessment. What is the 18 nature of this problem? We saw that approach to 19 assessment on the medium voltage side where we used 20 Tan Delta to sort cables into good, action required, 21 or further study required. Well, we want to do that 22 as well on the low voltage side. We want to be able 23 to sort our cables into these categories.
24 And the way we've achieved it, the way 25 we've gone about it is we started off by applying both NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
85 1 global and local diagnostic techniques to these cable 2 systems. On the global side, we're looking at low 3 frequency dielectric spectroscopy, which is kind of a 4 neighbor of Tan Delta, but it's across a set of 5 frequencies, and polarization/depolarization current.
6 This gets back to extracting more 7 information from a test that's similar to a Megger 8 test, an insulation resistance test, but looking at it 9 over time and how the current reacts as you first 10 apply voltage and then take that voltage away. What 11 is the reaction of that current and how does it apply 12 to the previous reaction when you applied voltage?
13 You can glean some information about the cable 14 condition from that.
15 And then you apply your local diagnostic 16 techniques, advanced TDR and FDR, and what we'll see 17 here in a little bit is the necessity to really look 18 at both of those as a body of data to help you zero in 19 on problems rather than trying to rely on one or the 20 other without having a full picture of the condition 21 of the cable. Can we hop to the next one?
22 So, and hopefully my little animations 23 here come through pretty well, but what you do when 24 you apply these tests, so what You're seeing here is 25 a population of test samples that was collected as NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
86 1 part of that previous test report that I mentioned.
2 And once that population is collected, on the left 3 side of the chart, you see a Tan Delta value across a 4 fixed frequency.
5 On the right side, you see that response 6 across multiple frequencies. But once you collect 7 that, your goal to make this test useful, and we're 8 using LFDS as an example, is to try to sort it into 9 good, action required, and intermediate, further 10 monitoring, you know, further testing or further 11 monitoring required categories.
12 So, if you can click once, it should show 13 the sorting. There we go. Now you see we've taken 14 the test results and we've really broken those 15 populations out across to see where they fall out, and 16 it's really clear when you take a look at the whole 17 body of evidence, again using low frequency dielectric 18 spectroscopy as an example, on this little right-hand 19 chart where you see your green, your good cables not 20 really showing a frequency dependence in their Tan 21 Delta values, and your red sorted valued showing a 22 pretty strong frequency dependence in their Tan Delta 23 values, and then the yellows are in-betweens, the ones 24 that are transitioning from the lower frequency 25 dependence to the higher frequency dependence, and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
87 1 that's the approach we use to really grade populations 2 within that test report.
3 You can go ahead to the next one. Yeah, 4 click through them. This is just exactly what I 5 explained with anomalies observes versus no anomalies 6 and an intermediate. Go ahead to the next one.
7 So, let's apply that same test technique 8 to another test that is part of this methodology, 9 polarization/depolarization. This is the outgrowth of 10 insulation resistance when You're looking at your 11 leakage current over time, first as you apply your 12 voltage, so I-Pole, and then as you take away your 13 voltage, what happens to it, so ID-Pole, and then you 14 ratio them to each other and you compare them to your 15 line, which is where you expect that ratio to fall 16 out.
17 And as you can see now, there is a 18 population of distribution relative to that line of I-19 Polarization versus ID-Polarization, and when you 20 apply -- when you look at that population and you look 21 at where it falls out -- go ahead and click.
22 You can once again start to sort it into 23 results that fall near your expected line in the 24 green, way away from your expected line in the red --
25 yeah, go, click forward more -- and then this NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
88 1 transition in the yellow as You're transitioning from 2 good test results to degradation is starting to occur 3 and you need to keep a closer eye on these particular 4 populations.
5 And this is just a large body of results 6 that we collected that shows exactly, you know, that 7 shows how that populational study was gathered and 8 broken out. Go ahead.
9 Going back once again, so if you remember, 10 I mentioned that those were our global condition test 11 techniques. Now we can take a quick look at what some 12 of the local techniques are telling us. So, this is 13 FDR and TDR.
14 And if you click through, we'll see a 15 couple examples of results. Here, You're seeing an 16 FDR trace, and You're seeing one that's good here on 17 the left side. In the middle, You're seeing possible 18 anomalies in the yellow, and on the right, that's 19 where You're seeing significant anomalies and then 20 echoes of those anomalies on the right-hand FDR trace.
21 Now, what I wanted to do with this slide 22 through is up top, you now see the corresponding TDR 23 trace, and what that's showing you is more information 24 about the issue that You're seeing, that's really 25 forcing what you are seeing.
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89 1 So, when you look at that bottom right FDR 2 and you see a set of peaks, but now you look at the 3 TDR above it and you see a defined peak in a specific 4 location that's then backed up what your FDR is 5 seeing, followed by some echoes of that, then it makes 6 it really clear that hey, we have a problem and it's 7 probably in this specific region because the two test 8 techniques, which are slightly different, are giving 9 you reinforcing results.
10 A similar thing in the middle point, the 11 anomalies observed investigation required result where 12 you see an anomaly both in the TDR and FDR, and it's 13 one that may not be as clear or as indicative in any 14 one of the two tests. When compared to each other, 15 you say hey, these tests are both telling me that 16 there's maybe something. It's not, you know, full 17 significance, full visibility yet, but there is 18 something going on here, so anomalies have been 19 observed in this cable in this specific region.
20 And on the left-hand side, you know, you 21 just see a clean trace TDR/FDR, and You're getting 22 good confidence on both that what You're seeing is, in 23 fact, a clean result, it makes, that cross-correlation 24 makes the results more interpretable, more usable, and 25 that's another piece, foundational piece of this low NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
90 1 voltage test methodology. So, let's go to the 2 summary. Next slide?
3 Just to summarize what we've talked about, 4 thermal degradation is the most common cause of 5 insulation degradation in low voltage cables, and it 6 is the most common adverse localized environment that 7 we've seen, external heating to those cables. The 8 current monitoring techniques, you know, what's 9 typically done today is not always catching these 10 degradations as they occur, and we really need 11 something to augment and improve our ability to catch 12 those.
13 The physical test methods were very 14 difficult to apply. They rely on having samples that 15 you can pull and do physical testing on, and rely on 16 knowing where your adverse local environments are.
17 The electrical tests that are commonly applied today, 18 they can often provide false indications of issues in 19 the case of TDR/FDR where there's really just changes 20 in the environment or changes in cable routing, and 21 then you can also, with insulation resistance just by 22 itself, often miss things that are, you know, that are 23 going to turn into larger issues as time goes on.
24 And what we wanted to show in this 25 presentation is that EPRI is, you know, has developed NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
91 1 and has piloted and is currently piloting in even more 2 places a low voltage test methodology that combines 3 multiple methods to give you an overall assessment of 4 this cable from a set of different techniques to 5 really get at, you know, what, the condition of that 6 cable.
7 And the status of it now is we've already 8 demonstrated it for some members. Other members are 9 requesting demonstrations, and throughout next year 10 and the following years, we're going to demonstrate it 11 more and more, and we're going to gather more and more 12 data just like we did with the Tan Delta in order to 13 show this method's applicability and impact. So, I 14 think I see one question from Dennis?
15 MR. BLEY: Yeah, where I'm kind of hanging 16 up -- this is very interesting and it's a great step 17 forward, but your discussion that most of this heating 18 comes from your plant changes after the original 19 design makes me think that, in addition to having ways 20 to test for it, providing guidance to mechanical and 21 electrical designers at the plants to include 22 consideration of this issue for any plant mods would 23 be a very helpful thing.
24 MR. GOLDBERG: Yeah, absolutely, and that 25 is already a consideration. What it comes to is, you NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
92 1 know, sometimes the impact isn't fully understood, and 2 the intention here is to have an ability to verify and 3 really understand especially if there was, you know, 4 already an exposure to external heating to a cable, to 5 understand the condition of that insulation.
6 And, you know, you can do a visual 7 walkdown. You can look for the extent of these 8 conditions, and they're often found and corrected, but 9 then, you know, often the question comes up is what's 10 the impact to the cables that were exposed to it? And 11 that's where a good bit of this work is aimed at, is 12 to be able to evaluate the condition of those cables.
13 And also, we want to be able to 14 prioritize, you know, where you see -- you know, which 15 cables require the most, you know, the most testing 16 work, you know, have a method that can give you an 17 idea of the condition of your system and find, you 18 know, conditions that you may not know exist.
19 CHAIR BALLINGER: Okay, thank you very 20 much. We're a little bit behind, but I don't -- it's 21 not terminal, so this is a point at which I'd like to 22 take a, let's say a ten-minute break. By mine, it's 23 10:40. Can we take a break and come back at 10:50?
24 We'll try to get a shorter break. Unless there's an 25 objection to that, we'll recess until 10:40.
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93 1 (Whereupon, the above-entitled matter went 2 off the record at 10:40 a.m. and resumed at 10:50 3 a.m.)
4 CHAIR BALLINGER: Okay, it's 10:50 a.m.
5 Boy, it seems like time flew. So let's --
6 MR. CHOROMOKOS: All right.
7 CHAIR BALLINGER: -- let's pick up where 8 we left off. Thank you.
9 MR. CHOROMOKOS: All right. Kurt, you 10 want me just to drop in, or you want to transition in.
11 MR. CRYTZER: No, please, go ahead and 12 start.
13 MR. CHOROMOKOS: Right on. Okay, good 14 morning. My name's Rob Choromokos, from EPRI. I work 15 in the Risk and Safety Management Group, RSM, and we 16 have -- actually, my role within the RSM Group, 17 focuses a good bit on external hazards.
18 I think you'll see, through this 19 discussion that, that kind of, falls in line with 20 external hazards. I've been at EPRI about three years 21 now, and I've been in the nuclear industry a little 22 over 36 years, mostly on the consulting side, and my 23 background is predominantly design engineering. I'm 24 a civil engineer, at the University.
25 Today's topic is nuclear resilience -- is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
94 1 resiliency and, while resiliency can pertain to 2 numerous threats, namely, our ability to respond to 3 weather-related hazards, from chronic weather changes 4 and extreme events and -- and how these might change 5 in the future.
6 So one last part of the intro, in the last 7 few years we've had an increased focus on the effect 8 of changing future climate. It's been in the news 9 quite a bit.
10 I'm seeing quite a few articles and 11 publications with a focus on how the power grid assets 12 are -- are -- are going to be challenged, potentially, 13 challenged by climate risk, specifically, related to 14 extreme heat, weather events, and in our extreme 15 events, such as storm, drought, and hurricanes and 16 such.
17 The primary concern is -- is that 18 historical weather events that we've used in our 19 original plant designs may not adequately capture or 20 bound the impact of future climate change, on our 21 weather-related hazards.
22 So additionally, we've got some aging 23 nuclear fleet out there that will have a shortened 24 horizon from making any investments, and what we want 25 to do right now is -- is -- is see if we can help NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
95 1 inform some decisions, regarding how to become more 2 resilient to the change in climate.
3 And we -- we certainly have some recent 4 examples of weather-related challenges that we could 5 all point to, deep freeze last Christmas, power 6 outages in Texas a couple of years back, heat domes 7 out in the northwest, and even in the upper-Midwest.
8 These have all challenged resiliency to the grid and 9 the components to the assets on the grid, including 10 nuclear power plants.
11 So as the climate is changing, science is 12 now telling us that there will be warmer average 13 temperatures but, also, a potential increased 14 frequency in magnitude of extreme weather events.
15 So that's today's topic, and I'm going to 16 give you a little bit of what we're doing, currently, 17 related to the nuclear and safety design basis, but I 18 want to quickly pivot to what we're doing on 19 operational side, what we're seeing and then what 20 we're going to help focus our research on, in terms of 21 -- of increasing our resiliency. So next slide.
22 So what is resilience? Resilience is the 23 ability to withstand and recover from a disruptive, or 24 unplanned, event. In today's discussion, we want to 25 ensure that the nuclear plant's prepared to withstand NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
96 1 the impact of the changing weather-related events, 2 with minimal, if any, disruptions in operations.
3 So if you look at that figure, on the 4 right-hand side, we're kind of rolling along 5 operationally, at normal power, and then an unplanned 6 event occurs.
7 And it's really how we respond and get 8 back up to normal operations that it is the measure of 9 our resiliency. So how deep we -- we go down that 10 drop, we'll say, is a d-rate.
11 And then, all the way down is a trip.
12 And, you know, depending on how prepared we are and 13 how well we've planned and how well we're hardened 14 helps -- helps with the -- the amount of -- of loss of 15 power, but also, the time of recovery, and our 16 efficiency helped shorten that time period, as well.
17 So while reliability is about reducing the 18 frequency of a disruption, resilience is about the 19 capability to avoid functioning during recovery of 20 that.
21 So you see the figure on the right, I 22 think most of us seen that, you know, we've got high-23 capacities in our industry, we've got robust design 24 margin and we've had relatively minimal impacts from 25 unplanned outages, with respect to internal events.
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97 1 And, based on these current capacity 2 factors, you know, unplanned outages account for about 3 three percent. There's a refueling component in 4 there, but unplanned outages, which include weather 5 impacts, account for about three percent of the total 6 availability.
7 And we're going to, kind of, take a deeper 8 dive into that. You know, the consensus -- hold on a 9 second -- well, consensus is that, that the weather 10 has -- you know, likely to worsen in the next couple 11 of decades.
12 It is regionally-based and severity is by 13 region and I'll talk a little bit today about what 14 we're providing, in terms of tools to -- to the sites, 15 to the -- for understanding a little bit more about 16 how those climate hazards may change in the future.
17 Next slide.
18 So just a little bit on what we're 19 currently doing, the current research, related to 20 design basis, extreme events, looking at external 21 hazards over the past ten years, what the significancy 22 of the -- the great East Japan earthquake and tsunami 23 and the accident at Fukushima, basically, provide us 24 two -- two key lessons learned implement -- related to 25 external hazards.
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98 1 The first, being portable equipment, you 2 know, we kindly refer that to, as flags, in the U.S.
3 And the second is, we -- we need an understanding, we 4 needed a continuous, systematic approach to monitor 5 for changes in external hazards, to make sure we're 6 staying current and how, either, the hazard, itself, 7 may change, or understanding that that hazard may 8 change.
9 So we've implemented a process based on a 10 recommendation, where we can continuously monitor 11 changes in, either, external hazards, themselves, or 12 -- or get an understanding.
13 It is very similar to a process that the 14 NRC has, it's called POANHI, and here we are, both, 15 the industry and regulator alike, monitoring for 16 changes and external hazards. Next slide.
17 One last bullet. I mean, our -- our 18 process has been in place for about, almost, seven 19 years now, since 2016. The process contains the 20 following, we develop a catalog. It's, kind of, 21 illustrated, on the right.
22 But we developed a catalog of credible 23 information sources of our external hand search, 24 namely, our seismic extreme heat, cold, extreme wind, 25 high winds, and flooding.
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99 1 So we're -- we're constantly monitoring 2 changes in those key hazards, but keeping an eye on --
3 on what's potentially coming down the lines, in terms 4 of new hazards, or new understanding of hazards.
5 We have reviewed over 1,100 pieces of new 6 hazard information, over the last six years that we've 7 been doing this. These encompass new precipitation 8 studies, a tsunami potential.
9 Recent one on NIST tornado maps, climate 10 change studies, and observations are creeping in more 11 and more. There's been some -- a -- a quite bit of --
12 of activity in the seismic hazard in MJ East and with 13 -- and are releasing some -- a NUREG on site 14 implications.
15 And so we -- we have some new information 16 on seismic hazard that we've been reviewing, over the 17 last year, and then every year we go through all the 18 operational experience that we see, from the INPO's 19 IRIS database, to see, you know, what's changing.
20 And, although, it may not impact the 21 design basis, it -- it certainly can give us a better 22 understanding of the types of challenges plants are 23 seeing. So the durational, for example, in Iowa, is 24 one. Frazzle ice hurricanes are -- are captured in 25 our operating experience.
