ML20206F390
| ML20206F390 | |
| Person / Time | |
|---|---|
| Issue date: | 04/29/1999 |
| From: | Advisory Committee on Reactor Safeguards |
| To: | |
| References | |
| ACRS-T-3073, NUDOCS 9905060103 | |
| Download: ML20206F390 (154) | |
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ACRST'3073 4
OFFICIA' L TRANSCRIPT OF PROCEEDINGS
-NUCLEAR REGULATORY COMMISSION l
l 1
i
Title:
' MEETING:- PLANT LICENSE
. RENEWAL -
f TRO4 (ACRS 4
RETURN ORIGINAL TC B M ITE
~?/
M/S T-2E26 415-7130 THANKSl Docket No.:
)
Work Order No.:
ASB-300-759 B
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~ LOCATIONi Rockville,MD.
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. DATE:
Thursday, April 29,1999 PAGES:112 - 272 50 1 3 990429 7-3073 PDR ANN RILEY & ASSOCIATES, LTD.
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O DISCLAIMER UNITED STATES NUCLEAR' REGULATORY COMMISSION'S i
ADVISORY COMMITTEE ON REACTOR SAFEGUARDS APRIL 29, 1999 The contents of this transcript of the proceeding
- of the United States Nuclear Regulatory Commission Advisory
~
()
' Committee-on Reactor Safeguards, taken on April.29, 1999, as j
reported herein, is a record of the discussions recorded at the meeting held on the above date.
This transcript had not been reviewed, corrected and' edited and it may contain inaccuracies.
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UNITED STATES OF AMERICA rs i
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NUCLEAR REGULATORY COMMISSION l
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4 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 5
6 ilEETING:
PLANT LICENSE RENEWAL 7
8 U.S. Nuclear Regulatory Commission 9
11545 Rockville Pike 10 Room T-2B3
)
11 Rockville, Maryland 12 e
13 Thursday, April 29, 1999 14
,A y,) ~
15 The subcommittee met, pursuant to notice, at 8:30 S
16 a.m.
17 18 MEMBERS PRESENT:
19 MARIO H.
FONTANA, Chairman, ACRS 20 MARIO V.
BONACA, Member, ACRS 21 THOMAS KRESS, Member, ACRS 22 DON W. MILLER, Member, ACRS 23 ROBERT L. SEALE, Member, ACRS 24 WILLIAM J.
SHACK, Member, ACRS 25 ROBERT E. UHRIG, Member, ACRS
[-
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PROCEEDINGS ye g
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2
[8:30 a.m.]
3' DR. FONTANA:
The meeting will now come to order.
I 4
This is the second day of the meeting of the ACRS i
5 Subcommittee on Plant Licens.e Renewal.
)
)
6 I am Mario Fontana, Chairman of the Subcommittee 1
7
.for Plant License-Renewal.
The ACRS members in attendance
-8 are Mario Bonaca, Thomas Kress, Don Miller, Robert Seale, i
i 9
William Shack, Robert Uhrig.
10 The purpose of the meeting is for the subcommittee
{
11 to review the NRC. staff's safety evaluation report 12 concerning Calvert Cliffs' plant license renewal application 13 and related matters.
14 The subcommittee will gather information, analyze.
s) 15 relevant issues and facts, and fo$mulate proposed positions 16 and actions as appropriate, for deliberation by the full 17 committee.
.18 -
Noel Dudley is the cognizant ACRS staff engineer 19-for this meeting.
20 The rules for participation in today's meeting 21 have been announced as part of the notice of this meeting 22 previously published in the Federal Register on April 5, 23 1999.
A transcript of the meeting is being kept and will be 24 made available as stated in the. Federal Register notice.
25 It is requested that the speakers first identify GQ-ANN RILEY & ASSOCIATES, LTD.
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themselves.and speak with sufficient clarity and volume so 2-that they can be readily~ heard.
13 We have received no written comments or requests 4
for Lime to make oral statements from members of the public.
5.
Today, we're going.to hear from staff on.a 6
presentation of their safety evaluation report.
Now, Noel 7
.has given the ACRS members a list of the SER chapters and a 8
listfof issues, with member assignments.
Please get your 9.
comments to Noel, who will collect them.
These are needed 10 by the full: meeting.next week so that we can incorporate 11
'them into the-interim letter.
12 Also, if you have any questions from the-staff 13 regarding the sections that are assigned to you or any 14
. additional areas of' interest, raise.them before the end of A~I J 15 the day so that-we can receive their replies in time for 16
. drafting of our letter next week.
17 We will proceed with the meeting and I call upon 18-Mr. Christopher Gratton.
19 MR. GRATTON:
Yes.
20 DR. FONTANA:
To proceed.
21 MR. GRATTON:
Thank you.
I'm not quite sure 22 whether or not I can speak loudly enough or clearly enough 23 to be heard, but my.name is Chris Gratton.
I'm the 24-divisional coordinator for license renewal activities in the 25 Division of Systems Safety Analysis, and I was also a ANN RILEY & ASSOCIATES, LTD.
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reviewer for the Calvert Cliffs license renewal project.
2 My presentation will be on the scoping and 3
screening portion of the safety evaluation report.
During 4
my. presentation, I'm going to cover the implementation of f
5 scoping requirements, the implementation of the screening.
j 6
requirements, how we handle structures and commodities, open 7
items pertaining to scoping and screening, confirmatory l
8 items pertaining to scoping and screening, and the license 9
renewal issues pertaining to scoping and screening.
10 The staff's goal was to have reasonable assurance
.L 1 that the applicant identified all the structures and l
12 components subject to aging management review.
In order to 13 get this reasonable assurance, we performed the following--
i 14 reviews to scope the systems, structures and components.
I O
5,j 15 The first thing that we did was we took a complete 16 list of the systems-and structures at Calvert Cliffs from 17 Table 3.1 in the application and identified those systems 18 and structures that had license renewal application reports 19 contained in the application.
j 20 From those systems and structures, without reports 21 of application, we sampled several systems to determine 22 whether they had intended functions, then we've included 23 them within the scope of license renewal.
We've used the 24 FSAR to determine whether the systems had any intended 25 functions.
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1 So our focus was on those systems that were not' I
l
.()
2 included in the license renewal application, since the other 3
ones were already in and evaluated.
4 We did identify some systems and structures that 5
did'not have reports in the application, but upon further 6
investigation and through the RAI process, we have 7
satisfactory responses from-the licensee that the components 8.
that perform intended functions were, in fact, in the 9
license renewal applications in other sections, such as the 10 commodities sections.
1 11 From this review, the staff obtained reasonable 12 assurance that all of the systems and the structures with 13 intended functions were identified in the license renewal 14 application.
15 The second review that we performed, we asked 16 ourselv'es what portion of the within-scope systems and 17 structures are required to perform intended functions.
For 18 each of the -- I believe there were 66 systems and j
19' structures in the application, 35 of vh.ch are broken out 20 into individual SERs in our safety evaluation report.
21 We compared the simplified drawings that were 22 provided by the. applicant to the flow diagrams in the FSAR 23 or other docketed diagrams or drawings of the system.
We 24 focused on those portions of the system that were not within 25' the scope of license renewal, to ensure that they did not b
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have any. intended functions to complete system level-
)
2 intended functions.
We used the FSAR to identify the 3
intended functions along with'the list of intended functions 4
provided by the application.
5 Special consideration was given to the boundary 6'
valves or boundary points to ensure that they were properly 7-account'ed for within the scope of license. renewal.
8' Next, we identified the within-scope components 9
that were in those portions of the systems that were within 10 the scope of license renewal.
For each system and structure 11 within scope, Calvert Cliffs provided a list of these 12 components that were within the scope of license renewal.
13 Using the flow diagrams, we validated those lists component 14 by component.
We found some emissions, but in interaction O
\\/
15 with the licensee, we clarified tdose emissions as either 16
.not required to be within the scope of license renewal or 17 the applicant agreed that the characterization of the system 18 boundaries was incorrect and they included those components 19 within the scope of license renewal.
20 At this point, we had boundaries for our systems 21 and we had a list of components that we had reasonable 22 assurance constituted the entire group of components that 12 3 were within the scope of license renewal and we went on to 24
.our screening portion.
25 This consisted of an active / passive determination t
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and a long-lived /short-lived determination.
The staff n()
2 compared the list of components within the scope of license 3
renewal to those subject to an aging management review and 4
focused on the applicant's justification for removing items J
5 from the second list.
The applicant actually provided two 6
lists; one within the scope of license renewal, and a second 7
subject' to an aging management review.
8 The difference between those two lists were 9
removed for one of two reasons, either an active / passive 10 determination or a long-lived /short-lived determination.
11 That's what the staff focused on, to see whether or not that 12 determination was made properly.
13 What remained from this second -- from this 14 screening process was a list of structures and components O
(,)
15 subject to an aging management review.
Now, I sort of mixed i
16 components and structures together and that's because the 1
17 evaluations were done similarly, although a structure is not j
18 a system.
The structures vere identified individually and j
i 19 broken down into their components and the same process was
]
1 20 performed as it was within the system.
We identified those i
21 portions that perform intended functions.
We focused on any i
22 portions of a building or a structure that was -- and if it 23 is not within the scope of license renewal, to see if it 24 performed any intended function.
l 25 Then we ensured that the list of components was i
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complete and that the components, subject to an aging p(_,)
2 management review, was also complete.
For commodity groups, 3
the structures and components were assembled in a different 4
manner.
The commodity groups, being several different 5
' systems, and the staff performed a review of the following 6
type.
7 The applicant stated that the commodities l
8 associated with the within-scope portions of the system were 9
also within scope.
.In the commodities section, the 10 applicant listed the systems contained in that commodity and 11 the staff verified that the list was accurate by sampling 12 the systems not included on the commodity list.
13 So in the commodities section, a table was 14 provided of those systems that contained that particular (D
(ms/
15 commodity.
If it was electrical equipment, it was 16 electrical equipment.
If the commodity group was component 17 supports, it was component supports.
18 Using the boundaries that we had validated in the 19 systems portion, if, say, the feedwater system was listed on 20 there as having a component support, those portions that 21 were within scope, including any piping and structural 22 components that extended beyond the last boundary valve, 23 that were used for structural support for seismic 24 considerations, weren't within scope.
23 This was true for the commodity groups.
This is
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the same way that we evaluated this.
The commodity groups bq) 2 were instrument lines and cables.
Cranes and fuel handling 3
was reviewed in an individual section.
It didn't span 4
different groups and fire protection system was evaluated as 5
a single system.
6 As far as open and confirmatory items, we still 7
have four open items.
The first one has to do with the 8
station blackout diesel building.
It was not included 9
within the scope of license renewal and it was erected in 10 close proximity of the seismic Category 1 EDG building, and 11 there were questions in the staff about whether or not the 12 design of the building brings it within the scope of license 13 renewal.
The words in the final safety evaluation report,
-14 final safety analysis report, that say that its failure O
' (_)
15 could impact the ability of the EDG building to perform its 16 safety-related function, but the staff is considering,.as I
17 you will see in the portion on license renewal issues, 18 cascading issues, and that is how far out and what sort of 19 boundaries do we place on scoping and items that do not i
20 itself perform safety-related functions or
-21
.non-safety-related functions whose failure can affect a 22 safety-related piece of equipment.
23 The second open item.
There are several nozzles l
24 in the charcoal filter beds.that were not scoped within the 25 scope of license renewal.
The licensee had indicated that A
- t]
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up'to the isolation valve for these nozzles, there's a c,hort
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2 section of piping and then a spray nozzle.
The fire
,3 protection staff in DSSA believes that this section of
-4 piping, these nozzles are required by 10 CFR 50.48, and 5
we're-trying'to address that.with the licensee staff.
6 The third issue also is a cascading sort of issue.
7 It has to do with the ductwork that provides cooling to 8
'certain rooms within the containment that provide the basis 9
- for environmental qualification calculations.
Without this l
10 ductwork or failure of this ductwork, the EQ requirements 11 may not be maintained.
The assumptions that were made in 12 the calculations would not be maintained, and the staff is 13 trying to address how to handle these secondary issues, 14 failure of a non-safety-related piece of equipment and its
,O)
's_,-
15 effect on a piece of safety-relate'd equipment.
j
(
16 The final open item is just sort of an editorial 17 type of thing.
We noticed that there were some I
18 inconsistencies between the referencing of individual system i
19 electrical commodities and the electrical commodity list.
20 So an open item was issued to make sure that those two i
21 sections -- well, not those two sections -- the electrical i
22 commodities list, which contains the table of all the 23 systems that have electrical commodities in them and the 24-systems themceives, that they cross-reference each properly, 25 because right now we've found several errors in that
(
l l
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relationship.
O[()
2 As far as the confirmatory items go, we have two.
3 Staff has been talking with the licensee about the tendon 4
galleries and their exclusion and we're waiting for 3
5 resolution on that issue, as well as certain solenoid valves 6
in the containment spray.
The information I had on these
~
7 valves is that they're air-operated valves and they do not 8
contact process systems.
9 So it's just a matter of identifying the type of 10 valve to see whether or not they would be within scope or 11 not.
12 Finally, the license renewal issues, there were 13 three in the DSSA section.
They covered consumables, which 14 was not addressed in the BG&E application.
Consumables, the O
staff just issued a position on tde 20th of April covering
\\_/
15 16 structural steel and grease, component filters, system 17 filters, fire hoses, fire extinguishers and air packs.
18 Staff plans to use that position.
It's calling 19 for comments at this time.
20 Fuses, there was a -- staff put out a position 21 that fuses were active components and BG&E countered that 22 the fuses were, in fact, passive and the -- I'm sorry.
Just 23 the opposite.
24 The staff believed that the fuses were passive and 25 BG&E thought they were active.
I' ' ~
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The final one is this cascading issue that I O
i j.
2 addressed earlier, and that is systems that are 3
non-safety-related or relied upon in calculations; you know, 4
should their failures be considered within the scope of 5
license renewal when performing your scoping.
i 6
Thank'you.
7 DR. FONTANA:
The cascading failures, how do you 8
go about analyzing those?
Do you track them from first 9
principles or does it go back to the PRA or something like 10 that?
11 MR. GRATTON:
It was pre-deterministic.
For this 12
.SBO failure, it was in the FSAR for another reason and the 13 description of the failure was in the FSAR itself and 10 CFR 14 54.4,.the B criteria, non-safety-related, whose failure t
xs/
15 could affect a safety-related piece of equipment, the EDG 4
16 structure being the safety-related piece of equipment, it 17
.was a direct deterministic evaluation.
18 DR. FONTANA:
Okay.
Thank you.
Ready to move on?
19 MR. GRATTON:
Yes.
20 DR. SEALE:
When you did these deterministic 21 calculations, were they, in some cases, replications of the 22 calculations that you had done or had been done back when 23 the license was first granted, the bounding kind of 24 calculation that is used in the licensing basis?
25 MR.'GRATTON:
No calculations were actually done.
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The current licensing basis actually carried forward into t
i 2
the. license renewal period.
That was one of the bases for s
3 performing this review.
This was a scoping review, where we 4
tried to bring the design basis events onto the systems and 5
determine which portion of the systems were actually 6
performingLthe system level intended functions that were 7
described in the FSAR.
8 DR. SEALE:
So you made no attempt to confirm that
]
j 9
you could replicate those calculations.
j 10 MR. GRATTON:
No.
I 11 DR. SEALE:
The laws of physics haven't changed, 12 but 13 MR. GRATTON:
Not that I know of.
14 DR. SEALE:
-- there may be other things that have
)
changed in the interval that would make that calculation 15 16 somewhat difficult at this point, I'm afraid.
17 DR. FONTANA:
Anything else?
18 MR. GRATTON:
Thank you.
19 DR. FONTANA:
Who is next here?
20 MR. GRIMES:
Dr. Seale, this is Chris Grimes, 21 Chief of the License Renewal and Standardization Branch.
22 I would like to point out that it is our 23 expectation that we may end up going back and looking at the 24 structural analysis for the non-safety-related station 25 blackout diesel building and, using that assessment, to make
'l \\.
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a determination about whether or not failure of that rN j
f j,.
2 building and its impact on the safety-related diesel 3
generator building is an appropriate failure to consider for 4
this purpose.
j 5
So we may end up going back into that analysis and 6
-looking at the conservatisms or the nature of the failure 7
modes.
4 8
DR. SEALE:
That analysis wasn't in the original 9
licensing basis,.was it?
i 10 MR. GRIMES:
When the station blackout -- no, not 11 in the original licensing basis, but when the station 12 blackout diesel was added, it became a'part of the licensing 13
- basis, t
14 DR. SEALE:
Yes.
And you.may confirm that.
\\_)
15 MR. GRIMES:
I expect tdat we will end up 16 reviewing that analysis to make a final determination on 17 this particular open item.
i 18 DR. SEALE:
I think we'd be interested in what you 19 find out there.
20 DR. FONTANA:
Okay.
]
i 21 MR. MUNSON:
My name is Cliff Munson.
I put l
l 22 together Section 3.1, common aging management programs, of i
I 23'
'the SER.
These are programs that appear throughout the --
24 that are used in the different structures and systems, in a Y
25 variety of structures and systems.
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The first one is the fatigue monitoring program,
()
2 the second one is the chemistry program, and then the third 3
is structure and system walkdowns, boric acid inspection 4
program, corrective actions program, and the age-related 5
degradation inspection program, ARDI, 6
So we'll start with the fatigue monitoring 7
program.
This program monitors and tracks low cycle fatigue 8
usage caused by pressure or thermal transients for 9
components in the nuclear steam supply system and steam 10 generator welds, and the cumulative usage factor is used to i
11 quantify the fatigue damage resulting from each transient.
i 1
12 The design limit for the CUF is one and corrective 13 actions are to be implemented before this CUF reaches one.
14 DR. KRESS:
It's easy to measure the pressure f~
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\\
15 variations, but thermal variations, you need thermocouples 16 stuck around everywhere.
17 MR. FAIR:
I'm John Fair, the reviewer on this.
18 What they mean by that is they're measuring process 19 temperatures as heat-ups and cool-downs occur.
20 DR. KRESS:
Okay.
And then they --
'21 MR. FAIR:
In some cases, they do have some more 22 detailed thermal measurements in certain locations.
23 DR. KRESS:
But.they just measure the temperature 24 of the fluid.
25 MR. FAIR:
Right.
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1 MR. MUNSON:
The fatigue monitoring program is f
I) 2 applied to these different systems that I've listed here.
3 As of right now, there are no open items or confirmatory t
4 items or license renewal issues for the fatigue monitoring 5
program.
6 DR. SHACK:
How does that handle GSI-190?
?
MR. FAIR:
We separated, in the SER, the 8
monitoring program by itself as a program that just. tracks 9
the fatigue from the issues related to fatigue in the other 10 sections, and we discussed the GSI-190 in Section 3.2.
11 MR. MUNSON:
The next common aging management l
l I
12 program is the chemistry program.
The chemistry programs 13 primarily manage the corrosive action of water for systems 14 containing primary, secondary water, component cooling, and O
15 service water.
The ARDMS managed'by the water chemistry 16 programs include various types of corrosion, from crevice 17 corrosion, galvanic, to general corrosion, pitting, 18 intergranular attack, stress corrosion cracking, 19 intergranular stress corrosion cracking, primary water 20 stress corrosion cracking, microbiologically-induced 21 corrosion, selective leaching, and degradation of 22 elastomers.
23 For the systems containing primary water, these 24 are a list of the systems containing primary water, and the 25 aging effects that apply to these systems that are managed D(]
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by the chemistry program.
f)
(j 2
These are the secondary -- systems that contain 3
secondary water, excuse me, and a list of their aging 4
effects.
l 5
DR. SHACK:
I assume that this really works -- I 6
mean, they reference EPRI guidelines for primary and 4
7 secondary water chemistry.
What is the commitment, that if q
8 EPRI revises those guidelines, what does Calvert Cliffs do?
i 9
MR. PARCZEWSKI:
Usually, the plants keep abreast 10 of any changes which are made in the guidelines.
{
i 11 -
DR. FONTANA:
Please identify yourself for the I
1 12 transcript.
13
-MR.
PARCZEWSKI:
Kris Parczewski, from Material 14 Engineering Branch, NRR.
k,)
15 DR. SHACK:
But there is no commitment then to --
m 16 MR. PARCZEWSKI:
There is no specific commitment 17
.in the submittal.
18 DR. MILLER:
.A question.
Several of those systems 19 do involve -- have some radiation.
Is there synergistic 20 effects between.the chemistry.and the radiation effects?
Is 21~-
that addressed in the guidelines?
I'm not familiar with the j
22 guidelines.
r 23 MR. PARCZEWSKI:
Those guidelines don't address 24-any radiation effects.
25 DR. MILLER:
Is there any -- I don't know.
- Bill,
(
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do you know about that?
Is there synergistic effect from f
(
2 those chemistry -- I'm not a-chemist, so I don't know, but 3
some of the systems do involve some level of radiation.
4 MR. MEDOFF:
I'm Jim Medoff, with the Materials 5
and Chemical Engineering Branch.
I've done chemistry 8 inspections.of plants in Region I.
Calvert Cliffs has been
(
7 one of the plants I have inspected.
8 Typically, these plants do monitor both the cold 9
chemistry of'the reactor coolant system and the radioactive 10 nuclides in their reactor coolant system.
In addition to 11 meeting the EPRI guidelines, the plants typically set 12 administrative limits that are more conservative than the 13 EPRI guidelines, because they typically don't want to get to 14 the levels or the limits set by the.EPRI guidelines.
O is_)
15 So the chemistry departments typically try to 16 maintain the water chemistry to levels that would be f
17 consistent or better than would be dictated by the limits 18 set by EPRI.
19 So from what I have found from my chemistry 20 inspections, the industry has been implementing their 21 chemistry control programs in accordance with the guidelines 22 and, actually, they've been doing such a good job of it, 23 this was one of the reasons they took the chemistry 24 inspections out of the core curriculum.
25 So I think that the licensees do address chemistry n
(
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quite well.
/-
/
2 DR. KRESS:
The answer to the question that he
(
3 asked is no, that the radiation levels in the cooling system 4
are so small, that it doesn't enter into the chemistry very 5
much.
6 DR. MILLER:
What's the limits on the radiation 7
for tha't?
8 DR. KRESS:
It's the iodine.
9 DR. SEALE:
Your other question, I mean, the radiation certainly does affect the water chemistry.
That's 10 11 basically why you have a hydrogen over-pressure, to make 12 sure that you don't generate undesirable species because of 13 the radiolysis.
You suppress that as part of the water 14 chemistry.
)
15 DR. KRESS:
Yes, but it's so low that it wouldn't 16 matter anyway.
17 DR. SEALE:
Not the radiolysis product you generate in the 18 core.
When you're in a BWR and you're not suppressing, you 19.
get a very different chemistry.
Not in your concern, but in 20 the corrosion person's concern, it generates a very 21 different corrosive environment, depending on whether he can 22 or cannot suppress those radiolysis products in a PWR.
23 DR. MILLER:
So in a PWR, it's not a concern.
In 24 a BWR, it might be a different situation.
25
.MR. PARCZEWSKI:
Actually,'the iodine, radioactive
>(
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iodine, which is dissolved in the sump, can be controlled by
,m w_-)
2 keeping pH in the sump water about seven, because then the 3
iodine is kept in ionic state and, of course, then it's not 4
released.
So there is a control of iodine, radioactive 5
iodine in the water.
6 DR. KRESS:
Yes.
But that has little to do with 7
the corrosion issue.
8 DR. SEALE:
It's a different issue.
9 DR. KRESS:
It's a different issue.
10 MR. MUNSON:
Continuing with chemistry programs 11 for component cooling and service water systems.
These are j
1 12 the aging effects listed here.
For the chemistry programs, 13 theza are no open items, no confirmatory items or license 14 renewal issues.
l rs
(_)
15 DR. SHACK:
Can I just go back to the fatigue 16 program for a second?
When they're monitoring fatigue, 17 they're monitoring these components for some sort of 18 bounding.
I mean, they're not monitoring every location, 19 obviously, so they pick bounding locations.