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100 1 As I said, we have some new information 2 for 2022 and 2023, related to seismic hazard 3 information, with MJ East, site amplifications, and we 4 also have some new information that we've passed on to 5 the plants, relative to the mismatch that got folded 6 into the ASAE '07 and '22, I believe, it was, related 7 to the new wave maps.
8 So we are seeing new information and we 9 are evaluating that information for relevance, 10 credibility, significance, and if it passes our 11 significance threshold, we -- we pass it on to the 12 plants for further evaluation. Next slide.
13 So just a quick snapshot of the -- of the 14 -- the volume of information that we're looking at, 15 you can see, on average, we're reviewing about 100 16 pieces of new information.
17 Divided amongst those five external 18 hazards, some of the evaluations you see completed are 19 where we actually take a look at the significance of 20 the change.
21 And we've had some wind pressure loads 22 from ASAE, in 2018. A new PMP study in 2020, MJ East 23 subjunction, 2022. And then, in this year, in 2023, 24 we -- we've had MJ East, a recent reel that was 25 released by NRR, and we were in -- on site NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
101 1 amplifications, as well as, the NIST tornado maps. So 2 it gives you some sense of the volume.
3 Next slide. Next slide. We've packaged 4 all this up in a report that we publish once a year, 5 pass it on to the -- to the sites, for them to 6 basically capture meeting the commitment that they've 7 committed to in -- in the INPO Recommendations, so it 8 allows them to complete that.
9 Next slide. The next area focus is -- is 10 really climate risk, now, so we're going to move over 11 to a little bit of the operating side and not so much 12 the nuclear safety side.
13 And -- and this question is really related 14 to how climate change may present a physical risk of 15 the utility assets, primarily, on the operations side, 16 and what strategies are available to minimize future 17 consequences.
18 So if you think about the -- the 19 resiliency curve, it's all about trying to manage the 20 depth and the duration of that curve. Also, looking 21 at what existed in their research and help answer 22 these questions, with a good focus on -- on what are 23 the current -- what's the current OE telling us, then, 24 what is the climate signs telling us how those weather 25 impacts are going to change in the future.
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102 1 So next slide. Oh. Sorry. I forgot, 2 You're on that one. A little -- back -- back up. So 3 we put together a -- a white paper, actually, and 4 there's two versions of the white paper, one -- one 5 is, kind of, to the Members, themselves, and then it 6 has a couple additional topics to it.
7 But, we've published one for the public 8 that, basically, goes through and -- and reviews the 9 OE, on ten years' worth of weather-related events, for 10 the nuclear sites in the U.S.
11 Our goal was to provide some independent 12 research on nuclear resiliency, using our knowledge of 13 how plants are designed, how they're operated, to kind 14 of, at least, get that in context of what we're 15 getting in the more public publications of climate 16 impacts on plants. We wanted to do something within 17 EPRI that gave us a good basis for any future 18 research.
19 A couple of key points we wanted to make 20 in the paper was a clear distinction between nuclear 21 safety and operational impacts. Plants are a -- have 22 significant margins and -- and what we're talking 23 about, when these impacts occur, these plants always 24 prioritize nuclear safety over operational, and the 25 plants always have the ability to, basically, derate, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
103 1 or trip the unit.
2 But, what we're talking about, today, in 3 terms of resiliency is -- is how do we minimize those 4 impacts and become more reliable on the grid? So 5 we've put together a -- a review of the operating 6 experience, as I said, and I'll go through that, in 7 the next slide.
8 In -- in the paper that we provided to the 9 plants we -- we also presented some climate modeling 10 to get them some insights into how various regions in 11 the United States may change, in the -- in the next 20 12 to 50 years, and give them a sense of how those may 13 impact those hazards that are regional to those 14 plants.
15 We'll, also, finish the paper with how 16 climate data could be used by plants to really 17 evaluate future vulnerabilities, and that was going to 18 end up being the -- a little bit of our future 19 research on vulnerability assessments. So this was 20 all published in the paper, on the bottom that's 21 downloadable.
22 Next slide. So as I said, we've reviewed 23 ten years of weather-related operating experience, 24 about 200 items, and we categorized them into each of 25 our external hazards, high winds, flooding, heat, and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
104 1 cold.
2 And we, also, added a couple more that 3 were showing up, and then we -- while following -- and 4 lightening, were showing considerable impacts. We 5 noted, not only how many events occur over that time 6 period, but how the plant was impacted, either, a 7 derate, or a trip.
8 And then, really, for how long, so using 9 its capacity we could get loss-production days and 10 some frequency of the magnitude of these events. Not 11 all of the reported items resulted in loss of 12 generation.
13 So they -- sometimes, they were managed 14 and the other important point is, not every event is 15 reportable to INPO, in terms of their IRIS database.
16 So there is a certain amount of, I'll say, derating 17 that can be managed at the -- at the plant level, and 18 is not reportable. And --
19 MR. BLEY: And I'll just --
20 MR. CHOROMOKOS: -- you know, this is just 21 -- that we looked at, only 120, you'll see that in the 22 top table, where it resulted in loss of generation, 23 high winds, storms, and lightening impacts represent 24 over half of those 120 events.
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105 1 and hurricanes tend to impact less-robust transmission 2 and distribution. I'll stop, in a second. All right.
3 In --
4 (Simultaneous speaking.)
5 CHAIR BALLINGER: -- Dennis has a 6 question.
7 (Simultaneous speaking.)
8 MR. CHOROMOKOS: Sure. Dennis.
9 MR. BLEY: Yes. In just terms of the page 10 -- I mean, there might be other things like this, 2013 11 and 2014 have no biofouling events, which just seems 12 surprising that there would be none, in two years.
13 The other stuff, I can understand why there would be 14 none, occasionally, can you explain it?
15 MR. CHOROMOKOS: Without pulling the 16 report open, I -- otherwise, I couldn't explain 17 exactly why that just didn't occur those years. It 18 could be for a number of reasons, in terms of the 19 reporting. Like I said, it -- it may not have 20 amounted to a magnitude that was reportable. But --
21 MR. BLEY: Okay.
22 (Simultaneous speaking.)
23 MR. CHOROMOKOS: I appreciate the question 24 and I -- I -- I had -- I knew something was going to 25 pop up on this slide, so I was trying to have it open, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
106 1 but you caught me on why it didn't happen, not why it 2 did, so I can't speak to that.
3 CHAIR BALLINGER: Yes, this is -- this is 4 Ron Ballinger. What does strike me is that, we only 5 go from 2010 to 2020, how far back do you go?
6 MR. CHOROMOKOS: I -- I went from '10 to 7 '20. We picked a ten-year time frame, just as a --
8 just a figure of merit, to be honest with you. We 9 could have gone back, you know, another ten years, as 10 well.
11 A lot of things have changed, I'll say, in 12 -- in -- in -- from those ten years, so I -- I don't 13 know that I wanted them to show a trend, as much as I 14 wanted to show the types and the -- of events we were 15 seeing, in terms of significance. So I guess, I could 16 go back another ten years.
17 CHAIR BALLINGER: Thanks.
18 MR. CHOROMOKOS: Sure thing. All right.
19 So where I left off was just kind of distinguishing 20 between the top and bottom, and it was really around 21 the -- the high winds and storms, really, taking out 22 the grid, itself, in terms of the plant's reliance on 23 outside power, would generally trip the plant.
24 So although, the plant was derated or --
25 or tripped, it wasn't a result, necessarily, of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
107 1 plant, itself, it was the result of the -- the grid, 2 itself, the TMB infrastructure wasn't able to deliver, 3 or receive electricity, the plant had put itself in 4 the safe condition.
5 So what I did is I removed those frequent-6 related impacted and I wanted to get a good sense of 7 the plant, itself, and the loss-production days goes 8 down significantly, almost, to a factor of two.
9 So clearly it -- what's not surprising 10 that the grid is the weaker link, and I think we all 11 know that, but it did allow me to focus a little bit 12 more on what our -- what is actually happening at the 13 plant.
14 So in the end, I was able to basically 15 look at the lost generation. If you recall, at the 16 beginning, I was trying to understand the impact of --
17 of weather-related events on the unit, itself, in 18 terms of its capacity effect, and I found they were 19 less than one percent, which is extremely good.
20 But, as you know, past performances are 21 not indicative of a future return. So what we wanted 22 to do and -- and given the -- the science is telling 23 us that these could change, in frequency and 24 magnitude, beyond what we've traditionally seen, and 25 so what -- what can we start to take away from this NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
108 1 and what can we begin to work on?
2 So next slide. So the take-aways are, you 3 know, from a safety standpoint and I -- I think 4 everybody on this call would -- would largely agree 5 wit that, they're -- they're designed quite robust and 6 able to withstand the events far more significant 7 than most critical infrastructure, given our fuel 8 type.
9 But, based on OEE and the high-capacity 10 factors, the power plants have demonstrated resilience 11 to extreme events. Most major loss of production 12 events come from grid-wide challenges, as you -- we 13 all know, we maintain a significance amount of OE and 14 knowledge to build upon.
15 As he just said, we can go back many years 16 to see the types of events that have happened. We 17 have numerous seasonal readiness programs, lessons 18 learned programs, corrective action programs that 19 we're able to draw upon, in terms of our OE.
20 And, you know, the climate impacts can 21 effect operational resilience. Forward looking 22 assessments could be a benefit and allow them to have 23 a more strategic response to the future chronic 24 changes and -- and I'll say, just changing ambient 25 temperatures and events, as well as, extreme weather NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
109 1 events.
2 So I -- I think OE's been good and the --
3 the reality is here, how do we maintain that high 4 level, given that plant fossil retirements are 5 happening, the public is going to rely, even more, on 6 us for producing reliable, available generation, and 7 what can we do to ensure that we're always there?
8 So before that, any questions on past OE, 9 or -- or impacts that -- or -- or recommendations on 10 things to, maybe, include in going forward?
11 If not, we'll keep going. Next slide. So 12 as I said, you know, maybe, a future opportunity is to 13 -- is for climate risk assessment, and I'll talk a 14 little bit more about the -- the institute level, the 15 upper-institute level, not just nuclear, but across 16 the entire grid.
17 So the question is, what does climate 18 change mean for a -- a nuclear station, or any asset 19 on -- on the grid? It's really a sense of looking at 20 the hazard, itself.
21 What's exposed, what's in harm's way, how 22 is it vulnerable and how might it respond, and then, 23 how do we manage that vulnerability and how do we make 24 decisions, regarding managing that risk, and it all 25 begins with how climate change may effect that hazard.
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110 1 So that's the model we're going to use 2 going forward is, primarily, how did climate change 3 effect the hazard, what's in harm's way, what's 4 exposed, what's the vulnerability, the critical 5 thresholds that we're looking at, and then, how do we 6 manage that?
7 And then, I think, you'll see a question 8 at the very end that, I am still working through, is 9 -- is how do we manage that in a way that -- that can, 10 basically, be integrated with the existing priorities 11 the plant has, in terms of reliability and resiliency?
12 So next slide. So this was a -- a 13 starting point that we just published, about a year 14 ago, I believe, and -- what's today, 2022 -- and it, 15 just at a high level, started to look at, really, what 16 are those systems that, probably, have a -- a high 17 impact in -- in their cooling systems, right, those 18 come to mind, steam turbine and condensers, and then 19 physical impacts, as well, from the -- or changing 20 hazards.
21 And, really, they were involved around our 22 air temperature or humidity changes, water temperature 23 changes, flooding, precipitation, in terms of 24 operations, so these are the ones that quickly came to 25 mind.
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111 1 And, in the last column, there is, it's 2 you know, very impact on plant performance and 3 operation. I don't need to go into the details on all 4 those, because I think folks on this call probably 5 understand that, pretty well, in terms of derating or 6 tripping the plant.
7 So just looking at a high-level of how to 8 start that climate risk assessment and, what we want 9 to do now is take it into a deeper dive. So next 10 slide.
11 So the -- kind of an illustration, we've 12 been communicating with, in -- in terms of looking at 13 the future weather projections, on the left, is how 14 the climate will become and whether it will be 15 changing, it's really geared around, you know, ten --
16 out beyond ten years, 30 years, 40 years.
17 It's when you have to make some storm 18 decisions, in terms of investment, and not working on 19 the seasonable readiness aspect. That's, kind of, 20 well-in-hand, but really looking at beyond ten years.
21 Although, there is a gap right now, where 22 we're trying to cover, I'll -- I'll say, projections 23 out, you know, two to ten years that -- that, really, 24 climate models don't do well at, and I think there's 25 a gap we need to fill, in terms of that time period, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
112 1 and we're working on that.
2 But it's those weather projections, how 3 they impact the asset, in terms of exposure and 4 vulnerability, and those vulnerabilities may show up, 5 in terms of margin reductions, as I've showed you, 6 impact on capacity factor, they -- they could effect 7 life expectancy of components, environmental 8 permitting on discharge.
9 They could effect maintenance and when we 10 decide to run the failure, or decide to change our 11 maintenance interval, and then health and safety. And 12 then, really, when we see those thresholds, or see 13 those impacts, how do we park them in the existing 14 plant programs, to make sure they're being prioritized 15 and acted upon, in a way that helps reduce that backed 16 up curve that I showed you earlier, in terms of 17 resilience.
18 I think we're really good at -- at the 19 systematic process of looking at exposure and 20 vulnerability and we've got a lot of programs, at the 21 plant level, in terms of -- of -- of plant health and 22 long-term asset management, is making sure that we get 23 climate risk the right context, so that it can go 24 within those decision-making programs to build this.
25 Still working on that a little bit.
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113 1 Next slide. We did publish some recent 2 climate vulnerability assessment guidance, they're 3 focused on how to develop your climate hazards, at 4 your site, in your region, and your site, using 5 climate models, probably, a little bit beyond the --
6 the capabilities of a -- a normal site, with mere 7 engineer. I can speak to that.
8 What I'd like is to have the hazards put 9 into context, so that I can go ahead and evaluate 10 critical thresholds with, but we wanted to, at least, 11 lay out what and how you would go about standardizing, 12 or establishing, a climate hazard.
13 And then, exposure and vulnerability, it's 14 really a screening process of how to identify those 15 critical assets to, either, safety or reliable 16 generation, and how do you identify those structure 17 systems or components that may be impacted by weather-18 related variables?
19 So you can really think of a matrix of 20 critical systems and then, across the top, the various 21 climate hazards that impact those systems, and then 22 drill down and find out the limiting components and 23 work through those critical thresholds, so it's been, 24 kind of, the process.
25 So that's exposure and vulnerability, and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
114 1 after vulnerability would become really managing that 2 risk and we're -- we're not quite there, yet, but we 3 are working toward that.
4 I will say that, the INPO is -- is 5 actively involved in -- in this, as well, and has come 6 up with a resiliency -- or she's coming up with a 7 resiliency standard -- and they're also coming up with 8 some resiliency, I'll say, vulnerability assessment 9 guidance and we worked, somewhat, together, in terms 10 of giving plants the right tools and methods to -- to 11 respond to questions, regarding vulnerability.
12 (Simultaneous speaking.)
13 MR. CHOROMOKOS: So next slide. We did 14 publish a literature review on how to perform a 15 climate vulnerability assessment. Went out to the 16 DOE, to various system operators, to asset owners, 17 beyond nuclear and some within nuclear, in terms of 18 how to do a vulnerability assessment.
19 I'm going to talk a little bit about 20 ready, at the very end, but our -- our goal is to help 21 develop a consistent way of assessing vulnerability 22 and then, assessing and proving resiliency, rather 23 than individual side-by-side isotope-by-isotope 24 approach, so we're looking for some consistency in 25 establishing that framework.
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115 1 However, some plants have undergone, or 2 are planning vulnerability assessments. I know a lot 3 of the fleet is, it's -- it's starting to think about 4 that.
5 In fact, some have completed it and some 6 are doing it right now and we're also helping a plant 7 do a pilot of our vulnerability assessment guidance.
8 So our goal, with the pilot, is to get some lessons 9 learned and what's the -- or what -- what can be 10 improved?
11 What's the most efficient way, and how are 12 we actually proceeding through the vulnerability 13 assessment, so that we can perhaps incorporate some 14 lessons learned and -- and refine the guidance, 15 itself.
16 And then, last -- that last bullet is just 17 making sure we're producing measured results, we're 18 adding value, and we're increasing resiliency.
19 Finding the -- the vulnerability in the INPO 20 threshold.
21 Understanding the climate change to that 22 threshold is -- it's not, necessarily, the whole 23 story, with respect to resiliency, but that there is 24 a response component to it, how the people respond and 25 -- and, depending on some investments, you may want to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
116 1 wait -- make.
2 So I think, even the vulnerability 3 assessment, there's still more work to do in the 4 future, in terms of incorporating that into your 5 decision-making. Next slide and --
6 (Simultaneous speaking.)
7 MR. BLEY: It's Dennis Bley, again. One 8 thing you haven't mentioned is smoke and, over the 9 last three years, there have been some really massive 10 forest fires, here and in Canada that have effected 11 people in the States.
12 I don't know if they've any nuclear 13 plants, or other industrial facilities, but I'm 14 wondering, if you know of any cases where it had an 15 impact on operators, or other personnel, or even was 16 thick enough to cause problems with the solid state of 17 electronics?
18 MR. CHOROMOKOS: I -- I'm not personally 19 aware of that, and interestingly enough, I'll be on a 20 call, this afternoon, with Bruce Power and OPG, and 21 I'll be sure -- I'll bring that up to them, as well, 22 but I'm not personally aware of any.
23 MR. BLEY: Okay. Thanks.
24 MEMBER HALNON: Hey, Rob, this is Greg 25 Halnon, just a quick question, as we go through this.
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117 1 There's -- there's really two impacts has on plants.
2 One, is the physical aspect, which is obvious, the 3 freezing and -- and other things.
4 But the other one's the -- the regulatory 5 impact, and sometimes, extreme heat causes a ultimate 6 heat sink to be inoperable, and then there's a 7 shutdown, or -- or a derate, and -- or, some other tec 8 spec issue.
9 Had -- is there a distinguish -- I mean, 10 a -- a -- a line between that and your studies on what 11 is a physical impact versus a regulatory impact?
12 MR. CHOROMOKOS: If they're both captured, 13 probably, could categorize -- I mean, I can -- I mean, 14 I could shift the data, but --
15 MEMBER HALNON: Because, when we're 16 talking about resiliency of a -- of a nuclear plant --
17 I mean, clearly, it's -- there's a -- physical limits, 18 probably, predominant.
19 I mean, I'm -- I would imagine, the 20 regulatory impacts are much on the small subset, but 21 it would be interesting to -- to see how you might 22 deal with the resiliency, through analysis and 23 regulatory change, or license change, versus a 24 physical modification to the plan or procedure.
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118 1 through this, that -- that -- the -- I've had both 2 happen to me, in the past, and probably equally, so I 3 was just curious, if there was something 4 distinguishing in this study, or not, but it sounds 5 like you've --
6 CHAIR BALLINGER: No that's a good point, 7 an ultimate heat sink, I -- I think a lot of the 8 plants have that type of mind, in terms of -- I mean, 9 that's part of the goal of the vulnerability 10 assessment is tell me -- project out, when I may be 11 encroaching on my -- my discharge limit?
12 Or I, you know, when do I need to have 13 them in OED and -- and those type -- when do I need to 14 go in for a license amendment to change a tec spec 15 limit? I think, those are all the questions that we 16 would want to be able to answer through such --
17 MEMBER HALNON: That's in the 18 vulnerability assessment process then?
19 (Simultaneous speaking.)
20 CHAIR BALLINGER: That -- that should be 21 an outcome of it, right, finding out where those are, 22 vulnerabilities were --
23 MEMBER HALNON: Okay.
24 (Simultaneous speaking.)
25 MEMBER HALNON: Thanks.
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119 1 CHAIR BALLINGER: Yes.
2 MR. CHOROMOKOS: So -- so I'll -- getting 3 back to the assessment, the vulnerability assessment, 4 again, we started with climate hazard projections, 5 EPRI has offered up a, what we call supplemental, 6 which is, kind of, ala cart.
7 Clients can pick and choose, if they want 8 to participate in some projects, and this project was 9 all around getting those plants that are starting on 10 their vulnerability assessment, what are the inputs 11 they're going to need, what are the projections, what 12 are the key variables that are impacting their 13 location, their site, and how will those variables 14 change, over time.
15 A nice opportunity for plants to get, kind 16 of, a, I'll say, introduced to -- to climate hazard 17 projections, climate change, understand a little bit 18 of the science, the uncertainty, the inputs that are 19 used.
20 And it was a really good opportunity for 21 the engineers to get with the climate science folks 22 and make sure that the data is coming across and 23 usable, in terms of looking at vulnerability, from an 24 engineering standpoint.
25 So a really good project, in terms of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
120 1 climate hazard projections, for the plants doing those 2 assessments. Next slide.
3 MEMBER MARTIN: Oh, this is Bob Martin.
4 MR. CHOROMOKOS: Sure.
5 MEMBER MARTIN: I just wanted to ask a 6 question, on the previous slide. Does your assessment 7 also consider, say, maybe, increased -- maybe, an 8 increase in the likelihood of grid instability?
9 You know, certainly, the Texas cold 10 weather event, from a couple of years ago, you know, 11 showed the, you know, the impact from, you know, the 12 loss of other power sources, you know, and -- which, 13 of course, where the nuclear power plant is good, you 14 know, be translated into a loss of off-site power. It 15 seems like --
16 MR. CHOROMOKOS: Yes --
17 MEMBER MARTIN: -- that the focus is 18 mostly local, than site-specific, but also, the 19 relationship to the grid, overall, is that captured it 20 in the -- in the report?
21 (Simultaneous speaking.)
22 MR. CHOROMOKOS: No, it's not. And -- and 23 it -- it's a -- and, if I'm understanding it 24 correctly, I -- I -- I think I talk a little bit about 25 the -- a -- the system, the power flow analysis, the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
121 1 system analysis that's going on, right now.
2 But I -- I think the plants are, largely, 3 reacting to the grid impacts. Certainly, you know, if 4 the -- if -- if a -- a hurricane's going to happen, or 5 an extreme event's going to happen, the client can be 6 asked to derate, or asked to down-power, but I -- I 7 think, when a lightening hits, or they trip for a loss 8 of off-site power, I -- I think that's more of a 9 reaction than a planned -- planned -- plan known, I'll 10 say, maybe. But I think that's a good question on --
11 on -- on how the plants respond to that, but I -- I 12 think they're more reactionary than anything else.
13 (Simultaneous speaking.)
14 MEMBER MARTIN: Sure. Thanks.
15 MR. CHOROMOKOS: Sure. Next slide. So 16 yes, I -- I talked about the vulnerability assessment 17 steps, so you know, this is exposure and -- and what's 18 in harm's way. I'll quickly go through this.
19 It's really the process of identifying all 20 plant SSEs, important stable reliable operation to 21 plant, we want to focus on those system that can trip 22 and derate the plant.
23 The real question is, you know, we don't 24 have a -- a nice -- a nice list to pull from, so we --
25 we're, kind of, going through that process, right now.
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122 1 In fact that's my aim this afternoon with 2 several plants, is how can we provide enough guidance 3 so that, systematically, you guys can go through and 4 identify all those SSEs that are potentially exposed 5 to weather-related impacts that can, basically, trip, 6 or derate the plant.
7 And it seems straightforward, but we just 8 want to make sure that we're providing all the 9 guidance and tools that they -- that we can, to make 10 sure they can do this in a consistent way.
11 Next slide. So the vulnerability 12 assessment, again, I just spoke to that, plants are 13 kind of in the process of doing that, they're looking 14 at those systems.
15 They've, kind of, identified the systems 16 important to generation, and now they're going through 17 each one of those systems and looking at the 18 vulnerable components, the -- the operating limits and 19 thresholds.
20 And then we can go ahead and take a look 21 at how those weather variables are challenging those 22 thresholds, in a way that can negatively impact a 23 plant.
24 And, we're still working through a little 25 bit of how we present that, you know, damage NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
123 1 functions, fragility curves, are -- are at somewhat 2 comfortable to us, we -- we know how to do those, as 3 nuclear unit, as a nuclear industry, trying to do 4 those in a consistent way, across all great assets, is 5 something we're looking at.
6 But, again, I -- I'll probably have more 7 to share on that, the next time, relative to what --
8 how we present the risk, in -- in terms of each key 9 thresholds and the uncertainty of associated with the 10 -- the climate variables.
11 But, we're in the process of identifying 12 all the critical thresholds through our vulnerability 13 system and, again, how do we prioritize with -- with 14 these results, is the next step, in terms of plant 15 health committee and asset management, and we're, kind 16 of, in the process of working through that, still, 17 still -- still on a journey here.
18 Next slide. So as I said, for -- for 19 2024, we're on -- we're looking at that next step, 20 already, so we're -- we're looking through practical 21 implementation of vulnerability assessments.
22 And we're starting to look at adaptation 23 strategies, how do we monitor them, how do we make 24 sure that we're getting the -- the -- the climate risk 25 incorporated into the programs, to build this IMC.
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124 1 This may include developing strategies for planning 2 implementation. It does definitely interface with 3 existing plant programs.
4 And, I think, our goal is to leverage all 5 the existing programs that plants have today, just 6 making sure that we're giving climate risk the right 7 context to be, I'll, I'll say, appropriately 8 considered in -- in terms of, all of their decision-9 making, as they allocate resources to plant upgrades, 10 or modifications.
11 Next slide. So I have two more slides 12 and, again, I wanted to just touch on, you know, 13 Climate READi, which is resiliency and adaptation 14 issue, R-E-A-D-I.
15 It is across the institute, so it's not 16 just nuclear, it covers all grid assets. And it, 17 basically, the -- it -- it's goal is to develop a 18 common framework, across the power system, develop a 19 comprehensive, informed, consistent approach.
20 And then, really, it's -- it's tailored 21 toward physical risk assessments, so it's really 22 making sure that we can get comparative answer 23 relative to investment strategies.
24 It's broken down into three work streams, 25 which are very similar to the climate physical risk NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
125 1 assessment on exposure and vulnerability that I showed 2 you, earlier.
3 But, the first work stream is -- this is, 4 both, climate data and guidance, it's where your 5 climate 101, it's where You're aggregating all your 6 data, your climate models, to really get through best 7 -- best science, in terms of how these weather 8 variables are changing, over time.
9 Work Stream 2 is, really, the 10 vulnerability assessment, it's what I've talked about 11 a lot today and where nuclear is primarily focused and 12 we, kind of, pipe up through Work Stream 2 and so is 13 our non-nuclear, our renewables, our transmission 14 distribution, all of those physical assets, kind of, 15 come up through Work Stream 2, in terms of a -- a 16 vulnerability assessment.
17 And then, Work Stream 3 was, well, what we 18 talked about, in terms of, how does that all feed a 19 power flow, or a system analysis, knowing that what --
20 what they're looking for is to model the grid.
21 They're looking to know, what is the 22 generation output, as a function of a weather variable 23 and, basically, put those in, as knows, and then model 24 climate change and demand a response to the system and 25 see how it reacts, and hopefully it will give insights NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
126 1 into where you need to invest to -- for the future, 2 for increased resiliency.
3 So that's, kind of, Work Stream 3, a -- a 4 pretty good initiative. But we're primarily focused 5 on Work Stream 2, at the moment, but I'm really 6 interested to see how the power flow and the system 7 analysis goes in Work Stream 3.
8 Our deliverables are actually in the 9 guidebooks. Again, it's what we're trying to promote 10 a consistent way across all the asset classes, on how 11 to do these physical climate risk assessments and 12 identify research gaps, and then fill those gaps in 13 the future.
14 Next slide. The last slide, here, is just 15 showing who some of the climate-ready numbers are, 16 mostly, system operators, but a fair number of them 17 have a nuclear units in there, so we've got a fair bit 18 of nuclear participation.
19 You can see AP, or D.C. Cook, BG&E, 20 FirstEnergy, Ameren, Vistra, so TBA, Southern Company, 21 so we've got quite a bit of nuclear representation and 22 Climate READi, as well.
23 Climate READi is scheduled to take about 24 three years, and we're about half-way through, and 25 right now, we're kind of in the thick of looking at NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
127 1 vulnerability assessment, so more to come.
2 So that brings me to my last slide, any 3 questions, I'd be happy to take them.
4 MR. SCHULTZ: Rob, this is Steve Schultz.
5 Just looking -- looking at your last slide, interested 6 to see that, you don't really have full utility 7 participation, especially, in some of those areas of 8 the country, where you might expect readiness to be a 9 -- an important factor in their overall planning.
10 Do you anticipate additional utility 11 participation, as you move forward with your program?
12 I'm thinking of Louisiana, Texas, Carolinas, Florida.
13 MR. CHOROMOKOS: We'd love to have them 14 participate, but I -- I can't speak to them, you'd 15 have to ask them, for sure. But, you know, I -- there 16 are -- I know, there are plants that are not in ready 17 -- there are utilities that are in ready that are 18 undertaking, I'll say, their own studies.
19 So I -- I -- I think, they're happening, 20 because it may not be happening through READi, in 21 terms of developing the consistent framework. And 22 I'll -- one thing I will add is, we have members that 23 I showed you, on the -- that graph.
24 We also have a group of stakeholders, 25 we'll call them, we call them Affinity Group Members, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
128 1 which are stakeholders, such as academia, PLE, -- the 2 labs, for example, consultants, so we've got a -- a 3 fair number.
4 I mean, almost over 80 of these Affinity 5 Group Members that are supplying some of their 6 knowledge and -- and insights into developing this 7 framework, so I think we're getting the benefit of 8 industry knowledge, it's just we're not getting full 9 participation.
10 MR. SCHULTZ: Okay, and I thought there 11 might be a way to fold in the information that could 12 be gathered from those utilities that may have been 13 working on this for a few years already and could 14 include their experience in the overall program.
15 (Simultaneous speaking.)
16 MR. CHOROMOKOS: We'd love to have them.
17 MR. SCHULTZ: I hope you get it. Thanks.
18 MR. CHOROMOKOS: As you know, it's a 19 voluntary, not a mandatory, so.
20 MR. SCHULTZ: I understand those programs, 21 yes.
22 CHAIR BALLINGER: Thanks, Steve.
23 MR. CHOROMOKOS: All right. So I'm going 24 to pass it over to -- to -- to John Black. I didn't 25 know it was Job. John, did you change your name, J-O-NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
129 1 B, that -- but, we're going to talk about, ultimate 2 heat sink, a little bit. So, John, take it away.
3 MR. BLACK: Thanks, Rob. So I'm John 4 Black and I've run our Aquatic Resource Protection 5 Programs, so I'm -- I'm the odd one out here, as 6 probably the only Fishery Biologist on this call.
7 And so you may be asking, well, why is a 8 Fisheries Biologist involved in ultimate heat sink?
9 Well, it really stems going back to about 2004, when 10 EPA was drafting requirements for fish protection, 11 under 316(d).
12 We started spending a lot of time at 13 cooling water intakes, thinking about how you would go 14 about retrofitting for fish protection technologies.
15 And in so doing and talking to operators, it really 16 became evident that, issues around debris and 17 biofouling were really a much greater concern and 18 that, actually, this offered an opportunity, perhaps, 19 to kill two birds with one stone and protect fish, 20 while at the same time addressing some of these debris 21 and biofouling issues.
22 So we started a -- a -- an internal 23 interest group, which I'll tell you about, here in a 24 minute, and -- that focused on those operational 25 issues and that is still going on today and that --
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130 1 that's how I became involved on -- on this side of the 2 house.
3 I've always worked closely with engineers.
4 I was 17 years a consultant, mostly, with Alton 5 Research Laboratory, and a consultant to EPRI, and 6 then, seven years ago, I joined EPRI.
7 So thanks for letting me speak today and 8 -- I -- I think Rob did a really great job, sort of, 9 setting up how we're thinking about climate risk and 10 improved resilience, here, at EPRI.
11 And, now, I'm going to just, sort of, 12 focus in on the intakes and the cooling water. And 13 with that, I will, in trying to catch up to a little 14 time here, I will go quickly through a couple of 15 slides, at the beginning, and then, because I really 16 want to get to the research that we're actually 17 implementing.