20 Are these bounding locations for the things that 21 were considered in their original design analysis or have 22 they incorporated industry experience that you're getting 23 fatigue, for example, in feedwater lines that you really 24 didn't anticipate in the original fatigue analysis?
Are you 25 bounding those, also?
(n)
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MR. FAIR:
Both are handled.
The answer is o
j Q
-2 correct.
Most of the locations are based on the original 3
tatigue analysis.
However, there were some additional items j
4 added, one of them being steam generator nozzles that were a i
5
. product of industry experience, and they did some fairly
-l 6
detailed monitoring at the plant to come up with their f
7 analysis of those nozzles.
8 DR. SHACK:
So they think they've bounded all 9
those locations then with the components.
10 MR. FAIR:
Yes.
They think they've bounded the 11 worst case.
The monitoring program, as you say, is a 12 sampling program and it relies on picking the worst cases 13 for the sampling.
14 DR. SEALE:
Let me make sure I understand what Id 15 we're saying and the code words tdat we're using and all.
16 I recognize this may not be within the narrow 17 scope of the review of the BG&E application.
But 18 nonetheless, there are pilot studies that have been ongoing 19 having to do with in-service inspection that are related to 20 fatigue problems in piping and stress corrosion.
21 And there are presently applications before the 22 Commission to go to a risk-informed inspection program where 23' the sites of the inspections are picked on the basis of 24 experience with previous problems with systems.
25
-If I read your comments correctly, I gather that ANN RILEY & ASSOCIATES, LTD.
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133 1
the positions that you have identified or that the applicant I
(~h
(_j/
2 has identified here as the places where they're doing their-3-
fatigue analysis encompass not only the kinds of fatigue 4
locations that were in their original in-service inspection, f
5 but also at least some selection of the results of the 6
experience that has been gained over the years of other 7
locations where fatigue has, in fact, been observed.
8 Now, that doesn't mean that BG&E is asking to go 9
to a risk-informed in-service inspection program, but they 10 are using some of those results in picking the sites for 11 doing their fatigue monitoring.
Is'that correct?
12 MR. FAIR:
I believe they're using the experienco 13 of past problems to pick some of their selected sites.
I 14 don't know that risk was factored into any of those
(~h
\\-sl 15 decisions.
16 MR. DOROSHUK:
This is Barth Doroshuk, from BGE.
17 We incorporate operating experience into locations that we 18 have in our fatigue program either as an ongoing monitoring 19 point or special analysis.
I'm not sure that we care if 20 it's a risk-informed location.
We're more concerned about 21 suspicion that there is damage occurring.
22 So we do not use a risk-informed type of approach 23 when we think there is something going wrong.
The locations 24 in the fatigue program would not be removed from the program 25 as a result of using a risk-informed approach.
If there was
(_))
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to be a removal of a point in the monitoring program, it
(~
t
,/
2 would have to be reviewed against 50.59 requirements to 3
ensure that the design basis requirements were still being 4
met.
5 So even though we are supportive of using 6
risk-informed ISI, we do not use that type of insight to 7
remove locations from the monitoring without proper 8
evaluation.
9 DR. SEALE:
If I may make a comment.
The obverse i
10 of that coin is that if the ISI -- if the risk-informed ISI 11 programs -- that is, the programs that are based on some l
12 sort of risk analysis -- don't pick up the, quote, 13 experience identified areas of concern that you have i
i 14 selected to add to your program, then there is something i
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i
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15 wrong with that risk-informed analysis.
That's the first j
1 16 point.
I 17 The second point is that I assume that whatever 18 we're doing in no way prejudices your option down the road 19 to come in and request a modification of your licensing 20 basis to allow you to go to a risk-informed in-service
~
21 inspection program.
22 But that's completely removed from and independent 1
23 of whatever the concerns are that we have right here.
I 24 MR. DOROSHUK:
I agree with you.
25 DR. SEALE:
Okay.
l
/' \\
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MR. DOROSHUK:
Maintaining the configuration and
/~(x) 2 being able to maintain the flexibility to change as you get 3
insight is an appropriate thing to do and we would -- we 4
believe the commitments that are being put in the 5
application as part of the licensing basis would be 6
modifiable if we did gain the flip-side, which is positive 7
experience, as well.
8 So we don't think we're handcuffing ourselves at 9
this point.
10 DR. SEALE:
It isn't your intent to do so.
11 MR. DOROSHUK:
No, sir.
12 MR. STROSNIDER:
This is Jack Strosnider, Director 13 of Division of Engineering.
I'd just like to confirm that, 14 number one, I agree completely with.what you said with
,m(,)
15 regard to risk-informed inspection programs.
Our 16 expectation, as you're aware, we're working through these 17 pilots now, is that when done properly, they would identify
)
18 the more likely locations of failure, that that's part of 19 the consideration there.
20 So we would expect that that would be the outcome 21 of a risk-informed program.
22 Secondly, yes, but nothing that's happening in 23 this amendment is going to preclude someone from proposing a 24 risk-informed inspection program down the road.
25 The final comment I want to make, which I just
(~x)
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thirk might help in this -- in understanding this section,
~
(Qj 2
is-to recognize that going through a number of programs here 3
and-if we talk about a chemistry program, for example, when 4
you get to a particular system, you may not be relying 5
solely on that chemistry program to manage degradation.
6 In this case, this fatigue monitoring is really 7
monitoring to compare to the design basis, the usage factor 8
type consideration.
For certain systems, there will also 9
be, on top of that, some Section 11 or other inspections f
10 that are performed.
I 11 So I think it's important to recognize that when 12 you talk about fatigue monitoring, this is not solely what's j
13 being relied on to manage the aging mechanisms.
14 Like I said, when you get.into the specific I
(')h
(
15 systems, you'll see that, well, ye'ah, you credit chemistry, j
16 you credit perhaps in-service inspection or whatever the 17 appropriate combinations are that will effectively manage 18 the mechanism.
19 MR. MUNSON:
The next common aging management 20 program is entitled structure and system walkdowns.
These
- 21 are walkdowns of structures and systems and components so 12 2 that any abnormal or degraded condition will be identified 23.
and documented, with the goal that corrective actions are to 24
- be taken before abnormal or degraded conditions proceed to
.25 the failure of the system or structure.
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I 137 1
Corrective actions are taken in accordance with
.(
2 the licensee's corrective action program, which is QL2, and 3
at a minimum, these walkdowns should occur at least once 4
every'six years.for every structure and system.
5-The walkdowns are to be performed on these 6
following structures and systems, component supports, 7
primary containment structures, al] the way through to 8
-safety injection systems, instrument lines.
I won't go 9
through the whole list.
10 DR. SEALE:
Here, again, you talk about what's 11 going to happen in the future.
It's the " going to be".
12 What about the "has been?" I mean, you haven't been 13 boycotting the inside of the plant for the last 20 years.
14 You've been walking around in there.up till now and if you O(_,/
15 found any water on the floor or wdatever the expression i
16 might be, you've identified the problem and you've taken 17.
corrective action.
18 And I would assume that there would be some 19 corporate memory so that those actions would show up in this 20 program,.too.
21 MR. HEIBEL:
This is Dick Heibel, B-
.imore Gas &
22 Electric.
You're exactly crrrect.
After every outage, the 23 system' engineers perform sfstem walkdowns to ensure that the 24 systems are ready to sttr. up.
There's also PMs that 25-require _wal)iswns at this six-year frequency specifically to
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1 look at degradation of the system.
But all of these systems r^(s) 2 will get a walkdown by the system engineer at least every 3
two years.
4-Additionally, the operators have to perform valve lineups after every outage and which valve lineups they do 5
6 and don't perform is controlled by a procedure that we 7
require them, at a minimum, every two cycles, to do an 8
entire-valve lineup.
9 DR. SEALE:
But in addition to that, if you've had 10 any experience in the past, I would assume that somehow 11 you've factored that into your assessment.
12 MR. HEIBEL:
Exactly correct.
13 MR. STROSNIDER:
This is Jack Strosnider.
Just to 14 add,. again, part of the staff's review ~is'to look at I
/~')
)
\\s,J.
15 operating experience.
We asked questions in that area and j
16 the submittal included information on prior experience.
So i
17 that is taken into consideration with regard to what you 18 might expect in the future or what corrective actions have 19 been.taken that might need to continue.
So that is a 20' specific part of the review.
21 DR. UHRIG:
In other words, that's just a 22 continuation of the existing program as far as walkdowns are 23 concerned.
24 MR. GRIMES:
This :u's Chris Grimes.
Except to the 25 extent that we look at whether or not the walkdown is fn)
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addressing a particular aging effect of concern.
I think
' (*3
,,).
2 fsome of the walkdowns have increased their scope or increased -- or changed the guidance to the plant personnel 3
4 who are' going to be looking for particular kinds of 5'
degradation.
6 DR. SHACK:
That's the 101 modified procedures we 7
saw yesterday or something like that.
8 MR. STROSNIDER:
In the broader context, the 9
question is what's-the operating experience not just for 10.
this unit, but even industry-wide, and does your program, 11 whether it's a walkdown program or whatever, does it have 12 the right attributes in it to address that experience.
13 Part of this gets into identifying what are the plausible aging mechanisms based on.looking at experience.
14
)
15 DR. FONTANA:
How many walkdowns have been done on 16 six-year intervals so far?
The question that I'm getting at 17 is, does six years appear to be a good number.
18 MR. DOROSHUK:
This is Barth Doroshuk, from BGE.
19
.The six years is for structures only.
As Dick Heibel 20 pointed out, these walkdowns occur when you get down at a 21 system level.
Each system engineer is required to walk down 22 all or part of his system on a monthly basis, unless it's 23-negotiated differently with his supervisor.
24 So this is a much more frequent activity than is 25-represented here, from a detail standpoint.
In addition, p
I 1
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)
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these activities -- these il.kdowns have been. formally in
()
2 place for over ten years, that these procedures or 3
guidelines have been in place and have been, of course, 4
maturing with the results of the inspections.
5 So the short answer is yes, we do think it's 6
. effective, and, of course, we'll continue to refine the 7
program as we conduct the walkdowns.
And it has been 8
refined for license' renewal in particular, as Mr. Grimes 9
pointed out.
10-DR. BONACA:
Just a question.
Operating 11 experience is also used to reduce'the number of components 12 which are within the aging management program, correct?
For 13 example, I was looking at the instrument lines, where an 14 evaluation of the failures that have occurred over 25 years, f3
(,,/
15 and because of the categorization that these are due to 16.
poor, inadequate maintenance, a lot of this lining is-17 removed from the list because we haven't seen aging issues 18-affecting the lines.
Is it correct?
19 MR. GRIMES:
This is Chris Grimes.
I believe that 20-the' characterization is in terms of whether or not there is 21
.a reason to believe that there is an aging effect that needs 22 to be managed for those lines.
)
23-DR. BONACA:
I understand that.
.24 MR. GRIMES:
As opposed to removing it, it was 25 more is there'a class of instrument line that requires O
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141 particular attention and an aging management program.
1
(
')
2 DR. BONACA:
Exactly.
So I understood that
%J 3
correctly.
The question I had is that clearly we -- this is 4
projecting that the future will be like has been for the i
5 past 25 years.
There may be some incipient aging effect we 6
haven't seen yet, either because we go to extended life or 7
because there are some phenomena that don't manifest 8
themselves -- haven't manifest themselves yet 9
How do we -- how do the programs address these 10 issues?
Where you don't have -- when looking at certain 11 areas because your program doesn't lead you to do that, 12 you're waiting for the failure of the component or -- I'm 13 trying to understand how does this get done.
14 MR. STROSNIDER:
Operating experience is one part
,e]
(,)
15 of the review, but it is not considered, in and of itself, 16 sufficient to define whether you need a program in the 17 future.
18 You also look, based from your knowledge of the 19 type of degradation mechanisms that might be anticipated, 20 you look at research results and then you -- so you look at 21 the potential basically, I guess, just from an engineering 22 or scientific basis of what potential mechanisms might show 23 up and you look for programs to address those.
24 But there are things that are covered in these 25 programs that have not been observed in operating reactors, I
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but there is an anticipation they could come about.
So you (n]
2 look at them.
3 So I think the important point is, yes, operating 4
experience is considered, but it's not the sole basis for 5
defining the program.
6 DR. BONACA:
Since we're not looking at risk issues'or risk importance of components in this program, 7
so 8
there could be some component there that because we haven't 9
seen any aging effect, is not being inspected specifically 10 or looked at.
Yet, it is risk ~significant.
11 Is it possible that we have the combination there?
12 MR. GRIMES:
We went back to look to see whether 13 or not there were any risk-significant components that were 14 passive that weren't otherwise captured by the deterministic nk,)
15 basis.
So that's a feature of the review, is to determine 16 whether or not the aging management programs are 17 sufficiently comprehensive.
18 I'd also like to add to what Jack said, that you 19 mentioned the potential that there might be incipient aging 20 effects that have not yet been manifest.
The concept about 21 having the current licensing basis and the existing 22 regulatory process carry over is a recognition that as we 23 learn things in the future and if we identify a new aging 24 effect, and we would like to think that's unlikely because 25 we did a -.we've got about 15 years worth of research
[\\ -) '
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that's looked at what are plausible aging effects, what are
( W) 2 applicable aging effects, and we've been reasonably i
3 conservative and the applicant has been reasonably 4
conservative about attaching aging effects to things for 5
which, as Jack mentioned, haven't been observed yet, but in 6
anticipation, they might occur, we'll make'sure that 7
inspect' ion and maintenance are appropriate.
8 DR. BONACA:
But you see what I was going at.
So 9
you have comfort in your review that the programs they have 10 implemented will allow for early detection of degradation in 11 certain components which are passive, but are not part of 12 what is recognized today as being under an aging program.
13 MR. STROSNIDER:
Correct.
And I think we have to 14
. acknowledge, we don't have a crystal ball, there's been a C(
15 lot of research done.
We're addressing those issues that we 16 consider plausible, things that could happen that we need to 17 look at.
18_
But the other.important thing is that these 19 walkdowns and the plant programs, you heard the sort of 20 frequency, there are indicators of -- if new problems show 21 up, these program walkdowns and other inspection activities 22 and stuff will show that that's occurring.
23 Then we do gain through operating experience and 24 we'd have to factor that in as new issues show up.
25 So when you go into the renewal period, some of ANN RILEY & ASSOCIATES, LTD.
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344 the same. programs and mechanisms that you use today for 1
]
(
2 identifying unexpected problems will carry forward into the 3
renewal period.
4 But the attempt here is.to address as much of what 5
you think is plausible as you can.
l 6
.DR. BONACA:
I had a question yesterday.
I said 7
that once the license is granted, it's a process that 8
continues.
There is no further review, and then they accept 9
that.
10 The only question I had on the part of the staff 11 is how is the staff planning to monitor, in the next 15 12 years, not only for this plant, but for the other plants, 13 and see if what they thought was a sufficient basis for the 14 license ten years from now is still. going to be good, what 15 have we learned from this process.
16 I'm trying to understand how you guys are going to 17 do that.
18 MR. GRIMES:
We would intend to do it better than 19 we have in the past, actually, in terms of the programs that 20 we have to change'the oversight process, that looks at plant 21 performance relative to.its licensing basis on a day-to-day 22 basis, and to constantly challenge whether or not the 23 licensing basis is adequately addressing safety.
24 W( have now developed a program that's going to
'25 look at plant performance indicators relative to our
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20036 I
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=. -
,i 145 1-expectations about plant performance and that includes 2.
program attributes, whether or not the programs are 3
' effective, are the events that are occurring -- do they indicate that there is some weakness in either the design or 4
5 the operation of the facility.
6 So to get back to your original question, we're
.7
'. working towards a conclusion that is based on comfort that i
8 actions have been or will be taken, using the language in 9
54.29, about the Commission's decision basis, that includes 10 a continuation of feedback mechanism that learns from 11 experience, adjusts as new information comes along, but is 12 constantly looking in areas that are risk-significant or 13 materially significant; that is, like fatigue, looking at 14 potential damage locations.
i 15 So we're confident that the processes will work to 16 carry forward these conclusions and continually challenge 17 them.
l 18 DR. BONACA:
And I appreciate that.
I'm only 19 saying that this is a rule which has a special opportunity 20 for being tested before it really goes into play, and that 21-it will be many years before this plant achieves its 40-year
-22 life and walks into the life extension.
23 I think because of that, there has to be a 24-sensitivity and monitoring almost itself as a rule, because 25 certainly ten. years from now, you're going to find that the ANN RILEY & ASSOCIATES, LTD.
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146 1.
presumptions which were in the rule and in this review were
()
2 pretty much correct.
We haven't learned anything else that 3
said we really didn't have our act together.
4 So that's an important point, I think, that there 5
should be some otrategy at the NRC level to learn these 6
lessons and monitor.
7 MR. GRIMES:
We agree.
8 DR. BONACA:
And that would give the comfort also 9
to the public and everybody else that these programs are 10 thorough and have a foundation.
So there is an opportunity.
11 MR. MUNSON:
For the structure and systems
-12 walkdown, there is one confirmatory item.
The walkdowns
-13 have been amended to detect the aging effects of reinforced 14 concrete structures.
Previously, that was overlooked.
O.
(,,/
15 The next aging managemedt program is the boric 16 acid inspection program.
This program manages the general 17 corrosion of the carbon and alloy steels exposed to 18 concentrated boric acid.
The program involves periodic f
19 walkdowns of borated systems to look for leakage and 20 subsequent corrective actions to mitigate the effects of the 21 concentrated boric acid corrosion.
22 This program also manages general corrosion, 23 erosion / corrosion, where, and stress corrosion cracking of 24 various carbon steel reactor pressure vessel components and 25 the program also manages, in part, primary water etress i
(
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-corrosion cracking of alloy-600 components.
fN
~
l
)
2 The program is applied to the following list of t
3' systems and structures.
4 The open item for this boric acid inspection 5
program is it does not provide'for removing interference; 6
thus, some internal. portions of the reactor vessel cooling 7
shroud'that harbor pockets of liquid may be inaccessible for 8
visual inspection.
9 The confirmatory item.is that the inspection scope l
10 is to be expanded to_ include reactor vessel cooling shroud I
11 anchorage to reactor vessel head and reactor vessel cooling 12 shroud structural support members, 13 DR. SEALE:
I don't quite understand your open 14 item.
You recognize that some areas a'e not accessible for r~
k_N) l 15 inspection as they are presently configured.
16 MS. COFFIN:
That's right.
This is Stephanie 17
' Coffin.
18 DR. SEALE:
You're going to live with that or are
)
19 you'doing something to --
l20 MS. COFFIN:
No.
It's an open item for the 21 applicant to address.
22 DR. SEALE:
I see.
So they're going to come up 23 with something which you will then assess for its adequacy 24 to remedy that.
25 MS. COFFIN:
That's right.
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1 DR. SEALE:
Okay.
()
2 MR. MUNSON:
The next common aging management 1
3 program is the corrective action program and this corrective 4
action -- the program is really one of.four phases of the 5
maintenance strategy used by,BG&E to manage the effects of f
6 aging.
The four phases are discovery, assessment analysis,
~
1 7
corrective action, and confirmation document.
8 The current licensing basis provides for the 9
assessment, analysis and corrective action and confirmation 10 documentation phases through the implementation of their 3
11 corrective action program, which is the QL2 corrective 12 action program.
13 The processes and activities encompassed by QL2 1
14 are conducted pursuant.to the requirements of Appendix B to
{
)
15 10 CFR Part 50 and cover all structures and components 16 subject to aging management review, and the staff determined 17 that this approach is acceptable to address the population 18 of safety-related structures and components subject to aging 19 management review.
20 There are no open items for the corrective actions 21 program.
22-There is a confirmatory item, a description'should 23 be included in the UFSAR supplement and for the applicant's 24
- --- ar.d/or the applicant's quality assurance policy for the 25 Calvert. Cliffs nuclear power plant to confirm that BG&E
+
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Appendix B program also applies to non-safety-related j)
(
2 structures and components that are subject to aging 3-management review for license renewal, so that these 4
programs can be controlled.
5 DR. UHRIG:
Is this an expansion of QA program?
6 MR. SOLORIO:
This is Dave Solorio.
I'm sorry.
7 When you say expansion of the QA program.
This is an 8
existing program.
It's a very mature program that BG&E has 9
had.
10 DR. UHRIG:
But it's going out to new components, 11 is it not?
12 MR. SOLORIO:
Well, you're shaking your head, 13 Barth, but before I so correct me if I'm wrong, but there 14 are certain components that BG&E has said are subject to an.
O' (j
AMR that were not safety-related dnd I believe BG&E will say 15 16 that some of those components have always been part of their 17 QL2 program.
18 But the staff's concern was that the 19 documentation, either the QL2 program or the UFSAR, did not 20
.specifically call out those components, non-safety-related 21 components, to be within the scope of the QL2 program.
22 Therefore, the staff is just asking for that to be committed 23 to.
'24 MR. DOROSHUK:
This is Barth Doroshuk, from 25 Baltimore Gas & Electric.
This is not an expansion of the
(
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quality assurance program.
All the components on-site, tRQ 2
whether they be safety-related or non-safety-related,
\\
are l
3 subject to the corrective action program and controls of 4
Appendix B.
5 What this confirmatory item does -- so in other 6
words, if we' find something wrong, we write an issue report 7
and we' walk through the licensing basis checks to check l
8 operability issues, irregardless of its classification.
9 But what this is going to do is recognize that 10 there is an aging dimension.that may be needed to be
{
clarified just for -- I guess we talked here yesterday about 11 J
12 the culture and changing behaviors, just to make sure that
)
13 that's captured.
14 DR. UHRIG:
Thank you.
15 MR. HEIBEL:
This is Dick Heibel.
To put a little 16 more definition.
We would consider it an expansion to the 17 program if it's being subject to QL2, the corrective action 18 program would change a component from being
{
19 non-safety-related to safety-related.
We don't intend to 20 change the designation from non-safety-related to 21 safety-related.
But it will still be subject to the -- the 22-entire plant is subject to the corrective action program, j
23-MR. MUNSON:
The final common aging management 24 program is the ARDI program.
These are one-time inspections 25
~to verify that an age-related degradation mechanism does not
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need to be managed for the period of extended operation or
()
2 to' verify the effectiveness of an existing separate 3
preventive or mitigative type program.
4 The ARDI is applied to a number of different 5
systems.
6 DR. SEALE:
That's a pretty long list.
Basically, 7
you're hoping that plants don't develop post-40-year i
8 geriatric diseases', like arthritis and some of these other 9
things that some of us have.
10 MR. DOROSHUK:
Yes, sir.
We agree with_you.
This 11 probably goes right to the question earlier on are we trying 12 do we have a crystal ball.
13 These aging effects that this program is being 14 employed on are on the periphery of.--
we haven't seen them 15' yet, but, again, we' set the thresdalds very low and we're
'16 going to go out and do these confirmations.
So hopefully 17 these types of activities do try to take into account Mr.
18
.Bonaca's concern.
19_
DR. SEALE:
'Well, when you come up with your 20 crystal' ball, maybe someone will come up with a silver 21 bullet to take care of some of our other problems, too.
22' MR. MUNSON:
The open item for ARDI is the staff 23 has identified some age-related degradation mechanisms that 3
24 we feel require periodic regular inspections and such as for 25 the verification of acceptable condition of codings and
' i'~
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152
]
1 verification that corrosion is not occurring due to leakage.
O Q
2 So there were some differences that we had with 3
the licensee with respect to whether ARDI should be applied I
4 to different systems.
5 DR. SEALE:
So basically, you moved them into a 6
more disciplined or scheduled inspection mode, right?
7 MS. COFFIN:
If we thought that a one-time 8
inspection wasn't enough, then we asked them to do something 9
more regular.
10 DR. SHACK:
How many of these ARDIs are open to 11 question now?
12 MS. COFFIN:
I don't understand what you mean.
13 DR. SHACK:
I assume that -- it says that they're 14 not acceptable for come of these.
\\
15
'MS. COFFIN:
That proba$ly affects about -- I'd 16 have to check.-- about three to five systems.