18 So next slide, please. We can skip that, 19 next slide. So we know that this long-term ecological 20 change is happening, it is something we need to get 21 our arms around.
22 And it's hard, again, as we look at the 23 specific level downscaling, we have these great big 24 wonderful climate models, at a much higher scale, but 25 as we start trying to figure out what this is going to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
131 1 do, at the individual power plants, and how that might 2 effect reliable sources of cooling water that's where 3 -- that's where we're -- I'm focusing my efforts in 4 research, here, at EPRI.
5 Next slide. So yes, we know that keeping 6 reliable sources of cooling water, today, is a 7 function of making sure that the cooling intake system 8 equipment is ready to operate.
9 That the operators are responsive to 10 events that are happening, and that there is adequate 11 preventative maintenance happening to these systems, 12 so that when they're needed, they're easy to operate.
13 So in general, as you saw, from Rob's 14 slides, on the number of outages, as a result of 15 debris events, while they're somewhat manageable, in 16 quotes, today, we are seeing very -- increase in 17 frequency, intensity, and duration, there are new 18 types of debris showing up at intakes that weren't 19 there, previously.
20 As the species composition and abundances 21 in the source water bodies is changing, what's showing 22 up at the intake is also changing. And so many of 23 these systems were designed and optimized for very 24 specific types of debris and biofouling, they now need 25 to reconsider what's happening.
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132 1 And, as Rob mentioned, these systems are 2 aging, as well, a lot of the equipments may need, it's 3 a balance, right, between life of the plant and how 4 much You're willing to invest, but it may also be 5 important to do so, to make these plants resilient to 6 these new types of challenges.
7 So understanding this, then, requires that 8 we evaluate the current operation and -- and OE, for 9 these cooling water intake systems, upgrade aging 10 equipment, as necessary, develop and test new novel 11 approaches.
12 And, as you'll see, in a minute, we've 13 also been focusing on developing forecasting systems, 14 so that operators can be prepared ahead of time for 15 these events, before they actually happen, which 16 allows them to, you know, scramble and -- and -- and 17 make, either, operational changes, or just have 18 equipment and -- and manpower ready to address them, 19 when it occurs.
20 Next slide, please. So on the right, 21 here, you know, this is what I think about, when I 22 think about intake reliability. It's going to be --
23 it's the function of the structural, functional, and 24 operational design of the equipment.
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133 1 adequate maintenance and that the staffing is well-2 trained and prepared for the types of events. In the 3 first, main bullet, here, we're talking about current 4 conditions.
5 You would -- you need to maintain 6 compliance with your -- any regulatory requirements, 7 and that includes, both, on the intake side, but also, 8 as we were talking, earlier, on the discharge side, 9 them changes in -- in the temperature, at the outfall, 10 and what that might do to your 316(a) requirements.
11 You need to be mitigating for fouling and 12 managing debris, and you need to be performing O&M and 13 preventative maintenance. That's under normal 14 operations.
15 You're also prepared today for these upset 16 events, these abnormal operations, you need to be able 17 to anticipate and then manage them when they happen.
18 But again, as we think about it, into the future, we 19 want to be monitoring long-term data trends and 20 observational data, so that we can help predict 21 changes and evaluate the existing equipment, under 22 these new scenarios that we're anticipating.
23 Next slide. So as -- well -- this is the 24 time, now, to be thinking long-term. It's not about 25 the issues that are going to happen next week, or next NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
134 1 month, this is about things that are going to be 2 happening on a decadal scale, sometimes.
3 We want to be having good communications.
4 When we understand some of these changes, what we're 5 anticipating, that needs to be communicated throughout 6 the -- the staffing, so that the -- we can review the 7 operational capacity and performance and existing 8 operational experience, not just from here, in the 9 U.S., but also internationally.
10 And then, if -- if necessary, take action 11 and revisit the design basis. And this may not 12 happen, in all cases, depending on what the -- the 13 estimated level changes might be, but examples of this 14 might be changes in water quality that might change 15 the corrosion potential of that water and -- and the 16 selection of materials.
17 It might include changes in water levels 18 and what that might do to pump habitation and the 19 like, so there are many things that we can be doing, 20 if we have a clear guidance, as to where things are 21 headed that we can anticipate and -- and implement, 22 going forward.
23 Next slide, please. So many of you are 24 probably familiar with the imposed SOER 2007-2. Part 25 of that, we've been talking with operators and power NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
135 1 companies and most of this is fairly straightforward, 2 but we're getting feedback, especially, on 3 Recommendation 1, which is, sort of, monitoring these 4 long-term environmental changes that, that has been a 5 real challenge.
6 Because the question is, what are you 7 looking for, so which parameters should you be 8 evaluating, how do you go about monitoring them, at 9 what frequency would you do that, how would you 10 analyze those data?
11 So there's a -- there are a lot of 12 questions, and so -- yes -- a project we would like to 13 initiate, going forward, would be to help develop some 14 guidance on -- on what that might look like.
15 And, of course, this might change on a 16 site-specific basis, based on the types of water body 17 from which You're withdrawing and other factors. So 18 -- but there certainly can be a -- a framework under, 19 which this would be much easier to develop. Again, 20 the -- as these things change, we have to be prepared 21 to -- to implement these, going forward.
22 Next slide. So one of the documents that 23 we just published, in 2021, is the best management 24 practices for preventing cooling water intake 25 blockages.
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136 1 This is a guidance document that we had 2 previously, but it was several years outdated, and a 3 couple of things that have changed, since then, we've 4 now included a lot more international experience and 5 -- and data from international events.
6 There are also a lot more new screen 7 designs that are available for travel and water 8 streams, downstream of the bar racks, upstream of the 9 circ water pumps, these -- the -- the screen types now 10 include polymer screen, multi-disc screens, and others 11 that you wouldn't have seen implemented, in the field, 12 ten years ago.
13 And the -- I -- what I think is also nice, 14 here, is we've included, both, successful and 15 unsuccessful mitigation attempts, lessons learned from 16 unsuccessful application, is often, as beneficial, as 17 successful applications. It just adds to the body of 18 knowledge we have available, for operational 19 experience, or debris management, at intakes.
20 Next slide. I also want to tell you about 21 an intake maintenance guide series that we've put 22 together. We can go to the next slide, please. So 23 yes, this is another guidance document that was -- it 24 used to be a single volume and was quite outdated.
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137 1 into three separate guides, and they roughly travel 2 from upstream to downstream, through the intake 3 structure.
4 So the first volume covers stop gates, 5 trash racks, and trash rakes. The next volume, Volume 6 2, covers the travel and water screens, or whatever 7 your fine screening technology, in Europe, it's often 8 drum screens, and then the final one is, once that 9 debris is removed, what are your options for debris 10 disposal?
11 So again, there's a lot of new 12 technologies out there that weren't in there, in that 13 other one, there wasn't much in the way of 14 international information that's, now, in there.
15 And, in talking with providers of 16 technologies, we've recognized that the maintenance 17 practices have also changed. This has been a cross-18 sector collaboration.
19 So we brought in information from fossil 20 plants, as well as, nuclear power plants, because in 21 many ways, a cooling water intake is a cooling water 22 intake, and we've developed preventative maintenance 23 templates that are being added and updated.
24 And so members are able to get a framework 25 under, which they can figure out their preventative NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
138 1 maintenance schedules, which components need to be 2 replaced, how to determine those, and make 3 inspections, so some information, there, as well.
4 Next slide. So to put these maintenance 5 series guides together, we looked at publicly-6 available information, we made interviews with 7 different vendors, we talked to architectural 8 engineering firms, who are working on cooling water 9 intakes.
10 We reviewed a bunch of equipment manuals, 11 for O&M, and again, these -- these -- this series of 12 guides provide description to the different 13 technologies, how -- what the PM recommendations are.
14 And in the next slide, you'll see, what we 15 found, to be the primary modes of failure for -- I'm 16 -- I'm focused here, on the traveling screen, so 17 Volume 2, and I just wanted to point out a couple of 18 these things, and I'm not going to read through these.
19 But, if we think about biofouling, of 20 course, that's now being changed, as global climate 21 change happens. If we think about corrosion, that's 22 also changing, as a result of water chemistry changes.
23 So a lot of these are dynamic. The -- the 24 way that things were handled, the way that they were 25 -- the maintenance that was done to these systems, ten NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
139 1 years ago, may not be the same today and, certainly, 2 won't be the same going forward.
3 So new -- different -- this may be 4 selecting different materials, it may be the frequency 5 of inspections, there's -- and there's guidance in 6 there about -- about all of these aspects.
7 Next slide. So just a couple of other 8 examples of intake-related research that we're doing 9 that I wanted to share with you. The first, is we're 10 working with one of our utilities, at a -- at one of 11 their stations, in -- in the -- in the Southeast U.S.,
12 where they have a major issue with aquatic floating 13 vegetation that has caused some derates and shutdowns, 14 historically.
15 That seems to be up-ticking, over time, 16 which may be partly due to climate change. It also 17 has to do with the establishment of the new aquatic 18 vegetation in the reservoir.
19 They have gone about and changed their 20 screens and they also changed their bar racks and 21 raking system with more narrowly-spaced bar racks and 22 a -- and a racking system that can operate 23 continuously.
24 But, despite that, they want this to never 25 happen again, so they are exploring additional NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
140 1 measures they can do. So we are engaged in a multi-2 year evaluation of air bubble curtains to -- the 3 divert some of that debris, before it gets to the 4 intake structure.
5 So we just completed the first phase of 6 that, which was primarily just getting -- gathering an 7 analysis and understanding the -- the issues. We are 8 now doing hydraulic modeling and an evaluation of 9 engineering designs and, eventually, we'll put 10 together a pilot test, hopefully, for 2025. So that's 11 that project.
12 Next slide, please. I mentioned that we 13 had -- we started that interest group, back in 2004, 14 when we were talking to operators and realized that 15 debris and biofouling issues were a major concern.
16 This is a informational exchange forum.
17 We bring together the members, we help develop EMP, to 18 address emerging issues. We transfer information, 19 through Webcast, workshops, newsletters, and tech 20 briefs.
21 Our next upcoming workshop will be in --
22 in Pennsylvania, in November, so we're looking forward 23 to that. Our hope here is that, we can minimize, or 24 prevent, unscheduled outages, keep everybody up to 25 date on the newer technology that are out there.
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141 1 We're available on-call, to help when 2 issues arise and, hopefully, it's an opportunity for 3 members just to be able to network and stay informed.
4 Next slide.
5 And I wanted to point out that we have 6 several tech briefs that have come out of here, on 7 different types of biofouling, or debris, issues and, 8 each one of these, they, you know, they range in 9 length, but they're all about a dozen pages, or so 10 that, pretty succinctly pull together information 11 about those species, what -- what the issues are, what 12 kind of problems they can present, and then, potential 13 solutions for those issues.
14 There's also information in there, about 15 experts in the field. So there are ways you can reach 16 out, use that information to reach out to people if --
17 if necessary.
18 So next slide, please. We also -- so one 19 of the things that we're very interested in doing is 20 developing a forecast -- oh -- forecasting systems, so 21 a way for operators to get some amount of heads-up, 22 ahead time, before these debris and biofouling issues 23 arise, which is more debris-focused than biofouling.
24 But we -- if we think about some of the 25 major upset conditions, these are often like jellyfish NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
142 1 blooms, or large debris -- aquatic -- aquatic floating 2 vegetation that comes in and overwhelms the screening 3 systems.
4 So we have, if we move on the finger, on 5 the right, from right to left, we have far-field, mid-6 field, and near-field. In the far-field, we want to 7 be looking for the first indication that there may be 8 the development of material in -- in the water body.
9 So this could be done, remotely, through 10 satellites, it could be done through hydro-acoustics, 11 or other in-water sensors, as we get closer we -- we 12 also had sensors in the water.
13 These can then help tell, actually, 14 calculate the amount of biomass that might be present, 15 it can start to tell you about the route, in which it 16 is -- it is moving, and the timing, in which you think 17 it might actually be there.
18 And then, in the near-field, we're 19 actually confirming the arrival of the events, and 20 this may give operators several days' notice about 21 these events, again, to prepare, start looking at the 22 screens more frequently, whatever it is they might 23 have, as their backup plans.
24 And we're -- we're working on other pieces 25 of this and, depending on the system and the types of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
143 1 debris, there may be biological pieces that could be 2 included in here.
3 For example, if you know that, when water 4 temperatures drop below a certain amount, the 5 organisms would've rooted to the bottom, die off, and 6 they float to the surface and then become that mass.
7 So you know, or it could be wind 8 direction, so meteorological data, there could be all 9 sorts of pieces that could be fit into these models.
10 What you would do, in theory, is you 11 would look at data sets, where you -- where you have 12 conditions, under which these -- the debris events 13 happened, previously, and try to hind-cast, or 14 understand those trends.
15 But, it only happened at certain 16 temperatures, or when the wind direction is from a 17 certain direction, or when -- whatever those 18 conditions are, so that you can then develop your 19 model.
20 And these, of course, have to be site-21 specific, based on each plant's unique set of 22 circumstances.
23 MR. BLEY: All right --
24 MR. BLACK: Next slide.
25 MR. BLEY: -- this is Dennis Bley --
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144 1 MR. BLACK: Oh.
2 (Simultaneous speaking.)
3 MR. BLEY: Can I ask you a couple of 4 questions about this one? This is a --
5 MR. BLACK: Sure.
6 MR. BLEY: -- reference manual, so I 7 suppose it's a -- a plant owner, but some --
8 especially, the far-field thing, seem like things 9 that, perhaps, the Government ought to be doing.
10 I don't think that it's within your 11 purview of what -- what EPRI might do, but you can 12 correct me on that, far-field, maybe, even mid-field, 13 are things that would effect multiple facilities, not 14 just one particular nuclear plant, and require some 15 technologies that -- that, based on the surface, and 16 a little unlikely to be done, by an individual plant, 17 it could be done by a group of plants, or by the 18 Government, trying to protect our infrastructure, is 19 there any effort going on with Government agencies to 20 participate, or anything along the lines that I was 21 just talking about?
22 (Simultaneous speaking.)
23 MR. BLACK: Yes that's a great questions, 24 and I'll -- I'll just preface my answer to say, it 25 also really depends, a lot, on the complexity of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
145 1 hydraulics of a -- of a system, whether it's, you 2 know, unit directional river, for example, or in a 3 estuary, where you -- where you have ebbing and 4 flowing tides.
5 But, certainly, tapping into publicly-6 available data sets is -- is -- is an option. So for 7 example, in -- in some systems, the National Oceanic 8 and Atmospheric Administration may have buoys that 9 have sensors, or -- including, meteorological data, 10 but some of them also have flow sensors on them.
11 And tapping into, you know, satellite 12 data, I don't know how much of that Government stuff 13 is available. There are certain private entities that 14 can supply that information, at a nominal cost, You're 15 not launching your own satellite system.
16 So the -- the guidance, here, it really 17 just lays out a framework for deciding how you would 18 go about putting together a forecasting system and 19 things you would consider.
20 Again, each system is going to be a little 21 unique and -- and really need to -- some thought put 22 in and understanding, sort of, how that system works, 23 in terms of, what are the fouling You're likely to 24 encounter and, how does it travel through that system.
25 But that's a great question. Yes that --
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146 1 we don't have any active conversations with the 2 Government, to try to tap into those, but I think 3 there probably are some data sets that could be used.
4 MR. BLEY: Are you providing any guidance 5 on how to access those data sets in this manual?
6 MR. BLACK: No, sir. This is -- this is 7 just explaining the -- the types of data that would be 8 beneficial, not how to access them.
9 MR. BLEY: And, I guess, the last thing, 10 along this line, is have -- have the members shared, 11 you know, have you had discussion groups with the 12 members, about how this might progress in the future?