17 DR. SHACK:
Three to five.
18-MS.' COFFIN:
Out of'--
19 DR. SEALE:
That 15.
20 MS. COFFIN:
Yes.
21 DR. FONTANA:
What specifically?
Is there one or 22 two that you can --
23 MS. COFFIN:
You want an example?
24
'DR.
FONTANA:~
Yes.
25 MS. COFFIN:
One example that the staff' identified
- D~
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was for the saltwater system, they are going to rely on ARDI
)
2 to' verify corrosion of carbon steel components due to 3
. leakage through1the system and the staff believes that since 4
leakage can happen anytime throughout the remainder of the 5
plant's life, doing a one-time inspection really is not 6-going to work for that aging effect, and that's something 7
that should be going into the system walkdown kind of a 8
procedure.
9 Actually, the applicant has decided that that's 10 how they're going to do it and that's more of a confirmatory 11 item for that particular system that I gave you an example.
12 DR. SHACK:
How about the service water?
That's 13 like a-long-shot for a one-shot inspection.
14 MS._ COFFIN:
I'd have to look at the application 15 ~
to'look at specifically what kind of aging effect they're 16f
'particularly addressing.
A lot of these things,.the 17
- applicant gave us a-lot of-information on the design and the 18 environment.
That made the staff feel very comfortable that 19 if there.is an aging effect, it's going to be very minimal,
-20 and they planned on doing these inspections to' verify that 21' assumption, and, of course, if that assumption is incorrect, 22 they're going to be implementing their corrective action 23 program.
24 MR. MUNSON:
That's the conclusion of Section 3.1, 25 DR. FONTANA:
Thank you.
Any additional questions
]
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.on this section?
2 (No response.)
.3-DR. FONTANA:
We'll go on to the next one.
4 DR. SHACK:
John, just before you leave.
Have you V -
5' decided what happens if, in fact, they can't manage to keep 6'
something below the line?
7 MR. FAIR:
I'm not leaving.
But if you were 8
excusing me, I'll be glad to go.
9 DR. SEALE:
No.
In a word.
10 MR. FAIR:
Yes.
They would have to write a 11-problem identification report and we had a discussion of 12 this, which they haven't -- there is no specific action they 13 can determine ahead of time, other than.it would probably i
14 require a look at an expanded scope.of components, since j
b),i this is a sampling procedure, and'they have several options
(-
15 16-for corrective actions; either do some more analyses, 17:
' propose some additional inspections, or maybe go as far as 18.
replacement of the component'.
19.
MS. COFFIN:
I just want to point out that r.11 20
.t'hese common programs that Cliff just went over today, 21 you're going to be seeing them again and again throughout
- 22 the presentations, and I don't think most of the presenters 23 are planning to spend a lot of time on all those common 24 programs,-since~we already went over them.
25 MR. ELLIOT:
My name is Barry Elliot.
I'm.with
()
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=1 the Materials and Chemical Engineering Branch of NRR, OV 2
Division of Engineering.
I'm going to be discussing our 3
review.of the reactor vessel, the internals and the reactor 4
coolant system.
5-The applicant-has 19 programs to manage the aging 6'
effects of the reactor vessel, the internals and the reactor
~
i 7
coolant system.
Nine are existing programs, five are 8
modified -- are existing programs that have.been modified, 9
and five are new programs.
10 I don't' intend to go through all 19 programs.
I'm 11 just going to take and highlight what I consider the most-12 important ones.
Some of them I just listened to and I heard 13 a lot of discussion.
So you're going to only hear a brief 14 description'of the program.
15 The first program is the water chemistry program.
16 For the reactor coolant system, it established limits on 17 impurities, such as fluorides, chlorides, hydrogen and 18 dissolved oxygen.
It measures primary coolant. parameters, 19 such as conductivity and pH.
20 The water chemistry program is used to assure the 21
. reactor' coolant system will not be subject to corrosion.
22 It's an existing program and will continue into the license 23 renewal term.
24 The next program is the eddy current examination 25 program for the steam generator tubing.
It's an existing ANN RILEY & ASSOCIATES, LTD.
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1 program and also will continue into the license renewal d
/T
!s )
2 stage.
It's used to detect denting, where stress corrosion
)
3 cracking and pitting.
4 The third program is the in-service inspection 5
program and it picked -- the inspection is a non-destructive 6
examination and a pressure test to determine critical 7
locations and components to manage the effects or where 8
erosion, corrosion and cracking.
i 9
This is an existing program.
However, as part of 10 our review, based on operating experience, based on 11 knowledge of aging mechanisms, we have recommended additions 12 to these programs and modifications to these programs.
13 I'll be talking about, later on, the modifications 14 to the ISI program for the internals and the open issues, in
)
15
-particular, there is a series of dodifications we are 16 recommending be included or at least right now are open 17 items that might need -- we might need to make adjustments 18 to the ISI program.
19 DR. SEALE:
Barry, just out of curiosity, are all 20 the cooper components gone or copper alloy components gone 21 from their secondary system, so they can truly optimize 22 their water chemistry?
23 MR. ELLIOT:
I don't have an answer to that.
24 MS. COLLINS:
Especially as it affects steam 25 generator tubes.
(A]
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157 1.
MR. ELLIOT:
The next program I'm going to talk
)
2 about is the reactor vessel material surveillance program.
)
)
3 This program is an interesting one for Calvert Cliffs, 4
because they have one of the best programs in the United 4
5 States.
6 In this program, generally, materials are removed 7
from capsules and periodically tested to monitor the effect i
8 of neutron radiation in the environment.
In the case of 9
Calvert Cliffs, they started with six capsules in their 10 vessel.
They've tested -- each vessel.
They have tested 11 two from each vessel.
So they have four capsules remaining 12 from their original program.
13 They have gone out and added to this program.
14 They have added' supplementary capsules that they got I
s_)
15 material from Shoreham.
It turns out Shoreham welds were 16 some of the critical welds in Calvert Cliffs Unit 1, also.
17 In addition, it turns out that McGuire also has 18 material that.is related to Calvert Cliffs, so that using 19 the-McGuire data to monitor and calculate the neutron 20.
irradiation embrittlement for the Calvert Cliffs vessel.
21 As far as the license renewal -- that's the 22 existing program.
We are concerned about two things, 23 generically, in license renewal for vessel surveillance l
24 programs.
First, that the data bound the neutron fluence j
i 25 for the license renewal period and the second thing is that I
l fy
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158 1
the data that is gathered, and, in many cases, it could be O)
(_,
2 gathered before the license renewal period ever begins, that 3
it be applicable to the operation of the plant during the 4
license renewal period.
5 In this case, I don't think it will be a problem 6
for Calvert, because although we've explained this to them,
~
7 that if they take -- there are two things they have to do.
8 They have to modify their program.
9 First, they have to extend the surveillance schedule to 10 include capsules out to the neutron fluence at the end of 11 the license renewal period.
Second, if they have early 12 withdrawal of capsules, they must establish limits on their 13 operations as far as temperature, flux, spectrum -- that's 14 about all I can think of right now -- that they must operate (D
\\_,/
15 the plant to and that the surveillance data is useful for.
16 If they go outside that bound, then they would 17 have to come back to us and either restart the surveillance 18 program, make adjustments to the surveillance program, or 19 tell us how they're going to adjust their irradiation 20 embrittlement estimates.
21 But I don't think this will be a problem for 22 Calvert.
They have a lot of capsules and they should be 23 able to monitor the radiation.
That's neutron irradiation 24 embrittlement.
25 The next is thermal embrittlement, cast stainless m.
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steel components.
/~h.
,)
(
2 DR. SHACK:
Just a quick question.
On that one, 3
do they have lots of margin on their PTS?
4 MR. ELLIOT:
Yes.
Well, it's not that they have 5
-- they have -- but I could.tell you, the PTS values, 6
they're below the screening criteria at end of license and 7
they're committed, as part of the regulations, to monitor 8
this.
In fact, six months ago, they submitted a new 9
estimate and they're still -- and their estimate included 30 the license renewal period and they're significantly below 11 the screening criteria for both units.
12 DR. SHACK:
I take it that they're even still at 13 50 foot pounds for the --
14 MR. ELLIOT:
Fifty foot pounds upper shelf energy.
,-f Y
(_/
15 They did an analysis that shows tdat at the end of the 16 license renewal period, they'll be just above 50 foot 17 pounds, like 51 or something like that.
This will be 18
. monitored as part of the vessel surveillance program.
19 The thermal embrittlement portion is a new 20 program, the cast austenitic stainless steel program, and 21 this program is to identify cast stainless steel materials 22 that are susceptible to thermal. embrittlement based on the 23 percentage of ferrite,.the amount of molibnimum, and the 24 casting methodology.
25 The criterion-associated analyses are documented (3')
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in EPRI topical report 106-092.
The criteria was developed
(
2 using measured and saturation lower bound JR curves.
The 3
. saturation lower bound curves were developed by Argonne 4
Laboratory from' tests on age, cast stainless steel material. In all cases, the Argonne prediction curves were equivalent 6
or conservative compared to the measured values.
7-
. Staff reviewed the topical report and' submitted an 8
. evaluation,;I think, to NEI and we've discussed it with 9
Calvert Cliffs.
There are some modifications that are 10 necessary to the program.
A few of the -- one criteria has 11 to be changed.
The method of calculating ferrite has to be 12 a particular way and the inspection method of -- should we 13 he recommending that it be qualified-to Appendix 8, if'they 14-can develop techniques that can qualify this.
This materially is very'hard to ultrasonically 15 16 inspect, but we're hoping that the industry will put an 17
' effort here and be able to qualify an inspection procedure 18 for this type of material.
19
.DR.
SHACK:
'I'm~ curious about that, because it had 20-
' comments about niobium in the stainless.
21 MR. ELLIOT:
Yes.
One of the things we said is 22'
.that if.there's any niobium in the cast stainless -- these 23 are part of the limits.' We modified the limit on -- we 24 modify'a~ ferrite limit for high molibnimum, but if there is 25 Lany niobium in the cast stainless steel, then this criteria
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would not apply, and the material would have to be
.g
(,,/ -
2 inspected.
3 DR. SHACK:
Did they really have enough foresight 4
to analyze for niobium in their cast stainless?
5 MR. ELLIOT:
They said they're going to look into 6
it.
7
~ MR. BALDWIN:
Marvin Baldwin, with Baltimore Gas.&
j 8
Electric.
Cast was one of the areas we looked at very 9
closely.
We reviewed the certified material test reports i
10.
that we got from Combustion Engineering, from fabrication, 11 and determined that we have no niobium.
Niobium was neither 12 specified in the fabrication of any of the cast components 13 that are in the RCS pressure boundary.
14 DR. SHACK:
I'm sure it wasn't specified, but was.
~..
s 15 it analyzed to find out if it got in some other way?
16 MR. BALDWIN:
I recall seeing niobium on.the data 17 sheets for some of the CMTRs.
I can't say that I saw them 18'
'for all, but what I did was I -- I'm not a metallurgist, but
~19 I know how to look at documentation to see what's there, and 20 I did see NB or, I think it was called something different 21 before, I forget what it was, and I did see those on some,
~22 where there were blanks or no numbers.
23 DR. SEALE:
I'm not sure I understand where this 24 niobium is supposed to be.
What if you went to a-different 25 cladding material?
i
(,)
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162 1
MR. ELLIOT:
Excuse me.
This is not cladding,
)
2 This is cast austenitic stainless steel.
3 DR. SEALE:
That's what I said.
I didn't know 4
where the niobium was supposed to be.
So you've answered my 5
question.
6 MR. ELLIOT:
Okay.
7 DR. SHACK:
It's not supposed to be there.
8 MR. ELLIOT:
Yes, it's not supposed to be there.
9-DR. SEALE:
I know, but if we talk about high burn-up fuels 10 and the possibility of modifying cladding.
11 MR. ELLIOT:
This issue, you could -- I mean, Bill 12 knows a lot about this.
13 DR. SEALE:
I'm sure he does.
14 MR. ELLIOT:
I think the French reactors, I think, O
15 specified niobium.
16 DR. SHACK:
No,.they didn't, but they got it.
17 MR. ELLIOT:
They got it.
And so that's why this 18 was a concern that was raised and specifically if there is 19 niobium, then all the criteria don't apply and the materials 20 would have to be inspected.
21 The next' program is a modification to the ISI 22 program.
It's the internals inspection.
It's the internals 23 program.
I'was listening before about here is a case where 24 the licensee says really there is no problem, but the staff 25 has decided that there is a potential problem in the future.
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)
1 In this case, the internals are subject to high 2
radiation and what we're concerned about here is
)
3-radiation-assisted stress corrosion cracking as well as just J
4 general embrittlement of the stainless steel.
5 Another part.of this is that we also have the cast 6
stainless components also.in this internals.
So not only 7'
are'they going to have the neutron embrittlement, but 8
they're-also going to have the thermal embrittlement of 9
those components.
10 At the moment, there is very limited data 11 available for. neutron embrittlement of stainless steel.
The i
12 applicant is participating in an industry program to develop
'13 that data.
14 However, until that data has gotten analyzed, we
{
(,/)
\\
s.
15 have decided that the ISI program needs to be enhanced.
The 1
16
. current program is-to do a VT-3.
Our experience with
)
i 17
. boiling water reactors is that a VT-3 will not discover the 18 type of cracks that you can get from IASEC and, therefore, 19 an enhanced'VT-1 examination.is going to be required for the 20 limiting' component or limiting locations in the internals.
21 The licensee has taken this to heart, finally, and 22' they have identified the inside surface of the re-entrant 23 corners of the core barrel as a location that is going to be 24 VT. enhanced VT-1 inspected.
That has the highest 25.
combination of stresses, because it's a welded corner.
It's ANN RILEY & ASSOCIATES, LTD.
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164 11 the closest to the core and it also has high temperatures.
)
i 2
-On one~ side, it has the hot leg temperature; the other side, 3
the cold leg temperature.
4 That takes care -- that's the stainless steel and 5
-welds.
Now, we're also concerned about the cast stainless 6
steel components.
There are two cast stainless steel 7
components.
The CE shroud assembly tubes and the core 8
support columns.
9-In this case, we are concerned about two things; 10 thermal embrittlement, like I said, and the neutron 11 embrittlement.
There is no data available for this type of 12 problem.
So, again, we asked the licensee to do an analysis 13 or to do the VT-1 inspection, enhanced VT-1 inspection of 14 these components.
15 Now, the analysis is -- this is how we're running 16 the -- this is how we're doing -- we asked them to do the 17 analysis.
We established' criteria for neutron fluents; that 18 is, ten to'the 17th neutrons per centimeter squared.
19 If the fluents receive, at the end of the license 20 period, for any of these components, are above that 21 criteria, it would be considered a high radiation area for 22 the program and the only way the components would not be 23 inspected would be if VT-3 -- would return to a VT-3 -- is 24 if they could demonstrate that the loads on this thing 25 during all ASME -- all accident conditions is either ANN RILEY & ASSOCIATES, LTD.
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compressive or very low.
Otherwise, if it has a high
()
2 fluence, it would get an enhanced VT-1 examination.
3 The second part of the criteria is for low fluents 4
components.
If it turns out they have low fluents; that is, 5
lower than ten to the 17th.
In that case, we would think 6
that the neutron irradiation embrittlement would not be a 7
factor.
The only factor to be considered then would be the 8
thermal embrittlement.
9 There, they can go -- they would have to show that 10 they meet the thermal embrittlement criteria we talked about 11 and we modified for the cast austenitic stainless steels.
12 If they could show that, then the inspection could be 13 reduced to a VT-3.
14 That's our modification there.
/~N
()
15 The next program 13 the alloy-600 program.
This 16 is for the primary system.
The alloy-600 program is a 17 program to manage primary water stress corrosion cracking 18 for pressure boundary components and it looks like the most 19 susceptible, most safety-significant components.
L 20 This is an existing program.
It basically ranks 21 the alloy-600 components based upon the residual and I
22 operating stresses, operating time, and material heat 23 treatment.
It turned out, as part of this review, that in 24 Unit 1, the most susceptible component is the vapor space 25 instrument nozzle in the pressurizer -- four vapor space yy t
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instrument nozzles in the pressurizer heads, and they will
-( )
2 be replaced during the -- with alloy-690 during the 3
2000-year outage.
4 In Unit 2, it turned out that the limiting, most 5
susceptible material was the. pressurizer heater sleeves, and 6
these materials were replaced with 690 in the 1989-1990.
7-The alloy-600 program has not identified any other 8
-- at this time, any other materials that need replacement.
9 The alloy-600 program, we use VT-1 and VT-2 to detect 10 leakage and to determine whether there is a problem with the 11 alloy-600 -- the other alloy-600 components.
12 The fourth, the last program I was going to talk
)
13 about, which we discussed already, was the fatigue j
i 14 management program for the primary system.
The fatigue monitoring program tracks the lowc ele fatigue usage of 15 s
16 critical reactor coolant system components.
17 The program has been modified to include reactor 18 coolant pumps, motor-operated valves, some pressurizer 19 components, control of drive mechanisms, reactor vessel 20 level monitoring system components.
21 DR. SRACK:
The other slide said there were no 22 open issues.
23 MR. ELLIOT:
I know.
That's not true.
24 MR. FAIR:
Could I help you with that?
It's just 25 the way that the -- we constructed'the SE.
As far as the ew ANN RILEY & ASSOCIATES, LTD.
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program itself, we didn't have a problem with the way it was O
(_,/
2 being implemented, and that is, tracking the worst 3
components and taking corrective actions.
4 In terms of the open items in this section, they 5
haven't completely evaluated.all the components to determine 6
if there were other locations that needed to be monitored.
7 So thats one of the_open items.
8 MR. ELLIOT:
We have several open items.
Some of 9
these may require modifications to the in-service inspection 10 program.
The first one is that -- this is not a 11 modification, but that the applicant should credit tech spec 12 limits of steam generator leakage as part of its aging 13 management program.
That's just we think that that should 14 be done.
w-15 We think there is a program needed to manage 16 stress corrosion cracking of the reactor pressure vessel 17 head closure seal leakage detection line.
This line has 18 had, in the past, stress corrosion cracking.
19 We think there is a program needed to manage the 20 cracking of pressurizer heads and shelves, in particular, 21 the cladding.
We've had cracking in the cladding that has 22 gone through the cladding into the base metal in Haddam 23 Neck, around the -- and the area that needs to be looked at 24 is the cladding around the surge nozzle and the heater 25
- welds.
Those are areas that have high thermal fatigue.
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DR. SHACK:
When we say this, does this mean you 2
want them to add to this to the fatigue monitoring program?
3 MR. ELLIOT:
No.
4 DR. SHACK:
Is that what is implied here?
5 MR. ELLIOT:
No.
In this case, we were 6
negotiating what kind of inspection they can do to look and 7
see whether or not we get any of the stress corrosion 8
cracking of the clad in this region or thermal fatigue 9
cracking of the clad in these regions.
10 The program that might need modification would be 11 the ISI program.
12 Again, an ISI program is needed to manage cracking 13 on the inside surface of small bore piping, including 14 Inconel material.
The applicant must document their
.(h U
15 inspection methods to detect where, before it begins to 16 compromise the function of the hold-down rings.
17 DR. SHACK:
Again, the small bore piping, that's
~18 piping'that now escapes Section 11 because of its size.
Is 19 that the --
1 20 MR. ELLIOT:
It doesn't escape it.
It has just a 21 surface examination.
It doesn't have a volumetric, and so 22 we don't see the inside surface.
So we need something more.
23 We have a few confirmatory items.
The applicant 24 is to revise the cast austenitic stainless steel program to 25 include.the criteria and methods of examination recommended ANN RILEY & ASSOCIATES, LTD.
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7 169 r.
_1-by the staff.
The applicant is to revise the RPV materials
! O)
(,
2 surveillance program to include data and establish operating 3
conditions for a period of extended operation, as I
'4 discussed.
5 The applicant is to confirm the applicability of 6
the alloy-600 CEDM program through the period of extended 7
-operation.
They have done the analysis for 40 years and now 8
they have to confirm that the analysis is bounded for the 60 I
9 years.
I 10 The applicant should document their conclusion 11 that the control element shroud bolts do not perform a 1
12 safety function, as described in 10 CFR 50.4, and,
)
'. 3 therefore, not subject to aging management review.
And the 14 applicant is to document the operating stress for hold-down O.
\\w /
15 ring, to demonstrate that the hold-down ring is not subject 16 to stress relaxation.
17 The final thing is you talked about fatigue.
We 18 have this as a confirmatory item.
This is the environmental 19 effects as related to GSI-190 and the applicant must resolve 20 the environmental fatigue issue for the period of extended 21 operation, if the issue is not resolved generically prior to 22 the end of the current license term.
23 To summarize the license renewal issues that are 24 critical for the vessel internals and reactor coolant system 25 or internals embrittlement, which I discussed.
Thermal
()
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1 aging of cast austenitic stainless steel, which I discussed.
,n-(_)
2 Vessel surveillance, which I discussed, the materials 3
surveillance program, and fatigue is the fatigue monitoring l
4 program.
5 That concludes my discussion.
6 DR. FONTANA:
Thank you.
7 DR. SHACK:
I guess I didn't quite -- is the 8
implication of the bullet on the fatigue really that that 9
one can stay open for a long time yet and you don't really 10
_need to_ resolve it until the end of the current license?
11 MR. FAIR:
Yes, that's correct.
What we're 12 relying on in that is we did the evaluation for current l
13 operating license, the 40-year evaluation, and we presented
(,,'h a finding that we didn't think we needed to backfit anything 14
\\- /
15 for the current operating license.
16 The open issue was whether we could extend that 17 conclusic into the renewed period of operation and we 18 thought we needed additional work in order to make some 19 safety conclusion in the renewed period.
20 MR. GRIMES:
I'd like to add.
The treatment of 21 this generic safety issue is the same approach that was used 22 during the operating license stage in terms of the treatment 1
23 of generic safety issues and recognizing that we weren't 24 making a licensing decision at this point, with a pending i
25 issue unresolved.
l I
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L-
{
171 I
[p 1
It is our expectation that the work that the L i,/
2 Office of Research is doing is going to identify a
,s 3
resolution of this issue well before the plant reaches the 4
end of the 40 years.
5 It is a unique generic safety issue in that 6
respect because we didn't have any other generic safety 7
issues'that bifurcated between 40 years and the period of 8
extended operation.
9 But we've also recognized that we could tackle it 10 on a plant-specific basis in much.the same way that Barry
]
11 described the way that we addressed these generic renewal 12 issues for embrittlement and CASS and other things, on a 13 plant-specific basis.
14 But at this point, we're just trying to reconcile 15 what it's going to take to resolve the generic safety issue i
16 is where the NRC staff thinks it ought to be expending its 17 energy rather than trying to resolve it on a plant-by-plant 18 basis.
19 DR. FONTANA:
Any additional questicns, comments?
l 20 (No response.]
21 DR. FONTANA:
Well, we're scheduled for a break h
22 now.
Thank you very much.
Let's be back here at 10:20.
23 (Recess.]
i.
l 24 DR. FONTANA:
We will resume the meeting.
You had l
25 a 20-minute break instead of a 15-minute break, so we're l
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172 1
going to_make it up later.
!..O
, (,)
2 MS. COFFIN:
Bill, I just wanted to get back to i
l 3
you; later today, when we go over the cooling systems, 4
you're going to hear a lot more about the aging management 5
programs, for example, for the service water system.
You'll l
6 see that ARDI is actually a very small component of the 7
programs in effect for that system.
8 My name is Stephanie Coffin.
I will be going over 9
with you the engineered safety feature systems, which 10 consist of the following three systems; the containment 11 isolation group, the containment spray system, and the 12 eafety injection system.
13 Just very quickly, the containment isolation group 14 functions to prevent uncontrolled or unmonitored releases.
l 15 The containment spray system limits pressure -- the primary 16 function is to limit pressure and temperature in the 17 containment following an accident.
The safety injection 18 system, the primary function is to supply emergency core 19 cooling following a LOCA.
20 Most of these programs you've seen before, because 21 they are the common aging management programs that Cliff 22 went over today.