13 MR. BLACK: Yes. In fact, I'm going to 14 tell you about another project here, if time allows.
15 I know we're short on time, about -- about a follow-on 16 project to this.
17 But we are also -- this whole intake 18 resilience and reliability work that we're launching, 19 we -- we will be -- we are having conversations one-20 on-one with utilities and, also, at our upcoming 21 annual meeting, we're going to have, very much, a 22 discussion session focused on where do we need to be, 23 focusing our efforts to bring -- to bring this 24 technology forward for more broad-scale application.
25 MR. BLEY: Okay. Thanks.
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147 1 MR. BLACK: Next slide, please. Go ahead 2 and see -- let's skip ahead. We can skip that. So 3 I want to tell you, another project we are working, we 4 have some internal EPRI funds, to evaluate a drone, 5 fitted with clean equipment for cleaning bar racks.
6 Our bar racks get covered in barnacles and 7 oysters and muscles and all sorts of other biofouling 8 organisms, if you really disrupt the flow into the 9 power plant.
10 Traditionally, you need to clean these 11 with divers, and it -- there are automated cleaning 12 systems, racks and rakes, but the really hard, 13 attached biofouling requires some literal scraping.
14 You can remove racks and -- and put -- put 15 on then, in their place, but often times, if You're 16 using divers, that is a real risk to the divers, human 17 health and safety risk, but it's also, often, it has 18 to be done under -- when the plant's not operating, 19 because again, for diver's safety, you don't want them 20 in there, under full-flow conditions.
21 So we are looking at using drones to take 22 the place of divers, for -- for doing this type of 23 cleaning. We have selected a -- a site for a demo.
24 We will be going down there -- I'll be heading down 25 there, in November, to Florida, to see the site and --
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148 1 and figure out the support that we can get from the 2 station and our plan is to actually demo that 3 technology in early-2024.
4 I should just add one other thing, here.
5 It doesn't necessarily have to be a free-floating 6 drone, like you see in the top, right picture, it --
7 really, we just need a stable platform, from which, 8 these, either, jets, or blasters, or -- or -- or 9 brushes can be deployed.
10 So it -- it may be a rack that goes in 11 front of the bar rack and it's -- and it's on that --
12 that it -- that the bot moves around and does the 13 cleaning.
14 But, anyway, this is a -- this is a really 15 exciting opportunity. I -- I think it has great 16 potential to blow up, in terms of O&M cost savings, 17 but more importantly, for human health and safety.
18 Next slide.
19 MR. BLEY: Jonathan, Dennis, again. Any 20 thoughts on coatings, of any sort that might help this 21 problem?
22 MR. BLACK: I -- I -- so coatings is an 23 area of active research, at EPRI. Dave Olack is on 24 the line and is -- runs our coating program. And, 25 Dave, did you want to say any words?
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149 1 MR. OLACK: Yes. Thanks, Jon. Yes, 2 coatings from -- for, you know, many immersed 3 surfaces, is it on -- is ongoing, you know, research 4 work with EPRI.
5 And there are -- we have done some 6 hydrophobic-type coating projects, in the past, and --
7 and that work will continue into the future. But --
8 yes, coatings are -- are definitely of -- of interest 9 in -- in the intake system, overall, whether it's 10 hydrophobic, or any other coating product.
11 MR. BLACK: So I think is my last slide, 12 and this is a project that Dave and I are working on.
13 Again, this is, sort of, the next step in this whole 14 forecasting system.
15 Depending on the complexity of the system, 16 you may have a lot of different data inputs into --
17 into this forecasting system. Again, it could be 18 meteorological data, hydrological data, it can be 19 biological data, it could be all -- all -- all sorts 20 of different pieces here, including possibly, either, 21 an overlaying on a computational fluid dynamic, hydro 22 -- hydrodynamic model.
23 And, one of the big questions is, really, 24 a -- a data analytics question and that is, how do you 25 take all of these data sources and integrate them into NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
150 1 a way, one, you want it to be near real time, because 2 you want to be able to make decisions quickly.
3 And, second, you -- You're dealing with 4 this geo-reference data and sometimes 3-D data that's 5 been -- can we integrate those into a single model 6 output that would then be used, as part of this larger 7 forecasting system.
8 So the goal is, 3-D real-time 9 visualization of all of these data inputs. And this 10 first phase, we are just looking at the -- the 11 feasibility, understanding the types of data that 12 these different sensors are going to be providing?
13 And then, is it realistic, from a 14 computing powers endpoint to actually integrate all of 15 those in -- in that near real-time, if that's 16 successful, then we may actually go to the lab and --
17 and demonstrate this and test it out, but that's down 18 the road. The short-term, here, is just a -- a 19 feasibility assessment. And I think that's -- that's 20 it, for me.
21 CHAIR BALLINGER: Thank you, Jonathan.
22 This is Ron. Oh. But, we're -- to do -- if you used 23 carpenter's dimensions, we're really on time. So 24 that, I think, is the last presentation, so I'd like 25 to ask the Members and Consultants, if they have any NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
151 1 comments, or questions that -- that need to be asked?
2 MR. BLEY: Well, Ron, it's Dennis, again.
3 I go back to my last question, since you have a 4 minute, here, and ask the gentleman, who was 5 discussing the coatings, that -- is these screens 6 underwater structures, or is there anything really 7 encouraging that you've been working on?
8 MR. OLACK: So I guess, I need to be 9 careful, regarding encouraging -- yes, our -- there 10 are some products that happened fairly successful.
11 It's the -- more of the longevity of them. Of course 12 -- and -- and that work continues.
13 You may be aware of one of our member 14 sites, I've been testing it on, since Service water 15 pump bowl assemblies, where they've applied a 16 hydrophone of coating and they've worked through that, 17 over the past, probably, three to four years of 18 continuing to do their inspections and working with 19 the manufacturer to -- to improve the quality and the 20 longevity, or the long-term performance of the coating 21 products. A number of different, you know, products 22 are out there, again, it's just how well -- what the 23 durability of them are.
24 MR. BLEY: Thank -- thank you, very much.
25 And, Ron, I guess, I just say, I found today very NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
152 1 enlightening. We've known about these problems for --
2 for years and I wasn't up to speed on what's being 3 done, currently, to improve the situations, so it was 4 a great day.
5 CHAIR BALLINGER: Thanks. I -- it was --
6 I've -- pretty much predictable, who would ask the 7 questions, mainly, it's somebody like you and the 8 operational people, like -- like Greg and -- and 9 others. So hopefully that -- the presentations today 10 will serve, as a, sort of, capstone of the four -- the 11 four presentations that we've had, so if there are no 12 other questions, and I don't see any hands, or 13 anything, it's -- it's too bad that the other EPRI 14 folks may, or may not, be listening from the other 15 presentations, but I would like to speak, if I can, 16 for the subcommittee and -- and -- and thank the EPRI 17 folks, big time, because these four presentations 18 were, I'm sure it took a lot of time to put together, 19 but were extremely informative and will, at least, to 20 my mind, constitute a -- a, kind of, a library that we 21 can -- we have access to, and so if there aren't any 22 further questions, I think that the -- we're probably 23 done. So I think we -- the -- the meeting -- Oh, 24 okay. No, no, go ahead.
25 (Simultaneous speaking.)
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153 1 CHAIR BALLINGER: Yes.
2 MEMBER HALNON: Public comment.
3 CHAIR BALLINGER: Oh. Oh. Oh, shoot.
4 Sorry. Are there any public -- members of the public 5 that would like to make a comment? Please, identify 6 yourself, and make your comment.
7 Ah, sorry. Since there are no public --
8 no -- no public comments, once again, I'd like to 9 think I can speak for the Subcommittee and, thank you 10 very much, for the presentations, and once again, the 11 -- we are adjourned. I guess, we'll see a lot of 12 people at about 1:30 p.m. Thank you, again.
13 (Whereupon, the above-entitled matter went 14 off the record at 12:08 p.m.)
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Full Name User Action Timestamp Christopher Brown Joined "10/18/2023, 7:54:49 AM" "Olack, David" Joined before "10/18/2023, 7:54:49 AM" Kelli Voelsing (EPRI) (Guest) Joined "10/18/2023, 7:58:58 AM" Tyesha Bush Joined "10/18/2023, 8:01:01 AM" "Crytzer, Kurtis" Joined "10/18/2023, 8:01:49 AM" "Crytzer, Kurtis" Left "10/18/2023, 8:02:35 AM" "Crytzer, Kurtis" Joined "10/18/2023, 8:03:31 AM" Shandeth Walton Joined "10/18/2023, 8:01:50 AM" Court Reporter - Sam Wojack (Guest) Joined "10/18/2023, 8:03:45 AM"
+1 704-614-3889 Joined "10/18/2023, 8:04:32 AM" Jose March-Leuba (ACRS) (Guest) Joined "10/18/2023, 8:04:36 AM" Dave Petti (Guest) Joined "10/18/2023, 8:06:24 AM" "Golberg, Ilya" Joined "10/18/2023, 8:08:03 AM" "Cimock, Dylan" Joined "10/18/2023, 8:09:23 AM" "Cimock, Dylan" Left "10/18/2023, 8:10:17 AM" "Cimock, Dylan" Joined "10/18/2023, 8:10:28 AM" "Varnam, Jeremie" Joined "10/18/2023, 8:09:53 AM" Ron Ballinger (Guest) Joined "10/18/2023, 8:13:07 AM" "Wolfe, Ryan" Joined "10/18/2023, 8:13:26 AM"
+1 707-318-4109 Joined "10/18/2023, 8:14:33 AM" "Choromokos, Rob" Joined "10/18/2023, 8:15:42 AM" "Black, Jonathan" Joined "10/18/2023, 8:15:49 AM" "Black, Jonathan" Left "10/18/2023, 8:49:06 AM"
+1 978-799-5494 Joined "10/18/2023, 8:16:55 AM"
+1 978-799-5494 Left "10/18/2023, 8:49:10 AM" "Johnson, Samuel" Joined "10/18/2023, 8:18:14 AM"
+1 704-595-2596 Joined "10/18/2023, 8:20:08 AM" Vesna B Dimitrijevic (Guest) Joined "10/18/2023, 8:20:23 AM" Vesna B Dimitrijevic (Guest) Left "10/18/2023, 8:22:21 AM" Joy Rempe Joined "10/18/2023, 8:20:53 AM" Weidong Wang Joined "10/18/2023, 8:23:21 AM" Tammy Skov Joined "10/18/2023, 8:24:02 AM" Stephen Schultz Joined "10/18/2023, 8:24:58 AM" Sandra Walker Joined "10/18/2023, 8:25:18 AM" Thomas Roberts Joined "10/18/2023, 8:25:27 AM" Bob Martin (He/Him) Joined "10/18/2023, 8:26:03 AM" Gregory Halnon Joined "10/18/2023, 8:27:09 AM" Michael Snodderly Joined "10/18/2023, 8:27:31 AM" Michael Snodderly Left "10/18/2023, 8:36:14 AM" Dennis Bley (Guest) Joined "10/18/2023, 8:27:46 AM" mattsunseri Joined "10/18/2023, 8:28:10 AM" mattsunseri Left "10/18/2023, 8:29:19 AM" Matt Sunseri Joined "10/18/2023, 8:29:10 AM" Derek Widmayer Joined "10/18/2023, 8:30:08 AM" Stephen P O'Hearn (Services - 6) Joined "10/18/2023, 8:32:15 AM" Vesna B Dimitrijevic (Guest) Joined "10/18/2023, 8:33:07 AM" Janet Riner (Guest) Joined "10/18/2023, 8:35:49 AM" Janet Riner (Guest) Left "10/18/2023, 8:39:59 AM" Thomas Dashiell Joined "10/18/2023, 8:43:02 AM" Edwin Lyman Joined "10/18/2023, 8:52:28 AM" file:///C/Users/CLB/Downloads/meetingAttendanceList%20(14).txt[10/24/2023 9:09:09 AM]
EPRIs Plant Reliability and Resilience Program:
Information/Update BOP Update - Topics of Interest Kurt Crytzer, Senior Principal Team Lead Advisory Committee on Reactor Safeguards October 18, 2023 www.epri.com © 2023 Electric Power Research Institute, Inc. All rights reserved.
Plant Reliability and Resilience Research 2024 - One program covering areas:
Active Mechanical BOP/Passive Mechanical Electrical Instrumentation & Control (I&C)
Eng/Maint Processes Plant Reliability and Resilience (PRR) Program allows integration maintenance and engineering research to address broad industry initiatives 2 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Research Aligned with Critical Industry Issues Plant Life Resiliency Efficient and Extension and (to Climate Change, Intuitive Access to Supply Chain Issues, Power Uprates and Other Factors) EPRI Information Risk-informed Modernization, and Graded Data, and Approaches Online Monitoring 3 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Agenda Please feel free to ask questions or interject at any time during the presentations 4 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Nuclear Aging Management and Corrosion Monitoring Research (BOP)
Buried Piping and Cathodic Protection Research Activities Dylan Cimock, Sr. Technical Leader Jeremie Varnam, Sr. Technical Leader Sam Johnson, Sr. Team Lead Advisory Committee on Reactor Safeguards October 18, 2023 5 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Recent Buried Pipe Meeting Topics of Interest
§ Selective Leaching (graphitic § Internal Pipe Repair Methods § Cathodic Protection corrosion) of cast iron piping & - Carbon Fiber Reinforced - Important to mitigating external valves Polymer (CFRP) corrosion of buried piping
- Cannot detect visually - Steel Composite Liner (SCL) - Finite life
- Multiple recent leaks / failures - Cured-in-Place Piping (CIPP) - Performance / reliability issues
- Impacts and regulatory scrutiny - Spray-in-Place Piping (SIPP) - EPRI Resources and Activities on license renewal (life - Mechanical Joint Seals extension) applications 6 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Selective Leaching 7 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Selective Leaching Background Selective leaching (SL) corrosion preferentially removes one alloying element from the parent matrix, enriching the remaining elements. Typically associated with exposure to untreated internal or external aqueous environments.
Affected material may stay in place with wall thickness remaining nominal
§ Relevant susceptible materials (NUREG-1801 & -2191, IAEA I-GALL)
- Ductile iron & gray cast iron
- Aluminum bronze with >8% aluminum
- Copper alloys with > 15% zinc
§ Examples of affected plant systems
- Fire Protection
- Condensate
- Auxiliary Feedwater 8 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Why Selective Leaching Research is Important?
§ Impact on power reactors licensed to operate beyond 40 years (and even more so for those licensed beyond 60 years)
§ Industry incurs significant expenses to meet aging management commitments for long term operations
- Large inspection population sample sizes
- Development of periodic inspection programs
§ Inspection Difficulties
- Corrosion features are complex (local plug type and uniform)
- Susceptible components are difficult to inspect (e.g., valve &
pump casing) 9 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Aging Management Program Challenges
§ Knowledge & Training
§ How to choose sample components amongst populations?
- GALL & GALL-SLR recommends to focus on lead components most susceptible based on time in service & severity of operating conditions
§ Inspection Techniques
- Effectiveness of visual examinations
- Accessibility of susceptible component surfaces
- Effectiveness of hardness testing
- Demonstrated NDE techniques (e.g., UT)
- Efficiency of destructive test
§ Dispositioning of findings
- What is relevant? (depth vs superficial)
- Fitness-for-Service rules for brittle materials
- Postulating growth rates 10 © 2023 Electric Power Research Institute, Inc. All rights reserved.