But very briefly, all three systems have 23 some. carbon steel, no alloy steel components, and because l
24 they're located in containment, they could potentially be l
l 25 exposed to concentrated boric acid.
So to mitigate general (O
, 'j ANN RILEY & ASSOCIATES, LTD.
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corrosion of those components, and this is -- the applicant
-Q' N,/
2 relies on its boric acid corrosion inspection program and we 3
went.over that earlier today.-
4' With regard to the inter.nals of these components, 5
the containment isolation group has a variety of internal 6
environments, including treated water, well water and 7-gaseous waste, and because of the design of the system and 8
the internal environments, the applicant presented 9
information that the corrosion effects are expected to be minimal and they're relying on ARDI and supplemented by some 10 11 local leak rate testing of some valves in their programs to 12 verify that,-for the management _of aging effects.
That 13 would be crevice corrosion pitting, general corrosion.
14 DR. SHACK:
What size is this piping that we're 15 talking about here?
16 MS. COFFIN:
I would have to look at the 17 application.
It probably varies.
For the containment spray i
18 system, it's exposed internally to treated water and we're 19 relying primarily on the applicant's chemistry program to
'20 mitigate the corrosive effects of that environment.
21 Because there are some stagnant conditions in the system, 22 because it's in a standby mode most of the time, the 23
. applicant has committed also to doing some age-related 24 degradation inspection, the ARDI inspections, to check 25 specifically-in those areas.
(O 4
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1 For the safety injection system, again, this
(
2 system is exposed internally to treated water, and we're 3
relying primarily on their chemistry controls to prevent 4
corrosion of the internal services.
5 There are some local leak rate tests and pumps and 6
valves in their IST program that they also rely on to detect 7
any degradation _that's going on, supplemented by ARDI in 8
some various portions of the system.
.9 One aging effect that's actually not on this chart is 10
' elastomer degradation and that's for a perimeter seal on 11 their refueling water tank, and the -- because it's exposed 12 to the element, the applicant identified some degradation 13 that is possible for that seal and they're relying on their 14 structure and system walkdowns to identify that.
5s 15 There are some modifications that they need to 16 make to that program that I'm going to talk about.in the 17 next slide, because those are confirmatory items.
18 For the safety injection system, there is 19 something unique in that system in that they have 20 experienced, at this plant, stress corrosion cracking of the 21 refueling water tank penetrations at the penetration welds 22 and they've discovered that through their walkdowru.
They 23 plan on continuing that program to monitor -- manage that 24 aging effect, although they're going to do some additional 25 engineering evaluation, that, again, I'm going to put off l
I n
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-just for a moment, because.it's part of our confirmatory
.,fq-js,):
2 items with respect to that aging effect.
3 Lastly, fatigue, this system is included in their l
4' fatigue monitoring program and, once again, there is going 5
.to be_a modification to that,.
The applicant is going to be
\\
6 doing some additional information relative to fatigue that I 7
will ta'lk to right now.
8 DR. SHACK:
Would this thing see cycles or is this j
9 some sort of leakage kind of induced fatigue?
i 10 MR. FAIR:
What they're monitoring right now is 11 the safety injection nozzle, which does see thermal cycles 12 during shutdown cooling initiation.
They're also taking a 13 look further in the line, certain sections of the line for 14 potential stratification effects, which they haven't Ok-15 completed yet.
16 MS. COFFIN:
There aren't any open items with 17 respect to these three systems and the confirmatory items 18 are, one, to modify the structure and system walkdowns and 19 specifically what they're planning to do is explicitly add 20' to the scope the inspections of the refueling water tank for 21 the safety injection system.
They're also going to add into 22 the-procedure inspection criteria for the perimeter seal for 23 the RWT and for the RWT penetrations, penetration welds.
241 The applicant committed to doing an engineering 25 evaluation of stress corrosion cracking at their RWT
- ()
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176 penetrations and they w&nt to reach the conclusion that they 1
(j 2
feel satisfied that the walkdowns are sufficient to detect i
3 stress corrosion cracking before there is a loss of intended 4
function.
If they can't reach that conclusion to their l
)
5 satisfaction, then they're going to implement an ARDI-type 6
inspection program for that particular aging effect.
7 Do you want to add something Barth?
8 MR. DOROSHUK:
I want to;make one comment.
This 9
is Barth Doroshuk, from BGE.
Yesterday I referred to this 10 engineering evaluation of SEC as a leak-before-break 11 analysis, and I misspoke.
That is an engineering 12 evaluation, not a leak-before-break.
So for the record.
13 MS. COFFIN:
And the last confirmatory item, John 14 spoke to this a minute ago, is that.the applicant is Ilght p_
now reviewing industry reports, pdrticularly with respect to 15 16 thermal stratification for some portion of this system and 17 to see if and how the fatigue monitoring program needs to be 18 modified, particularly for this system, to ensure that 19 fatigue is managed for the safety injection system.
~
20 With that, that takes care of these systems.
21 DR. UHRIG:
Could you expand a little bit on -- I 22 think it's called thermal fatigue.
23 MS. COFFIN:
I would love to.
John?
24 MR. FAIR:
What did you want me to explain?
25 DR. UHRIG:
The thing that I'm most familiar with N
'q_)
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is stress.
)
2 HMR. FAIR:
Yes, and that's what is being 3
monitored.
4 DR. UHRIG:
This is just basically thermal cycling 5
reduces stress, but now you're' talking about thermal 6
stratification, and this has got me confused.
7 MR. FAIRt Well, there's an issue that came up f
8 with potential stratification in lines due to leakage 9
through check. valves and there was a bulletin issued on it, 10 -
it was Bulletin'88-08.
11 A lot of licensees have gone back to look and see 12 if they have this problem in any of the systems in their
.13 plant and the stratification problem is a combination of 14 stratified flow and cycling flow due to leakage and 15 circulation in certain parts of these systems.
s 16 They do cause alternating stresses, quite a number 17 of cycles of these alternating stresses and can result in 18 cracking and eventual leakage.
)
19 DR. UHRIG:
I had an associated stratification 20 fatigue.
21 MR. FAIR:
It oscillates.
22 DR. UHRIG:
I see.
All right.
23 MR. FAIR:
The stratification can cause other 24 problems.
25 MR. PATNAIK:
I'm Pat Patnaik.
In answer to your I
S'
' \\~
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i 178 1
question, Bill, about the size of injection containment p) y 2
spray piping, they're all six inches.
They're over four 3
inches and they're up to 12 inches diameter, stainless 4
steel.
5 DR. FONTANA:
Okay.
Anymore questions, comments?
6 (No response.]
7.
DR. FONTANA:
Thank you.
8 MR. HOU:
My name is Shou-Nein Hou, NRR.
I'm the
)
9 reviewer on Section 3.4.
That covers three areas; the 10 chemical boron control system,~the compressed air system, 11 and' fire protection.
12 For the chemical and boron control systems, the 13 major component consists of piping, accumulator, strainer, 14-tank, flow, temperature, heat exchanger, and various kinds
)
15' of valves.
~
(
16 The material, essentially.it's stainless steel j
t 17 inside; on the inside.
That means the contact of process j
18 flow.
Outside, they do have carbon steel, alloy or l
19 stainless steel.
{
20 Another is' compressed air.
The material, it's 21 carbon steel, and inside is the compressed air.
That is 22 enclosed instrument air, plant air, and standby saltwater 23 air.
24 The major components, as you can see, are piping,
~25 accumulator, air compressor, and various valves.
- Now, j '
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4 179 1
another' area is about' fire' protection.
.In the license h) 2' review,..there are 66 systems'and components, and 42 of them 3;
crelate to the firefprotection function.
.4-InLthese 42 systems, 26 are safety-related 5
structures'and-. systems such as'the pressure boundary system c
- 6-
'and the structures to perform tho' fire barrierLfunctions,
~
7-and also some electrical equipment.
8 So in this section, we're only talking about the 9
remaining 16 systems.
Now, in these 16 remaining systems, 10 nine -- part is safety-related and part is 11 non-safety-related.
But for safety-related, there is also E12
'another 26 I;just mentioned, all be addressed separately in-J13 other sections about the aging management.
14 So for_this particular review, only those
-15 non-safety-related portions of these 16 systems.
16 First, we talk about the chemical boron control 17.
system.
Not because we.have that operated as it inside'the 18-component, so there is a generic corrosion concern.
So 19 water chemistry program is very essential.
I think that's
'20
.one of the common' improvements that we have discussed this 2 15 morning and that essentially isLjust a program to identify 22
.the' perimeters need to be monitored and also the frequency 23 and also what's the' acceptance limit.
If.you're beyond the
~
' limit'and what kind of action need to be taken.
24 25' So that would take care 1of that generic corrosion b.
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inside those components, contact with the borated acid.
()
2 Now, in case if there is a leak, because the 3
fastener is -- it's carbon steel and alloy, which are 4
subject to corrosion effects to the borated acid.
In that, 5
-they have borated acid corrosion inspection program.
That's 6
also been discussed in this morning.
7 Now, the plant also -- this system also has a 8
unique concern is about using the heat trace to maintain the 9
temperature of the systems above their limit to avoid i
10 saturation of the borated acid.
That's about the stress 11 corrosion cracking, stress corrosion cracking caused by the 12 heat tracing.
Because it contains hydrogen, which is a 13 corrosive element.
14 Now, the licensee have a plant modification to
/'
l()s 15 remove this.- That program being started in '91 to replace 16 ~
it with a non-corrosive one, and the program is still 17 ongoing, and we were told that it would be completed by the 18 end of the current licensing period.
19 I think that will take care of the stress 20 corrosion cracking concerns.
j 21 Now, there are various valves.
The valve seat and 22 the dick is subject to wear, because it's normal operation.
.23 For that, they have a leak rate testing and that's a part of 24 the plant surveillance test procedure.
25.
So attention to all this.
Now, they also i
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e L;o l;
181 1
~ supplement by.an ARDI program.
.The ARDI program for these
.n
( )
.2 particular system, it try to verify no severe previous 3
corrosion impeding internals of the components contacting 4
the boric water and the shear side of the heat exchanger.
5
.That essentially is kind of.walkdown process and it's been 6
discussed in the morning.
7 Another is no significant vibration fatigue.
8-Inat, I had to go back'to.the slide in here, talk about CVCS 9
fezigue, the problem.
Now, we know fatigue is a problem.
10 It has two kind of' concerns.
One is low cycle fatigue, one 11 is the high cycle fatigue.
12 JThe low cycle fatigue is about the thermal 13 transients-and the cause of stress, fluctuation, and they 14 have the fatigue monitoring program.and we know this 15'
-program, as present earlier, and dhat program is not 16
. complete yet.
The place, the location for the monitoring, i
17 critical locations, has not been finalized.
I 18 Also, there are generic concerns also being 19-discussed, the GSI-190, how to categorically qualify 20=
operating plant for the 60 years.
Use the statistical 21 approach, not risk-informed, to pick up sample from five PWR 22 and the two BWR plants and perform an analysis using the 23 modified. curve generated by Argonne.
24 Now, besides that, now, there is a concern about
~25-the charging pump.
The charging pump has created the l
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I 182 1
operational vibration and that caused the cracking of the
,G
- l. (_,L 2
pump or block and also the suction side of the piping, as 3
well.
That has been -- that problem is being identified and i
i 4
also they have plant modifications in the design and also 5
improve the pump operating practice.
So the problem 6
cssentially is resolved and we're told about all this
\\
7 resolution and we agree with it, except for that information
{
\\
i 8
not yet being shown in the application.
9 So the application needs to be modified to 10 incorporate that information.
That essentially covers one 11 of the confirmatory items.
l 12 DR. MILLER:
When you say that problem is 13 resolved, how do you reach that conclusion?
14 MR. FAIR:
This is John Fair, again.
What b
\\._ /
15 occurred on the CVCS system is eadly in operation, they had 16 some vibration problems on the suction side that led to some 17 failures.
They went in and corrected the design, changed l
18 the design, changed the thickness of the piping, did some 19 monitoring of the system, determined that they had an 20 adequate fix for the --
21 DR. MILLER:
How did they determine that?
22 MR. FAIR:
That they didn't have significant 23 vibration.
24 DR. MILLER:
Do they have on-line vibration 25 monitoring now?
()
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183 1,
MR. DOROSHUK:
This is Barth Doroshuk, from BGE.
fw
)
2 We do have a maintenance condition monitoring program.
That
}
J 3
is a vibration monitoring program.
It monitors systems 4
throughout the plant.
That program was most likely used in l
5 the verification corrective action follow-up after these j
(
6 modifications were done to the supports and to the piping to
)
i 7
make sure that vibration was insignificant,-as well as 1
8 understanding or not seeing any additional failures or 9
degradation in the system.
We concluded that vibration was I
10 not plausible for this system.
11 DR. MILLER:
How did you determine it was not 12 plausible?
13 MR. DOROSHUK:
Vibration, we believed that 14 vibration is a result of an installation or design defect
,O)
's /
15 and the design defect or installat[ ion defect was corrected 16 here through a plant modification and then verified through 1
17 follow-up monitoring.
18 DR. MILLER:
Okay.
19 MR. DOROSHUK:
So in this particular location, 1
20 vibration, we believe, is not an aging effect.
i 21 DR. MILLER:
When was this done?
I've looked at I
22 your SER, but it doesn't tell me a timeframe.
23 MR. DOROSHUK:
Fifteen to 20 years ago.
24 DR. MILLER:
So you've got that much experience.
1 25 MR. DOROSEUK:
Yes, sir.
1 Q)
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I
'I L
i 184 1
MR. FAIR:
Just to clarify what the issue was on A) 1 2
this.
Originally, they proposed to do an ARDI on this I
3 piping to verify they had no vibration fatigue damage.
.4 There was a' question as to how an ARDI was going to verify 5
'this and after some discussions, it was determined that 6
since they had so much operating experience on the system as 7-modified, that it really wasn't plausible at this time.
8 DR. MILLER:
Part of this is response to Generic 9
Letter 88-14.
Is that what I'm reading here?
10 MR. FAIR:
I don't believe so.
Where are you 11 reading?
12 DR. MILLER:
I'm just reading the SER, on the 13 overall problem that came up.
14-MR. HOU:
You m' fan Generic Letter 88-14?
(~)
1
(_)
15 DR. MILLER:
Right, Generic Letter 88-14.
16 MR. HOU:
I'm going to talk about that later.
17 DR. MILLER:
You're going to talk about that one.
18 MR. HOU:
Yes, right.
{
19 DR. MILLER:
That relates to instrument air, which 20 apparently --
21 MR. HOU:
That's right.
22 DR. MILLER:
stimulated -- did that stimulate 23-the vibrations?
i 24 MR. HOU:
That is not a vibration problem.
25 DR. MILLER:
Okay.
I I
f.
ANN RILEY & ASSOCIATES, LTD.
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MR. HOU:
Not a vibration problem.
That's a --
I 2
well, I'm going to talk'about it.
Are you finished?
-3 MR. FAIR:
Yes.
4' MR. HOU:
About the compressed air system,.the 5
inside is compressed air.
Now, the material is carbon 6
steel.
That carbon. steel can only cause corrosion concern 7
if the~ air has some problems; for instance, it contains the 8
moisture.
So they have a preventive maintenance program.
9 That. program is going to check the air quality.
But that 10 program is later on being in place after it caused the 11 piping failure problem and the failure is caused by the 12 corrosion.
13 Because of that -- well, this is not.only the 14 plant problem, it also is the industry-wide problem.
So the (O
\\,_)
15 NRC issued Generic Letter 88-14.
'Because of this letter, 16 they modified the plant and also changed the maintenance 17 procedures and also they put in place the checklist to 18 ensure that the air quality inside the instrumentation is
~
19 dry and free of oil, free of the particulates, particles.
20 DR. MILLER:
So there is a monitoring system for 21 that.
22 MR. HOU:
A monitoring system.
23 DR. MIL ~iIk :
Generic Letter 88-14 spoke to that.
24 MR. HOU:
88-14 probably -- it's asking for some I
25 actions, but also providing information.
This is an i
O)'
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186 1
information letter.
But with that, they performed a l
!O'
(,)
2 corrective action to try to resolve the problem, and this is 3
what they do.
So the problem no more exists.
l 4
And as for the plant air, and others, like 5
saltwater, they do not have the air quality control, but, 6
however, due to their preventive maintenance procedures,
)
7 they look at more frequently and also they do have certain 8
filters, dryers,.to make the air quality good.
But --
9 except they do not have to monitor it.
Quality monitor the 10 instrument air.
11 But recently they have looked on those plants and 12 see how the condition look like and find out those lines are 13 in very good shape.
So it look like it's not much a 1
14 concern.
h
\\_/
15 Now, talk about fire protection.
Now, the fire I
16 protection, they actually -- they perform a certain way 17 procedures, try to manage the aging problem.
The first, in 18 the updated FSAR, it has to be reviewed by the staff and we 19 accept that, there is a fire protection program in there.
20 That contains certain systems and the components 21 to ensure they have -- maintain its function and for the 22 fire-fighting -- for the fire protection purpose.
23 And if -- for the non-safety-related components of
~24 the 16 systems fell into this category and there is not a 25 problem.
Now, in particular, what -- for example, that i <~r f (,)
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L 187 l
1:
includes the feedwater, auxiliary feedwater and also the
'. s,j 2_
plant drain and also something, I guess, sprinklers and also
-3' hose stations.
4 Now, another screening, there's about a structural 5
system, actually it's a moni.toring the operating conditions 6
of the system and component and that's by walkdown, periodic walkdown, and also by monitoring their performance during 7
8 the plant operations.
.9 So if have this' covered, we know there is no 10 problem because the operating condition for those system and 11 components actually -- the fire-fighting capability, because 1
12 in the safety-related components, we have -- now, there are i
13 other concerns, like LOCA, like seismic, but for this 14 non-safety-related, they do not have -- for the operating (D.
A/
15 loading is already large enough.
s 16 So if the operating condition is good,.we know 17 their fire-fighting capability is maintained.
18:
Now, that kind system, for example, component 19 cooling and compressed air system.
Now, another approach 20 they're taking is those systems -- now, they have part of it 21 is safety-related, but also another portion is 22 non-safety-related.
Now, for safety-related, we know they 23 have aging management programs defined, but in a 24 non-safety-related, they have the same material, subject to 25
.the same environment.
t
.fg
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So if they apply the safety-related aging 2
management, the program, to this non-safety-related portion, 3
that will take care of the aging concern.
So this is that 4
their third approach.
5 Now, with all of these three approaches, they 6
also, they have supplemented by an ARDI.
The ARDI program is one~ time inspection,.just to verify those fire protection 7
8 non-safety-related portions, there is no significant general 9
corrosion.
10 Now, with all these three
- proaches taken, that 11 covers the 15 of the 16 remaining issues just mentioned, the 12 non-safety issue,'but there is one remaining one.
It's the 13 condensate system.
The condensate system, the 14 non-safety-related portion, the makeup line is downstream of Od 15 a normally closed manual isolatior[ valve.
But that can take 16 care of by the ARDI.
17 Now, talk about open items.
Now, earlier, in my 1
18' discussion on the component -- the CVCS, I mentioned about f
19 there is a concern on the stress corrosion cracking and the 20 caused by the heat trace adhesive and they going to replace f
21 it with a new material.
22 But.this replacement, it is started in 1991 and 23 they said they're going to' conclude it by end of the current licensing period.
That means more than ten years away.
If 25 we know this is a concern and also we know that there is a 1
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1 way to'fix it.and also it's being started, so why take so
{
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{
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long to finish, and that's one of our open items.
We want
{
3 to have reasons.
4 Another one of concern is within -- for this 5
program, because it takes so. long, and also because of the l
J 6
replacement, but we have to know what is the situation of 7
the piping, would it already have a crack or they may 1
8 generate cracks during the ten years period of time.
S So we'd like the program also to consider the 10 inspections to ensure that the condition of the piping.
1 11 That's another open item.
12 Now, the third open item is about the fatigue.
l 1
13 The fatigue, about in the -- in the low cycle fatigue, they 14 have some -- they monitor the thermal transient and they
("n
(_
15 perform analysis based on monitor'of the results.
But the 16 analysis, the evaluation scope, it also include heat 17 exchanger and thermal, is what they indicate in application.
18 But in the application does not provide a detail about the 19
' process how to conduct this evaluation.
So this is the 20 third open item.
21 That concludes my presentation.
22 DR. FONTANA:
Any comments?
I guess one question 23 for BG&E, which I guess they don't really need to answer, is 24 when you get asked for what's taking you so long, what kind 25 of answer do you give?
Ai,'")
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MR. HEIBEL:
This is Dick Heibel, from Baltimore
,q( j.
2.
Gas & Electric.
What we were doing with the installation on 3
the boric ---the heat tracing on the boric acid, we're 4-replacing it as. components are pulled out_for maintenance 5
and on a catch-as-catch-can basis.
It's a type of 6
modification that, quite frankly, on-its face, did not merit 7
a -- it's'very. expensive-program to undertake.
8 So what we have is stocks of this different type
-9 of heat tracing and when we. pull pumps, valves, and do work 10 on' sections of pipe, replace it on a catch-as-catch-can 11 basis, or.if the heat tracing fails.
12 DR. FONTANA:
All right.
Thank you.
13 MR. HOU:
Do you have anything to say about it?
14 MS. COFFIN:
I would just. add the comment that the
'/h
- }s /
15 application has seen stress corros' ion cracking of these 16
. tanks due to the heat and that's why identified the problem,
)
17 and I'm'sure.they have an engineering evaluation of why they I
f18 can wait, but the staff hasn't seen that yet.
19.
-DR.
FONTANA:
Okay.
Who's next?
20 DR. SEALE:
Dr. Powers will probably be here the
)
21 ne::t time you talk about fire protection, so you may have a 22' few questions to come up at that time.
You're not off the 23
-hook.
24~
MR. GEORGIEV:
Good morning.
My name is George
'25 Georgiev,-and I'm with the Materials and Chemical
()
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Engineering Branch, with the Division of Engineering, and I O
1(,)
2 will be doing the presentation of Section 3.5.
3 Section 3.5 includes four systems; component 4
cooling systems, saltwater system, service water system, and 5
the spent fuel pool cooling system.
All these systems have 6
in common,.in general, the low temperature and as the name 1
7 implies', they provide cooling to various equipment 8
components within the plant.
1 9
The license application reported that several j
J 10 operating problems have occurred with those systems and with i
11 all fairness, they are all normal kind of problems that have 12 been in other plants.
An example of those problems, they 13 had a. leaky valve, valves in the component cooling system, j
14 they got some degradation of cement.in the saltwater system, l
tN l
(~sI 15 some high cycle fatigue in the spent fuel systems, and all l
16 these problems have been addressed and the repaired and 17 there haven't been any other problems.
18 The materials of all this system are various 19 because they all operate under various conditions.
They 20 include carbon steel, stainless steel, carbon-nickel, you've 21 got various type of linings, rubber linings, cement lining, 1
22 and all this is necessary to do the operation.
23 To address the problems and to take care of 24 various degradation mechanisms, the application reports 25 aging effects and for the purpose of this presentation, if g]
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192 1
you see here in the first where it says corrosion, that 2
includes various type of corrosion.
It includes crevice
-3.
corrosion, pitting corrosion, galvanic corrosion, general 4.
corrosion, and the microbiological induced corrosion.
5 Also, there are other specific fo'r these systems, 6
degradation mechanism like wear, selective leaching, 7
elastomer and rubber degradation,-mortar, cement lining 8
degradation, and sulfur.
9 DR. SHACK:
A question.
I thought yesterday they 10 said they had rubber-lined. systems, and you say cement.
11 MR. GEORGIEV:
Yes, they do have both.
They do 12 have above-ground piping, cement lined.
In fact, they have 13 reported some leakage with this.
I believe it has been 14 replaced.
But one has to address all these effects, the 15 licensee has identified aging management program and most of 16 them are existing programs.
They are either site director 17 procedures, programs to -- maintenance program items, and in i
18 some cases, they had to modify to address the aging effects.