EPRI Research on Selective Leaching NDE Year Report Number Title Published Evaluation of Electromagnetic NDE Techniques for Detection of Wall Thinning 3002023785 2023 Due to Selective Leaching Degradation in Gray Cast Iron Piping 3002020832 Electromagnetic NDE Techniques for Gray Cast Iron Piping 2021 3002020830 Ultrasonic Techniques for Selective Leaching in Gray Cast Iron Components 2021 3002016057 Selective Leaching: State-of-the-Art Technical Update 2019 Nondestructive Evaluation: Guidance for Conducting Ultrasonic Examinations for 3002013168 2018 the Detection of Selective Leaching Assessment of Available Nondestructive Evaluation Techniques for Selective 3002008013 2016 Leaching: Technology Review Nondestructive Evaluation: Correlation of Selectively Leached Thickness to 1025218 Hardness 2012 for Gray Cast Iron and Brass Nondestructive Evaluation: Update to NDE for Selective leaching of Gray Cast Iron 1019111 2009 Components Nondestructive Evaluation: NDE for Selective leaching of Gray Cast Iron 1018939 2009 Components 11 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Selective Leaching NDE Reports Inspection Techniques Research
§ Technical Brief: 3002020830 Ultrasonic Techniques for Selective Leaching in Gray Cast Iron Components
- Scope: detection of internal selective leaching from outside surface examination (opposite surface)
- 3 techniques successful demonstrated on field removed components for detection and characterization of opposite surface SL
§ Technical Brief: 3002020832 Electromagnetic NDE Techniques for Gray Cast Iron Piping
- Four (4) different techniques evaluated on field removed piping components
- Includes both internal and external techniques
§ Technical Report: 3002023785 Evaluation of Electromagnetic NDE Techniques for Detection of Wall Thinning Due to Selective Leaching Degradation in Gray Cast Iron Piping
- More details and analysis of results from EM techniques
- Includes results for two (2) additional techniques evaluated in 2022 Reports Provide Techniques and Quantitative Results of Demonstration 12 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Examples of Electromagnetic NDE Techniques Pulsed Eddy Current Low Frequency Through-Transmission Electromagnetic Technique Remote Field Testing Magnetic Flux Leakage Saturation Eddy Current 13 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Example Results from Electromagnetic Techniques 14 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Summary: Selective Leaching NDE
§ Cast Iron
- Recent EPRI Research has demonstrated NDE capabilities to detect wall loss due to selective leaching in cast iron materials
§ Six (6) commercially available electromagnetic techniques for piping
§ Three (3) Ultrasonic techniques for opposite surface detection
§ Copper-zinc alloys
- Past industry OE indicates success in detecting SL in copper-alloy heat exchanger (HX) tubing using eddy current testing (ECT)
§ Aluminum Bronze
- Industry demonstration and advancement of advanced UT (Time-of-Flight Diffraction and Phased Array)
§ EPRI has submitted comments on Draft NUREG-2191 Revision 1 (GALL-SLR)
- Recommend NRC Staff consider results of recent EPRI reports and include NDE as viable options for the XI.M33 Selective Leaching AMP
§ Outstanding Research gaps:
- Objective demonstration of ECT on HX tubing
- Applicability of ultrasonic techniques to same surface SL is progressing from in cast irons
- Evaluation of surface eddy current (array) sensors to multiple materials for detection 15 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Selective Leaching R&D Tasks Report Number Topic Publication Year / Status 3002016057 State-of-the-Art Report 2019 3002020822 Susceptibility Evaluation 2021 3002020830 NDE Technique Development 2021 3002020832
- Tech Brief ultrasonics 2023 3002023785
- Tech Brief electromagnetics 3002020713 Selective Leaching: Leveraging Risk Insights 2022 N/A Development of Analytical Techniques Project: 2024 (tentative) 3002026340* Recommendations for an Effective Selective Leaching Aging Project: November 2023 Management Program 3002015155 Development of SL Training 2019: Instructor-Led 3002018468 Training 2020: Computer Based Training (CBT) 2023: Updates
- Report in publication process at time of presentation 16 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Non-Metallic Repairs and Rehabilitation of Piping 17 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Repair / Rehabilitation / Refurbishment Approaches CFRP:
Carbon Fiber Reinforced Polymer SIPP:
Source: ML20014E476, Structural Technologies Spray-in-Place-Pipe CIPP:
Cured-in-Place-Pipe HDPE Photo Credit: Framatome, 2021 Photo Credit: Elite Pipeline, 2017 Summer EPRI BPIG Meeting EPRI NUCC Meeting 18 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Carbon Fiber Reinforced Polymer (CFRP) Composites
§ System is comprised of multiple layers of woven carbon fiber fabric, saturated in polymer resin, hand applied to pipe
§ Can be installed on the inside or outside of piping
- Inside: diameter requires manned entry (>30 inch)
§ Can be designed / installed to structurally reinforce the existing pipe
§ Alternatively - can be designed/installed as a stand-alone repair Photo Credit: Dominion Energy & Structural Technologies, 2018 EPRI Summer BPIG Meeting
- CFRP credited for all structural and pressure loads
- No reliance on the original host pipe, except at terminal ends
- Host pipe serves only as a form for installing
§ Can be applied to multiple material substrates, including carbon steel and concrete Cross-Section of CFRP Mock-up: 0.375-in steel with 5 layers of CFRP 19 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Spray-in-Place Polymeric (SIPP) Linings
§ Internally spray-applied corrosion barrier for piping
- Thermoset pipe within a pipe
- Epoxy, polyurethane, or poly-urea are most common materials
§ Has been used as structural or semi-structural repair in non-nuclear industries
- AWWA C620, Spray-in-Place Polymeric Lining for Potable Water Pipelines 4-inch and Larger
§ Recent products presented at EPRI Conferences:
- Use fast-curing poly-urea resin
- High build dry film thickness (>0.10 inch)
- Multiple utilities pursuing as internal corrosion liner option
- Interest expressed by vendor(s) and utilities on potential pathway for structural repair Photo Credit: Framatome, 2021 EPRI Summer BPIG Meeting 20 © 2023 Electric Power Research Institute, Inc. All rights reserved.
EPRI Observed Gaps and Projects: CFRP-SIPP CFRP SIPP
§ 3002020823 NDE of Metallic Substrates § SIPP Technology and Gap Assessment (Nov.
Beneath CFRP Materials 2023)
§ NDE of Carbon Fiber Composite Materials
- 2023-2025 project § Guidance on testing & qualification of SIPP as
§ ASME Code Case support a corrosion lining for Safety-Related Piping
- On-going
§ Material properties to support structural
§ Projects Under Consideration credit of SIPP
- Appropriate margin between CFRP glass transition temperatures and maximum system design temperatures
- Cure temperature adjustment factors for material properties
- Stress Intensification Factors (SIFs) / Fatigue Factors 21 © 2023 Electric Power Research Institute, Inc. All rights reserved.
CFRP Workshop - Technical Information Exchange
§ EPRI held in-person CFRP workshop July 25-26, 2023
§ Attendees:
- CFRP repair designers & installers
- NDE technology suppliers
- US NRC and US national labs
- Universities
§ Topics
- Overview of CFRP applications, designs, processes
- Flaw types and flaw evaluation
- Current quality assessment technologies
- New NDE inspection technologies
- Fabrication of mock-ups and intentional defects 22 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Leak Detection Using Electrical Resistivity Tomography 23 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Conceptual Measurement Current Source Amp Meter Current injection well Positive Current Negative Current Negative Potential Positive Potential Electrode Electrode Electrode Electrode Volt Meter V Potential (Volts)
Rt = I
= Current (Amps) 24 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Electrical Resistivity Tomography (ERT)
§ Project Objective: Autonomous monitoring for leaks in buried piping and tanks allowing for early identification
§ Current Status
- 3002010596Geo-Electrical Subsurface Leak Detection and Monitoring at Nuclear Power Plants: Phase 1 Feasibility Report
- 3002023782 Electrical Resistivity Tomography for Leak Detection and Imaging at Nuclear Power Plants: Phase II Demonstration
§ Small Pilot with PNNL at BWR Service Water Piping from 2020-2022
- Simulated leaks detected (Salt Water/Freshwater) Electrode Cable Control
- Major rainfall event monitored to distinguish leaks Unit (~1ft depth)
With appropriate electrode spacing, the area requiring excavation can be minimized 25 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Demonstration Site Setup Buried Piping Diagram Control ERT Computer Instrument Coolin g Wa Pump B Pump ter Po D Pump A Pump B nd Pump C Pump D Line Storage A ERT Cables Line B
Northing (m)
Container Line C
Line Vacuum breaker standpipe D
Main Vacuum breaker standpipe Line Electrodes buried 6 inches to oce Leak simulation tube an terminated at top of discharge beneath surface Line B Easting (m)
Vacuum breaker standpipe 26 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Leak Injection Test A Pump B Leak injection tube Two water types were tested: terminates at top
- Potable water @ 388 uS/cm of pipe ~ 2ft below ground.
- Canal water @ 31530 uS/cm Injection rate set to 1 gpm ERT survey time required ~20 minutes Test sequence:
Pond Water Day 1 Pipe B Hose outflow Injection Setup
- 1. 171 gallons (3 barrels) of canal water @ 1 gpm
- 2. 2090 gallons of potable (flush) water Day 2 (agile testing, troubleshooting, Pipe B,C)
- 1. 57 gallons (1 barrel) of canal water on C
- 2. 278 gallons of canal water on pipe B
Conclusion:
- Electrodes were too far from the leak
- Design mistake (based on incorrect assumptions) and lesson learned 27 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Leak Injection Test B Temporary Surface Electrodes 2 lines of 8 electrodes @ 1m spacing Two water types were tested:
- Potable water @ 388 uS/cm
- Canal water @ 31530 uS/cm Injection rate set to 1 gpm Leak Injection Pipe B ERT survey time required ~10 minutes Test sequence:
Pipe B
- 1. ~100 gallons of potable water water
- 2. ~100 gallons of canal water Surface Electrodes 28 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Leak Injection Test B Potable Water: 388 µS/cm Canal Water: 31530 µS/cm Potable water leak found after 15 gallons Canal Water leak found after 10 gallons 29 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Cathodic Protection and Tank Inspection Resources 30 © 2023 Electric Power Research Institute, Inc. All rights reserved.
EPRI Cathodic Protection Resources EPRI ID Title Year 3002000596 Cathodic Protection Application and Maintenance Guide 2013 3002002949 Recommendations for Managing an Effective Cathodic 2014 Protection System 3002005067 Evaluation for Installing or Upgrading Cathodic Protection 2015 Systems 1025252 Cathodic Protection System Design Specifications 2012 3002010674 Cathodic Protection Effectiveness: A Review of Protection 2017 Criteria, Threshold Values, and Evaluation of Alternative Methods 3002015460 Cathodic Protection Data Management and Trending Software 2020 (CPWORKS) 3002007627 State-of-the-Fleet Assessments of Cathodic Protection Systems 2016 3002010678 (2015-2017) 2017 3002013202 2018 31 © 2023 Electric Power Research Institute, Inc. All rights reserved.
EPRI Research on Tank Inspections
§ Previous Projects:
- 3002013172 Nondestructive Evaluation (NDE):
Assessments for Tanks and Containment Liners:
Readily Available NDE Methods to Inspect Tanks and Containment liners
- 3002003071 Guidelines for Tank Inspections
§ Current and Future Projects
- Guided Wave UT Deployed from the Exterior of Tanks
- Robotic Platforms for Deploying NDE for Tank Inspections
- Comprehensive Tank Inspection Reference Guide 32 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Computational Fluid Dynamics Analysis of Stagnant Lines for Flow Accelerated Corrosion 33 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Significant FAC Observed in Unexpected Location
§ Unexpected wall thinning of the C Feedwater Bypass line was below Tmin
- No inspection history as bypass lines were categorized as non-susceptible due to less than 2% operating time
- Actual thickness of 0.100" versus code minimum of B 0.213" (Tnom = 0.337")
§ Scope expansion for A and B bypass lines C - A minimum thickness of 0.052"
- B minimum thickness of 0.092"
§ All exhibited a rippled or orange peel surface typical in single-phase Flow-Accelerated Corrosion (FAC)
- No anomalies in chemical composition, hardness, and microstructure A § Emergent replacement of thinned components with P22 chrome-moly material Ref: K. Burke, CHUG Meeting, January 2023 34 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Causal Factors and Extent Utilitys FAC lead contacted EPRI and coordinated with the CHUG Advisory Committee to help define the extent of condition
- Operating time, erosion, and leak-by were likely not factors
- Entrance effect and water chemistry may have been factors but not enough history for certainty
- Turbulent flow conditions warranted additional investigation Ref: K. Burke, CHUG Meeting, January 2023 35 © 2023 Electric Power Research Institute, Inc. All rights reserved.
CFD Analysis of Stagnant Lines
§ To validate whether FAC thinning was the likely cause
§ Could similar FAC thinning of stagnant lines occur at other plants and warrant change to EPRI guidance, Computational Fluid Dynamics (CFD) modeling will be used to characterize conditions at the branched bypass line connection 36 © 2023 Electric Power Research Institute, Inc. All rights reserved.
CFD Modeling: Preliminary Results No monotonic convergence at residuals 37 © 2023 Electric Power Research Institute, Inc. All rights reserved.
CFD Modeling: Preliminary Results Turbulence Kinetic Energy Wall Shear Model results are consistent with locations of thinning 38 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Next Steps: Correlations and Parametric Analysis Parametric analysis is being done to help prioritize additional locations and define extent of condition for the industry 1 Bypass Line Sizing 2 Location of Bypass Entrance 3 Pipe Connection Geometries 4 Bypass Operation 5 Bypass Valve Leakage 39 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Cable Condition-Monitoring for Aging Management Programs Ilya Golberg, Sr. Technical Leader Advisory Committee on Reactor Safeguards October 18, 2023 40 © 2023 Electric Power Research Institute, Inc. All rights reserved.
MV Cable Insulation Condition-Monitoring 41 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Cable Aging Management During LTO
§ Cables initially were classified as long-lived, passive components that did not require maintenance/testing (position was endorsed by (NUREG 1526) and the NRC endorsed NUMARC 93-01, Maintenance Rule Implementation Guide
§ MV cables degrade primarily due to dielectric effects (water treeing, partial discharge) not thermal aging (there are known, but rare instances)
§ Majority of cables will last for the plant life except:
- Cables that are exposed to adverse local equipment environments (ALEEs)
- Cables damaged during installation or maintenance Common Cable ALEEs
- Cables degraded over time due to poor installation practices, or maintenance induced damage
§ Successful cable aging management programs identify and managing cables in ALEEs
§ The AMPS for cables in GALL/SLR-GALL are designed to manage aging 42 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Background - Medium Voltage Cables (MV cables)
§ MV cable failures began occurring in mid 1970s
§ GL-2007-01 summary report provided data on MV cable insulation degradation that the staff reviewed and summarized
- 188 of the 269 cable failures* in the industry responses were MV cables (rated 5kV to 46kV)
- Water/moisture was the leading reported cause of degradation (approximately 50%)
- Failures occurred on all commonly used insulation types (Butyl Rubber, XLPE, EPR)
§ Unknown, Butyl rubber, and black EPR made up the highest incidence of failures
- Includes in-service and test failures NOTE: Low voltage cable failures by number was the highest contributor to all industry failures, but that is insignificant when you consider they represent the larger population of cables in a typical plant (30,000 - 40,000 LV cable versus a few hundred MV cables) 43 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Background - Medium Voltage Cables (MV cables)
§ The NRC staff conclusions and recommendations based on GL-2007-01 industry data included the following:
- Many utilities did not have cable specific testing programs
- There was an increasing trend in failures and/or plant upsets as plants aged
- Reasonable provisions should be made to keep cables dry
§ Some assumptions evolved out of this GL
- Cables are not designed or qualified for submergence
- Concern that a common-mode failure of cables could occur 44 © 2023 Electric Power Research Institute, Inc. All rights reserved.
EPRI Research to Address MV Cable Aging
§ A need for research of commonly used EPR MV cables was lacking (most research focused on XLPE insulation)
§ MV cable failure mechanism research began in 2006, the first report issued in 2007
- EPRI collected thousands of feet of harvested MV cables that had in-service failures or were replaced based on poor test results to support research
- Evaluation was performed on all insulation types installed in US NPPs
- In total 8 reports were issued between 2007 and 2015 (all are available at no cost) 45 © 2023 Electric Power Research Institute, Inc. All rights reserved.
MV Cable Failure Mechanism Research Results (continued)
§ A systematic approach to isolate degraded insulation was developed
- VLF tan delta results capable of identifying degraded insulation
- Using ever smaller size test probes the degraded areas were isolated
- AC breakdown testing was used to determine the change in insulation condition compared to other sections of the same cable that were not degraded
- Wafering and inspection of degraded areas showed locations of the water trees 46 © 2023 Electric Power Research Institute, Inc. All rights reserved.