19 And the only problem for this particular four 20 system is the ARDI program, which is the inspection program 21 that they'll do to look specifically for aging degradation, 22 for these systems.
23 And as far as having open items, we don't have any 24-open items and we don't have any licensing issues.
25 That concludes my presentation.
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DR. FONTANA:
Any questions, comments?
JN
's 2
[No response.)
3 DR. FONTANA: 'Very good.
Let's move on then to --
4 MR. GEORGIEV:
Give my time for somebody else.
5 DR. SEALE:
That's, generous.
6 DR. FONTANA:
Get out the heating ventilation and 7
air conditioning systems.
8 MR. CHENG:
My name is Tom Cheng, with the 9
Mechanical and Civil Engineering Branch.
Today I'm going to 10 discuss something about Section 3.6, the HVAC systems.
11 My presentation is going to cover three systems, 12 which are the auxiliary building heating-and ventilation 13 system, primary containment heating and ventilation system, 14 and the control room HVAC system.
(D
\\%/
15 Before I start my presentation, I would like to 16 highlight some operating experience identified at the site.
17 Some cracking has been discovered at the HVAC ducting due to 18 vibration-induced fatigue.
Some losing fasteners has been 19 experienced because of the dynamic loading.
The control 20 room air' conditioning unit was placed out of service to 21 repair the broken damper linkages.
Also, during the 22 performance period, the elastomer degradation being 23 identified.
24 BG&E, based on their operating experience and the 75 review of industry documents, so identified those five in()
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aging-relate; qations can cause possible aging effects,
).((~
2 which is corro.Cc F.id elastomer degradation, effect of 3
dynamic loads, F/M une wear of valves and radiation damages 4
to the non-metallic material.
i 5
BG&E uses five aging management programs, as are 6
listed in my viewgraphs.
The first one is the structure and 7
system walkdown procedures.
I think that Dr. Munson already
-8 presented. Also, the ARDI, and he presented also.
9 Structure and cystem walkdown procedures, which is
{
10' existing, the ARDI is a new one.
In addition to those, BG&E 11 also uses containment leakage rate testing program.
This i
12 program would be used to discover and manage the leakage of 13 surface wear and also the leakage of crevice corrosion, due 14 to crevice corrosion, general corrosion, degradation.
s_
15 Also, preventive maintenance program, which is 16 existing program, to be used to discover and manage the 17 effect of. corrosion problem.
-18 The third -- the fourth one is the administrative
.19 procedure -- I'm sorry.
Excuse me.
The chemistry program 20 procedure, CP-206, to be used to identify the corrosion.
I i
21 have to apologize.
I forgot to list this one on my 22 viewgraph.
23 BG&E has demonstrated in their application that 24 the combination application of this aging management 25 programs can provide a reasonable approach to inspect and
)
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(A)-
assess the condition of the systems such that any 2
degradation condition will be identified and documented and
-3 corrective action can be taken before the degradation 4
proceeds to failure to perform the intended function.
5 The staff who reviewed BG&E's application drew the 6
following conclusions.
BG&E's approach for determination of 7
possible aging effect and approach to identify possible 8
aging effect are reasonable and acceptable.
9 The combination application of this aging effect 10 program, management program, meets the ten elements of the 11 SRP.
I did not identify any open items, except one 12 confirmatory item.
13 According to the application, the two new diesel 14 O
generator buildings and also associated HVAC-are placed into k/
15 operating in 1995.
Because the aging of the existing m
16' control room HVAC system equipment is some 20 years ahead of 17 the aging of those located in the diesel generator building 18 and also because the new equipment is.just at the beginning 19 of its design life and the system have the design life of 45
)
i 20 years, BG&E concludes that the aging management of the new 21 equipment can be deferred.
22 BG&E's conclusion is acceptable, providing BG&E 23 needs to confirm that, the environmental conditions such 24 that the moisture contents in the air, temperatures and so 2C forth in the two diesel generator buildings are similar to ANN RILEY & ASSOCIATES, LTD.
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4 196 1
the conditions in the control room and that the material and f"%
)
2 hardware configuration of the HVAC system located in the new lO 3
building are similar to those in the control room.
4 This concludes my presentation.
5 DR. SHACK:
What's,the nature of the dynamic 6
loading?
This is the vibration-induced?
7 MR. CHENG:
That's just, for example, like 8
accumulators in a location and create a vibration, like a 9
fan, those things.
10 DR. UHRIG:
Imbalance.
11 MR CHENG:
Imbalance, correct.
1:2 DR. FONTANA:
Any additional comments?
l 13 (No response.)
14 DR. FONTANA:
Thank you very much.
We'll move on
~
15 to emergency diesel generator systems.
16 MR. GEORGIEV:
Hello again.
Since we are formally 17 introduced already, I'll skip the first slide and go to the 18 second.one.
The emergency diesel generator system actually 19 includes two systems, the diesel generator itself and the 20 diesel fuel oil system.
21 In general, the diesel has been operating 22 adequately'and several problems have been reported, but all 23 of them have been. addressed and resolved by BG&E.
24 The operating condition for the diesel basically
-25 is external environment, which is plant quality type of air, ANN RILEY & ASSOCIATES, LTD.
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197
.1 and internal environment, it's either water, tritiated 2
water, or oil, or exhaust gases coming when the diesel is
-3 operated.
-4 To address the degradation mechanism associated 5
with diesel fuel oil, the application basically divide the 6
problem into external piping and buried piping, and I
7 materials involve the carbon steel materials and for the 8
buried piping, the buried piping has been wrapoed with 9
protective coating and they also use cathodic protections to 10 protect the buried piping.
11 For the external service of the piping, they are 12 protected by paint.
In essence, what BG&E reports to do to l
13 address the degradation mechanisms, which are corrosion, 14 weathering, fatigue, and wear, they.have existing plant
[,}
~
L/
15 programs and also are creating four other new programs, 16 which are a program which is catching all type of problem, 17 the program to inspect the buried pipe, and a program to i
18 inspect the balance for the fuel oil storage tanks and they i
19 also have created a new program for caulking around the 20 storage fuel oil tank.
The reason being to prevent water 21 and other material to seeps and effect the metal.
22 We have, in essence, agreed with BG&E's proposal 23' to manage the aging effects.
However, we do identify one 24 open item and this open item pertains to BG&E has classified 25 the cathodic protection as not being needed for aging ANN RILEY &~ ASSOCIATES, LTD.
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i 198 j
)
1 management of buried piping.
The staff disagrees with this.
(O,)
2 We believe that they do need both.
They do need the 3
protective wrapping measures and also the cathodic i
4 protections.
5 License renewal issues, we don't have any.
We 6
have no confirmatory items.
7 That, in essence, concludes my presentations.
8 DR. FONTANA:
Any comments?
9 DR. UHRIG:
Does the cathodic protection --
10 MR. DAVIS:
It's a compressed current system, but 11 it acts the same way.
12 DR. FONTANA:
Thank you.
I guess we can go on to 13 the next item before lunch.
It looks.Like it's fairly long, j
14 but we seneduled 20 minutes for it..
l 15 Moving on to the steam and power conversion 16 systems.
17 MR. PARCZEWSKI:
My name is Kris Parczewski.
I am 18 a member of staff of Material and Chemical Engineering 19 staff, in the Division of Engineering.
20 I'm going to present to you a raview, staff's i
21 review of steam and power conversion systems.
The. steam and 22 power conversion systems included in the license 23 application, license renewal application consist of six
~24 systems; auxiliary feedwater' system, feedwater system, main 12 5 steam system, steam generator blowdown system, extraction f~s
[]
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i 199 1-steam system,.which, by the way, is inoperable, and
(,-s) 2 nitrogen / hydrogen systems.
3 Now, the system, the material, the materials of 4
the system are mainly carbon steel,-but some of the systems 5
have some additional material.
For auxiliary feedwater 6
system has,-in addition to carbon steel, alloy steel, 7
bronze', brass, cast iron, and elastomers.
It is exposed to 8
an environment of chemically treated water at temperatures 9
just below 200 degrees Fahrenheit.
10 DR. FONTANA:
Excuse me.
Could you push that
)
11 other microphone out of the way?
Thank you.
12 MR. PARCZEWSKI:
The feedwater system, in addition 13 of carbon steel, has chrome alloy steel.
It is exposed to 14 an environment of chemically treated water, the secondary ID (s/
15 water, basically, atahighertemherature,upto475 degrees 16 Fahrenheit.
17 Main steam system, in addition to carbon,.has 18' alloy steel and some stainless steel, and the orifice is 19 made out of stainless steel.
It's exposed to an environment 20 of wet steel and two-phase fluid in the drain line when the 21 condensation occurs.
22 The steam generator blowdown system has, in 23, addition to. carbon steel, stainless steel, brass and cast 24 iron.
It.is exposed to an environment, two-phase fluid on 25 the side of the heat exchanger and the component cooling p*] -
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200 1-water on the tube side of the heat exchanger.
()
2 The extraction of steel is made strictly from 3
carbon steel and it's exposed to the moist air.
It's empty, 4
because it's not being used presently.
The nitrogen and 5
hydrogen system is made out of carbon steel and it is 6
exposed to an environment of very, very dry gases, with dew 7
point minus 40 degrees Fahrenheit, which is extremely dry.
8 But still it might have some corrosion, so the applicant 9
included it in the review.
10 There are several different aging mechanisms, 11 aging effects.
The most prevalent definitely is the 12 corrosion and there are several managing -- aging management 13 programs for different systems, depending on the operating 14 conditions and the type of material.and so on.
Os
- (_/
15 There are really two types of aging management 16 programs.
One is a preventive program and the other one is 17 monitoring.
The preventive program, in most cases, as you 18 can see here, is controlled with secondary water, there's 19 pH, oxygen consideration, some iron, boron, if there is 20 boron in the system, and so on.
21 DR. SHACK:
What do they use for their pH control 22 agent?
23 MR. PARCZEWSKI:
They use -- for pH control, they j
24 use the hydrogen, which, of course, is composed in the heat 25 exchanger, the high temperature.
You generate some ammonia, 1
i i
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which keeps pH.
()
2 In the auxiliary feedwater system, in addition to 3
secondary water,-there is a buried pipe inspection program, 4
which is -- pipe are exposed to MIC, microbiologically 5
influenced corrosion, and there is no way to control it.
6 The only way to prevent it, the only way is just inspecting 7
it.
8.
The~second one is, of course, preventing 9
maintenance.
Corrosion inspection, this is a new program, 10 ARDI program, they do corrosion inspection.
I 11 In feedwater, again, there is a corrosion
{
i 12 inspection program, which is the new ARDI program.
In 13 water, main steam line, main steam system, the secondary 14 water, to some extent, prevents some corrosion.
This is the
- /^\\
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15 only way we can do it.
16 DR. SHACK:
In the feedwater system, what is the 17.
ARDI looking for here?
18 MR. PARCZEWSKI:
The ARDI is looking for damage 19 due to corrosion, inspection.
20 DR. SHACK:
So there is no regular 21 erosion / corrosion checkmate type program.
j l
22 MR. PARCZEWSKI:
There will be another point in my 23 presentation on erosion / corrosion.
It's a specific type of 24 corrosion, which is not included in the corrosion.
We did 25.
it separately because there is slightly different control of
.O l
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this particular mechanism.
It's the next slide, p(,)
2 In the steam generator blowdown system, we have 3
already secondary water chemistry.
Then there is, of 4
course, another component, cooling water, which controls the 5
chemistry of the cooling water in the heat exchanger, the 6
one which goes through the tubes, and there is an additional 7
corrosi'on inspection ARDI program.
8 In extraction steam, there is an ARDI program for 9
control -- for inspecting the corrosion in this extraction 10 system, which I indicated really has only moist air.
In 11 nitrogen / hydrogen system, you have motion control, which is 12 really inspecting, but if there is any corrosion, it's 13 extremely small, because the gases are kept in a very, very 14 dry condition.
}
15 Now, erosion / corrosion.
Erosion / corrosion is a w-16 very, very significant aging mechanism and this is why we i
17 looked at it as a separate item.
It is, to some extent, 1
1 1
18 controlled -- prevented by controlling secondary water.
19 However, there is a problem there.
Usually to reduce 20 corrosion, you keep oxygen down as much as you can.
It is 21 not true erosion / corrosion.
22 To optimize, you have to go up to a certain point.
23 You cannot go completely -- usually, you chould keep above 24 about 40 ppb.
Of course, you cannot do this.
So really, in j
i 25 order to control corrosion, you cannot optimize i
l
'/h i
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203 l'
erosion / corrosion system.
Therefore, prevention using r~N
[(,)
.2 secondary water is somehow limited.
3 So we have, in addition to inspection programs, i'
4 monitoring programs.
One of them -- we have the chemistry 5
-- we.have a monitoring program which uses a program 6
developed by EPRI and they have a check -- I have experience 7
with-th'at, an excellent program, and what it does,-it 8
predicts which components are susceptible to corrosion and 9
in addition, it predicts when they're going to fail.
10 The program has to be, so to speak, calibrated, 11 which means some of the components have to be measured, the 12 effect of erosion / corrosion, by using the either ultrasonics 13 or radiography, and then input into the code.
This 14 calibrated code then can predict some other components which
[\\
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15 are not measured, when they're going to fail, when they have 16 0 to be replaced.
17 It's being used by practically all the licensees, 18 because it does a very good job.
19 In addition, there is an ARDI program for 20 inspection which basically is an extension of this 21 monitoring program, using the same program, but it adds 22 additional components which originally were not included in 23 the program.
So basically, it's an extension of the E/C 24 program.
25 This is for -- in main steam line, again, you have (m.
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i i
secondary water chemistry monitoring, basically the same
)
r%
i()
2 programs as for water -- in feedwater.
j i
3 The same applies to steam generator blowdown.
j 4
Again,-you have the same program.
So all those three 5
systems have the same program.
6 In addition, cavitation is another mechanism 7
which, of course, is not a chemical.
It doesn't involve 8
corrosion.
It's hydrodynamic phenomenon, and there is an --
9 there is going to be established an ARDI program for i
10 inspecting cavitation damage.
There is no way to mitigate 11
-- to prevent it.
Just the only thing is to inspect it.
12 This same applies to the wear program.
ARDI 13 inspects the control of seats and plugs of steam atmospheric 14 valves and sterite carbon steel borders and MSIVs.
So this 15 program will be limited to those components.
16 Now, the steam generator blowdown system would 17 have a leaching mechanism.
There are some components made 18 out of cast iron or made out of brass.
In.those components, 19 the environment, corrosive environment removes selectively 20 materials in' case of cast iron to remove the ferrite phase.
21 In the case of brass, it removes zinc.
So this is the 22 corrosion mechanism.
23 Again, there is no -- you can control, to some 24 degree, through secondary chemistry, but it still needs to i
25 be inspected and there is inspection program, ARDI
( )'
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inspection that is going to take care of it.
q,)
'2 Now, elastomers, there are two programs addressing 3
the elastomer degradation.
One program, which is the 4
sealant inspection program, will take care -- again, you
(
5 cannot prevent the program.
The only thing is to inspect 6
it.
7 The sealant inspection program, which inspects the 8
sealant around the condensate storage tank, which might be 9
affected by the environment.
ARDI elastomer program, which 10 will address the inspection of solenoid operated valve made 11 of ethylene, propylene, and subject to wear.
So that's the 12 programs.
13 The final is fatigue.
In some of the piping in 14 feedwater, you have stratification of fluid in the pipe and N_)
15 this stratification would produce thermal stresses which 16 will obviously produce some fatigue of the piping.
So this 17 is the final program I will be discussing here.
18 DR. SHACK:
John, just a question on that fatigue.
19 You need a horizontal run of piping to have that problem, 20 don't you?
21 MR. FAIR:
Yes.
As a matter of fact, that's why 22 they selected this section of the pipe, right near the 23 nozzle.
We asked a question as to why it wasn't a concern 24 anywhere else and it was because there is a vertical riser 25 coming up to that horizontal run of pipe.
3 ANN RILEY & ASSOCIATES, LTD.
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DR. SHACK:
So there's just one sort of small p)
(,
2 segment of horizontal piping here.
3 MR. FAIR:
Yes, and this is an area where they 4
have a fairly detailed monitoring of the thermal 5
temperatures in the area'to do a detailed fatigue analysis.
6-DR. FONTANA:
Any additional comments?
7 (No response.)
8 DR. FONTANA:
Thank you very much.
I think we'll 9
move on to the next topic,' sampling and monitoring systems.
10 MR. PATNAIK:
I'm Pac Patnaik, from the Division 11 of Engineering.
I've been asked -'- I compiled the sampling 12 and monitoring system Section 3.9.
This sampling and 13 monitoring system comprises of nuclear steam supply sampling 14 system, radiation monitoring system, and the instrument
. - ~
(>
15 lines.
16 Mine is going to be a snapshot of the SER.
The 17 nuclear steam supply, NSSS sampling system provides for
-18 sampling of liquids, steam gases, radioactive and chemical 19.
control of plant fluids, and this has five subsystems, which 20' is reactor = coolant sampling, steam generator blowdown l
1 21 sampling, radioactive waste sampling, gas analyzing
-22 sampling, and post-accident sampling.
23 The general categories of equipment are 24 accumulators, air drives, piping, valves, valve operated 25 panels, instruments, sample vessels, and pumps.
The c
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- 1-O.
materials.for these components are stainless steel or carbon A,)
2 steel.
3 These are compatible with the medium inside the
-4 pressure boundary, which is either borated water or 5
chemically treated water.
{
6-The components in this NSSS sampling system that we eval'uated had the intended functions of maintaining the 7
a pressure; boundary.
It provides containment actuation of the 9
nuclear steam supply sampling system during a LOCA.
It also l
10 provides capability to sample gaseous fluid during an 11 accident.
12 The RMS, which is the release and monitoring 13 system, detects an increasing radiation level or an abnormal 14 radioactivity concentration at selected points in the plant.
15 It.provides indication of such conditions to operating 16-personnel and the system monitors also the-discharge of 17' radioactive fluids from the plant and provides a signal to 18 isolate components in the event of abnormal conditions, to 19 prevent uncontrolled release _to the environment.
~
20 Again, the RMS comprises of piping, tubing, pumps, 21 valves, filters, instrumentation, and the materials are 22' either stainless steel or carbon steel, and which are 23 compatible with the internal environment which is either 24 air, borated water, or chemically treated water.
25.
They had intended functions of maintaining the
~
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pressure boundary.
It provides containment isolation, t
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(,)
2 radiation signal to the engineered safety feature actuation 3
system for containment isolation and radiological release 4
control.
5 DR., SEALE:
Would you help me?
I've got a block.
6 What's the BACI, again?
l i
7 MR. PATNAIK:
That's the horic acid corrosion i
t 8
inspection program that you heard in the earlier 9
presentation.
10 DR. SEALE:
Okay.
I knew I had heard it, but I 11 had forgotten what it was.
Somehow or another, I didn't 12 feel comfortable.
13 MR. PATNAIK:
This is the program that the 14 in-service inspection personnel perform right after the
,~
is,)
15 outage and walk down the system-,
16 DR. SEALE:
Yes, okay.
17 MR. PATNAIK:
Now, moving on.
The instrument L
18 lines are associated with all plant systems.
Therefore, the l
19 applicant evaluated this as a commodity.
And for the 20 purpose of instrument line, the evaluation is from the --
21 looks at from the process line down to the first hand valve 22 l or route valve.
Then it went line-up to the instrument.
In 23 other words, it's defined as the components located 24
' downstream of the first hand valve off the main process line 25 3 or the vessel, which is called the route valve, and the
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instrument lines are all piping, tubing, fittings, hand 2
valves.
3 The materials are stainless steel, carbon steel, 4
4
. copper, depending on the environment inside, which could be 5
horated water, chemically treated water,' oil, air.
The 6
components that we evaluated had the intended functions of 7
maintaining pressureiboundary integrity.
'. 8 Corrosion manifests as general corrosion of 9
external, which is due to leakage of borated water from 10 piping or joints.
As the previous' speakers'well stated, the 11' ARDI program is -- the licensee has taken credit for the
~
12 ARDI program and the BACI program., boric acid corrosion
- 13 inspection program, on the nuclear steam supply system 14 sampling lines.
n v
.15l And for radiation monito" ring system, also, ARDI
'16 program has been taken credit and on.the instrument lines, 17 again, we have ARDI program.
Structures and. systems la-lwalkdowni which you've heard.
- 19 Then there are two other programs that the 20.
'lleensee has taken credit for, which is control of shift 21' activities and ownership of plant operating spaces.
22-I want to walk you through these last two, because
~
23-you haven't heard anything of these two.
.24 Under control of shift activities,. operators i
25
. perform the walkdowns, plant operators.
They inspect
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accessible operating spaces during each shift and when the
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2 containment -- when the -- during an outage, they also 3
perform these walkdowns inside the containment, once per 4
shift.
5 This program provides for' discovery of conditions 6
that could allow general corrosion to progress for the
' instrument line supports, by performing visual inspections.
7
-8 The inspection items related to aging management include vibrations and effects that may have caused by this 9
10 age-related degradation mechanism, such as damaged piping, 11 instrument tubing, or leakage of fluids.
12 Also, this program would also detect leakage of fluids, which is as a result of conditions progressing from 13 14 the age-related degradation mechanism.
And the licensee
(~h^
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T 15 also has the corrective actions program which will.take care ms 16 of any cf these aging effects noticed during the 17 inspections.
18 The other program is the ownership of plant 19-
' operating spaces.
Under this program, the plant operating
'20 spaces, they have owners identified within each space who 21 would provide a point of contact for any individual who 22 finds deficiencies or any concern with the space, and the
-23 responsible individuals are required to periodically inspect
]
24 their assigned spaces for housekeeping, cleanliness, 25 material condit' ions,.and radiological deficiencies.
j 1
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This program provides for discovery.of general f~
(,)f 2
corrosion of the instrument line supports by performing 3
visual inspection in plant operating areas.
4.
Again, the inspection items related with this 5
aging management include items related to specific 6-age-related degradation mechanisms, such as corrosion; item 7
two is' effects that may have been caused by age-related 8
degradation mechanisms, such as loose lines or loose 9
fasteners, because of fluids, and the conditions of pipes, 10 loose fasteners, conditions that would allow progression of 11 age-related degradation mechanisms, such as unbracketed 12 lines and pipes.
13 Again, they have the corrective action program 14 which takes care of any deficiencies that they identify.
t 1
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15 That's the general corrosion.
16 Next,'we have this crevice corrosion and pitting.
17
-For the nuclear steam system, we have the ARDI program and 18 then we have the other programs like specification and 19 surveillance of the system, component cooling, service 20 water, secondary chemistry program.
21 These are all the chemistry programs, which the 22 licensee is taking credit for, as mitigation.
Then the 23 third is the local leak rate test of penetrations.
- Actual, 24-this local leak rate test of penetrations is identifying 25 where'in the control valves, but the staff didn't evaluate (7.l ANN RILEY & ASSOCIATES, LTD.
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aging management on the valve internals because the valve r')
-(,j
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2 internals' perform their intended function with moving parts
]
3 and changes in the configuration, which is not subject to 4-aging management review.
5 DR. SHACK:
Would.this local-leak rate give you a 6
thermal cycling' problem and a fatigue problem?
7 MR. PATNAIK:
Local leak rate --
)
8 DR. SHACK:
Through the valve.
Is this a hot / cold 9
-- hot fluid going to a cold fluid kind of thing?
10 MR. PATNAIK:
No.
I'm talking about Appendix C 11 test -- I mean, Appendix J, Type C test.
12 DR. SEALE:
Okay.
Which is --
13 MR. PATNAIK:
Which is different.
14 I guess I have one more slide.
Lastly, the low cycle thermal fatigue is one of tde possible plausible 15 16 age-related degradation mechanisms on the nuclear steam 17 supply sampling system.
Anytime you draw a sample, you.go 18 through a thermal cycling, and what the licensee has used 19 fatigue monitoring program.