MV Cable Failure Mechanism Research Results (continued)
§ Key research findings
- VLF tan delta testing identified degraded insulation, and it also showed the EPRI criteria for good, further study and action required correctly identified the degree of degradation (i.e., higher the mean tan delta, lower the breakdown strength of the insulation)
§ This allows cable repair/replacement decisions to be made before the cable could potentially fail in-service
- Water trees do not develop homogeneously or even in parallel sections of the other cables for the same equipment being fed (not a common mode failure mechanism) 47 © 2023 Electric Power Research Institute, Inc. All rights reserved.
EPRI Research to Address MV Cable Aging
§ Program guidance issued for aging management of MV cables
- Report 1020805, Aging Management Program Guidance for Medium-Voltage Cable Systems for Nuclear Power Plants issued in June 2010.
Current guidance: 3002000557 Aging Management Program Guidance for Medium-Voltage Cable Systems for Nuclear Power Plants, Revision 1 issued in 2013.
- 1021070 Medium Voltage Cable Aging Management Guide, Revision 1 issued December 2010
§ These reports recommend the following actions for MV cable in wetted conditions (presently or in the past)
- Perform inspections of inaccessible cables to determine the frequency of pump-outs would be required to keep the cables dry
- Performing VLF tan delta testing
§ On a six-year frequency for cables that tested good,
§ Increased frequency (2-3 years) if further study
§ Repair/replace as soon as reasonable if in the action required range 48 © 2023 Electric Power Research Institute, Inc. All rights reserved.
VLF Tan Delta Effectiveness Evaluations
§ EPRI collected industry test data between 2008-2015
§ Two reports evaluating the test effectiveness in identifying good to severely degraded insulation were issued
- 1025262 Evaluation and Insights from Nuclear Power Plant Tan Delta Testing and Data Analysis
- 3002005321 Evaluation and Insights from Nuclear Power Plant Tan Delta Testing and Data Analysis - Update 49 © 2023 Electric Power Research Institute, Inc. All rights reserved.
RIL 2021-011 Response
§ NRC found methodology of EPRI Tan Delta testing was sound and criteria were sufficiently conservative relative to IEEE 400.2.
§ NRC did not endorse EPRI VLF TD methodology due to insufficient data populations of some cable types (Brown EPR and XLPE).
§ Failure mode is consistent across insulation types and when data is taken evaluated as a whole, it demonstrates the capability of the test to identify degradation regardless of insulation type.
50 © 2023 Electric Power Research Institute, Inc. All rights reserved.
VLF Tan Delta Effectiveness Evaluations
§ Key Findings of Test Data Evaluations
- VLF Tan Delta can be used for condition assessment of all commonly used insulation types
- Testing every 6 years was sufficient to prevent cable degradation from good to "degraded".
- When combined with VLF withstand test (hi-pot test) provides reasonable confidence to prevent immediate in-service failures
- Data indicates a hierarchy of the three acceptance criteria, but all three are useful to determine what part of the insulation system is degraded
- If a degraded part of the cable system (insulation, splice, or termination) can be isolated as the cause; replacing it can restore the cable to good 51 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Other EPRI MV Cable Research (continued)
§ More recent research has focused on VLF testing of
- 3002013161 Field Guide for Very Low Frequency Tan Delta Testing of Medium-Voltage Motors and Cables from the Cable Terminations
- 3002018284 Medium-Voltage Transformer and Cable Very Low Frequency (VLF) Tan Delta Testing from the Cable Termination: VLF Testing of Transformers
§ Both reports show that degradation of the end device and/or cable insulations can be detected
§ Two pilot sites and several others have applied the research with motor or motor lead degradation being identified
§ In-progress: Evaluation of cable insulation shields attenuation effects on high frequency test signals (partial discharge, frequency and time domain reflectometry)
§ EPRI continues to evaluate member tan delta test data, but unlike the 2009 - 2015 period where we collected all data, it is now done on member request for input 52 © 2023 Electric Power Research Institute, Inc. All rights reserved.
In Review
§ The adoption of manhole monitoring and VLF tan delta testing post GL-2007-01 has resulted in improved OE (very few in-service failures since 2015)
§ MV Cable insulation degrades from dielectric stressors, not thermal
- VLF tan delta testing analysis has proven capable of identifying cable degradation for both wet and thermal aging (although much rarer)
- Water trees form at stress points caused by manufacturing anomalies or latent damage from installation
- Insulation degradation sites are not due to aging, they are not the result of homogeneous degradation in EPRs. Thus, they should not be considered as a potential common-mode concern
- Keeping the cables dry or even wet and then dry is better than being submerged continuously and testing will identify issues
- MV cable insulation will be long-lived because
§ Dielectric stress can be managed by the above strategies and degradation can be corrected to restore cable condition to good via partial or full cable replacement when necessary
§ Thermo-oxidative aging is not typically a factor in MV cable as a contributor to insulation degradation 53 © 2023 Electric Power Research Institute, Inc. All rights reserved.
LV Cable Insulation Condition-Monitoring 54 © 2023 Electric Power Research Institute, Inc. All rights reserved.
LV Cable Aging Management During LTO
§ LV Cables are also long-lived passive components
§ All the common ALEEs shown have been seen in plants, but thermal oxidative aging from external heating(not ohmic heating) is most common cause identified for cable degradation
§ Identifying ALEEs and monitoring and managing those cables is key to the Common Cable ALEEs aging management of these cables 55 © 2023 Electric Power Research Institute, Inc. All rights reserved.
LV Cable Test Methodology - Background
§ LV cables in adverse local equipment environments (ALEEs) can typically be visually identified and qualitatively assessed.
§ Walkdowns pre-Period of Extended Operation and thereafter at least every 10 years are required for LTO to identify ALEEs
§ Thermal degradation from high temperatures in ALEEs is the main cause of LV cable aging
§ LV cables do not degrade by water treeing due to their low operating voltages
§ Visual indications can be seen on the cable jackets including weeping of plasticizers, spontaneous cracking, or jacket discoloration
§ External visual indications on jackets typically precede insulation degradation, however a quantitative assessment of the insulation condition will be warranted at some point 56 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Background (continued)
§ There are many quantitative test available that fall into various categories
- Destructive, non-destructive (e.g.,
elongation at break versus indenter modulus)
- Laboratory versus In-situ (e.g.,
Oxidation Induction Time versus insulation resistance)
- Mechanical, Physio-Chemical, Electrical
- Global versus localized
§ All mechanical and physio-chemical tests but indenter modulus require harvested materials to perform the test technique 57 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Condition Monitoring Gap
§ Insulation resistance for dry cables is not always reliable indication of insulation condition
- Dry cables, even when severely degraded often have high Megger values as air is a good insulator
§ Time and Frequency Domain Reflectometry results indicate anomalies in insulation, not all are degradation Research Gap: How can low voltage condition be more reliably identified?
58 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Electrical Testing: Global vs. Local
§ Global Evaluation - determination of the insulation condition along entire length of a cable
§ Local Evaluation - determination of the condition of a material at a specific location on the cable Local Global Test detects defects at discreet Test provide a global assessment point(s) along the cable like Time of the insulation condition like Domain Reflectometry (TDR) or Insulation Resistance, Dissipation Frequency Domain Reflectometry factor/Tan Delta, Dielectric (FDR) Spectroscopy and Polarization/Depolarization Current 59 © 2023 Electric Power Research Institute, Inc. All rights reserved.
3002020818 Test Protocol for Condition Monitoring of Low Voltage Cable Using Dielectrically Based Methods Manhole with Spliced Cables 60 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Example LFDS Results Population - Tan at Fixed Frequency No Anomalies Observed Moderate Anomalies Observed High Anomalies Observed (i.e., Good) (i.e., Further Investigation) (i.e., Action Required) 61 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Example PDC Results PDC - IPOL vs. IDEPOL No Anomalies Observed (i.e., Good)
Moderate Anomalies Observed (i.e., Further Investigation)
High Anomalies Observed (i.e., Action Required) 62 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Test Results - FDR and TDR
§ Cross-correlation with TDR results used for increasing accuracy No Anomalies Observed Anomalies Observed Significant Anomalies Observed (i.e., Good) (i.e., Investigation Required) (Indication of Fault) - Action Required 63 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Review - LV Cables
§ Thermal degradation in ALEEs is the leading cause of insulation degradation
§ Current condition monitoring improvements are needed because once degradation requires quantitative methods the current options are either
- Difficult to implement mechanical, Physio-Chemical test methods
- Electrical tests can provide false indication of insulation degree of degradation
§ EPRI has provided a new test methodology that has proven capable of identifying thermally degraded or wet insulation degradation
- Verified via pilot at a member site and ongoing testing there
- And promoting it via demonstration at members sites on request 64 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Nuclear Power Plant Resilience Research Rob Choromokos, Principal Group Leader Advisory Committee on Reactor Safeguards October 18, 2023 65 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Resilience 66 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Nuclear Resilience to Weather Events
§ Nuclear plants have robust design margin and a historically high capacity factor even when challenged with weather-related events
§ Weather-related hazards are likely to worsen for nuclear power plant operators over the next two decades as a result of climate change, with severity varying by region
§ Nuclear plants must remain resilient in the face of extreme weather events to contribute to grid stability and remain a part of a low-carbon energy future Global climate change and extreme weather events 67 © 2023 Electric Power Research Institute, Inc. All rights reserved.
External Hazards Information Compilation and Analysis
§ Benefits nuclear power plants who commit to the implementation of Recommendation 2 of INPO Event Report (IER) L1-13-10 or similar external hazard monitoring program
§ Broadened participation worldwide in 2021
§ Current scope of changes to hazard required by the US are seismic, flooding, high winds, extreme heat, and extreme cold/snow/ice
§ International hazards maybe be different and need to go through the screening process
§ Project been in place since 2016 An efficient, shared resource for understanding changes in external hazards 68 © 2023 Electric Power Research Institute, Inc. All rights reserved.
External Hazards Information Compilation and Analysis
§ Reviewed over 1100 pieces of new hazard information over the last 6 years
- New precipitation studies Monitoring
- East Coast Tsunami potential
- NIST Tornado Map Changes
- Climate Change Studies/Observations Reporting Screening
- Seismic Hazard (NGA East Earthquake)
- Operating Experience (Derecho, Frazil Ice, Hurricanes)
§ New information identified in 2022/2023 Evaluation
- Seismic hazard information
- Wind hazard information Nuclear plants maintain a robust design margin for safety 69 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Summary of Recent Years Project Work Project Year: 2018 2019 2020 2021 2022 New information items 0 0 0 0 0 reported Evaluations completed 1 0 2 0 1 Potential new information items requiring consideration 11 9 15 12 16 of additional technical information Individual items screened requiring no 109 109 98 87 107 action EPRI Report Number 3002016048 3002018235 3002020757 3002023811 3002026415 70 © 2023 Electric Power Research Institute, Inc. All rights reserved.
2022 External Hazards New Information Report Technical Report 3002026415 External Hazards Information: Compilation and Analysis: 2022 New Information Report Objective of this Report This report is a product of EPRIs External Hazards: Information Compilation and Analysis Supplemental Project and presents credible new information, identified during the 2022 calendar year, Annual Summary Report for Responding to INPO Recommendation 71 © 2023 Electric Power Research Institute, Inc. All rights reserved.
New Research Area - Climate Risk
§ How climate change may present a physical risk to utility assets and operations and what response strategies are available to minimize future consequences?
§ What existing and new research can help can answer this question?
§ OE in Weather impacts on nuclear plants operations
§ Considerations of future climate impacts Identifying Potential physical impacts of a changing climate 72 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Recent Operational Experience
§ Highlight distinction between nuclear safety and operational impacts
§ Historical review of available US nuclear operating experience to weather-related events over past 10 years
§ Impact of weather-related events on capacity factor at US NPP plants
§ Discuss future research regarding forward looking climate vulnerability assessments Nuclear Plant Resilience to Weather-related Events between 2011 to 2020 3002025519 - EPRI White Paper 73 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Weather Related Operating Experience (2010 - 2020)
Events including Grid Impacts Total Number Average Range of Number of of Production Weather Events Recovery Recovery Events over Days Lost (days) (days) 10 years (days)
High Winds / Storms 4 0 to 32 48 207 Extreme Cold 3 0 to 10 17 55 Flooding 7 0 to 16 6 44 Biofouling 2 0 to 6 22 34 Lightning 1 0 to 6 15 22 Extreme Heat 2 0 to 13 12 22 Total 120 384 Events excluding Grid Impacts Total Number Average Range of Number of of Production Weather Events Recovery Recovery Events over Days Lost (days) (days) 10 years (days)
High Winds / Storms 2 0 to 18 25 52 Extreme Cold 3 0 to 10 11 19 Flooding 7 1 to 16 6 44 Biofouling 2 0 to 6 22 34 Lost generation due to weather-related events in the Lightning 2 0 to 6 9 19 US nuclear fleet is less than 0.1%.
Extreme Heat 2 0 to 13 12 22 Total 85 190 Nuclear plants are currently very resilient and need to maintain this performance 74 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Key takeaways
§ NPPs are specifically designed to safely withstand events far more severe that most critical infrastructure.
§ Based on OE and high capacity factors, NPPs have demonstrated resilience to extreme events. Most major loss of production events come from grid-wide challenges.
§ NPPs maintain a significant amount of OE and knowledge to build upon in addressing weather-related vulnerabilities.
§ Climate impacts can affect operational resilience. Forward looking assessments could allow plants to have a more strategic response to chronic changes and extreme weather events.
Plants currently maintaining high degree of availability 75 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Climate Risk Assessment What does climate change mean for a nuclear station?
Vulnerability Risk & Risk Climate Hazard? Exposure? Management? Nuclear Change & Response?
Generating Are physical Whats in harms Is the risk large?
conditions way? Does it matter?
What are robust Asset changing? How might we and resilient respond?
strategies?
Past and Past and Structures, Current and Current and potential potential systems, potential potential global local components, climate risks and risk climate climate operations, impacts and management change change supply, responses infrastructure 76 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Starting Point for Physical Climate Risk Assessment 77 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Future Weather Impact on Asset - Exposure & Vulnerability Projections Planning &
Margin Investment Reductions Prioritization Temperature Impact on Capacity Asset Factor Management Life Program Precipitation Expectancy Environmental Impacts &
Ice Compliance Informed Design Approach Maintenance Extremes Adaptation Health &
Strategies Safety Physical climate risk assessment 78 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Climate Vulnerability Assessment Guidance
- 1. Climate Hazards - how to establish Climate Hazard future climate change-related trends and extremes at the local nuclear Exposure plant Monitoring &
- 2. Exposure - how to identify and Adaptation screen critical assets, systems or components likely to be impacted by weather-related variables Recovery Vulnerability Actions
- 3. Vulnerability - how to establish design and operating margins, potential impacts and potential risks Climate Vulnerability Assessment Guidance for Nuclear Power Plants 3002023814 - EPRI Technical Report 79 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Climate Vulnerability Assessments
§ Several NPPs have undergone or are planning vulnerability assessments
§ More work to do on consistency of assessments
- EPRI and INPO guidance should help
- More guidance on selection of climate variables, modeling, uncertainty, etc.
- How to present findings
§ How to ensure we are producing measurable results and increasing resiliency with existing plant programs 80 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Site-specific Climate Hazard Projections Challenges:
ü Changing Weather and Extreme Events
ü Climate Vulnerability Assessments
ü What climate data to use and how much margin?
ü What are my specific climate related challenges?
Improved Climate Hazard Information:
§ Site-specific estimates of key climate-related variables based on latest generation climate model projections
§ Interpretation and analysis of climate information to support technical insights and clarify potential uncertainties or limitations associated with current climate modeling state-of-practice
§ Workshops to enhance understanding of climate hazards, data, timeframes, resources, and applications
§ Documented guidance and technical basis upon which to conduct climate risk and vulnerability assessments Anticipating Climate Change Impacts to Nuclear Power Plants (3002023431) 81 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Critical Asset - Exposure Assessment
§ Identify what might be in harms way - Identify all plant SSCs important to safe and reliable operation of the plant - focus on those systems that can trip and derate the plant
§ Identify those SSCs that are potentially exposed to weather related impacts
- Could the weather event cause an LCO?