20 We have an open item on-this, like many other 21 fatigue items, items on~ fatigue, this item involves -- there 22 are 11. locations in the RCS that are being monitored for fatigue and our staff thought that the applicant should 24 provide validation to demonstrate that the low cycle fatigue 25 uses of piping and valves in the RCS hot leg sampling is
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bounded by monitoring of those 11 fatigue critical
,m
(,v) 2 locations.
That was the only open item.
3 There is one other item, age-related degradation, elastomer 4
degradation.
The internals of check valves in the past, the 5
post-accident sampling system gas return line tot he i
i 6
containment, and some of the supports in the instrument j
7 line.
'They contain the elastomer materials that are 8
susceptible to age-related degradation.
9 The staff determined that the applicant's ARDI 10 program will effectively manage this age-related degradation 11 mechanism.
So the staff concluded the applicant has 12 demonstrated that the aging effects associated with the I
13 sampling and monitoring systems are adequately managed, such 14 that there is reasonable assurance that the systems will
(_)
15 perform their intended functions in accordance with the i
16 current licensing basis.
17 So this is a nutshell of what we presented of the 18 ACR.
19 DR. FONTANA:
Any additional comments?
j 20 (No response.]
)
21 DR. FONTANA:
Well, thank you very much.
The next 22' item is a fairly long one, so I think we ought to break for 23 lunch now.
Since we're ahead of time, I guess we can show 24 up at 1:00.
25 MR. GRIMES:
That would be acceptable to the
,m
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staff.
As a matter of. fact, we would prefer that, since the
(~h is,j 2
folks that are supposed to be here for the afternoon session 3
'might not otherwise know when to show up.
So if we could 4
reconvene at one, that would be our target.
5 DR. FONTANA:
That's fine.
Okay.
We'll come back 6
at 1:00.
7 (Whereupon, at 11:53 a.m.,
the meeting was 8
recessed, to reconvene at 1:00 p.m.,
this same day.]
9 10
.11 12 13 14
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-24 25 I
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AFTERNOON SESSION
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2
[1:00 p.m.]
3 DR. FONTANA:
The meeting will resume.
We'll move 4
into the presentation on building structures.
David Jeng.
5 MR. JENG:
Yes.
6 MR. GRIMES:
Dr. Fontana, before we continue with 7
the staff presentation, I would like to mention that I just 8
provided a copy of a staff position that was issued 9
yesterday to NEI on fuses, which concludes that aging 10 management review for fuses is not necessary.
11 Assuming that NEI does not object to the 12 conclu61on'in that position or that we otherwise don't 13 receive critical comments on the basis for arriving at that 14 decision, that will address one of the open items in the
('~h (s/
15 Calvert Cliffs review.
16 That letter also illustrates the process.by which 17 we're going through and defining these generic renewal f
18 issues and addressing the resolution and then documenting I
19 the results.
20 It describes the nature of the guidance that we 21 would add to the standard review plan.
So we offer that i
22 also to the subcommittee as an illustration of how the 23 process is working.
24 DR. FONTANA:
Thank you.
25 MR. JENG:
Good afternoon.
My name is David Jeng.
)
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I am'with the Mechanical and Chemical Engineering Branch of
(
2
-the Division of Engineering.
3 Today,.I am. going to report:to you our review a
4 findings of the building structures, which is covered in the 5.
ACR Section 3.10.
Please go,to page 75.
1
' 16 Building structures of BG&E include the following five it' ems; primary _ containment structure, turbine building, 7
8 intake structure, miscellaneous-tank involved, auxiliary 9
building, and safety-related diesel generator building 10 structures.
The basic approach of B3&E in achieving aging 11 l
12 effect management for their structures are as follows.
i 13 They, first, identified all the structures and component 1
14
' types, such.as the concrete structure components or steel f-)s 15 structure components, and matching these types to the s_
16 potential aging-related degradation mechanisms, such as the j
17 corrosion of the' steel, cracking of the concrete, and 18 corrosion of the stainless steel liners'in the spent: fuel 19
-pool.
-20 By matching these two concepts, the component 21-types,.with the potential. age degradation _ mechanisms, they 22_
'come up with some' ten structure and component types such 23-aging type. categories.and I am going to report to'you hou 4
24 these ten categories are identified and how their aging i
L25 management programs are proposed to be handled.
n'
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i 217 1
. Going to page 76.
The first item is the corrosion
])
~
~2 of tendons ~in pre-stressing losses.
BG&E, in this 3
- evaluation, determined that their aging management program for.this item should include mitigation -- periodic tendon
' 4 ':
5 surveillance program and implementation of a long-term 6
corrective action program, which was established after their discovery'of the earlier degradations in the tendons group.
7' 8
Going to the'second item on the same page.
9 Concrete reinforcing degradations.
BG&E determined that the 10 aging effect of freeze / thaw, leaching, aggressive chemical 11 attack, groundwater, boric acid, and flow-in water do not
.12
' apply to their concrete structures, except for the intake 13 structure, which is submerged into a bay water, a more
-14 aggressive environment type water.
()
15 The reason for their judging that these effect do 16 not apply because the concrete they provided is a very high 17
_ quality concrete and their aggregate are tested to standards 18
-and also the design is such that they are consistent with
.19 the ACI process and~they are going to ensure such effect 20 would not prevail.
21 Please go to page 77.
22 DR. FONTANA:
Are they also inspected at some 23-point to make sure that that kind of construction standard 24 really does -- those kind of construction standards really 25 does provide concrete that is that good?
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MR. JENG:
Yes.
As I said in the slide, in the
()
2 curing, which covers the good quality construction practices 3
and the post-construction curing of the concrete.
4 Going to page 77.
Weathering of the caulking, 5
sealants and expansion joints.
BG&E's aging management 6
program items include for the fire barriers in the auxiliary 7
building and adjacent rooms, they are going to implement an 8
existing fire barrier program.
For the other caulking and 9
sealants which are non-fire barrier functioning, they are 10 going to propose a new program to perform inspection.
11 But BG&E did not adequately cover the potential 12 aging effect of radiation temperature on the non-metallic 13 portion of the penetration assemblies, such as the cable 14 installation, sealants for their penetration, and this item
()
15 remains open, and this is listed in the open items later.
16 Please go to page 78.
The corrosion sf 17 containment wall and dome liners.
BG&E's evaluation decided 18 that the program should include use of a protective coating 19 to minimize corrosion effects, implementation of visual 20 inspections.
They are using STP-M-665 1/2 on the two i
21 plants, respectively.
22 And the last item that BG&E indicated that the --
23 based on their past experience, their inspection program has 24 been shown to be quite effective.
25 Please go to page 79.
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DR. SHACK:
What is the nature of the periodic
(_j 2
inspection?
3 MR. JENG:
Okay.
The most inspection is the type 4
of inspection -- for instance, the containment liner inspection, which is based on the ASME IEW/IWL provision, 5
as 6
well as the Reg Guide 1.35, and they are done on every 7
refueling outage.
8 DR. SHACK:
But is that a visual inspection?
9 MR. JENG:
Basically, visual inspections.
10 We are on page 79.
Corrosion of steel.
The aging 11 management program lists item includes use of protective 12 coatings to minimize corrosion.
Again, implementation of a 13 periodic visual inspection program.
But for the containment 14 emergency sump cover and screen, which is sort of unique, it i
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15 was not specifically covered in tde earlier BG&E maintenance 16 program and they are proposing a new inspection program, 17 number STP-M-661.
18 Going to the lower part of the page, corrosion of 19 the refueling spent fuel pool liners and cavity sealing 20 ring, but in 1995, BG&E did inspect the fuel transfer canal 21 and ensured that there was no indication of damage or 22 corrosion.
23 So for this item management, BG&E indicated that 24 the concern is the potential IGSCC, which may be applicable 25 to the stainless steel liners and the PCSR and for this item
,s
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management, BG&E proposes to use a periodic walkdown, that's f s) 2 MN-1-319, to manage the aging effects.
(
3 Please go to page 80.
The next item in the 4
category is degradation of intake structure containing 5
concrete walls, sluice gates,, and steel subject to 6
aggressive chemical attack.
7 The aging management program proposed by BG&E for i
h 8
this category include use of a preventive coating to l
4 9
minimize steel components corrosion, implementation of 10 periodic inspection, and performance of structure and system 11 walkdowns.
12 The lower portion of the page, corrosion of steel 13 components inside miscellaneous tanks involve enclosures.
14 For this particular category, BG&E proposes to use
/~
s (s,%)
15 preventive coating to minimize corrosion, implementation of l
i 16 periodic walkdowns, and through application of these 17 programs, they intend to manage the corrosion of CST tank 18 number-12, FOST tank number 21, and the auxiliary feedwater 19 valve enclosure.
20 Please go to page 81.
21' DR. UHRIG:
You said they propose to use.
They 22 presently have preventive coating, do they not?
23 MR. JENG:
They do, but they are making it 24 official' commitment for some enhancement of the content of 25 the program, i
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DR. UHRIG:
Thank you.
2 MR. JENG:
Please go to page 81.
Weathering of 3
vertical tendons.
EG&E did discover some degradation in the 4
vertical tendons.
For this category, it proposes to include 5
implementation of periodic inspection and to perform needed 6
engineering evaluation and take whatever needed corrective 7
actions'.
The staff finds this to be acceptable.
8 Go to the lower portion of the page.
The 9
evaluation of neutron absorbing materials.
For this 10-particular consideration, BG&E proposes to perform periodic 11 sampling of the neutron absorbing materials and also to 12 implement the EGP 86-03R title, analogies of neutron 13 absorbing material in spent fuel storage racks.
14 Please go to page 82.
Besides the about ten items
)
I discussed, BG&E also looked intd the potential effectuof
\\)
15 16 foundation settlement and it concluded, and the staff' agreed 17 to their conclusion, that because of the following three t
i 18 reasons, the foundation settlement is not a plausible 1
19 concern for the BG&E structural foundations.
20 The number one basis is the design is such that 21 the building capacity of the foundation material is so high, 22 with a margin of more than ten.
Secondly, there is the 23 underground drainage system in place right now which would 24 tend to control groundwater levels.
And the third reason is 25 the -- after all these years, the settlement, if any, should
'()
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be mostly in the uniform settlement and the settlement
'2 normally do not effect the structure performance.
3 For the intake structure, BG&E did also maintain 4
that the first and third reason alone should be able to 5
justify that there will be no settlement concerns for intake 6
structures.
Incidentally, the intake structure of the 7
underground drainage system.
8 I have covered the major, some ten component i
9 category aging effects and the BG&E proposed management 10 programs.
The staff did review all these proposed programs 11 in great details and except for the open item which we have 12 three items later, we have come to conclusion that they have 13 done adequate evaluation job and proposed adequate scope of 14 programs to achieve the needed management of aging effects 15 of BG&E building structures.
16 Please go to page 83.
There are three open items.
The first one is pertaining to the tendon force trending 17 18 analysis. Because of the major difficulties experienced in 19 the tendon areas, and the staff asked BG&E to show some 20 trending of the existing forces in the tendons to stay above 21 the minimum requirements called for by the design, et the 22
'end of the 60 years or 20 years extended period, and this is 23 the first open item.
24 The second one pertain to the concern of the 25 groundwater effect on the intake structure from the embedded i
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surface areas and the BG&E presented some chemical analysis O(j 2
of the groundwater for the plant.
In fact, they provided
'3 three reports.
One of the three testing show very high --
4 concern on the degradation of the concrete surfaces.
5 So for this reason, the staff asked BG&E to commit 6
to perform at least some porcion of the inspection on the 7
outside' exterior surfaces of the intake structures before 8
the starting of the license renewal period at least one 9
time, and this is the second open item.
I 10 The third open item pertain to the BG&E need to 11 further address the effect of aging due to irradiation and 12 temperature on the cover, 0-ring and other known metallic 13 materials for the electrical penetrations.
14 Please go to page 84.
There are two confirmatory r ~'s k-)
15 items.
The first one pertain to the BG&E commitment to s
16 perform inspection before year 2002 of the containment j
17 domes.
There have been some freeze / thaw induced degradation i
18 observed on the top of the containment and BG&E maintains 19 that -- but the staff wants to make sure, you do this 20 inspect one before year 2002, and they consented.
21 The second item pertain to the BG&E commitment to 22 further enhance the guidance on their MN-1-319, which is 23 quite often used in many of the programs.
The enhanced area 24 covers, number one, to provide much more detailed guidance 25 on how to judge the functionality of the structures and (O)
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components.
)
2 The second item is to further enhance the guidance 3
on how they can change -- the authority to change the 4
programs, scoping decision criteria, and.ow to change the 5
schedule of inspection.
6 So these two item BG&E has committed enhance in 7
their program MN-1-319.
There are six -- page 85, 8
please.
There are six license renewal issues.
Most of 9
these issues are not germane to BG&E because they already 10 provided information specific to their plant and one item --
11 two items that staff has yet to develop their own position.
12 So I am reporting to you that the license renewal 13 issue does not pertain to BG&E application.
14 With this, I am concluding my presentation and if.
15 you have any questions, I would be' pleased to answer your 16 question.
17 DR. FONTANA:
Let me take time to look at these 18 just for a second here.
19 DR. UHRIG:
These issues will be resolved before 20
-- these six issues.
21 MR. JENG:
The six issues are not germane to 22 BG&E's situation.
23 DR. UHRIG:
Okay.
24 DR. FONTANA:
Any comments?
Any additional 25 comments?
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1 (No' response.]
f f"%
.{)
2 DR. FONTANA:
Well, thank you very much.
3 MR. JENG:
Thank you.
4 DR. FONTANA:
Thank you.
We'11 move on to j
i
<5_
component support, cranes and electrical commodities.
i
-6 MS. LI:
I'm Renee Li, from Mechanical Engineering i
'7 Branch,' in Division of. Engineering.
The section I'm going 8
to talk about is Section 3.11, which covers component
- 9 supports, cranes and electrical commodities.
I 10 For component support, the component support is defined as the connection between a system or a component 11 12 within a system and the structure member.
All component 13 support type that provide support to system and the 14 components which are within the scope of license renewal are 1
15 also considered to be within the [icense renewal.
16 The component support including piping supports, 17 cable raceway support, HVAC ducting support, and equipment 18 support.
The support section also include'the piping i
19 segments that provide structure support.
20 These piping segments include piping segments 21 beyond the. safety and the non-safety-related boundary to the j
i 22 first seismic restraint and they perform the intended 23-passive function of providing structure support to the 24 safety-related piping.
25 The crane section include fuel handling equipment i
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1 and other heavy; load handling cranes.
This section covers
( )
2 the evaluation of, A, components involved in fuel handling 3
and' transfer.and, B, cranes that routine,1y lift heavy loads 4
over safety-related components that are associated with fire j
5 systems,. spent fuel storage,. refueling pool, elevator fuel 6
handling and the cranes.
I 7.
The last section I'm going to talk about is the j
8 electrical commodity.
The electrical commodity include the i
9 structure enclosure for electrical equipment which provides 10 support and protection of the electrical equipment located i
11 within them.
j i
12 The electrical commodity include miscellaneous panels, motor 13 control center cabinets, switch gear, disconnectes cabinet, 14 bus cabinets, circuit breaker cabinet, local control station A)
(_
15 panel, battery terminals, and the' charger cabinet, and 16 inverter cabinet.
17 The following three slides will show the applicant 18 proposed aging management program to manage the aging 19 effects and which will also show which components that --
20 component support that those aging management are credited 21 for.
22 Our review is to ensure that the applicant's 23 proposed aging management program will manage the aging 24 mechanism and the effects in such a way that the intended 25 function of the component supports will be maintained in ANN RILEY & ASSOCIATES, LTD.
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1 accordance with the current licensing basis during the
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()
2 period of extended operation.
I 3-As you see,.the aging management program for 4
general corrosion of steel, which has combination of 5
numerous program, and the most of the program have been 6
addressed earlier.
I think the only one maybe is the 7
snubber visual inspection surveillance program, and that's 8
the tech spec snubber surveillance program, which has a 9
table that will determine the frequency and also the sample 10-size of each inspection.
11
.The other have been covered, except addition of 12 baseline walkdown, which is to pick up those component 13 supports that are not covered by the original baseline 14 inspection.
~D f( s/
15 Preventive maintenance c'hecklist.
Usually, the PM 16 checklist or the task is for a specific component or I
17 component support.
For example, there is a preventive 18 maintenance checklist that's a modified version of the 19 existing program and it's credited for aging management of 20 the metal spring isolator and the fixed basis component
-21 supports, s6ch as containment air cooler fan.
22 The same program for the general corrosion of 23 steel are used for managing the effects of loading due to 24 hydraulic vibration or water hammer.
25 The next slide shows the aging effects of loading
()
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1-1 228
'due to some extension of piping and the component, and aging l
1 t~'f
\\
/
2
' management program basically are very similar to the j
1 3
previous one.
The firsc one is the structure and the system
)
'4 walkdown.
The second one is the control of shift activity.
)
1 5
The third one is the ownership of plant operating spaces and l
6 also the section 11 ISI program.
7 The same program is also used to manage the aging 8
effects of loading due to rotating machinery.
The last 9
slide for the component supports has to do with aging effect j
10 of elastomer hardening and the program -- the aging i
11-management program, the three programs we already discussed, 12 plus the plant modification program, the plant modification 1
13 program is a new program and that's credited for the
)
14 modification of control room HVAC air handler support to l
15 replace elastomer isolator with the spring-type isolator 16~
The last aging effect is the stress corrosion 17 cracking of high strength bolts and the aging management 18 program that is credited for ISI and addition of baseline 19 walkdown.
20 And for the piping segment that provides structure 21 support, in the application, BG&E states that the same aging 22 effect for the safety-related portion of the piping will 23 apply to these piping segment beyond the safety and the 24 non-safety-related boundary.
Therefore, the aging 25 management program that credits for managing the aging
()
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effects of safety-related portion of piping are also
(_f 2
applicable.to those piping segments.
3-The'next two slides are for fuel handling i
4; equipment and other heavy load handling cranes.
Again, our 5
review is to ensure that-the. applicant's proposed aging 6
management program will manage the aging effects in such a
\\
way thit~the intended functions of the components will be
)
7 8
maintained in accordance with the current licensing basis
=
9
-during the period of extended operation.
10 BG&E has proposed numerous evaluation programs, i
11 procedures, instructions, and including PM tasks, and those 12 programs have been used for different combinations of aging j
13 effects and the fuel handling equipment or the heavy load 14 handling crane.
Theagingeffectsthey<[overhasgeneral 15 16 corrosion, oxidation, fatigue, and wear.
17 The next slide will show the mechanical 18 degradation, distortion, and also corrosion due to boric 1
19 acid.
I will not go into the detail of the various PM 20 programs.
21 This is the slide for the mechanical degradation, 22-distortion,,and also corrosion due to the boric acid.
23 Most of the programs that I-just showed, they are existing 24-
. programs.
Just a few are the modified programs and the 25 programs generally provide requirements for inspection.
V,O -
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Most of the inspections are visual inspections, but they
(
)
2 have some NDE, and each program is credited for discovery 3
and management of certain aging effects for a specific group 4
of components.
5 I think one of the programs, that is the boric 6
acid corrosion inspection, this morning has been discussed 7
and there are same specific concerns of that program.
8 DR. SHACK:
Is the snubber considered a passive 9
support or are you --
10 MS. LI:
The snubber itself is active.
But 11 between the snubber and the structure, the portion we 12 consider as a support to the snubber, is passive.
So that 13 is the one that's inside scope.
j 14 DR. SRACK:
But the active function of the snubber
(
15 is checked.
16 MS. LI:
Is checked per the tech spec.
17 DR. SHACK:
Under the tech spec.
18 MS. LI:
That's right.
The next two slides are 19 for the electrical commodity.
The applicant has identified 20 the aging effects of fatigue and electrical stressor and the 21 wear, also general corrosion and the dynamic loading on the 22 motor panels.
I 23 As far as the aging management program, for the 1
24 fatigue, the licensee credits the PM checklist, I think the 25 name is reactor trip circuit breaker inspection, and that i
I
<y
( j.
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has a requirement of every 48 weeks, they do a visual 2
inspection and also require that if any fatigue degradation 3
is detected, it should be reported and they evaluate per 4
site corrective procedures, and operating experience showed 5
that this has'.been very effe.ctive.
6 Also, the program, ARDI is also credited for these 7
aging effects.
8 For the electrical stressors, the PM procedure, 9
MN-1-102, is credited and in accordance with the PM 10 procedure, repetitive tasks are performed, train, inspect, 11 and calibrate the electrical commodity, and if there is any 12-degradation, it will be reported and they evaluate and 13 correct action taken.
Also, the ARDI program is credited 14 for this aging effects and I think for the other two, for 15 maintenance procedure and the ARDI, the dynamic load -- yes.
16 The dynamic loading on the motor control center panel are 17 the one that nearby the emergency diesel generator and the 18 concern is the vibration.
'19 The staff's review, we do not identify any open 20 item or. confirmatory item and also there is no license
'21 renewal issue in this area.
22 Based on the information provided by the 23 applicant, we are able to conclude that the aging management 24 program will be adequate to manage the aging effects 25 identified by the applicant and we believe that there is a ANN RILEY & ASSOCIATES, LTD.
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20036 (202) 842-0034
'l 232 1
reasonable assurance that component support, fuel handling
(~N i
)
2 elements, heavy load handling cranes and the electrical s
3 commodity will perform their intended function in accordance i
4 with the current licensing basis during the period of 5
extended operation.
6 That concludes my presentation.
I 7
DR. FONTANA:
Any comments?
)
8
[.No response.]
9 DR. FONTANA:
Thank you very much.
10 DR. SEALE:
Drinking with a fire hose.
11 DR. FONTANA:
Pardon?
12 DR. SEALE:
Drinking with a fire hose.
13 DR. FONTANA:
The next area -- is it one presenter 14 for the remaining areas?
,_/\\ s) f 15 MR. SHEMANSKI:
Yes.
I've got the next four m
16 sections.
17 DR. FONTANA:
- Okay, 18 MR. SHEMANSKI:
I may need some help, though.
19 DR. FONTANA:
All right.
20 MR. SHEMANSKI:
Good afternoon.
My name is Paul 21 Shemanski.
I'm with the Electrical Instrumentation and 22 Control Branch, Division of Engineering.
I will be making 23 presentations on the four remaining sections; Section 3.12, 24 3.13, 4.1 and 4.0.
25 Starting with Section 3.12, which is entitled i
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electrical components.
This section is devoted primarily to
()
2 not EQ cables.
Electrical cables are long-lived, passive 3
-components-that are within scope and subject to an AMR and 4
cables that are associated basically with every plant 5
system.
6 At Calvert Cliffs, there are approximately 30,000 7
cables and of the 30,000 cables, 29,000 are non-EQ cables 8
and 1,000 are EQ cables.
9 Again, this section deals primarily with the 10 non-EQ cables.
Because of the large population, BGE decided 11 to treat cables, the non-EQ cables as a commodity and for 12 efficiency, the 29,000 non-EQ cables, they were divided up 13 into six groups, as indicated on the slide.
14 The first two groups are located in the main steam 15 penetration room.
Thefirstgroudconsistsofcablesand 16 power control servers routed without maintained spacing, 17 whereas the second group consists of cables and power 18 servers which are routed with maintained spacing.
19 The reason group number two has maintained spacing 20 is that these cables are designed to carry larger currents, 21 so they have to be spaced a certain number of cable 22 diameters away from each other, so that you don't suffer the 23 thermal effects of self-heating, due to ohmic heating.
24-DR. MILLER:
So the spacing requirements are 25 strictly the ohmic heating.
[
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MR. SHEMANSKI:
It's the ohmic heating and the 2
spacing is determined by the actual -- I guess they go 3
through_and do the thermal calculations and determine how 4
many cable diameters away form each other they must be 5
spaced.
It's a function of the cable loading, the current 6
it's carrying.
7 DR. MILLER:
Are any of these cables -- are there 8
any in radiation areas?
I notice you have -- I'm looking at 9
the LRA right now and you have a lot of discussion of cables I
10 that are in radiation areas and how you're going to handle 11 those through calibration and so forth.
12 MR. SHEMANSKI:
These particular cables are 13 located in the main steam. penetration room and I do not 14 believe -- Carl, is that correct?
I think they're only
{
15 subject to thermal.
16 DR. MILLER:
These probably aren't in radiation 17 areas.
18 MR. SHEMANSKI:
I don't believe these are.
19 MR. YODER:
My name is Carl Yoder.
Those cables 20 in the first two groups are outside containment.
They are 21 in the aux building, not just the main steam pen room, but 22 throughout the aux building.
23 MR. SHEMANSKI:
Now, group three, cables and power 24 servers, those are located in containment and they are 25 subject to synergistic thermal and radiation aging and the
(
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l 1
max temperature in containment is 120 degrees F.
{
l(,j 2
Group four, cables in the four KV power service, 3
those cables are subject to thermal aging and they are used 4
for the four KV pump motors in the saltwater system.
5 Group Inndoer five, those cables are located in 6
instrumentation service and they are subject to thermal 7
aging resulting from a reduction of insulation resistance.
8 DR. MILLER:
So those are subject to degradation.
.9 MR. SHEMANSKI:
Yes, they are.
Instrumentation 10 cables tend to be smaller and more susceptible because of 11 their physical dimensions, more susceptible to thermal l
1 12 degradation, and those particular ones, they manage the
]
13 aging through instrument calibration program.
They i
O periodically calibrate the instrumentation circuitry and i
14 C/
15 they can, in essence, tell if they're getting degradation 16 due to calibration errors or whatever -- not calibration 17 errors, but changes in calibration.
18 DR. MILLER:
So the concept I'm reading this 19 section right now in the LRA.
The concept there is you have 20
-- starting at excessive drifting, for example.
You're 21 going to attribute those to cabling or --
22 MR. SHEMANSKI:
You start by doing a root cause 23 analysis and it may lead you to a determination that the 24 cable insulation may be degrading, resulting in the increase 25 in -- or I should say reduction in insulation resistance and 3
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};
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236 i
i
)
'1'
.that.would effect the calibration of the instrumentation j
)
2
- circuits.
\\
'3
'DR. MILLER:
And all those cables are accessible,
.4' so'they can repiace them.
1 L
5 MR. SHEMANSKI:
I believe so..And the last. group
~
are cable. sin the four KV power service.
They're also used 4
6-
]
- l
-7 for.the~four KV pump motors in'the saltwater system, but' 1
8
~they're;--.welli they' looked to see if'they were susceptible 9'
to a degradation mechanisms called treeing.
Treeing is a 10-form -- it's a high voltage induced degradation.
It results 11
.in kind of a tree-like pattern in the cable insulation and 12-
'its. degradation that provides hollow microchannels in the 13 cable to grow.
f 14 And as those microchannels grow, I guess, the i
15 cable becomes -- you have? changes'in the dielectric l
16
. material, dielectric. characteristics of the insulation.
l
.,17.
'However,.they did.do anI ARDI and found that there was no' 18 1 evidence 1of;any treeing in.those high. voltage cables.
-19 DR.. MILLER:
And none of those cables -- are those 2 0.,
cables in. radiation. areas?
21 MR. SHEMANSKI:
No.
They're'in the -- they're j
. 22' used for the four KV' pump motors.
They are subject to.
4
.23.,
thermal degradation.
24 DR. MILLER: 1So the only cables'really in the 25:
radiation areas are' instrumentation cables.
Is that right?
ANN RILEY &' ASSOCIATES,'LTD.
Court Reporters 1025 Connecticut Avenue, NW, Suite 1014 l'
Washington; D.C. 20036' (202)' 842-0034'
c
~
il 237 IL NR. SHEMANSKI:
No.
There are cables in power
.p
,,j.
2 service in containment, group three.
{
3 DR. MILLER:
.I'm sorry.
You're right.
4 MR. SHEMANSKI:
And those, of course, are subject 5
to synergistic thermal and radiation aging.
.6 DR. MILLER:
So how are -- I can probably read it 7-here an'd find it.
How are they going to handle those 8
effects in case -- instrumentation, I can see they're going 9
to-do surveillance.
On the power service, how are they 10 going to do those, if there is any degradation?
Since we I
11 know that degradation of instrumentation cables -- I mean, 12-there are different insulators and so forth, I'm certain 13 there are.
14 MR. SHEMANSKI:
Group three was subjected to an 15-ARDI.
As a matter of fact, all six groups were. subjected to 16 ARDIs and the ARDIs, the age-related degradation 17 inspections, have been completed.
Specifically, for group 18 three, BGE is telling uc that any power cables that satisfy
-19 the following criteria, if they're inside containment, if 20 they use EPR, which is ethylene, propylene, rubber or 21 cross-link polyethylene, if they're not environmentally 22 qualified, which these are non-EQ cables, they're saying 23
'that'these are considered to be subject to plausible 24 synergistic radiation and thermal aging.
So they will --
25 those are plausible aging mechanisms, so they will p].
t
' ANN RILEY & ASSOCIATES, LTD.
Court Reporters 1025 Connecticut Avenue, NW, Suite 1014 Washington, D.C.
20036 (202) 842-0034 6
.i c
j l
238
{
1 periodically have to look and see if they are getting any j
I<s) lf type of degradation, i
i 3
DR. MILLER:
Is that by visual inspection?
4 MR. SHEMANSKI:
Well, one way.
They do have 1
5 monitors, radiation.temperat.ure monitors.
They know what 6
the threshold levels are of the cable insulation material.
I 1
7-Carl, I believe, wants to amplify.
{
8 MR. YODER:
I just want to clarify.
With regard l
9 to those cables we have determined.to a subject to l
10 plausible aging, except for the instrumentation cables, 11 which will be subject to loop calibrations that include the 212 cables, the rest of those, we've committed to replace.
13 DR. MILLER:
So they're all accessible for 14 replacement, in other words.
1 O
l i,/
15 MR. YODER:
Well, we'll probably end up re-running j
s 16 them.
We won't pull all the cables out.
17 DR. MILLER:
So you pull the old ones out and 18 you'll re-route them if you can't route them --
19 MR. YODER:
We normally would not pull an old 20 cable out because it would probably' damage surrounding i
21 cables.
So we'd run new ones.
22 DR. MILLER:
I see.
J 23' MR. SHEMANSKI:
This particular slide shows the 24 various aging effects which cables are, subject to, 25.
embrittl'ement, cracking, reduced mechanical integrity, 1
(
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1 Court Reporters 1025 Connecticut Avenue, NW, Suite 1014 i
' Washington, D.C.
20036 (202) 842-0034 I
7)
I 239 1
swelling and so forth, insulation resistance reduction.
And p;
2 we= mentioned the ARDI~ program, which has been completed for 3
these. cables.
4 I also talked'about the instrument calibration
)
1 5
program.
)
i 6
.As a result of our review of these non-EQ cables, I
7 we did'not identify any open-items or license renewal g
8 issues.
9 DR. MILLER:
Now, somewhere I saw that, of course, 10" there is a generic issue 168 on cables.
How do we get 11 around that?
That's not been fully reconciled yet.
l 12 MR. SHEMANSKI:
This particular section is on 13 non-EQ cables.
-14 DR. MILLER:
That's non-EO, you're right.
I'll 15 wait for that, i
16' MR. SHEMANSKI:
My last presentation will be on 17 EQ.
168, GSI-168 is devoted to environmental qualification.
18 DR. MILLER:
We'11 wait.
19 MR, SHEMANSK1:
This is not the section, 3.13.
20 This is confusing.
Let me explain how we arrived at putting 21 this section in the SER.
22 If you.ock in the license renewal rule, EQ 23 appears-twice.
It appears once under scoping, where the 24 five regulated events are listed, ATWS, fire protection, Y
25 PTS, so EQ is listed under scoping.
Then it appears again ANN RILEY & ASSOCIATES, LTD.
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240 1
in the EQ rule -- I mean, in the renewal rule as a TLAA.
/' N Q
2 This particular section, when BGE generated their
-3 application, they wanted to address the scoping aspect of 4
EQ, which requires that you look at passive, long-lived 5
components.
So what they did was they took the EQ master 6
list and they only looked at the long-lived, passive 7
components.On the EQ master list, where there may be j
intended functions of these components that are not managed 8
9 by the EQ program, and because the EQ program focuses f
10 primarily on radiation and temperature.
Those are the main-11 carameters.
)
.12 However, if you look at some of these components, 13 auch as the cont.ainment penetration assembly, that is 14 subject to general corrosion.
Well,, that general corrosion
()
15 is not handled by the EQ program..
{
/7 So BGE identified four I
16-components here, the containment penetration assemblies, 17 core exit thermocouples, they're subject to crevice 18 corrosion and pitting, solenoid valves, they're subject to 19 crevice corrosion and pitting, and the reactor level vessel 20 monitoring in core assembly, which is subject to crevice 21 corrosion and pitting.
22 For those particular aging effects, they 23 identified the-following programs.
For the specific class 24 of EQ components, the ones I just mentioned, general 25 corrosion, crevice corrosion and pitting, those are handled A'
t ANN RILEY & ASSOCIATES, LTD.
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20036 (202) 842-0034 1
6 6 l
l u
I 241 i
1 by the chemistry control program in PEG-7, which I believe i
.2 is,a walkdown type program.
.3 Kapton-unique aging, that one is dealing with the 4
insulated wires on Valcor solenoid valvaa.
It turns out 5
that Kapton, it's not an extruded insulation material.
It's 6'
sort of. wrapped.and, as such, it's more susceptible to k
1 7:
absorbing moisture and under-hot high moisture conditions, i
8 hot temperature and high moisture conditions, the Kapten can i
9 absorb water and then it becomes very brittle.
10 It really should only be used in an environment 11.
less than 40 percent.
So'that's. sort of a unique aging 12 effect for a particular type of solenoid valve that BGE is 13 using.
{
1 i
14 There were no open items or confirmatory items or
{
n N-
'15 license renewal issues' associated with this subset of EQ s
16 components that I just discussed.
17-DR. UHRIG:
Are any of the Kapton-unique 18 components used in safety systems?
19 MR. SHEMANSKI:
I believe so.
They're used as 20-solenoid valves and I.believe the answer is yes, they are in 21 safety-related systems.
They are on the EQ master list.
22 DR. UHRIG:
So anything that's EQ would be on a 23 safety system.
24 MR. SHEMANSKI:
Right.
Although it is possible, 25 on the EQ master list, there are some non-safety-related r%
.()..
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+
242 1
components that may have to be qualified.
But probably 95
(~)N
(,
2 percent of the components on the.EQ master list are 3
safety-related electrical components.
4 DR. MILLER:
The idea here is they've already been 4
l 5
qualified.
j 6-MR. SHEMANSKI:
They've already been qualified.
l 7
DR. MILLER:
Tested at least.
8 MR.'SHEMANSKI:
Right.
They've been qualified 9
through LOCA testing.
10 DR. MILLER:
And somebody has agreed that a 11 short-term LOCA type test is equivalent to a long-term --
12 you have the same number of rads over long-term and it's the j
13 same number of a short-term.
14 MR. SHEMANSKI:
Well, basically, you're trying to l
(')
k.)
.15 in a LOCA chamber, you're trying to simulate LOCA and 16 they go through and make a calculation of what the expected 17 pressure and temperature is.
They try to simulate that in 18 the LOCA chamber and then they add in the accident dose that
.19 you would expect, typically 150 mega-rads.
So it's, in 20 essence, trying to simulate LOCA conditions.
21 How long you test it in.the LOCA chamber is a 22 function of how long the equipment is required to cperate 23 post-LOCA, and that varies depending on the plant CLV.
Some 24 plants have a~30-day operability time, others go up to, I 25 believe, one year.
It's a function of when the plant was
,A i,)
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m 243 I
licensed.
j
/
(,,N) 2 DR. MILLER:
Of course, that's not a synergistic 3
test.
Temperature and radiation is not the same thing.
4 MR. SHEMANSKI:
Well, you do get a -- there.is a 5
synergistic effect.
You get,added degradation when you l
6 combine radiation and temperature.
i 7
DR. MILLER:
They just aren't done at the same 8
time.
9 MR. SHEMANSKI:
Right.
Are there any additional 10 questions on cables?
Because the next presentation will be f
1 11 on TLAAs.
f I
12 DR. MILLER:
The generic issue, are you going to 1
l 13 address that here sometime?
l 14 MR. SHEMANSKI:
Yes.
The.next presentation --
i (D
\\_)
15' MR. SOLORIO:
Paul, can I interrupt something?
16 Before you go on, Paul.
BG&E pointed out to me something 17 related to an earlier presentation the staff has made on 18 Section 3.11.
With respect to the electrical commodities, 19 BG&E has changed their commitment to use ARDI as one of 20 their aging management programs and they're going to use i
21 electrical penetrations.
That was a recent change and the
'22 staff is reviewing that against the SER, because it's 23 currently not reflected in the staff's SER.
24 However, I don't anticipate there being any 25 significant changes, because we're really talking about O,g ANN RILEY & ASSOCIATES, LTD.
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20036 (202) 842-0034
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]
L1
' going to'-- the nature of the program probably is going to
'2 be very similar and it's probably going to be even more 3
frequent.
4 As opposed to a one-time inspection, it's going to 5
'be a periodic type of inspection.
So I don't see a 6
significant change in that area.
7 MR. SHEMANSKI:
Okay.
The next section in the 6
SER, Section 4.1, is the identification of time-limited 9
aging analyses, TLAAs.
BGE has identified each TLAA with its aging effect and its disposition, demonstrating that the 10 11 analyses either remain valid for the period of extended 12 operation, the analyses have been projected through the end 13 of the period of extended operation, or the effects of aging 14 on the intended functions will be adequately managed for the 15 period of extended operation.
~
16 In my next presentation, I'll go into a little 17 more detail on EQ, because you haven't heard anything about I
18 that yet.
However, for the other TLAAs, which appear on 19 this slide and the next slide, this is a total list of 20 TLAAs.
21 Do you have any specific questions on those?
You heard most of the discussion regarding fatigue monitoring 22 23
. program and I believe most of these, if not all, have been 24
' covered by_ previous speakers.
So if you do have any 25 specific questions on any of these TLAAs, we have several
()
ANN RILEY & ASSOCIATES, LTD.
Court Reporters 1025 Connecticut Avenue, NW, Suite 1014 Washington, D.C. 20036 (202) 842-0034
F 245 1
' staff members that probably would be in a better position to 2
answer them.
3 Basically, what I've given you here is the list of 4
the TLAAs that have been identified by BGE.
I'll just run l
5 through them one by one.
Th,e heat-up and cool-down curves,
{
l 6
the aging effect is radiation embrittlement and the aging
'7 management program relies on the G and H, 10 CFR 50 8
Appendices G and H curves, and data from the surveillance 9
capsules.
10' DR. FONTANA:
TLAA involves equipment that whose 11 lifetime originally -- let me see if I understand this 12 properly.
It's equipment whose lifetime originally could 13 have gone past 40 years, but if you're going to extend a 14 licenea, it can go -- the equipment.will have to operate-f_ t t
'\\ l 15 beyond what may have been its design life.
Is that correct, 11 6 basically?
And you have to analyze that it's going to be 17 able to perform its function during this additional time 18 period, is that correct?
19 MR, SHEMANSKI:
Right.
20 DR. FONTANA:
Now, the analysis then is done, like 21 the heat-up and cool-down curves on radiation embrittlement, 22 the analysis is obviously quantitative.
You have models and 23 predictions and that sort of thing.
24 They're not referenced here.
I guess if you look 25' at the BG&E report and you track the references all the way r~N
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1 through, they should take you to the models and data and
. f ~g
(,)
2 uncertaintiee and everything else.
Is that correct?
3 MR..SHEMANSKI:
Well, they should, yes.
Right.
4-DR. FONTANA:
Well, do they?
1 5
MR. GRIMES:
Dr. F.ontana, if I cculd.
The 6
simplest way to describe time-limited aging analysis is l
7 basically a design analysis that, in some way, incorporates 8
40 years in the design calculation.
So for example, the PTS 9
analysis has a plant life assumption it.
Fatigue has a 10 certain number of cycles assumed in it.
11 And this, the aging management aspect of i
12
-time-limited aging analysis is either that you show that the l
l 13
-- you state the analysis has'already been updated for a 14-60-year life, you -- it either already exists, it has been
(, \\
(
's_,/
15 updated to 60 years, or it will be managed in some way.
16 DR. FONTANA:
Well, how do you know it's any good?
17 MR. GRIMES:
We review the analysis results.
18 We've either done it -- as Barry mentioned earlier, we've 19 already done a safety evaluation related to embrittlement 20 for a 60-year life.
In other cases, there are analyses that t
21 we've seen before.
So by sampling a typical analysis, we 22 have confidence that simply redoing the analysis with a i
23 different assumption is all right, or there is an aging
)
1 24 management aspect associated.
There is a process aspect i
1 25 that we can refer to.
I I
7-~
4
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i 1
MR. ELLIOT:
I'm Barry Elliot.
The pressure
'2 temperature limits curves are developed from the 3
requirements in Appendix G and the requirements in Appendix 4
H is the surveillance program.
That's just to confirm that 5
the embrittlement we used fo.r the curve is what we think it 6
is.
7 Now, the embrittlement -- the non-embrittled 8
-portion of the analysis is in the ASME code.
It's a I
9 specified way of calculating pressure temperature limits.
10 The part that's age-related degradation is the embrittlement 11 portion and that is -- we have regulatory guide, Reg Guide 12 1.99, Rev 2, which describes how you are to calculate the 13 amount of embrittlement which goes into these pressure l
~14 temperature limits.
What we do is if a new pressure O
1
\\m /-
15 temperature limit comes in, we review the surveillance data, 4
i 16 we review the methodology of calculating the embrittlement 17 to make sure it complies with what's in the regulatory 18 guide.
I 19 So this is time-limited aging.
It happens to be, i
20 for this particular plant, they gave us a 48 effective full 21 power year curve already and so they've already done -- for i
22 the equivalent fluence of 48 effective full power years, for 3
23 Unit 1.
For Unit 2, I think they have only a 30 effective
)
24 full power years.
25 So sometime in the future, before 30 effective j
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1
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full power years, they have to give us another curve that (A) 2 applies to 48 effective full power years.
But they would be 3
following the guidance in the -- the requirements of 4
Appendices G and H and the regulatory guidance in Reg Guide 5
1.99 to calculate those curves.
6 DR. FONTANA:
Okay.
Thanks.
7 MR. SHEMANSKI:
Okay.
The next two TLAAs involve 8
fatigue analysis for RCS piping, steam generator 9
pressurizer, pressurizer auxiliary spray line, and 10 pressurizer surge line.
The next one is the fatigue 11 analysis for main steam supply lines for turbine-driven aux 12 feed pumps, aad those are both managed by the fatigue 13 monitoring program.
14 In addition, the next TLAA is also managed by the 1
(_/
15 fatigue monitoring program, fatigu'e analysis for the 16 containment liner plate.
The next TLAA is the pre-stress 17 loss calculations on containment tendons.
That particular 18 TLAA has been deferred by Baltimore Gas & Electric to the 19 year 2012.
20 Another TLAA is.the spent fuel pool criticality 21 calculation, the aging effect is loss of neutron absorption i
22 and the coupon surveillance program is used as the aging 23 management program for that.
24 DR. FONTANA:
I'm just curious.
How do you go 25 about measuring the tension in the tendon?
f'N
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MR. SHEMANSKI:
They've got a lift-off test which O
(,/
2 is in the tech specs and I forget the parameter, 2000 KIPS 3
or'some -- I don't recall the exact number, but they have
~
4 kind of a jack and they're able to measure the lift-off 5
force with the tendons, and that's really not my area.
G DR. FONTANA:
Okay.
7 MR. SOLORIO:
The NRC staff reviewer who evaluated 8
that isn't here at the moment, but I believe someone from 9
BG&E has some information they can provide.
10 DR. FONTANA:
I'm sure you know how to do it.
I 11 was just curious.
12 MR. WARD:
I'm Don Ward.
It's sort of backing out 13 of the way they're installed initially.
The tendons are 14 installed with shims under both ends, so that you wind up
(*h 5-)
15 with stretching the wire in orderto get the tension in 16 there.
17 When you do the lift-off test, you put a ram back 18 on one end or a jack, a thousand-ton -- I'm sorry -- a 119 500-ton jack, pull on it, and measure the force.
There are 20 gauges on ti.e jack that you can measure the force with.
21 DR. FONTANA:
Five hundred ton jack.
22 MR. WARD:
Yes.
They carry about 700,000 pounds 23 each.
j 24 DR. FONTANA:
Thanks.
i 25 DR. SHACK:
What does it mean when the program is
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deferred to 2012?
-O r
(,/
2 MR. PATNAIK:
This is Pat Patnaik.
What we got 3
from the applicant, that they would provide us the curves, 4
the loss of stress, pre-stress loss, on the tendons, 5
calculated to the new values.
That will be covered in the 6
tech specs.
Those are in the tech specs.
7 MR. WARD:
Don Ward again.
The part that was in 8
the tech specs, that you will now remember being in the tech 9
specs, was recently moved to chapter 15 of the FSAR, but 10 it's the same sort of thing.
It's these curves plot'on 11 semilog paper as a straight line.
We were just looking to 12 see if tnere are any nuances and so it's being deferred a 13 bit, particularly until we decide what we're doing with the le vertical tendons.
('
15 MR. SOLORIO:
Th'.s is Dave Solorio.
I just wanted 16 to point out also thac there is an open item associated with 17 this.
Page 109.
9 MR. SHEMANS.KI :
It's open item 4.1.3-2, deferral 19 of the re-calculation of loss of pre-stress on contrinment 20 tendons, to the year 2000.
Since we're on open items.
21 There is also an open item on the addition of the 22-upper shelf energy evaluation as a TLAA.
The staff has 23 concluded that this is a TLAA and should be treated as such.
24 The third open item is the addition of. metal fatigue of 25 B-31-7 Class 2 and Class 3 piping as a TLAA.
Apparently,
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I 1
BGE did not -- I'm sorry -- BGE did consider the number of j
f~%
(_,)
2 cycles in the evaluation of Class 2 and Class 3 piping.
3
_Therefore, the staff feels that this is a TLAA, 4.
should be treated as a TLAA.
There is one confirmatory item I
5 regarding documentation of containment liner plate fatigue 6
analysis.
Basically, BGE needs to document the evaluation
{
l 7
which demonstrates that the current analysis remains valid l
8 for the period of extended operation.
9 We list one license renewal issue, 98-0048, 10-elevated temperature of pre-stress in tendons.
This, I l
11 believe, was previously discussed in Section 3.10 of the 12 staff SER on building structures.
13 Are there any additional questions regarding 14 TLAAs?
("
(_,
15 (No response.)
16 DR. FONTANA:
I guess not.
17 MR. SHEMANSKI:
If not, then I'll go to the final 18 TLAA, which is EQ, environment qualification of electrical 19
-equipment.
BGE identified the 10 CFR 50.49 program, that's 20 the EQ rule, 50.49.
BGE identified that as a TLAA for 21 license renewal.
22 Now, it's important to note that when the staff 23
- evaluated the BGE TLAA for EQ, we focused on the program 24 elements and process, and I will repeat that again.
We 25 focused'on the' program elements and process provided by BGE.
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l 252 1
They are using standard approved EQ methodology rs
(,)
2 and acceptance criteria in accordance with the 10 CFR 50.49 3
EQ rule.
4 Basically, the way BGE is treating it, for all of l
5 the long-lived active and passive, this TLAA is unique, it i
6 includes -- this is the only TLAA, the only place in the 7
application you'll see where we have active components in 8
9 It just sc happens that the EQ rule 50.49, when 10 you look the EQ mastur list, it consists of active and 11 passive components.
12 DR. MILLER:
Did they do that just for 13 convenience?
14 MR. SHEMANSKI:
No.
I mean, that was the way the 15 EQ rule initially was developed.
You had to list or include 16 all of the electrical components that --
17 DR. MILLER:
All safety-related.
l 18 MR. SHEMANSKI:
All safety-related electrical j
i
_19 components that are, number one, subjected to a LOCA or main j
20 steam line break or high energy line. break; that is,
)
i 21 subjected to a harsh environment, and then required to 22 mitigate that particular DBE.