- Does the weather hazard impact the safety analysis?
- Is there OE from these weather events? Derate or trip?
- Are key operating parameters impact by this weather hazard?
- Could the weather event have an impact on a supporting SSC?
Identify Critical Assets and Infrastructure for Climate Risk Assessment 82 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Vulnerability Assessment
§ Identify potential consequences of exposure to a changing climate and options for responding - derate or plant trip
§ Damage functions, fragility curves for impacts on generating asset Ref: INPO 09-003
§ How to factor in the risk-informed approach?
§ How do plants decide how to prioritize with these results?
Ref: ORNL/TM-2019/1252 Assess the vulnerability of nuclear assets to climate scenarios 83 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Adaptation and Monitoring Guidance (new for 2024)
§ Response Prioritization
§ Identifying adaptions to maintain or Climate Hazard improve resiliency
§ Develop strategies for planning and Exposure implementation Adaptation &
Monitoring
§ Interface with existing plant programs
- Maintenance and Reliability Vulnerability
- Plant Health Committee Recovery Actions
- Asset Management Program
- Enterprise Risk Management
§ Monitoring & Evaluation 84 © 2023 Electric Power Research Institute, Inc. All rights reserved.
EPRI Climate Resilience and Adaptation Initiative (READi)
§ Development of a Common Framework across the Power System
§ Comprehensive, informed, and consistent approach to climate risk assessment and strategic resilience planning
§ Applicable to the assessment of physical risk at the asset, infrastructure, and operational level Workstream 1 Workstream 2 Workstream 3 Physical Climate Energy System & Asset Resilience/Adaptation Data & Guidance Vulnerability Assessment Planning & Prioritization PHYSICAL CLIMATE VULNERABILITY ADAPTATION HAZARD ASSESSMENT RESPONSES
- Identify application
- Develop risk framing
- Assess power system needs
- Assess vulnerability at and societal impacts:
- Assess data available the component, resilience metrics and provide system and market and value measures Deliverables: Common Framework Guidebooks recommendations levels
- Identify optimal on data suitable for
- Identify mitigation investment priorities
- Climate data assessment and
- Recovery planning different analyses options
- Develop cost-benefit application guidance
- Hardening technologies
- Address data gaps
- Enhance design / analysis and hardening adaptation strategies
- Vulnerability assessment
- Adaptation planning
- Risk mitigation investment
- Research priorities 85 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Climate READi Members UNITED KINGDOM FRANCE JULY 6, 2023 Member Headquarters Member Operating States/Provinces ISO Service Territories (only HQ location shown for IPPs) 86 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Intakes and Heat Sink Research Update Job Black, Technical Executive Advisory Committee on Reactor Safeguards October 18, 2023 87 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Agenda
§ Long-term Ecological Change and Impacts to Ultimate Heat Sink
§ Recently completed research
- Intake Guides
- Preventing Cooling Water Intake Blockages
- Intake O&M and Optimization Interest Group
- Debris Forecasting
§ Innovation and Ongoing Research
§ Future Directions 88 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Long-term Ecological Change and Impacts to Ultimate Heat Sink 89 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Environmental conditions impact CWIS requirements Changes in environmental conditions:
§ Currently require
- CWIS equipment readiness
- Adequate responsiveness of operators during events
- Adequate PM (e.g. structural integrity, operation settings, etc.)
§ While most events are still manageable today, these will
- Increase in frequency, intensity and duration Tim Hogan, Maarten Bruijs, Jonathan Black October 1, 2021
- Be of new types of debris not experienced previously
- Challenge the reliability of current (ageing) intake designs
- Require
§ evaluation current CWIS designs OE
§ upgrade of ageing equipment
§ develop and test novel approaches
§ ability to forecast https://www.powermag.com/water-intake-reliability-in-the-age-of-environmental-uncertainty/
90 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Importance of Intake Reliability Intake Reliability is a function
§ Readiness for current conditions of the structural, functional, and operational design of
- Normal operation equipment; adequate
§ Maintain compliance preventive maintenance; and the preparedness/training of
§ Mitigate fouling and manage debris competent operating staff
§ Perform efficient O&M/PM
- Abnormal operation The screening assembly must
§ Ability to manage
- be designed to operate
§ Ability to anticipate under the expected environmental conditions,
§ Preparedness for future conditions
- capable of managing the
- Monitoring long term data/trends and debris type(s) expected, observational info and
- Predict changes
- properly maintained to assure good working order
- Evaluate CWIS design and equipment requirements (and retrofit as anticipated) 91 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Anticipating Future Challenges - a Today Task!
The nature of the intake issues as we know them will change As changes are gradual, power plant operators need to:
§ Think long-term
§ Communicate among team EPRI provides a
- observed & expected changes framework and expertise to launch
- review intake operational capacity and performance new research in
- review international OE support of adaptation
§ Act to gradual changing environmental
- Revisit design basis - e.g. conditions
§ water levels in relation to operating margins,
§ water quality in relation to material selection,
§ equipment and operational settings (and assumptions) in relation to debris types 92 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Monitoring Long-term
§ Recommendation 1: Identify and periodically (at least Environmental Changes once every three years) update station information on site-specific environmental conditions that must be addressed in the design bases of the intake cooling
§ SOER 2007-2 recommends monitoring changing water structure, equipment and associated systems, to environmental conditions prevent or minimize obstructions and degradation that may affect cooling to the plant.
§ Long-term ecological change can be challenging to monitor § Recommendation 2: Develop monitoring and predictive
§ EPRI is interested in developing guidance on which methods to anticipate site-specific environmental parameters are best to monitor, at what parameters and initiate appropriate mitigating actions.
frequency, and how they should be analyzed § Recommendation 3: Verify that plant operating and
§ Data from other climatic regions, acting as design features of intake cooling water structures and reference site for future conditions, could be used equipment and associated systems minimize the as example likelihood and consequences of intake blockage or degradation- this requires validation every two operating
§ Data can be used for hindcasting and developing / cycles.
improving forecasting tools
§ Recommendation 4: Implement maintenance strategies
§ Expected enviro changes may include:
and work control processes to maintain the functional
- Increased storm-related debris events capability of intake cooling water structures, equipment
- Increased nuisance species (e.g., jellyfish, hydrozoa) and associated systems.
- Water conditions (temp, chemistry) impacting equipment § Recommendation 5: Prepare operators and other integrity support personnel to anticipate and respond to cooling water blockage and degradation in a conservative manner.
93 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Intake Best Management Practices Efficient screen operation 3002019660
§ Best Management Practices for Preventing Cooling Water Intake Blockages
§ Guidance published in June 2021
§ Guidance includes international events n l oad D ow
§ New screen types and designs e e for i s Fr p or t
§ With international input, we increase Re knowledge
- Both successful and unsuccessful mitigation/forecasting efforts
- Application of specific (novel?) intake system types
- Add to the body of OE related to debris management at intakes Managing large amounts of debris 94 © 2023 Electric Power Research Institute, Inc. All rights reserved. 94
Intake Maintenance Guide Series 95 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Intake Equipment Maintenance
§ Existing guide (2004) was outdated:
- Addition of new technologies
- Missing international relevance
- Changes in maintenance practices
§ New guide divided into three volumes:
- Vol. 1 - Stop gates, trash racks, & trash rakes e d
- Vol. 2 - Fine screening (TWS, drum screens) vi s
- Vol. 3 - Debris disposal Re
§ Cross-sector collaboration
§ Preventative maintenance templates are being added/updated 96 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Approach
§ Review publicly available info
§ Interviews with vendors
§ Interviews with A/E engineers
§ Review equipment O&M manuals
§ Reports designed to provide:
- Technology descriptions (operation, common failure modes, recommended maintenance)
- Technology graphics
- Technology animations
- PM recommendations
- PMBD templates (Preventive Maintenance Basis Database) 97 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Common Failure Modes/PM Needs for Fine Screening TWS Drum Screens Passive WWS
§ Biofouling § Biofouling § Biofouling
§ Mesh panel damage § Mesh panel damage § Screen damage
§ Corrosion
§ Corrosion § Corrosion
§ Faulty seals
§ Faulty seals
§ Carrier chain wear/tension § Central bearing wear Active WWS
§ Sprocket teeth wear § Spraywash system § Screen damage
§ Spraywash system clogs § Corrosion clogs § Poor lubrication § Brush wear
§ Poor lubrication 98 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Additional Recent Intake Research 99 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Air Bubble Curtains for Aquatic Vegetation
§ EPRI is working with a nuclear facility in the Phase 1 Phase 2 Phase 3 Southeastern U.S. where floating aquatic Data Hydraulic Pilot Testing vegetation has overwhelmed intake Gathering Modeling, and Analysis Laboratory screening and forced outages or derates Evaluation, and
§ In addition to intake screening upgrades Engineering (new narrower spaced rack and raking Designs system & new traveling screens), the facility is exploring additional measures to reduce exposure
§ Multi-phased project to evaluate air bubble curtains as a potential mitigation measure 100 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Intake O&M and Optimization Interest Group (OMOIG)
Objectives and Scope
§ Forum to discuss intake blockages, operational impacts, O&M and screen optimization
§ Develop BMPs to address emerging debris and traveling screen issues
§ Support nuclear reporting requirements
§ Webcasts, workshops, newsletters and technical briefs to disseminate information Value
§ Minimize or prevent unscheduled outages or reduced operating efficiencies
§ State-of-technology on intake screen design, operation and optimization
§ On-call assistance for emergency intake management issues
§ Contribute to and benefit from a network of informed Project Description- EPRI 3002017668 peers Practical Solutions for Power Generators Tech transfer through webcasts, newsletter, tech briefs, and annual meeting 101 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Relevant OMOIG Technical Briefs Several tech briefs on different types of biofouling and debris types that can force outages
§ Hydrilla (3002002526)
§ Bryozoans and Hydroids (3002003052)
§ Jellyfish (3002014362)
§ Frazil Ice (3002004233)
§ Fish Kills (3002004640)
§ Cooling Water Intake Debris Management: Coatings for Biofouling Control (3002007621)
§ Marine Debris: Issue, Modeling, &
Detection (3002016687)
§ Harmful Algal Blooms (3002018397)
§ Results of zebra and quagga mussel member survey (3002025119) 102 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Reference Manual on Forecasting
§ Describes major components of forecasting system
§ Step-by-step guide illustrating integration of key components
§ Hypothetical case study for illustration
§ 3002024512 Reference Manual for Forecasting Debris Events at Cooling Water Intake Structures 103 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Innovation and Ongoing Research 104 © 2023 Electric Power Research Institute, Inc. All rights reserved.
EPRI Technology Innovation (TI) is funding a multi-year research project to evaluate the use of remotely operated vehicles to clean intake structures under full flow conditions to improve diver safety and reduce O&M costs 105 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Remote Technologies for Cleaning Trash Racks
§ Key task:
- Understand how well the cleaning tools work for a variety of biofouling (e.g., hydroids, bryozoans, barnacles, oysters, mussels)
- Test platform stability under full flow conditions
- Test (custom) tools developed for fouling removal
§ Variables include: intake hydraulic characteristics, biofouling types, minimum trash rack cleanliness to be achieved, degree of fouling at which cleaning is initiated
§ Study design based on demo site characteristics
§ Testing
- Field testing of selected technologies (platform and cleaning tools) at a selected demo site
- Power facility in Florida in early 2024
- Potential estuarine site in 2025, if results from 2024 are positive 106 © 2023 Electric Power Research Institute, Inc. All rights reserved.
New TI Project: Data Integration for Event Forecasting
§
Background:
Forecasting debris events at CWIS requires an understanding of debris types (e.g., macroalgae, jellyfish), debris density, timescales, and physical behavior of debris (area, depth, trajectory)
§ Issue: A forecasting model is data intensive and includes multiple data types (e.g., surface and submerged sonar, unmanned aerial vehicle, satellite imagery, hydrodynamic, meteorological)
§ Research: Assess the feasibility of an information technology system that can collect, store, and process multiple data streams from various monitoring technologies and produce a 3D/real-time visualization model of the cooling water source waterbody. Can be incorporated into a forecasting system.
107 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Open Discussion 108 © 2023 Electric Power Research Institute, Inc. All rights reserved.
TogetherShaping the Future of Energy 109 © 2023 Electric Power Research Institute, Inc. All rights reserved.
BACKUP SLIDES 110 © 2023 Electric Power Research Institute, Inc. All rights reserved.
CFD Modeling
§ Solid and fluid geometry models have been developed using design information from the Surry Power Station
§ Boundary condition locations have been defined
- Inlet: 18" lines feeding into 18" header
- Outlet: 14" lines, prior to motor-operated valves
§ Mass flow rate, pressure, and temperature data from the plant was used
§ Mass flow rates of 18" feed ducts assumed to be the same
§ Menters Shear Stress Transport (SST) model with automatic wall functions used Photo courtesy of Surry Power Station 111 © 2023 Electric Power Research Institute, Inc. All rights reserved.
CFD Modeling Mesh 1 Nodes 2,986,315 Elements 2,919,432 Minimum orthogonality angle, º 31.2 Mesh expansion ratio 5 Mesh aspect ratio 1,051 Area-averaged ! 280 112 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Residence Time to Determine Simulation Time
§ Residence time of 1.5 s
§ Performed 8 times for total simulation time of 12.0 s
§ Time increments on 0.001 s
§ 12,500 total time steps for each simulation
- ~32 hours to complete 113 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Other CFD Applications in the Balance of Plant
§ Refinement of prior CFD studies examining entrance effects
- Include the pipe wall in the model and investigate non-steady flow based on this work
§ Evaluate design modifications to improve heat transfer or flow distribution
- Investigate velocity distribution along heat exchanger shell to identify areas of possible high wear
- Identify areas of potential vibrational issues
§ Heat exchanger tubing integrity with adjacently plugged tubes
§ Revisit Condenser Performance Evaluations using CFD
- Last EPRI study performed in 1998 114 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Future Options
§ Full-scale pilot
§ Look for active (non-simulated) leaks
§ Evaluate influence of man-made noise
§ e.g., cathodic protection, non-insulated reinforced concrete, grounding grids
§ Assess seasonal variations
§ e.g., rain/snow events, salt treatments for icing
§ Current discussions with host sites for leak detection in fire protection and other buried piping
§ Deployment strategy
§ (i.e., commercialization, common design package)
§ Stretch Goal: Can the leak detection system detect a coating holiday?
115 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Significant Weather and Potential Saline Discharge
§ In March 2020, Pump C was offline for maintenance
§ Two large, anomalous increases detected in soil conductivity near Line D vacuum-breaker pipe during precipitation events
§ Suspected storm-induced backpressure on Line D resulting in saline water overflow of the vacuum breaker line saturating the soil.
116 © 2023 Electric Power Research Institute, Inc. All rights reserved.
Other EPRI MV Cable Research
§ 3002010591 Effects of 0.1 Hertz Withstand Testing on Medium-Voltage Cable Insulation
- Research question, is withstand testing destructive?
- A control group and a group of cables that were subjected to 60 consecutive days (78 hours9.027778e-4 days <br />0.0217 hours <br />1.289683e-4 weeks <br />2.9679e-5 months <br /> total) of 30 minute withstand testing at 7kV, then at 12 kV for 30 minutes, 21 kV for 30 minutes and 23 kV for 30 minutes
- Results showed the test was not destructive (degrades good insulation) because there was no difference in AC breakdown strength between the control group and the test group
§ 1025263 Plant Engineering: Dewatering Effects on Medium-Voltage Ethylene Propylene Rubber Cable - Study of wet, wet-dry, dry effects on cable insulation condition showed that drying wet cables improved cable condition but keeping them dry is better
§ Two studies for accelerated wet-aging were attempted, but were unsuccessful in aging the insulation
- Use of high frequency voltage (450 MHz and 900 MHz) did not give the expected aging effect as no increase in tan delta occurred after 1-3 years of aging 117 © 2023 Electric Power Research Institute, Inc. All rights reserved.