.23 You look at the list, it includes, as you could 24 see, motors, transmitters, pressure switches, all of which 25 are active.
But for this particular TLAA, we do include
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.1 both active and passive long-lived components, e-(s) 2 DR. MILLER:
But it wasn't required to do that.
3 Is it required to do that by the rule?
4 MR. SHEMANSKI:
Which rule are you referring to?
5 DR. MILLER:
By th,e rule, the license renewal 6
rule.
7 MR. SHEMANSKI:
The focus of the Part 54 rule is 8
on long-lived --
9 DR. MILLER:
Passive.
i 10 MR. SHEMANSKI:
-- passive components.
- However, 11 it does list five regulated events.
It lists -- in 12 paragraph 54.3, it lists fire protection EQ, ATWS, PTS, and
'13 station blackout.
And by picking up the EQ rule, you 14 automatically pick up the EQ rule master list, which has O) -
(%,
15 active components.
~
16 DR. MILLER:
So by including EQ, you automatically 17 pick it up.
18 MR. SHEMANSKI:
You automatically pick these up.
19 So there -- and basically the aging management program for 20 EQ is the 50.49 program.
21 DR. MILLER:
In a way, the rule 54 picks up 22 through EQ the active components.
23 MR. SHEMANSKI:
Right.
1 24 DR. MILLER:
The EQ program then covers you.
25-MR. SHEMANSKI:
That's correct.
f
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V 254 l'
DR. MILLER:
That's a simple way to put it.
)
2 MR. SHEMANSKI:
And the way BGE approaches the 3
qualification of these particular components is prior to the 4
end of an equipment's qualified life, the equipment will be 5
replaced, unless it can be -- unless the qualified life can 6
be extended through reevaluation, primarily re-analysis.
So 7
they te'll us that sufficiently in advance, prior to the 8
expiration of a component's qualified life, they will go 9
through and determine whether or not that component needs to 10 be replaced or whether or not they could extend the 11 qualified life based on re-analysis or some type of 12 reevaluation.
13 Now, we reviewed the methodology that BGE is using 14 in their current EQ program, and keep in mind that they do O
15 have an approved 50.49 program. -[ hey've got an SER issued 16 by t'a staff in the mid '80s which finds their EQ program in 17 compliance with 50.49.
So they're solid for the first 40 18 years.
19 And as equipments on the EQ master list approach 20 the.end of their qualified life, they will be re-assessed 21 ten years from now just as they are today.
They will be 22 using the same methodology.
1 23 So we looked at how they extend their component 24 qualified life and we evaluated or looked at the acceptance 25 criteria they apply, what type of corrective actions they
()
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.l 255 1
use, how they go about refurbishing.
(A_,)
2 We looked very closely at how they would be 3
applying re-analysis, how they treat the thermal and I
4 radiation environments, and what effect any plant 5
environmental changes would have on the qualification 6
status.
So we took a pretty in-depth look at their existing 7
program, basically doing a process type evaluation, and are 8
satisfied that 50.49 is an acceptable aging management 9
program.
10 DR. MILLER:
So 50.49 covers everything that we've l
t 11 talked about all day today.
12 MR. SHEMANSKI:
Well, 50.49 focuses primarily on 13 electrical components in a harsh environment.
The key 14 stressors they are subjected to are. thermal and radiation b
A s/
15 and if they happen to be subject to spray from the ECCS 16 system, caustic spray, then, of course, they --
17 DR. MILLER:
Boron -- boric spray.
18 MR. SHEMANSKI:
Right, they've got to simulate 19 that in the LOCA chamber, that is part of the qualification l
20 process.
l 1
21 This slide shows the aging effects due to thermal 1
22 and radiation primarily, and those aging effects are managed 1
23 by the qualification process, which is utilized in the 50.49 24-program.
t
~
i 25 DR. MILLER:
So were all the things like all the
{
rh iy ANN RILEY & ASSOCIATES, LTD.
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sensors and so forth excluded and all the rest of the
("%y.
(,)
2 program, now we've got pressure and flow transmitters all 3
included at this point for these -- if they're EQ.
4 MR. SHEMANSKI:
Right.
5 DR. MILLER:
And we assume an environmental 6
qualification covers all the issues we talked about.
7 MR. SHEMANSKI:
Well, it does not cover things 8
like crevice corrosion or general corrosion.
It turns out 9
that some of these components on here, electrical 10 penetration assemblies, solenoid valves, they have a license 11 renewal intended function, for example, to maintain pressure 12 boundary and that particular function is really not -- it's 13 not evaluated in the EQ program.
That was why BGE, when I 14 went through Section 3.13, they loo 8ed to see are there --
(
they went through these -- this edtire EQ master list and 15 16 they said are there any of these components that have 17 intended functions such as pressure boundary that are not 18 covered by the EQ program, and they did find four, I 19 believe.
20 DR. MILLER:
Solenoid valves were addressed 21 separately in there.
22 MR. SHE14ANSKI :
Right.
So they are subject to 23 general corrosion or pitting and, of course, those aging 24 effects are not managed by the EQ program, but they're 25 managed by other programs, I believe the chemistry control b
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program.
f~)
'(_j 2
So the bottom line is I think they've got all the 3
-- all of the plausible aging effects have a management 4
program.
S' DR. MILLER:
In that list, there's, of course, a 6
whole bunch of passive components.
They've already been 7
covered under the other program, as well as this one.
8 MR. SHEMANSKI:
Right.
9 DR. MILLER:
So the only questionable one would be 10 components such as flow transmitters and pressure 11 transmitters and level transmitters.
Those might be the 12 only ones that might be falling through the crack, so to 13 speak.
14 MR. SHEMANSKI:
I don't believe they have fallen
\\_/
15 through the crack, because I don't think those particular 16 ones have any license renewal intended functions that are 17 not being managed by the EQ program.
18 DR. MILLER:
I'm not saying they did.
I'm saying 19 they could have.
20 MR. SHEMANSKI:
They could have.
We did look and 21 I don't believe --
22 DR.' MILLER:
Based on the fact that we spent maybe 23 five or ten hours on this, everybody else has spent many 24 more than that.
.I just looked at it from a superficial 25 viewpoint and I would say, gee, did we cover everything of
- (
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those active components that weren't covered under all the 2
other programs, does EQ cover everything under those.
)
3 MR. GRIMES:
Dr. Miller, I looked at --
4 DR. MILLER:
Am I asking a question that makes any 5
sense?
6 MR. GRIMES:
Yes, and I'd like to attack your j
7 question in a slightly different way.
{
8 DR. MILLER:
Don't attack it.
- Address, k
9 MR. GRIMES:
Address.
Okay.
First of all, I want 10 to clarify, time-limited aging analysis don't care about the 11 license renewal scope.
They're a time-limited aging 12 analysis.
There is a qualified life.
EQ just happens to be 13 the biggest qualified life question we've tackled and for --
)
14' to the extent that managing the environmental qualification G
D 15 time-limited aging analysis relied upon the 50.49 program, 16 regardless of whether or not you've got a piece of equipment 17 that's active, passive, long-lived, short-lived, whatever it 18-is, if it's got an EQ qualified life of a year, 40 years or 19 1,000 years, the 50.49 process will sort that out.
20 To get back to your other question about what do 21 we do with GSI-168, to the extent that information comes out 22 of'that research that challenges the qualified life of any 23_
particular cable, then that same compliance with 50.59 24
. process, about making decisions about replacing, 25 refurbishing, re-analyzing or re-testing, we rely on that ANN RILEY & ASSOCIATES, LTD.
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process to' address GSI-168 until the research identifies l'Q) something different to do.
2 3
But to the extent that EQ stuff is also captured 4
as -- in 4.13 of the -- I'm sorry -- 3.13 of the safety 5
evaluation, where.we also look at it from the standpoint of 6
are there other aging effects that are not explicitly 7
addressed by this qualified life process, like crevice j
8 corrosion or fatigue or other thing, then we address that 9
specifically for passive components.
10 For active components, all of those things are 11.
excluded for the same' reason we excluded active equipment 12 and that's basically we're looking at reliability under the 13 maintenance program as the means to. manage aging effects for 14 active components.
k-15 DR. MILLER:
I think I'm visually seeing 16 everything fitting together.
I'm now seeing the cracks are 17 closing.
18 MR. GRIMES:
The EQ was particularly troublesome 19 for us, as well, because even though it's a well established 20 and well regulated program, it's got this overlapping area 21 of responsibility and so that's why we ended up with one 22 section of the safety evaluation that treats aging effects 23 and aging management programs and then time-limited aging 24 analysis also has an aging management aspe'ct of it, as well, 25 but it really gets back to the process question.
( )'
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MR. SHEMANSKI:
My last slide, there are no open
()
items or no confirmatory items regarding EQ.
However, we 2
3 did have one license renewal issue, 98-0014, which basically 4
asked the question whether or not 10 CFR 50.49 is an 5
adequate aging management program under the license renewal G
rule.
And basically, the answer is yes, and we concluded in the BGE SER that 10 CFR 50.49 is an acceptable aging 7
8 management program under 10 CFR 54.21, 9
MR. GRIMES:
Paul, if I may.
I would like to 10 clarify that this particular generic renewal issue has now 11 blossomed into what we call the credit for existing programs 12 issue, which was forwarded to the Commission and I believe 13 that the ACRS received a copy when we forwarded the NEI 14 letter.
(D
()
15 We're developing a Commission paper that addresses 16 the extent to which the staff can conduct a license renewal review without challenging the adequacy of these existing 17 18 programs.
19 So you will be hearing more about that, but for 20 the purpose of this review, we challenged the existing 21 programs.
We went digging into, for example, environmental 22'
' qualification and compliance with 50.49.
The means of 23 compliance as it relates to managing aging.
24 So you will be hearing some more about that issue, 25 but it's really more relevant to treating future l(N I
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applications.
()
2 DR. FONTANA:
The future applications, these i
3 license renewal issues that are resolved now, are they 4
assumed to be resolved for all future applications?
5 MR. GRIMES:
To the extent that we would add 6
guidance to the standard review plan or that NEI would add 7
guidance to the NEI 95-10 guide on preparing an application, 8
yes, we consider them resolved for future applications, too.
9 DR. FONTANA:
We're a little overdue on our break.
10 Any questions on this area here?
11 MR. WESSMAN:
Before we go on a break.
I'm Dick 12 Wessman, with the staff.
A minor housekeeping item.
On 13 page 108 of the viewgraphs, we had an erroneous entry there 14 and I wanted to clarify that.
If you look at that, you will 15 see a couple of entries, one of tIem dealing with fatigue 16 analysis for the containment liner and another one at the 17 bottom dealing with Class 2 and 3 piping.
18 Those two activities are not covered by the 19 fatigue monitoring program, per se, but they are addressed 20 by analysis activities done by-the applicant.
21 DR. FONTANA:
Thank you.
22 MR. WESSMAN:
Yes, sir.
That's all.
23 DR. FONTANA:
Let's take a break.
Let's see.
24 When we come back, we'd like to discuss what will be 25 presented at the May full ACRS meeting, some topics for an
[)
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262
'l ACRS interim letter,.and possibly what would be appropriate D)
\\
2 for additional staff presentations and maybe for future 3-meetings.
So you all may want to be giving some thought to 4
those-items.
5 So let's-come back at 20 of.
-6 (Recess.]
7 DR. FONTANA:
The meeting will.come back into 8
' session.
The first thing that we would like to discuss with 9
you is what should be included in a presentation for the 10~
full ACRS meeting the first week in May.
You have an hour
'11 and a half, and that's on the first day, I think, Wednc c_y.
12 Will you be making most of the presentation?
13 MR. GRIMES:
Were you addressing me personally or 14 the staff?
15 DR. FONTANA:
You.
j 16 MR. GRIMES:
We'll do -- actually, we do almost 17 anything you want.
We can do a summary overview.
We can 18 just have a very high level with Dave-giving his overview 19-presentation and maybe putting together some summaries or if 20 there are particular topic areas, Mr. Wessman was graciously 21' supporting us and we could get particular staff to come talk 22 about topical interests.
.23 DR. FONTANA:
Well, the full committee I don't
.24
-believe-has received a presentation from you in this area, 25
-in my memory at least, I don't think.
So-I think it's ANN'RILEY:& ASSOCIATES, LTD.
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probably appropriate to start from the top and give a --
' I^T
(,j 2
because I'm sure that two or three of them that are not here 3-
~ and some that are:here don't understand the whole philosophy 4-of this license renewal, which is really rather esoteric, 5
just coming off.the street and listening to it.
6 So I think an overview of the philosophy basically 7.
.that you as the staff are working within the constraints of 8
Part 54 and whereas we on the committee aren't necessarily.
9 But with regard to what you're doing, I think you probably 10 should quickly overview what Part 54 is constraining you to 11 do.
12 DR. SEALE:
How long do we have?
13 DR. FONTANA:
An hour and a half.
But I think 14 maybe taking about ten minutes to get everybody on the satae
.O\\
V 15 page is probably going to be wort 1[while, because questions 16 that are going to arise are how do you determine what's in 17
. scope and what's not in scope, and the concept of TLAA is 18 rather esoteric, so you may want to say -- just like you 19 said about 20 minutes ago, perfect.
20 Then the area of issues, I'm sure there is going 21 to be some confusion about what are generic license renewal 22 issues compared to the other list of GSIs, and you may want 23-to identify what the difference is, and how you -- the basis 24.
for the prioritization of the issues, the fact we now have 25 105 of them, when I think there's --
I\\
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MR. GRIMES:
It's 109.
,O
. U 2
DR. FONTANA:
It's 109, and I forget how many are 3'
on the priority one list.
In fact, you would allow some 4
issues to go into --
5 DR SEALE:
Sixty years.
6 DR..FONTANA:
To go beyond the end of the current i
7 license, and I'm sure you're going to get asked about that.
8 With respect to the SER, I think we'd like an 9
overview of it, relating most of the key agreements and what i
10 the key issues lett are and what the key confirmatory things j
.11 '.
are.
There aren't many of them left, as far as I could see.
)
y
-12' DR. SEALE:
Could we get some words from BG&E?
l J
1 13 MR. DOROSHUK:
Yes, sir, we could support that.
}
14 Is there any specific area?
h.
1 j
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15 DR. SEALE:
Well, in yot r presentation you made, 16 of course, there's a lot of it that's background and all, 17L
'but the: material and the scope, your perception of what the 3
18-scope is, and then the IPA process you went through, and 19 then maybe a.aummary of some sort.
20' MR. DOROSHUK: 'Yes, sir.
21
~DR. SEALE:
I think that would be very helpful to j
22 the' committee, because it -- I won't call it a bottoms-up i
23 approach, but it is the applicant now working with the 24 process as-opposed to the regulator's perception of what the
'25 process'ought'to come up with, and I think that's very I
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important.
- 1. n k,/
2 DR.'FONIANA:
Those two diagrams.
You have the m
.3-IPA flow' diagram, I think that's useful and very valuable.
4' DR. SEALE:
Yes.
5 MR. GRIMES:
You could start about the IPA flow 6
diagramLand end up abouc the last pie chart, and it's that 7
chunk in'the middle there, t
8' DR. FONTANA:
How much time do you think BG&E 9
should have out of this hour and a half?
10 DR. UHRIG:
Twenty, 30 minutes.
'13 DR. SEALE:
Yes.
Something like that.
11 2 DR. FONTANA:
Something like that.
And I guess 13-you will start it, the staff will start.it, and you
[.
14 determine between yourselves where to break into it, I'
15 guess.
16-MR. WESSMAN:
I think it would be constructive for 17:
the staff to do that int'roduction and overview of the 18.
philosophy,'then go to BG&E with their discussion of how l19 they did the submittal and then come back to our SER and 20 we'll pick the specifica that you'want us to. That's how to 21 handle three 30-minute segments, for lack of a better term.
22 DR. SEALE:
Exactly.
Recognizing that you're 23 going to get interruptions.
24 MR. WESSMAN:
Of course.
Especially by people who 25 are not here.
At least we know who they are.
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DR. FONTANA:
Any additional thoughts on what
)
ought to be covered in the meeting?
2 3
DR. SEhLE:
I could facetiously say that if you 4
don't want to get too many interruptions, you might not say 5
anything about fire protection, but I guess that 6
DR. FONTANA:
Or risk-based.
7
-MR.
WESSMAN:
That's right, George will be here.
8 We could use, as a clue from you all, as to the specific 9
areas.that you think, as we try to characterize the SER, 10 that you want us to spend time on.
I think there's been a i
11 lot of interest in fatigue and we probably need to offer 12 that up.
But if you could give us some other specific areas 13 that you think are areas of interest.
14 DR. MILLER:
I'm not certain this -- this is
,s AJ 15 something I need to look at for my own edification, but I'd 16 like to have more information on the environmental j
17 qualification program and how that all fits together, the 18 things we hit near the end.
19 Now, again, that may not be generic enough for the 20 committee, though.
21 DR. FONTANA:
Well, first of all, you want to get s
22 23 DR. SEALE:
We're down to an hour here, guys.
24 DR. MILLER:
I know, that's what I say, an hour 25 and a half, we won't have enough time for any of these ANN RILEY & ASSOCIATES, LTD.
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2f DR. FONTANA:
When you get to the SER, an 3':
important idea to get across', whichever way you do'it, is
!4 -
the extreme depth.
The thing was actually exhausting to --
5 -
DR. SEALE:
I think the run-through from.the first 6
. day viewgraphs are a good way to-state it.
Your s
7
- presentation, basically.
8 DR. KRESS:
David's.
9.
'DR.
SEALE:
Yes.
Then the question is do you try 10.l to cherry-pick somewhere through the rest of the 110.
11 l DR. MILLER:
Certainly, we've got 30 minutes to go i
12' through the other 110 slides,.and which ones are we going to 13 -
pick.
14 l DR. SHACK:
You'll vote for EQ, I'll vote for t
15 Barry's part,'and everybody will pick the part that 16 interests them.
17 DR. KRESS:
I would pick the steam generators.
L18 DR. SEALE:
I think just to get across the. idea 19 that>you're putting a.very hcM y reliance on inspection, 20 that that's really the tool that this' process, this whole 21 process relies on.
'22 DR.-UHRIG:
I also think it would be useful to 23 convey the concept that this is really using existing 24
. programs to the maximum extent possible, with modifications 25-where necessary.
Only when this was not appropriate did you ANN RILEY & ASSOCIATES, LTD.
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go to new programs.
C 2
DR. FONTANA:
I guess you ought to do something 3
for common aging management programs.
4 DR. SEALE:
Yes.
5 DR. FONTANA:
This, category.
Because I think 6
that's important.
7 DR. UHRIG:
There were some numbers given about 8
what percentage of the -- how many new procedures, how many 9
existing procedures, how many modified procedures.
I don't 10 remember the exact numbers, but it was --
11 MR. GRIMES:
Out of the 430, there were 329 --
12 DR. UHRIG:
Those kind of numbers.
I think that 13 gives you a picture.
14 MR. GRIMES:
Yes, 11 new,.101 modified, something O
15
^
like that.
16 MR. DOROSHUK:
We'll make sure we have those 17 slides for that particular part of the, presentation.
18 DR. MILLER:
I guess we're looking at kind of a 19 condensed version of what we heard yesterday, right?
20 Mostly.
21 DR. FONTANA:
Bill Shack, do you think one of the 22.
things that should be touched on is the Section 3.2, vessels 23 internals and reactor coolant system?
That's what Barry 24 Elliot covered.
25 DR. SHACK:
Well, after you go through the big I (
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. overview, I don' t know whether we should -- the 3.1, the 2-aging management. review of the common management programs 3
maybe should be the big sweep.
Even there, I don't think we 4'
~~ you know,.we can't go through it in the detail that you 5
went here, ^but somehow you'v.e got to, out of this thing,
'6 grab that~ chunk out.
7 I think that will probably chew up --
8.
DR. MILLER:
You've got an hour and a half right 9
there.
)
10 DR. SHACK:
-- most of the time.
Between those 11 two presentations, it's sort of gone.
12 DR. FONTANA:
It sounds like we really can't get 13 into much of the specific areas.
14 DR. SHACK:
I don't see how we can get into the i
,s I )~
\\_
15 specific areas.
16 DR. FONTANA:
Unless the question pops up.
17 MR. DUDLEY:
There is :.n alternative.
For the 18 three people who are not here, provide them a copy of the 19_
slides, where they can see what programs are or what systems 20 are evaluated in each chapter.
21 DR. KRESS:
Those three people will have also read 22 part of the SER and they can come prepared to ask questions.
23 So we'll make it known that if they have an issue with some 24 of that SER,.that they.need to ask.
25 DR. UHRIG:
But you could easily send them the
.r~)
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slides that were used today.
2 MR. SOLORIO:
I would like to ask that if you'd 3
let us know what areas they've read, so we can prepare the 4
staff.
5 MR. WESSMAN:
Yes.
I hate to muster 20 people 6
over here, even though it's only an hour and a half.
If 7
there is any way we can focus it down to a smaller number of 8
key players.
They're busy working on Oconee.
9 DR. FONTANA:
It seems to me that you three guys 10 will be able to cover it at the level we're talking about.
11 DR. SEALE:
Why don't we ask them who they can 12 best do -- I mean, the rest of the guys.
13 MR. GRIMES:
I'd also like to suggest you -- we've 14 got a head start this time.
To the. extent that two and a l
15 half of us anyhow can try and get through as many of'the ss 16 common programs and the basic stuff and address broad l '/
questions about aging management, as much of that as we 18 could accomplish in an hour and a half we're going to have 19 next week, we could do that, and then we've still got open 20 items to resolve.
We could -- we're going to come back to 21 the committee at least once more.
22 So we could -- maybe we could get a sense next 23 week about what particular areas you'd like to explore 24 further and we could just make a commitment that we'll 25 address those in a future meeting.
Os
\\_,/
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To'the extent that we can dispose of as much as
)
2 you can dispose of and focus down on particular areas of 3
interest.
4-DR. UHRIG:
I think in the preparation of the 5
letter, this will be brought.to a focus.
6 DR. FONTANA:
Will that give you enougn to go on?
7 MR. GRIMES:
We're going to -- in the hour and a 8.
half, we're going to devote about 30 minutes to a broad 9
overview of Part 54, terminology,.the basic elements, what 10
.are the time-limited aging analysis, basically a day's 11 presentation in a half an hour for BG&E, and then a 12 half-hour for the safety evaluation overview, which means 13 three 15-minute prepared presentations.
Does that pretty 14 well cover it?
/ -~w 15 DR. FONTANA:
So that the need for additional 16.
staff presentations, I think we're saying we will need them, 17 but what's going to be included probably will come out of 18 the things that are not going to be covered next week, 19 right?
20 MR. GRIMES:
Right.
21 DR. FONTANA:
So these guys can work up --
22 MR. GRIMES:
We'll make commitments next week to 23
. address particular questions and basically frame an agenda
.24 '
for'a future meeting.
i 25-MR.'WESSMAN:
We can bring a few of the key
~
(_)
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people.
I think Stephanie Coffin did a lot of work on the i
O
(,,/
2 ARDI and we'll have her here and that may eliminate some of 3
that area of questioning.
So it isn't like it will just be 1
4 the three of us, but I just don't want to muster all 20.
5 DR. FONTANA:
Any additional ideas, questions?
j 6
No?
If not, are we done?
)
7 DR. SEALE:
I think so.
j i
8 DR. FONTANA:
I'd like to thank the staff and
/
9 BG&E.
These were really well organized response of talks, 10 they were to the point, good presentations.
They reflect a 11 tremendous amount of work and we appreciate the considerable 12 amount of work you did preparing for this meeting, which I'm 13 sure is significant, particularly considering all the other 14 things-you've got to do.
O)
(_
15 So, again, thank you very much, on behalf of the 16 committee, the subcommittee.
We appreciate it, and we'll 17 see you next week.
18 This meeting is over.
19
[Whereupon, at 2:58 p.m.,
the meeting was 20 concluded.]
'21 1
22 j
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